National Emission Standards for Hazardous Air Pollutants From Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel-Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial-Institutional Steam Generating Units; Revisions, 8441-8484 [2015-01699]
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Vol. 80
Tuesday,
No. 31
February 17, 2015
Part III
Environmental Protection Agency
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40 CFR Parts 60 and 63
National Emission Standards for Hazardous Air Pollutants From Coal- and
Oil-Fired Electric Utility Steam Generating Units and Standards of
Performance for Fossil-Fuel-Fired Electric Utility, Industrial-CommercialInstitutional, and Small Industrial-Commercial-Institutional Steam Generating
Units; Revisions; Proposed Rule
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Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
ENVIRONMENTAL PROTECTION
AGENCY
40 CFR Parts 60 and 63
[EPA–HQ–OAR–2009–0234 and EPA–HQ–
OAR–2011–0044; FRL–9921–04–OAR]
RIN 2060–AS41
National Emission Standards for
Hazardous Air Pollutants From Coaland Oil-Fired Electric Utility Steam
Generating Units and Standards of
Performance for Fossil-Fuel-Fired
Electric Utility, Industrial-CommercialInstitutional, and Small IndustrialCommercial-Institutional Steam
Generating Units; Revisions
Environmental Protection
Agency.
ACTION: Proposed rule.
AGENCY:
The U.S. Environmental
Protection Agency (EPA) is proposing
this action to correct and clarify certain
text of the final action titled ‘‘National
Emission Standards for Hazardous Air
Pollutants From Coal- and Oil-Fired
Electric Utility Steam Generating Units
and Standards of Performance for
Fossil-Fuel-Fired Electric Utility,
Industrial-Commercial-Institutional, and
Small Industrial-CommercialInstitutional Steam Generating Units,’’
which was published in the Federal
Register of Thursday, February 16,
2012. We are also proposing to remove
rule provisions establishing an
affirmative defense for malfunction
events in light of a recent court decision
on the issue.
DATES: Comments. Comments must be
received on or before April 3, 2015.
Public Hearing. If anyone contacts the
EPA requesting a public hearing by
February 23, 2015, the EPA will hold a
public hearing on March 4, 2015 from
1 p.m. (Eastern Standard Time) to 5 p.m.
(Eastern Standard Time) at the U.S.
Environmental Protection Agency
building located at 109 T.W. Alexander
Drive, Research Triangle Park, NC
27711. If the EPA holds a public
hearing, the EPA will keep the record of
the hearing open for 30 days after
completion of the hearing to provide an
opportunity for submission of rebuttal
and supplementary information.
ADDRESSES: Submit your comments,
identified by Docket ID. No. EPA–HQ–
OAR–2011–0044 (NSPS action) or
Docket ID No. EPA–HQ–OAR–2009–
0234 (NESHAP/MATS action), by one of
the following methods:
• Federal rulemaking portal: https://
www.regulations.gov. Follow the
instructions for submitting comments.
• Agency Web site: https://
www.epa.gov/oar/docket.html. Follow
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SUMMARY:
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the instructions for submitting
comments on the EPA Air and Radiation
Docket Web site.
• Email: Comments may be sent by
electronic mail (email) to a-and-rdocket@epa.gov, Attention EPA–HQ–
OAR–2011–0044 (NSPS action) or EPA–
HQ–OAR–2009–0234 (NESHAP/MATS
action).
• Fax: Fax your comments to: (202)
566–9744, Docket ID No. EPA–HQ–
OAR–2011–0044 (NSPS action) or
Docket ID No. EPA–HQ–OAR–2009–
0234 (NESHAP/MATS action).
• Mail: Send your comments on the
NESHAP/MATS action to: EPA Docket
Center (EPA/DC), Environmental
Protection Agency, Mailcode: 28221T,
1200 Pennsylvania Ave. NW.,
Washington, DC 20460, Docket ID No.
EPA–HQ–OAR–2009–0234. Send your
comments on the NSPS action to: EPA
Docket Center (EPA/DC), Environmental
Protection Agency, Mailcode: 2822T,
1200 Pennsylvania Ave. NW.,
Washington, DC 20460, Docket ID. No.
EPA–HQ–OAR–2011–0044.
• Hand Delivery or Courier: Deliver
your comments to: EPA Docket Center,
EPA WJC West Building, Room 3334,
1301 Constitution Ave. NW.,
Washington, DC 20460. Such deliveries
are only accepted during the Docket’s
normal hours of operation (8:30 a.m. to
4:30 p.m., Monday through Friday,
excluding legal holiday), and special
arrangements should be made for
deliveries of boxed information.
FOR FURTHER INFORMATION CONTACT: For
the NESHAP action: Mr. Barrett Parker,
Measurement Policy Group, Sector
Policies and Programs Division, (D243–
05), Office of Air Quality Planning and
Standards, U.S. Environmental
Protection Agency, Research Triangle
Park, North Carolina 27711; Telephone
number: (919) 541–5635; Fax number
(919) 541–3207; email address:
parker.barrett@epa.gov. For the NSPS
action: Mr. Christian Fellner, Energy
Strategies Group, Sector Policies and
Programs Division, (D243–01), Office of
Air Quality Planning and Standards,
U.S. Environmental Protection Agency,
Research Triangle Park, North Carolina
27711; Telephone number: (919) 541–
4003; Fax number (919) 541–5450;
email address: fellner.christian@
epa.gov.
SUPPLEMENTARY INFORMATION:
Comment Instructions. All
submissions must include agency name
and respective docket number or
Regulatory Information Number (RIN)
for this rulemaking. All comments will
be posted without change and may be
made available online at https://
www.regulations.gov, including any
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personal information provided, unless
the comment includes information
claimed to be confidential business
information (CBI) or other information
whose disclosure is restricted by statute.
Do not submit information that you
consider to be CBI or otherwise
protected through https://
www.regulations.gov or email. The
https://www.regulations.gov Web site is
an ‘‘anonymous access’’ system, which
means the EPA will not know your
identity or contact information unless
you provide it in the body of your
comment. If you send an email
comment directly to the EPA without
going through https://
www.regulations.gov, your email
address will be automatically captured
and included as part of the comment
that is placed in the public docket and
made available on the Internet. If you
submit an electronic comment, the EPA
recommends that you include your
name and other contact information in
the body of your comment and with any
disk or CD–ROM you submit. If the EPA
cannot read your comment due to
technical difficulties and cannot contact
you for clarification, the EPA may not
be able to consider your comment.
Electronic files should avoid the use of
special characters, any form of
encryption, and be free of any defects or
viruses.
Public Hearing. If requested by
February 23, 2015, we will hold a public
hearing on March 4, 2015, from 1 p.m.
(Eastern Standard Time) to 5 p.m.
(Eastern Standard Time) at the U.S.
Environmental Protection Agency
building located at 109 T.W. Alexander
Drive, Research Triangle Park, NC
27711. Please contact Ms. Pamela
Garrett of the Sector Policies and
Programs Division (D243–01), Office of
Air Quality Planning and Standards,
Environmental Protection Agency,
Research Triangle Park, NC 27711;
telephone number: 919–541–7966;
email address: garrett.pamela@epa.gov;
to request a hearing, register to speak at
the hearing or to inquire as to whether
or not a hearing will be held. The last
day to pre-register in advance to speak
at the hearing will be March 2, 2015.
Additionally, requests to speak will be
taken the day of the hearing at the
hearing registration desk, although
preferences on speaking times may not
be able to be fulfilled. If you require the
service of a translator or special
accommodations such as audio
description, we ask that you pre-register
for the hearing, as we may not be able
to arrange such accommodations
without advance notice. The hearing
will provide interested parties the
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opportunity to present data, views or
arguments concerning the proposed
action. The EPA will make every effort
to accommodate all speakers who arrive
and register. Because this hearing is
being held at a U.S. government facility,
individuals planning to attend the
hearing should be prepared to show
valid picture identification to the
security staff in order to gain access to
the meeting room. Please note that the
REAL ID Act, passed by Congress in
2005, established new requirements for
entering federal facilities. If your
driver’s license is issued by Alaska,
American Samoa, Arizona, Kentucky,
Louisiana, Maine, Massachusetts,
Minnesota, Montana, New York,
Oklahoma or the State of Washington,
you must present an additional form of
identification to enter the federal
building. Acceptable alternative forms
of identification include: Federal
employee badges, passports, enhanced
driver’s licenses and military
identification cards. In addition, you
will need to obtain a property pass for
any personal belongings you bring with
you. Upon leaving the building, you
will be required to return this property
pass to the security desk. No large signs
will be allowed in the building, cameras
may only be used outside of the
building and demonstrations will not be
allowed on federal property for security
reasons. The EPA may ask clarifying
questions during the oral presentations,
but will not respond to the
presentations at that time. Written
statements and supporting information
submitted during the comment period
will be considered with the same weight
as oral comments and supporting
information presented at the public
hearing. Verbatim transcripts of the
hearing and written statements will be
included in the docket for the
rulemaking. The EPA will make every
effort to follow the schedule as closely
as possible on the day of the hearing;
however, please plan for the hearing to
run either ahead of schedule or behind
schedule. Again, a hearing will not be
held on this rulemaking unless
requested. A hearing needs to be
requested by February 23, 2015. Again,
please contact Ms. Pamela Garrett of the
Sector Policies and Programs Division
(D243–01), Office of Air Quality
Planning and Standards, Environmental
Protection Agency, Research Triangle
Park, NC 27711; telephone number:
919–541–7966; email address:
garrett.pamela@epa.gov to request a
hearing.
Docket. All documents in the docket
are listed in the https://
www.regulations.gov index. Although
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listed in the index, some information is
not publicly available (e.g., CBI or other
information whose disclosure is
restricted by statute). Certain other
material, such as copyrighted material,
will be publicly available only in hard
copy form. Publicly available docket
materials are available either
electronically in https://
www.regulations.gov or in hard copy at
the EPA Docket Center, Room 3334,
1301 Constitution Avenue NW.,
Washington, DC. The Public Reading
Room is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding
legal holidays. The telephone number
for the Public Reading Room is (202)
566–1744, and the telephone number for
the Air Docket is (202) 566–1742.
I. Technical Corrections
The final Clean Air Act (CAA) rules
published in the Federal Register on
February 16, 2012 (77 FR 9303),
establish national emission standards
for hazardous air pollutants (NESHAP)
from coal- and oil-fired electric utility
steam generating units (EGUs), referred
to as ‘‘the Mercury and Air Toxics
Standards’’ or ‘‘MATS,’’ and new source
performance standards (NSPS) for fossilfuel-fired electric utility, industrialcommercial-institutional, and small
industrial-commercial-institutional
steam generating units, referred to as the
Utility NSPS.
In this document, the EPA proposes to
correct certain regulatory text. The
proposed corrections can be categorized
generally as follows: (a) Resolution of
conflicts between preamble and
regulatory text, (b) corrections that we
stated we would make in response to
comments that were inadvertently not
made, and (c) clarification of language
in regulatory text. Below, we identify
each proposed technical correction to
the regulatory text as found in the Code
of Federal Regulations (i.e., 40 CFR).
The EPA is soliciting comments on all
of these proposed corrections.
1. Section 60.49Da(f) is revised to
amend the procedures for calculating
compliance with the NSPS daily average
particulate matter (PM) emission limit
for affected facilities using PM
continuous emission monitoring
systems (CEMS) and that commenced
construction, modification, or
reconstruction before May 4, 2011. Even
though it was not included in the
proposal, in an effort to clarify certain
language in 40 CFR 60.48Da(f), we
amended the procedure for calculating
compliance with the daily average PM
limit for affected facilities for which
construction, modification, or
reconstruction commenced before May
4, 2011, using PM CEMS (78 FR 24073;
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April 24, 2013). The amendments
removed the provision that for operating
days with less than 18 hours of PM
CEMS data, the data for that day would
be rolled into the following operating
day(s) until 18 hours of data are
available. The intent of the original
language was to assure that compliance
with the daily PM emission rate was not
determined with significantly less than
24 hours of data, but that all emissions
data would still be used. The intent of
the revised data was to eliminate the
requirement to roll emissions data
recorded on days without sufficient data
to determine a daily average to the
following operating day, but that a
minimum of 18 hours would still be
required to determine compliance with
the daily PM standard. Industry
requested reconsideration stating that
they did not have an opportunity to
comment on the issue, and that the
revised calculation procedures could in
fact require compliance determinations
with significantly less than 24 hours of
data. The proposed revisions would
undo those changes and return the
calculation procedures to the approach
used prior to April 24, 2013.
Specifically, for operating days with less
than 18 hours of PM CEMS data, that
data would be rolled into the following
operating day(s) until over 18 hours of
data are available to determine
compliance with the operating day
standard. We are soliciting comment on
whether the intent of the current
calculation procedures should be
maintained (i.e., data collected on days
with less than 18 hours of data would
not be used to determine compliance
with the PM standard and would also
not be rolled into the following
operating day(s)). If the current
approach is maintained, the regulatory
language would be revised to avoid
situations where compliance
calculations would be made with less
than 18 hours of data.
2. Section 63.9983(a) is revised to
clarify that MATS does not apply to
either major or area source combustion
turbines, except for integrated
gasification combined cycle (IGCC)
units. In the final MATS rule, 40 CFR
63.9983(a) exempted from MATS ‘‘any
unit designated as a stationary
combustion turbine, except an
integrated gasification combined cycle
(IGCC) unit, covered by 40 CFR part 63,
subpart YYYY.’’ Because area source
stationary combustion turbines are not
subject to subpart YYYY, which is
applicable to stationary combustion
turbines located at major sources, the
Agency received questions concerning
the applicability of MATS to the area
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source units in that category. The EPA
intended by the exemption to exempt all
stationary source combustion turbines
other than IGCC units from the
requirements of MATS, because the EPA
does not interpret the statute to include
those units within the definition of EGU
in CAA section 112(a)(8). The proposed
revisions to the regulations will clarify
the EPA’s interpretation and intent and
prevent future confusion concerning the
applicability of the MATS rule to
stationary combustion turbines located
at area sources.
3. Section 63.9983(b) and (c) is
revised consistent with the definitional
changes discussed below. The
definitional changes are being proposed
so that sources will know the time
period to consider when determining
whether their coal or oil utilization
triggers applicability of the MATS rule.
As explained below, the change is
particularly important in the first 3
years after the compliance date when
sources will be required to estimate coal
and oil utilization in their EGUs to
determine applicability of the MATS
rule.
4. Section 63.9983(e) is added to
clarify CAA section 112 applicability to
the units that meet the definition of a
natural gas-fired EGU in MATS, and,
because they combust greater than 10
percent biomass, also meet the
definition of a biomass-fired boiler in
the Industrial Boiler NESHAP (40 CFR
part 63, subpart DDDDD). These
overlapping definitions led to confusion
in the regulated community about
whether such units are natural gas-fired
EGUS pursuant to MATS or biomassfired boilers subject to the Industrial
Boiler NESHAP. We are revising the
MATS rule to make clear that such units
are biomass-fired boilers subject to the
industrial boiler NESHAP. Similar
revisions to the applicability provisions
of the Industrial Boiler NESHAP have
been proposed.1
5. Section 63.9991(c)(1) and (2) is
being revised to clarify the conditions
that are required in order to use the
alternate sulfur dioxide (SO2) limit.
6. Sections 63.10000(c)(1)(i)(A) and
63.10005(h) are revised to clarify the
provisions of units designated as being
low emitting EGUs (LEE) when an acid
gas scrubber and a bypass stack are
present.
7. Section 63.10000(c)(1)(i)(C) is
added to allow EGUs the ability to seek
LEE status if their bypass stacks vent
through stacks that are able to measure
emissions. In addition, the proposed
language would allow EGUs with LEE
status the ability to bypass emissions
control devices during emergency
periods provided certain fuel and time
restrictions, along with notification
requirements, occur.
The final MATS rule did not allow
EGUs whose emissions control devices
had bypasses to seek LEE status. Owners
and operators of EGUs whose emissions
control devices had no bypass stacks,
but instead routed bypass emissions
through main stacks equipped with
emissions measurement capability,
requested that we allow their EGUs to
seek LEE status provided emissions
were measured during bypass events.
We believe that EGU owners or
operators that have the ability to
measure and report emissions during
bypass events should be able to seek
LEE status as long as bypass emissions
are included in the calculations
required to demonstrate the LEE status
eligibility. For this reason, we are
proposing to allow this option.
Also, a number of EGU owners or
operators requested that we allow EGUs
with LEE status the ability to bypass
their emissions control devices in
emergency conditions, provided that the
EGUs were combusting clean fuels and
that the bypass periods were of short
duration.2 We reviewed the requests
and believe that control device bypass
operation for up to 2 percent of EGU
operating hours while combusting clean
fuel during emergency periods is
reasonable, provided a report detailing
the emergency event, its cause, the
corrective action taken to alleviate the
emergency event, and estimates of the
emissions released during the
emergency event are provided. In
addition, an EGU owner or operator
must include these emergency
emissions along with performance test
results in assessing whether its EGU
maintains LEE status. We seek comment
on the adequacy of the restrictions
associated with bypass conditions
regarding maintaining LEE status.
8. Section 63.10000(c)(2)(iii) is
revised to state that EGU owners or
operators who choose to use quarterly
testing and parametric monitoring for
hydrogen fluoride (HF) or hydrogen
chloride (HCl) compliance must include
the continuous monitoring systems
(CMS) that will be used in their sitespecific monitoring plans to comply
with the monitoring requirements.
1 Prepublication version found at https://
www.epa.gov/ttn/atw/boiler/boilerpg.html. The
prepublication version will be replaced with the
Federal Register document when the proposal is
published.
2 To the extent these EGUs bypassed their control
devices without measuring emissions, the hours of
bypass operation would need to be reported as
hours of monitoring deviation and subject to
potential enforcement action.
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9. Section 63.10000(m) is added to
clarify that EGU owners or operators
who choose to meet the work practice
standards contained in paragraph (2) of
the definition of startup may verify,
instead of certify, monitoring systems
used to generate data to meet the work
practice standards. Moreover, this
addition clarifies that those monitoring
systems may be installed, verified,
operated, maintained, and quality
assured using manufacturer’s
specifications.
10. Section 63.10001 is revised to
remove the affirmative defense
provisions as explained in Section II
below. The section is reserved.
11. Section 63.10005(a) is revised to
clarify that different compliance
demonstrations may require different
and additional types of data collection
and to clarify the date by which
compliance must be demonstrated for
existing EGUs.
12. Section 63.10005(a)(2) is revised
to clarify the date by which compliance
must be demonstrated for EGUs using
CMS or sorbent trap monitoring
systems.
13. Section 63.10005(a)(2)(i) is revised
to clarify applicability of the provision
to both the 30- and 90-boiler operating
day performance testing requirements.
14. Section 63.10005(b)(1) is revised
to clarify the time period allowed for
existing EGUs to use stack test data
collected prior to the applicable
compliance date.
15. Section 63.10005(b)(6) is added to
clarify the date EGUs must begin
conducting required stack tests when
stack test data collected prior to the
applicable compliance date are
submitted to satisfy the initial
performance test requirement.
16. Section 63.10005(d)(3) and
(d)(4)(i) is revised to more clearly state
when compliance must be
demonstrated.
17. Section 63.10005(f) is revised to
clarify when sources must complete the
initial boiler tune-up after the
compliance date, and the timing for
subsequent tune-ups when a tune-up
conducted prior to the compliance date
is used to satisfy the initial tune-up
requirement.
18. Section 63.10005(h)(3) is revised
to clarify that the alternate 30- and 90day averaging provisions are both
applicable to mercury (Hg) emission
limits, and to clarify the sampling probe
location.
19. Section 63.10005(i)(4) is revised to
delete paragraphs (iii) and (iv). The
identified test methods contain
requirements for fuel sampling, not
determining fuel moisture content, as
required in the provision.
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20. Section 63.10006(f) is revised to
specify EGU operational status with
respect to performance testing; to
identify the requirements—including
make-up testing and reporting—if the
performance testing schedule is missed
apart from using existing skip
procedures; and to identify intervals
between performance tests. The final
MATS rule had no provision that
allowed an EGU owner or operator to
skip a required performance test if its
EGU was otherwise not operating; we
did not believe the rule needed to be
explicit in stating that EGUs need not be
turned on solely to conduct
performance testing. However, we have
received questions regarding this
circumstance. We believe it is
appropriate to allow an EGU owner or
operator the ability to skip a required
performance test if its EGU is not
otherwise operating, and are proposing
this in this action. The final MATS rule
had no provisions regarding make-up
testing and reporting should a regularly
scheduled performance test be missed
for reasons other than the existing skip
procedures. We believe it is appropriate
to specify a schedule for required makeup testing and reporting, and are
proposing such a schedule in this
action. The final MATS rule specified
the time periods between performance
tests, but EGU owners or operators
expressed concerns about being able to
adhere to such a schedule. We believe
their concerns about having too tight a
timeline for retesting to occur and our
concern about having a sufficient
interval of time between tests such that
the results better reflect characteristics
of different periods can be addressed by
specifying a minimum interval of time
between subsequent performance tests,
which we are proposing in this action.
We welcome comments as to the need
for, as well as efficacy of, these
proposed revisions, as well as on these
proposed intervals.
21. Section 63.10009(a)(2) and (a)(2)(i)
is revised to clarify that the 90-boiler
operating day averaging period is
available as an option for Hg emissions
from non-low rank virgin coal-fired
EGUs (i.e., EGUs in the subcategory
‘‘unit designed for coal ≥8,300 Btu/lb’’).
In the final MATS (77 FR 9303 at 9385),
we had indicated that we were
providing the 90-boiler operating day
averaging period as an alternative
compliance approach (to the standard
30-boiler operating day averaging
period) for Hg emissions from EGUs in
that subcategory. However, the
regulatory text in 40 CFR 63.10009(a)(2)
did not clearly reflect this option.
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The term ‘‘gross electric output’’ is
also corrected to ‘‘gross output’’ which
is the term defined in 40 CFR 63.10042.
22. Section 63.10009(b)(1) is revised
to clarify group eligibility equations 1a
and 1b. These equations were developed
to provide EGU owners or operators a
quick method for determining if their
emissions averaging group could meet
the emissions limit when operated at
the maximum rated heat input and, in
some cases, steam production.
Commenters reported difficulty in using
the equations in the final rule, so the
equations have been revised so that
individual EGU characteristics, whether
from CEMS or stack testing results, are
easier to input. We request comment on
the proposed revisions concerning their
usefulness in calculating the maximum
potential emissions rate from an
emissions averaging group. The term
‘‘gross electric output’’ is also corrected
to ‘‘gross output’’ which is the term
defined in 40 CFR 63.10042.
23. Section 63.10009(b)(2) and (3) is
revised to correct the term ‘‘gross
electric output’’ to ‘‘gross output’’ which
is the term defined in 40 CFR 63.10042.
24. Section 63.10009(f) is revised to
clarify the conditions for determining
the ability of the emissions averaging
group to meet the emissions limit and
to clarify use of the alternate Hg
emission limit. Instead of relying on the
maximum normal operating load of each
EGU in determining the ability of the
emissions averaging group to
demonstrate initial compliance, as was
contained in the final MATS rule, we
are proposing in this action to use the
maximum possible heat input or gross
output of each EGU in determining the
ability of the emission averaging group
to demonstrate initial compliance. In
addition, instead of calculating the
maximum weighted average emissions
rate, as used in the final MATS rule, we
are proposing in this action to calculate
the initial weighted average emissions
rate. Finally, instead of specifying just
one date for submitting an emissions
averaging plan, as was done in the final
MATS rule, we are proposing in this
action to allow an EGU owner or
operator the flexibility to choose other
dates to begin using an emissions
averaging plan by allowing the
submission of an emissions averaging
plan at least 120 days before the date on
which emissions averaging is to begin.
We believe these changes will provide
additional flexibility without
undermining the enforceability of the
final standards.
25. Section 63.10009(f)(2), (g)(1),
(g)(2), and (j)(1)(ii) is revised to correct
the term ‘‘gross electric output’’ to
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‘‘gross output’’ which is the term
defined in 40 CFR 63.10042.
26. Section 63.10010(a)(4) is revised
to add a requirement to route exhaust
gases that bypass emissions control
devices through stacks that contain
monitoring so that emissions can be
measured and to clarify that hours that
a bypass stack is in use are to be
counted as hours of deviation from
monitoring requirements.
27. Section 63.10010(f)(3) is revised to
clarify that 30-boiler operating day
rolling averages are to be based only on
valid hourly SO2 emission rates.
28. Section 63.10010(h)(6)(i) and (ii),
(i)(5)(A) and (B), and (j)(4)(i)(A) and (B)
is revised to clarify that data collected
during certain periods are not to be
included in compliance assessments but
such periods are to be included in
annual deviation reports. The final
MATS rule established that all data
collected with PM CPMS, PM CEMS,
and HAP metals CEMS during all boiler
operating hours were to be used in
assessing compliance except those data
collected during monitoring system
malfunctions, repairs associated with
monitoring system malfunctions,
required quality assurance or quality
control activities, or monitoring out-ofcontrol periods. In addition, the final
MATS rule sections combined the
requirement to report the periods when
data collected during these operating
periods as deviations into one long
sentence. In this action, we are
proposing to separate these
requirements into two sentences to ease
readability.
29. Section 63.10010(l)(i) is revised to
replace the incorrect reference to
§ 63.7(e) with the correct reference to
§ 63.8(d)(2).
30. Section 63.10010(l) and (l)(4) is
revised to clarify that EGU owners or
operators who choose to meet the work
practice standards contained in
paragraph (2) of the definition of startup
may verify, instead of certify,
monitoring systems used to generate
data to meet the work practice
standards. Moreover, this revision
clarifies that those monitoring systems
may be installed, verified, operated,
maintained, and quality assured using
manufacturer’s specifications.
31. Section 63.10011(b) is revised to
remove the incorrect reference to Table
4 and to replace the incorrect reference
to Table 7 with the correct reference to
Table 6.
32. Section 63.10011(c)(1) and (2) is
revised to clarify the date by which
compliance must be demonstrated by
EGUs that use CEMS or sorbent trap
monitoring systems. In addition,
§ 63.10011(c)(1) is revised to clarify that
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the alternate Hg emission limit may be
used.
33. Section 63.10011(e) is revised to
replace ‘‘according to’’ with ‘‘in
accordance with.’’
34. Section 63.10011(g)(4)(v)(A) and
Table 3 are revised to clarify our intent
regarding clean fuel use ‘‘to the
maximum extent possible.’’ Our goal in
the work practice is to minimize HAP
emissions during startup and shutdown
periods, and that goal can be
accomplished by minimizing primary
fuel use and maximizing clean fuel use
because of the inherently low HAP
content of the defined ‘‘clean fuels.’’ As
stated in the preamble to the final
startup and shutdown reconsideration
rule, EGUs that chose to comply with
the alternative work practice will be
required to have sufficient clean fuel
capacity to startup and warm the facility
to the point where the primary PM
controls can be brought on line at the
same time as, or within 1 hour of, the
addition of the primary fuel to the EGU.
79 FR 68777 at 68779, November 19,
2014. We recognize that the clean fuel
requirement may require sources to
increase clean fuel capacity, modify the
startup burners, and/or take additional
actions to comply with the final rule. 79
FR 68777 at 68779, November 19, 2014.
Thus, we expect clean fuels to be
combusted in at least the amount
needed to bring the emissions control
devices to operational levels necessary
to comply with the numeric standards at
the end of startup. We do not expect
clean fuel use to the extent that it
compromises the integrity of the boiler
or its control devices; neither do we
expect clean fuel to be combusted in
excess of the amount needed to bring
the emissions control devices to
expected operational levels. We have
determined that it is appropriate to
slightly revise the language in the
November 19, 2014, final rule. 79 FR
68777. The proposed revision would
change the language from ‘‘to the
maximum extent possible’’ to ‘‘to the
maximum extent practicable, taking into
account boiler or control device
integrity.’’
35. Section 63.10020(e) is revised to
clarify that it applies only to those EGU
owners or operators who choose to meet
the work practice standards contained
in paragraph (2) of the definition of
startup. In addition, the undefined term
‘‘electrical load’’ has been replaced with
the defined term ‘‘gross output’’ and the
incorrect terms ‘‘liquid to fuel ratio’’
and ‘‘the differential pressure of the
liquid’’ in § 63.10020(e)(3)(i)(E) have
been replaced with the correct terms
‘‘liquid to flue gas ratio’’ and ‘‘the
pressure drop across the scrubber.’’
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Finally, in order to clarify our intent
that existing instrumentation or
engineering calculations can be used to
provide flow information,
§ 63.10020(e)(3)(i)(A) and (B) is revised
to remove the term ‘‘rate’’ and to
acknowledge the use of existing
combustion air flow monitors or
combustion equations.
36. Section 63.10021(d)(3) is revised
to clarify the type of monitoring that is
to be used to demonstrate compliance.
37. Section 63.10021(e) is revised to
clarify the condition that allows delay of
burner inspections for initial boiler
tune-ups.
38. Section 63.10021(e)(9)(i) and (ii) is
revised to clarify the dates that tune-ups
must be reported.
39. Section 63.10023(b) and Table 6
are revised to clarify that all EGUs using
PM continuous parametric monitoring
systems (CPMS) for compliance
purposes are to follow the same
procedure for determining the operating
limit. The final rule allowed existing
EGUs to determine the operating limit
based on the highest 1-hour average PM
CPMS value recorded during a
performance test, even if that average
time was associated with a test run in
excess of the numeric standards, while
new EGUs were required to use a
scaling factor or the average PM CPMS
value recorded during the PM
compliance test demonstrating
compliance with the PM limit to
establish the operating limit.3 We
believe all EGUs should use a consistent
set of procedures for both new and
existing EGUs for establishing an
operating PM limit, so we are proposing
in this action to revise the procedures
for existing EGUs. The procedures for
existing EGUs, contained in
§ 63.10023(b)(1) are reserved, and
§ 63.10023(b)(2) and Table 6 are revised
so that all EGUs are to follow the
operating limit development procedures
for new EGUs (i.e., use a scaling factor
or the average PM CPMS value recorded
during the PM compliance test
demonstrating compliance with the PM
limit to establish the operating limit).
40. Section 63.10030(e)(1) is revised
to replace the phrase ‘‘identification of
which subcategory the source is in’’
with ‘‘identification of the subcategory
of the source.’’
41. Section 63.10030(e)(7)(i) is revised
to clarify that the date of each stack test
conducted for purposes of
demonstrating LEE eligibility is to be
provided. The final rule establishes that
each test for pollutants other than Hg
conducted over a 3-year period must
3 See the description of the ‘‘third approach’’ at
79 FR 24708 (April 24, 2013).
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meet the LEE emission limit in order for
an EGU to be eligible for LEE status.
42. Section 63.10030(e)(7)(iii) is
added to establish the procedures by
which an EGU owner or operator may
switch between mass per heat input and
mass per gross output emission limits.
The EPA has received questions about
how frequently an existing EGU could
alternate between the two compliance
formats. Although we did not envision
that an owner or operator of an existing
EGU would want to change the basis of
the EGU’s emission limits, we believe it
is reasonable to allow such action
provided certain conditions, including
performance testing demonstrating
compliance with the new format,
submission of a written request to
change formats, and receipt of
permission from the Administrator to
change formats, are met. We request
comment on these procedures, as well
as on the concept of switching emission
limits, particularly during performance
averaging periods.
43. Section 63.10030(e)(8)(i) is revised
to clarify that it applies only to those
EGU owners or operators who choose to
meet the work practice standards
contained in paragraph (2) of the
definition of startup. Moreover, the
provisions requiring a description of PM
control device efficiencies and PM
emission rates are revised to clarify that
such efficiencies and emission rates are
those of periods other than startup and
shutdown periods. As the uncontrolled
emission rates can be calculated from
control device efficiencies and
corresponding emission rates, the
provisions requiring reporting of
uncontrolled emission rates have been
removed.
In addition, as current EGU
characteristics are most relevant for
compliance with the MATS rule, the
requirements concerning identification
of intermediate changes to the EGU
design have been removed. In order to
reduce redundant reporting, the rule has
been revised to require no additional
identification if no changes to the EGU’s
design characteristics have occurred.
Finally, § 63.10030(e)(8)(ii)(A) has
been revised to remove the requirement
for use of an independent professional
engineer. Consistent with the discussion
contained in 71 FR 16869 (April 4,
2006), we believe that a professional
engineer, regardless of whether they are
independent, is able to give a fair
technical review because of the
programs established by the state
licensing boards, which serve to enforce
objectivity from each registrant. We
believe that the revision will allow
EGUs to reduce burden without
compromising environmental safety by
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using in-house expertise. Professional
engineers employed by an EGU should
be more familiar with its design and
operational characteristics and should
be in a position to expedite collection
and submission of required information.
44. Section 63.10030(f) is revised to
add notification requirements for EGUs
that move in and out of MATS
applicability.
45. Section 63.10031(c)(4) is revised
to clarify the reporting requirements for
EGU tune-ups.
46. Section 63.10031(c)(5) is revised
to clarify that it applies only to those
EGU owners or operators who choose to
meet the work practice standards
contained in paragraph (2) of the
definition of startup.
47. Section 63.10031(c)(6) is revised
to add emergency bypass reporting for
EGUs with LEE status.
48. Section 63.10031(f)(5) is revised to
state that the Administrator retains the
right to require submittal of reports
subject to paragraph (f)(4), as well as
paragraphs (f)(1) through (3).
49. Section 63.10032(f) is revised to
clarify that the requirements of
§ 63.10032(f)(1) apply only to those EGU
owners or operators who choose to meet
the work practice standards contained
in paragraph (1) of the definition of
startup, while the requirements of
§ 63.10032(f)(2) apply only to those EGU
owners or operators who choose to meet
the work practice standards contained
in paragraph (2) of the definition of
startup.
50. The definitions of ‘‘Coal-fired
electric utility steam generating unit,’’
‘‘Coal refuse,’’ ‘‘Fossil fuel-fired,’’
‘‘Integrated gasification combined cycle
electric utility steam generating unit or
IGCC,’’ ‘‘Limited-use liquid oil-fired
subcategory,’’ ‘‘Natural gas-fired electric
utility steam generating unit,’’ and ‘‘Oilfired electric utility steam generating
unit’’ in § 63.10042 are revised to clarify
the period of time to be included in
determining the source’s applicability to
the MATS.
During the comment period on the
proposed MATS rule, industry noted
that many EGUs would convert to
natural gas or other non-fossil fuel prior
to the compliance date and those
sources would remain subject to MATS
because the proposed rule required
sources to determine applicability based
on the 3 calendar years prior to the
compliance date. See, e.g., 40 CFR
63.10042 (definition of ‘‘fossil fuelfired’’). The EPA agreed that this was
not the EPA’s intent and in the final
MATS rule revised several definitions,
including the definition of fossil fuelfired, that required sources to evaluate
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usage after the applicable compliance
date.
The EPA inadvertently created
confusion in its attempt to address
industry concerns in the final MATS
rule. The confusion is best illustrated by
an analysis of the proposed and final
definitions of ‘‘fossil fuel-fired.’’ The
EPA’s proposed definition stated, in
part, that ‘‘[i]n addition, fossil fuel-fired
means any EGU that fired fossil fuel for
more than 10.0 percent of the average
annual heat input during the previous 3
calendar years or for more than 15.0
percent of the annual heat input during
any one of those calendar year.’’ See 76
FR 24975 at 25123 (emphasis added).
The intent in this definition was to
require sources to look at the usage from
the 3 previous years to determine if the
average or the single year usage from
those 3 years exceeded either of the
thresholds.
To address the commenters’ concern,
the EPA revised the definition of ‘‘fossil
fuel-fired’’ in the final rule to state, in
part, that ‘‘[i]n addition, fossil fuel-fired
means any EGU that fired fossil fuels for
more than 10.0 percent of the average
annual year input during any 3
consecutive calendar years or for more
than 15.0 percent of the annual heat
input during any one calendar year after
the applicable compliance date.’’ 40
CFR 63.10042 (emphasis added). This
definition creates at least two potential
compliance issues: (1) It creates
confusion as to how sources are to
determine MATS applicability during
the first 3 years after the applicable
compliance date; and (2) it subjects
sources to MATS in perpetuity if the
usage thresholds are ever exceeded after
the compliance date—‘‘any 3
consecutive calendar years’’ or ‘‘any one
calendar year’’ ‘‘after the applicable
compliance date.’’
The proposed revisions to the
definitions address both issues.
Concerning applicability in the first 3
years after the applicable compliance
date, this proposed rule states that
sources must project their coal and oil
usage for the first 3 years to determine
whether the EGU will exceed either the
10.0 or 15.0 percent threshold. The
EPA’s understanding is that sources
know with sufficient specificity the
fuels they will use in advance, and
requiring sources to project their usage
accommodates industry concerns that
the sources that are converting to
natural gas or biomass prior to the
compliance date not be subject to
MATS. The EPA is also proposing that
sources that permanently convert to
natural gas or biomass after the
compliance date are no longer subject to
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MATS, notwithstanding the coal or oil
usage the previous 3 calendar years.
The EPA is also proposing to revise
the definitions to make clear that after
the first 3 years of compliance, EGUs are
required to evaluate applicability based
on coal or oil usage from the 3 previous
calendar years on an annual rolling
basis, consistent with the definition of
‘‘fossil fuel-fired’’ proposed in the
MATS rule. This proposed change will
prevent EGUs from being subject to
MATS in perpetuity if they exceed the
10 or 15 percent threshold at any time
after the compliance date.
A definition of ‘‘neural network’’ is
also being added because the term is
used in 40 CFR 63.10005(f), 63.10006(i),
and 63.10021(e) and Table 3 to subpart
UUUUU of Part 63 but is not defined.
51. Table 1 to subpart UUUUU of Part
63 is revised to correct the term ‘‘gross
electric output’’ to ‘‘gross output’’ which
is the term defined in 40 CFR 63.10042
in footnotes 1, 4, and 5.
52. Table 2 to subpart UUUUU of Part
63 is revised to correct the term ‘‘gross
electric output’’ to ‘‘gross output’’ which
is the term defined in 40 CFR 63.10042
in footnote 2. Provision 1(c) (the Hg
limit for EGUs in the subcategory ‘‘unit
designed for coal ≥8,300 Btu/lb’’) is also
revised to clarify the applicability of the
alternate 90-boiler operating day
compliance option.
53. Table 3 to subpart UUUUU of Part
63 is revised as described earlier to
clarify the term ‘‘maximum extent
possible.’’
In addition, we have received
questions concerning the interpretation
of the definition of startup, particularly
the language defining the end of startup.
Industry has inquired whether the
triggering action is either the generation
of electricity or of steam for any useful
purpose under both definitions of
startup. The EPA does interpret the end
of startup in a consistent manner as
between the two definitions.
Specifically, we interpret the phrase
‘‘. . . when any of the steam from the
boiler is used . . . for any other
purpose,’’ contained in paragraph (1) of
the definition of startup, to have the
same meaning as the phrase ‘‘for
industrial, commercial, heating, or
cooling purposes (other than the firstever firing of fuel in a boiler following
construction of the boiler,’’ as provided
in paragraph (2) of the definition of
startup. EGUs trigger the end of startup
whenever they use either electricity or
steam for any useful purpose either on
or offsite.
54. Table 4 to subpart UUUUU of Part
63 is revised to clarify that existing as
well as new EGUs using PM CPMS
share the same procedures for
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developing operating limits (i.e., those
that are based on the higher of a
parameter scaled from all values
obtained during an individual emissions
test to 75 percent of the emissions limit
or the average parameter value obtained
from all runs of an individual emission
test as the operating limit provided that
the result of the individual emissions
test met the emissions limit
requirements).
55. Table 5 to subpart UUUUU of Part
63 is revised to state that when using
Method 5, you are to report the average
of the final 2 filter weighings, and to
clarify that when using Method 29, you
are to report the metals matrix spike and
recovery levels. These provisions are
needed for the required electronic
reporting.
56. Table 6 to subpart UUUUU of Part
63 is revised to clarify that existing, as
well as new, EGUs using PM CPMS
share the same procedures for
developing operating limits (i.e., those
that are based on the higher of a
parameter scaled from all values
obtained during an individual emissions
test to 75 percent of the emissions limit
or the average parameter value obtained
from all runs of an individual emission
test as the operating limit provided that
the result of the individual emissions
test met the emissions limit).
57. Table 8 to subpart UUUUU of Part
63 is revised to clarify that compliance
reports are to include information
required by § 63.10031(c)(5) and (6).
58. Table 9 to subpart UUUUU of Part
63 is revised to correct an inadvertent
omission of 30-day notification
requirements of § 63.9.
59. Paragraphs 4.1.1.3 and 5.1.2.3 and
Tables A–1 and A–2 to Appendix A to
subpart UUUUU of Part 63 are revised
to adjust Hg CEMS language regarding
converters. Research has shown that all
Hg CEMS need weekly single-level
system integrity checks.
60. Paragraph 7.1.2.5 to Appendix A
to subpart UUUUU of Part 63 is added
to require that owners or operators flag
EGUs that are part of emission averaging
groups.
61. Paragraph 3.2.1.2.1 of Appendix A
to subpart UUUUU of Part 63 is revised
to specifically indicate that Hg gas
generators and cylinders are allowed.
62. Paragraphs 4.1.1.1, Table A–1,
Table A–2, 5.1.2.1, and 4.1.1.3 of
Appendix A to subpart UUUUU of Part
63 are revised to exclude use of
oxidized Hg gas standards for daily
calibration of Hg CEMS.
63. Paragraph 5.1.2.3 of Appendix A
to subpart UUUUU of Part 63 is revised
to make the weekly single level system
integrity check mandatory.
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64. Paragraphs 4.1.1.5.2, Table A–1,
Table A–2, and 4.1.1.5 of Appendix A
to subpart UUUUU of Part 63 are
revised to provide an alternative relative
accuracy test audit (RATA) procedure
for EGUs with low emissions that is
related specifically to the emission
standard.
65. Paragraph 5.2.1 of Appendix A to
subpart UUUUU of Part 63 is revised to
correct the number of days for sorbent
trap use from 14 to 15.
66. Paragraph 6.2.2.3 of Appendix A
to subpart UUUUU of Part 63 is revised
to clarify that the 90-day alternative Hg
standard may be used and that electrical
output is gross output.
67. Paragraph 7.1.2.6 of Appendix A
to subpart UUUUU of Part 63 is added
to clarify that EGU owners or operators
are to keep records of their EGUs that
constitute emissions averaging groups.
68. Paragraphs 2.1, 2.3, 2.3.1, 2.3.2,
3.1, 3.2, 3.3, 5, 5.1, 5.2, and 5.3 of
Appendix B to subpart UUUUU of Part
63 are revised to clarify that use of
Performance Specification (PS) 18, a
proposed technology-neutral PS for HCl
CEMS which will soon be promulgated,
will be allowed. Consistent with our
statements in the final rule, we expect
that PS 18 will likely be promulgated in
advance of the rule’s compliance date.
An EGU owner or operator who wishes
to use proposed PS 18, along with
quality assurance (QA) procedure 6,
prior to their promulgation dates is
welcome to submit an alternative
monitoring request in accordance with
the requirements of § 63.8(f) for use of
proposed PS 18 and QA Procedure 6 to
us.
69. Paragraph 5.4 of Appendix B to
subpart UUUUU of Part 63 is added as
part of the renumbering due to the
addition of PS 18.
70. Paragraph 8 of Appendix B to
subpart UUUUU of Part 63 is revised to
accommodate use of PS 18.
71. Paragraphs 10.1.8, 10.1.8.1,
10.1.8.1.1, and 10.1.8.1.2 of Appendix B
to Subpart UUUUU of Part 63 are
revised as part of the renumbering due
to the addition of PS 18.
72. Paragraph 10.1.8.1.3 of Appendix
B to Subpart UUUUU of Part 63 is
revised to clarify that records of relative
accuracy audits (RAAs) are also
required.
73. Paragraphs 10.1.8.2, 10.1.8.1.2.1,
and 10.1.8.1.2.2 of Appendix B to
Subpart UUUUU of Part 63 are revised
to clarify the quarterly gas audit
recordkeeping requirements for PS 15
and the quarterly data accuracy
assessments for PS 18 (which are
reserved).
74. Paragraph 11.4 of Appendix B to
Subpart UUUUU of Part 63 is revised to
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replace the incorrect abbreviation ‘‘i.e.’’
with ‘‘e.g.’’
75. Paragraph 11.4.2 of Appendix B to
Subpart UUUUU of Part 63 is revised to
specify the requirements of the daily
beam intensity checks for EGUs using
PS 18.
76. Paragraphs 11.4.2.1, 11.4.2.2,
11.4.2.3, 11.4.2.4, 11.4.2.5, 11.4.2.6,
11.4.2.7, 11.4.2.8, 11.4.2.9, 11.4.2.10,
11.4.2.11, 11.4.2.12, and 11.4.2.13 of
Appendix B to Subpart UUUUU of Part
63 are revised to hold the requirements
of the daily beam intensity checks for
PS 18 (which are reserved).
77. Paragraph 11.4.3 of Appendix B to
Subpart UUUUU of Part 63 is revised to
reflect the reporting requirements for PS
15.
78. Paragraphs 11.4.3.1, 11.4.3.2,
11.4.3.3, 11.4.3.4, 11.4.3.5, 11.4.3.6,
11.4.3.7, 11.4.3.8, 11.4.3.9, 11.4.3.10,
11.4.3.11, 11.4.3.12, and 11.4.3.13 of
Appendix B to Subpart UUUUU of Part
63 are revised to include PS 15
reporting requirements.
79. Paragraph 11.4.4 of Appendix B to
Subpart UUUUU of Part 63 is revised to
reserve the reporting requirements for
quarterly parameter verification checks
for PS 18.
80. Paragraphs 11.4.4.1, 11.4.5,
11.4.5.1, 11.4.6, 11.4.6.1 of Appendix B
to Subpart UUUUU of Part 63 are added
to reserve the reporting requirements for
quarterly gas audit information and for
quarterly dynamic spiking for PS 18.
81. Paragraph 11.4.7 of Appendix B to
Subpart UUUUU of Part 63 is added to
include reporting requirements for
RAAs.
82. Paragraphs 11.4.7.1, 11.4.7.2,
11.4.7.3, 11.4.7.4, 11.4.7.5, 11.4.7.6,
11.4.7.7, 11.4.7.8, 11.4.7.9, 11.4.7.10,
11.4.7.11, 11.4.7.12, and 11.4.7.13 of
Appendix B to Subpart UUUUU of Part
63 are added as part of the renumbering
due to the addition of PS 18.
83. Paragraph 11.5.3.4 of Appendix B
to Subpart UUUUU of Part 63 is revised
to include reporting requirements for
beam intensity checks for PS 18.
II. Affirmative Defense for Violation of
Emission Standards During
Malfunction
In several prior CAA section 112 and
CAA section 129 rules, including this
rule, the EPA included an affirmative
defense to civil penalties for violations
caused by malfunctions in an effort to
create a system that incorporates some
flexibility, recognizing that there is a
tension, inherent in many types of air
regulation, to ensure adequate
compliance while simultaneously
recognizing that despite the most
diligent of efforts, emission standards
may be violated under circumstances
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entirely beyond the control of the
source. Although the EPA recognized
that its case-by-case enforcement
discretion provides sufficient flexibility
in these circumstances, it included the
affirmative defense to provide a more
formalized approach and more
regulatory clarity. See Weyerhaeuser Co.
v. Costle, 590 F.2d 1011, 1057–58 (D.C.
Cir. 1978) (holding that an informal
case-by-case enforcement discretion
approach is adequate); but see Marathon
Oil Co. v. EPA, 564 F.2d 1253, 1272–73
(9th Cir. 1977) (requiring a more
formalized approach to consideration of
‘‘upsets beyond the control of the permit
holder.’’). Under the EPA’s regulatory
affirmative defense provisions, if a
source could demonstrate in a judicial
or administrative proceeding that it had
met the requirements of the affirmative
defense in the regulation, civil penalties
would not be assessed. Recently, the
United States Court of Appeals for the
District of Columbia Circuit vacated an
affirmative defense in one of the EPA’s
CAA section 112 regulations. NRDC v.
EPA, 749 F.3d 1055 (D.C. Cir., 2014)
(vacating affirmative defense provisions
in CAA section 112 rule establishing
emission standards for Portland cement
kilns). The court found that the 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 in such cases lies exclusively
with the courts, not the EPA.
Specifically, the court found: ‘‘As the
language of the statute makes clear, the
courts determine, on a case-by-case
basis, whether civil penalties are
‘appropriate.’ ’’ See NRDC, 749 F.3d at
1063 (‘‘[U]nder this statute, deciding
whether penalties are ‘appropriate’ . . .
is a job for the courts, not EPA.’’).
In light of NRDC, the EPA is
proposing to remove the regulatory
affirmative defense provision in the
current rule. As explained above, if a
source is unable to comply with
emissions standards as a result of a
malfunction, the EPA may use its caseby-case enforcement discretion to
provide flexibility, 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. Cf.
NRDC, at 1064 (arguments that violation
were caused by unavoidable technology
failure can be made to the courts in
future civil cases when the issue arises).
The same is true for the presiding officer
in EPA administrative enforcement
actions.
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III. Statutory and Executive Order
Reviews
Additional information about these
statutes and Executive Orders can be
found at https://www2.epa.gov/lawsregulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory
Planning and Review and Executive
Order 13563: Improving Regulation and
Regulatory Review
This action is not a significant
regulatory action and was, therefore, not
subject to review by the Office of
Management and Budget (OMB).
B. Paperwork Reduction Act (PRA)
This action does not impose any new
information collection burden. This
action clarifies but does not change the
information collection requirements
previously finalized and, as a result,
does not impose any additional burden
on industry. The OMB has previously
approved the information collection
requirements contained in the existing
regulations (see 77 FR 9303, February
16, 2012) under the provisions of the
PRA, 44 U.S.C. 3501 et seq. and has
assigned OMB control number 2060–
0567. The OMB control numbers for the
EPA’s regulations are listed in 40 CFR
part 9.
C. Regulatory Flexibility Act (RFA)
I certify that this action will not have
a significant economic impact on a
substantial number of small entities.
The EPA has determined that none of
the small entities will experience a
significant impact because the action
imposes no additional regulatory
requirements on owners or operators of
affected sources.
D. Unfunded Mandates Reform Act
(UMRA)
This action does not contain an
unfunded mandate as described in 2
U.S.C. 1531–1538, and does not
significantly or uniquely affect small
governments. The action imposes no
enforceable duty on any state, local, or
tribal governments or the private sector.
E. Executive Order 13132: Federalism
This action does not have federalism
implications. It 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.
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8449
F. Executive Order 13175: Consultation
and Coordination With Indian Tribal
Governments
This action does not have tribal
implications as specified in Executive
Order 13175. This action does not
significantly or uniquely affect the
communities of tribal governments.
Thus, Executive Order 13175, does not
apply to this action.
G. Executive Order 13045: Protection of
Children From Environmental Health
Risks and Safety Risks
The EPA interprets Executive Order
13045 as applying only to those
regulatory actions that concern
environmental health or safety risks that
the EPA has reason to believe may
disproportionately affect children, per
the definition of ‘‘covered regulatory
action’’ in section 2–202 of the
Executive Order. This action is not
subject to Executive Order 13045
because it does not concern an
environmental health risk or safety risk.
H. Executive Order 13211: Actions
Concerning Regulations That
Significantly Affect Energy Supply,
Distribution or Use
This action is not subject to Executive
Order 13211 because it is not a
significant regulatory action under
Executive Order 12866.
I. National Technology Transfer and
Advancement Act (NTTAA)
This rulemaking does not involve
technical standards.
J. Executive Order 12898: Federal
Actions To Address Environmental
Justice in Minority Populations and
Low-Income Populations
The EPA believes the human health or
environmental risk addressed by this
action will not have potential
disproportionately high and adverse
human health or environmental effects
on minority, low-income or indigenous
populations. The corrections do not
involve special consideration of
environmental justice-related issues as
required by Executive Order 12898, and
an evaluation was not necessary for this
action.
The EPA’s compliance with the above
statutes and Executive Orders for the
underlying rule is discussed in the
February 16, 2012, Federal Register
document containing ‘‘National
Emission Standards for Hazardous Air
Pollutants from Coal- and Oil-fired
Electric Utility Steam Generating Units
and Standards of Performance for
Fossil-Fuel-Fired Electric Utility,
Industrial-Commercial-Institutional, and
Small Industrial-Commercial-
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Institutional Steam Generating Units.’’
(77 FR 9303).
List of Subjects
40 CFR Part 60
Environmental protection,
Administrative practice and procedure,
Air pollution control, Incorporation by
reference, Intergovernmental relations,
Reporting and recordkeeping
requirements.
40 CFR Part 63
Environmental protection,
Administrative practice and procedure,
Air pollution control, Hazardous
substances, Incorporation by reference,
Intergovernmental relations, Reporting
and recordkeeping requirements.
For the reasons discussed in the
preamble, the EPA proposes to correct
and amend 40 CFR parts 60 and 63 to
read as follows:
PART 60—STANDARDS OF
PERFORMANCE FOR NEW
STATIONARY SOURCES
1. The authority citation for part 60
continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
2. Section 60.48Da is amended by
revising paragraph (f) to read as follows:
■
Compliance provisions.
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*
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(f) For affected facilities for which
construction, modification, or
reconstruction commenced before May
4, 2011, compliance with the applicable
daily average PM emissions limit is
determined by calculating the
arithmetic average of all hourly
emission rates each boiler operating
day, except for data obtained during
startup, shutdown, or malfunction
periods. Daily averages are only
calculated for boiler operating days that
have non-out-of-control data for at least
18 hours of unit operation during which
the standard applies. Instead, all of the
non-out-of-control hourly emission rates
of the operating day(s) not meeting the
minimum 18 hours non-out-of-control
data daily average requirement are
averaged with all of the non-out-ofcontrol hourly emission rates of the next
boiler operating day with 18 hours or
more of non-out-of-control PM CEMS
data to determine compliance. For
affected facilities for which construction
or reconstruction commenced after May
3, 2011 that elect to demonstrate
compliance using PM CEMS,
19:45 Feb 13, 2015
3. The authority citation for part 63
continues to read as follows:
■
Authority: 42 U.S.C. 7401, et seq.
4. Section 63.9983 is amended by:
a. Revising the section heading and
paragraphs (a), (b), and (c); and
■ Adding paragraph (e).
The revisions and addition read as
follows:
§ 63.9983 Are any fossil fuel-fired electric
generating units not subject to this
subpart?
*
■
VerDate Sep<11>2014
PART 63—NATIONAL EMISSION
STANDARDS FOR HAZARDOUS AIR
POLLUTANTS FOR SOURCE
CATEGORIES
■
■
Dated: December 19, 2014.
Gina McCarthy,
Administrator.
§ 60.48Da
compliance with the applicable PM
emissions limit in § 60.42Da is
determined on a 30-boiler operating day
rolling average basis by calculating the
arithmetic average of all hourly PM
emission rates for the 30 successive
boiler operating days, except for data
obtained during periods of startup and
shutdown.
*
*
*
*
*
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*
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*
(a) Any unit designated as a major
source stationary combustion turbine
subject to 40 CFR part 63, subpart YYYY
and any unit designated as an area
source stationary combustion turbine,
other than an integrated gasification
combined cycle (IGCC) unit.
(b) Any electric utility steam
generating unit that is not a coal- or oilfired EGU and that meets the definition
of a natural gas-fired EGU in § 63.10042.
(c) Any electric utility steam
generating unit that has the capability of
combusting more than 25 MW of coal or
oil but does not meet the definition of
a coal- or oil-fired EGU because it did
not fire sufficient coal or oil to satisfy
the average annual heat input
requirement set forth in the definitions
for coal-fired and oil-fired EGUs in
§ 63.10042. Heat input means heat
derived from combustion of fuel in an
EGU and does not include the heat
derived from preheated combustion air,
recirculated flue gases or exhaust gases
from other sources (such as stationary
gas turbines, internal combustion
engines, and industrial boilers).
*
*
*
*
*
(e) Any electric utility steam
generating unit that meets the definition
of a natural gas-fired EGU under this
subpart and that fires at least 10 percent
biomass is an industrial boiler subject to
standards established under 40 CFR part
63, subpart DDDDD, if it otherwise
meets the applicability provisions in
that rule.
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5. Section 63.9991 is amended by
revising paragraphs (c)(1) and (2) to read
as follows:
■
§ 63.9991 What emission limitations, work
practice standards, and operating limits
must I meet?
*
*
*
*
*
(c) * * *
(1) Has a system using wet or dry flue
gas desulfurization technology and an
SO2 continuous emissions monitoring
system (CEMS) installed on the EGU;
and
(2) At all times, you operate the wet
or dry flue gas desulfurization
technology and the SO2 CEMS installed
on the EGU consistent with
§ 63.10000(b).
■ 6. Section 63.10000 is amended by:
■ a. Revising paragraph (c)(1)(i);
■ b. Revising paragraph (c)(2)(iii); and
■ c. Adding paragraph (m).
The revisions and additions read as
follows:
§ 63.10000 What are my general
requirements for complying with this
subpart?
*
*
*
*
*
(c)(1) * * *
(i) For a coal-fired or solid oil-derived
fuel-fired EGU or IGCC EGU, you may
conduct initial performance testing in
accordance with § 63.10005(h), to
determine whether the EGU qualifies as
a low emitting EGU (LEE) for one or
more applicable emission limits, except:
(A) You may not pursue the LEE
option if your coal-fired, IGCC, or solid
oil-derived fuel-fired EGU is equipped
with a main stack and a bypass stack
exhaust configuration that allows the
EGU to bypass any pollutant control
device.
(B) You may not pursue the LEE
option for Hg if your coal-fired, solid
oil-derived fuel-fired EGU or IGCC EGU
is new.
(C) Notwithstanding paragraph
(c)(1)(i)(A) of this section, you may
pursue the LEE option provided:
(1) Your control device bypass stack
is routed through the EGU main stack so
that emissions are measured during the
bypass event; or
(2) You bypass your EGU control
device only during emergency periods
for no more than a total of 2 percent of
your EGU’s annual operating hours; you
use clean fuels to the maximum extent
practicable during an emergency period;
and you prepare and submit a report
describing the emergency event, its
cause, corrective action taken, and
estimates of emissions released during
the emergency event. You must include
these emergency emissions along with
performance test results in assessing
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whether your EGU maintains LEE
status.
*
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*
(2) * * *
(iii) If your existing liquid oil-fired
unit does not qualify as a LEE for
hydrogen chloride (HCl) or for hydrogen
fluoride (HF), you may demonstrate
initial and continuous compliance
through use of an HCl CEMS, an HF
CEMS, or an HCl and HF CEMS,
installed and operated in accordance
with Appendix B to this rule. As an
alternative to HCl CEMS, HF CEMS, or
HCl and HF CEMS, you may
demonstrate initial and continuous
compliance through quarterly
performance testing and parametric
monitoring for HCl and HF. If you
choose to use quarterly testing and
parametric monitoring, then you must
also develop a site-specific monitoring
plan that identifies the CMS you will
use to ensure that the operations of the
EGU remains consistent with those
during the performance test. As another
alternative, you may measure or obtain,
and keep records of, fuel moisture
content; as long as fuel moisture does
not exceed 1.0 percent by weight, you
need not conduct other HCl or HF
monitoring or testing.
*
*
*
*
*
(m) Should you choose to rely on
paragraph (2) of the definition of
‘‘startup’’ in § 63.10042 for your EGU,
on or before the date your EGU is
subject to this subpart, you must install,
verify, operate, maintain, and quality
assure each monitoring system
necessary for demonstrating compliance
with the work practice standards for PM
or non-mercury HAP metals controls
during startup periods and shutdown
periods required to comply with
§ 63.10020(e).
(1) You may rely on monitoring
system specifications or instructions or
manufacturer’s specifications when
installing, verifying, operating,
maintaining, and quality assuring each
monitoring system.
(2) You must collect, record, report,
and maintain data obtained from these
monitoring systems during startup
periods and shutdown periods.
§ 63.10001
[Removed and reserved]
7. Section 63.10001 is removed and
reserved.
■ 8. Section 63.10005 is amended by:
■ a. Revising paragraphs (a)
introductory text, (a)(2) introductory
text and (a)(2)(i);
■ b. Revising paragraph (b)(1);
■ c. Adding paragraph (b)(6);
■ d. Revising paragraphs (d)(3), (d)(4)(i);
■ f. Revising paragraph (f);
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■
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g. Revising paragraph (h) introductory
text, and (h)(3) introductory text;
■ h. Removing paragraphs (i)(4)(iii) and
(iv).
The revisions and additions read as
follows:
■
§ 63.10005 What are my initial compliance
requirements and by what date must I
conduct them?
(a) General requirements. For each of
your affected EGUs, you must
demonstrate initial compliance with
each applicable emissions limit in Table
1 or 2 of this subpart through
performance testing. Where two
emissions limits are specified for a
particular pollutant (e.g., a heat inputbased limit in lb/MMBtu and an
electrical output-based limit in lb/
MWh), you may demonstrate
compliance with either emission limit.
For a particular compliance
demonstration, you may be required to
conduct one or more of the following
activities in conjunction with
performance testing: collection of data,
e.g., hourly electrical load data
(megawatts); establishment of operating
limits according to § 63.10011 and
Tables 4 and 7 to this subpart; and CMS
performance evaluations. In all cases,
you must demonstrate initial
compliance no later than the date in
paragraph (f) of this section for tune-up
work practices for existing EGUs; the
date that compliance must be
demonstrated, as given in § 63.9984 for
other requirements for existing EGUs;
and in paragraph (g) of this section for
all requirements for new EGUs.
(1) * * *
(2) To demonstrate initial compliance
using either a CMS that measures HAP
concentrations directly (i.e., an Hg, HCl,
or HF CEMS, or a sorbent trap
monitoring system) or an SO2 or PM
CEMS, the initial performance test may
occur on or before the first averaging
period (30- or, for certain coal-fired
existing EGUs that use emissions
averaging for Hg, 90-boiler operating
days) after the date that compliance
with this subpart is required but must
occur such that the averaging period is
completed on or before the date that
compliance must be demonstrated.
(i) The CMS performance test must
demonstrate compliance with the
applicable Hg, HCl, HF, PM, or SO2
emissions limit in Table 1 or 2 to this
subpart.
*
*
*
*
*
(b) * * *
(1) For a performance test of an
existing EGU based on stack test data,
the test was conducted between 180 and
365 calendar days prior to the date that
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8451
compliance must be demonstrated as
specified in § 63.9984.
*
*
*
*
*
(6) If the performance test data that
are collected prior to the date that
compliance must be demonstrated are
used to demonstrate initial compliance
with applicable emissions limits, the
interval for subsequent stack tests
begins on the date that compliance must
be demonstrated.
*
*
*
*
*
(d) * * *
(3) For affected EGUs that are either
required to or elect to demonstrate
initial compliance with the applicable
Hg emission limit in Table 1 or 2 of this
subpart using Hg CEMS or sorbent trap
monitoring systems, initial compliance
must be demonstrated no later than the
applicable date specified in § 63.9984(f)
for existing EGUs and in paragraph (g)
of this section for new EGUs. Initial
compliance is achieved if the arithmetic
average of 30- (or 90-) boiler operating
days of quality-assured CEMS (or
sorbent trap monitoring system) data,
expressed in units of the standard (see
section 6.2 of appendix A to this
subpart), meets the applicable Hg
emission limit in Table 1 or 2 to this
subpart.
(4) * * *
(i) You must demonstrate initial
compliance no later than the applicable
date specified in § 63.9984(f) for existing
EGUs and in paragraph (g) of this
section for new EGUs.
*
*
*
*
*
(f) For an existing EGU without a
neural network, a tune-up must occur
on or before 180 days after April 16,
2015. For an existing EGU with a neural
network, a tune-up must occur on or
before 180 days after April 16, 2016. If
a tune-up occurs prior to April 16, 2015,
you must keep records showing that the
operating conditions remain the same
and that the tune-up met all rule
requirements.
*
*
*
*
*
(h) Low emitting EGUs. The
provisions of this paragraph (h) apply to
pollutants with emissions limits from
new EGUs except Hg and to all
pollutants with emissions limits from
existing EGUs. You may pursue this
compliance option unless prohibited
pursuant to § 63.10000(c)(1)(i).
*
*
*
*
*
(3) For Hg, you must conduct a 30- (or
90-) boiler operating day performance
test using Method 30B in appendix A–
8 to part 60 of this chapter to determine
whether a unit qualifies for LEE status.
Locate the Method 30B sampling probe
tip at a point within 10 percent of the
duct area centered about the duct’s
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centroid at a location that meets Method
1 in appendix A–1 to part 60 of this
chapter and conduct at least three
nominally equal length test runs over
the 30-boiler operating day test period.
Collect Hg emissions data continuously
over the entire test period (except when
changing sorbent traps or performing
required reference method QA
procedures). As an alternative to
constant rate sampling per Method 30B,
you may use proportional sampling per
section 8.2.2 of Performance
Specification 12 B in appendix B to part
60 of this chapter.
*
*
*
*
*
■ 9. Section 63.10006 is amended by
revising paragraph (f) to read as follows:
§ 63.10006 When must I conduct
subsequent performance tests or tune-ups?
*
*
*
*
(f) Time between performance tests.
(1) Notwithstanding the provisions of
§ 63.10021(d)(1), the requirements listed
in paragraphs (g) and (h) of this section,
and the requirements of paragraph (f)(3)
of this section, you must complete
performance tests for your EGU as
follows:
(i) At least 45 calendar days must
separate performance tests conducted
every quarter;
(ii) At least 370 calendar days must
separate performance tests conducted
every year; and
(iii) At least 1,050 calendar days must
separate performance tests conducted
every 3 years.
(2) Although you are not required to
operate your EGU solely in order to
conduct a performance test, you must
conduct a performance test in the 4th
quarter of a calendar year if your EGU
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*
Where:
WAERm = Maximum Weighted Average
Emission Rate in terms of lb/heat input
or lb/gross output,
Hermi,j = hourly emission rate (e.g., lb/
MMBtu, lb/MWh) from CEMS or sorbent
trap monitoring for hour i from EGU j,
Rmmj = Maximum rated heat input, MMBtu/
h, or maximum rated gross output,
MWh/h, for EGU j,
p = number of EGUs in emissions averaging
group that rely on CEMS,
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has skipped performance tests in the 3
quarters of the calendar year.
(3) If your EGU misses a performance
test deadline due to being inoperative
and if you have at least 168 boiler
operating hours in the next test period,
you must complete an additional
performance test in that period as
follows:
(i) At least 15 calendar days must
separate two performance tests
conducted in the same quarter.
(ii) At least 107 calendar days must
separate two performance tests
conducted in the same calendar year.
(iii) At least 350 calendar days must
separate two performance tests
conducted in the same 3 year period.
*
*
*
*
*
■ 10. Section 63.10009 is amended by:
■ a. Revising paragraphs (a)(2)
introductory text and (a)(2)(i);
■ b. Revising paragraphs (b)(1) through
(3);
■ c. Revising paragraphs (f) introductory
text and paragraph (f)(2);
■ d. Revising paragraphs (g)(1) and (2);
and
■ e. Revising paragraph (j)(1)(ii).
The revisions read as follows:
§ 63.10009 May I use emissions averaging
to comply with this subpart?
(a) * * *
(2) You may demonstrate compliance
by emissions averaging among the
existing EGUs in the same subcategory,
if your averaged Hg emissions for EGUs
in the ‘‘unit designed for coal ≥8,300
Btu/lb’’ subcategory are equal to or less
than 1.2 lb/TBtu or 1.3E–2 lb/GWh on
a 30-boiler operating day basis or if your
averaged emissions of individual, other
pollutants from other subcategories of
n = hours in an averaging period (e.g., 720
for a 30-group boiler operating day
averaging period or 2160 for a 90-group
boiler operating day averaging period),
qj = hours in an averaging period for EGU j
(e.g., 720 for a 30-group boiler operating
day averaging period or 2160 for a 90group boiler operating day averaging
period),
Terk = Emissions rate (lb/MMBTU or lb/
MWh) from the most recent test of EGU
k,
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such EGUs are equal to or less than the
applicable emissions limit in Table 2 to
this subpart, according to the
procedures in this section. Note that
except for the alternate Hg emissions
limit from EGUs in the ‘‘unit designed
for coal ≥8,300 Btu/lb’’ subcategory, the
averaging time for emissions averaging
for pollutants is 30 days (rolling daily)
using data from CEMS or a combination
of data from CEMS and manual
performance testing. The averaging time
for emissions averaging for the alternate
Hg limit (equal to or less than 1.0 lb/
TBtu or 1.1E–2 lb/GWh) from EGUs in
the ‘‘unit designed for coal ≥8,300 Btu/
lb’’ subcategory is 90-boiler operating
days (rolling daily) using data from
CEMS, sorbent trap monitoring, or a
combination of monitoring data and
data from manual performance testing.
For the purposes of this paragraph, 30(or 90-) group boiler operating days is
defined as a period during which at
least one unit in the emissions averaging
group has operated 30 (or 90) days. You
must calculate the weighted average
emissions rate for the group in
accordance with the procedures in this
paragraph using the data from all units
in the group including any that operate
fewer than 30 (or 90) days during the
preceding 30 (or 90) group boiler days.
(i) You may choose to have your EGU
emissions averaging group meet either
the heat input basis (MMBtu or TBtu, as
appropriate for the pollutant) or gross
output basis (MWh or GWh, as
appropriate for the pollutant).
*
*
*
*
*
(b) * * *
(1) Group eligibility equations.
Rmtk = Maximum rated heat input, MMBtu/
h, or maximum rated gross output,
MWh/h, for EGU k,
rk = hours in an averaging period for EGU k
(e.g., 720 for a 30-group boiler operating
day averaging period or 2160 for a 90group boiler operating day averaging
period), and
m = number of EGUs in emissions averaging
group that rely on emissions testing.
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8453
(MMBtu/lbsteam or MWh/lbsteam) from
EGU k.
output per pound of steam generated
(MMBtu/lbsteam or MWh/lbsteam) from
EGU j,
Smtk = maximum steam generation, lbsteam/h
or lb/gross output, for EGU k, and
Cfmk = conversion factor, calculated from the
most recent compliance test results, in
terms units of heat input or electrical
output per pound of steam generated
Where:
Heri = hourly emission rate (e.g., lb/MMBtu,
lb/MWh) from unit i’s CEMS for the
preceding 30-group boiler operating
days,
Rmi = hourly heat input or gross output from
unit i for the preceding 30-group boiler
operating days,
p = number of EGUs in emissions averaging
group that rely on CEMS or sorbent trap
monitoring,
n = number of hours that hourly rates are
collected over 30-group boiler operating
days,
Where:
variables with similar names share the
descriptions for Equation 2a,
Smi = steam generation in units of pounds
from unit i that uses CEMS for the
preceding 30-group boiler operating
days,
Cfmi = conversion factor, calculated from the
most recent compliance test results, in
units of heat input per pound of steam
generated or gross output per pound of
steam generated, from unit i that uses
CEMS from the preceding 30 group
boiler operating days,
Sti = steam generation in units of pounds
from unit i that uses emissions testing,
and
Cfti = conversion factor, calculated from the
most recent compliance test results, in
units of heat input per pound of steam
generated or gross output per pound of
Where:
Heri = hourly emission rate from unit i’s
CEMS or Hg sorbent trap monitoring
system for the preceding 90-group boiler
operating days,
Rmi = hourly heat input or gross output from
unit i for the preceding 90-group boiler
operating days,
p = number of EGUs in emissions averaging
group that rely on CEMS,
n = number of hours that hourly rates are
collected over the 90-group boiler
operating days,
Teri = Emissions rate from most recent
emissions test of unit i in terms of lb/
heat input or lb/gross output,
Rti = Total heat input or gross output of unit
i for the preceding 90-boiler operating
days, and
m = number of EGUs in emissions averaging
group that rely on emissions testing.
Where:
variables with similar names share the
descriptions for Equation 2a,
Smi = steam generation in units of pounds
from unit i that uses CEMS or a Hg
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(2) Weighted 30-boiler operating day
rolling average emissions rate equations
for pollutants other than Hg. Use
equation 2a or 2b to calculate the 30 day
rolling average emissions daily.
Teri = Emissions rate from most recent
emissions test of unit i in terms of lb/
heat input or lb/gross output,
Rti = Total heat input or gross output of unit
i for the preceding 30-boiler operating
days, and
m = number of EGUs in emissions averaging
group that rely on emissions testing.
steam generated, from unit i that uses
emissions testing.
E:\FR\FM\17FEP3.SGM
17FEP3
EP17FE15.002</GPH>
EP17FE15.003</GPH>
EP17FE15.004</GPH>
EP17FE15.005</GPH>
(3) Weighted 90-boiler operating day
rolling average emissions rate equations
for Hg emissions from EGUs in the
‘‘coal-fired unit not low rank virgin
coal’’ subcategory. Use equation 3a or 3b
to calculate the 90-day rolling average
emissions daily.
EP17FE15.001</GPH>
tkelley on DSK3SPTVN1PROD with PROPOSALS3
Where:
Variables with the similar names share the
descriptions for Equation 1a,
Smmj = maximum steam generation, lbsteam/
h or lb/gross output, for EGU j,
Cfmj = conversion factor, calculated from the
most recent compliance test results, in
terms units of heat input or electrical
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Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
sorbent trap monitoring for the preceding
90-group boiler operating days,
Cfmi = conversion factor, calculated from the
most recent compliance test results, in
units of heat input per pound of steam
generated or gross output per pound of
steam generated, from unit i that uses
CEMS or sorbent trap monitoring from
the preceding 90-group boiler operating
days,
Sti = steam generation in units of pounds
from unit i that uses emissions testing,
and
Cfti = conversion factor, calculated from the
most recent emissions test results, in
units of heat input per pound of steam
generated or gross output per pound of
steam generated, from unit i that uses
emissions testing.
tkelley on DSK3SPTVN1PROD with PROPOSALS3
*
*
*
*
*
(f) Emissions averaging group
eligibility demonstration. You must
demonstrate the ability for the EGUs
included in the emissions averaging
group to demonstrate initial compliance
according to paragraph (f)(1) or (2) of
this section using the maximum
possible heat input or gross output over
a 30- (or 90-) boiler operating day period
of each EGU and the results of the initial
performance tests. For this
demonstration and prior to preparing
your emissions averaging plan, you
must conduct required emissions
monitoring for 30- (or 90-) days of boiler
operation and any required manual
performance testing to calculate
maximum weighted average emissions
rate in accordance with this section.
Should the Administrator require
approval, you must submit your
proposed emissions averaging plan and
supporting data at least 120 days before
the date on which you plan to being
using emissions averaging. If the
Administrator requires approval of your
plan, you may not begin using
emissions averaging until the
Administrator approves your plan.
*
*
*
*
*
(2) If you are not capable of
monitoring heat input or gross output,
and the EGU generates steam for
purposes other than generating
electricity, you may use Equation 1b of
this section as an alternative to using
Equation 1a of this section to
demonstrate that the maximum
weighted average emissions rates of
filterable PM, HF, SO2, HCl, non-Hg
HAP metals, or Hg emissions from the
existing units participating in the
emissions averaging group do not
exceed the emission limits in Table 2 to
this subpart.
*
*
*
*
*
(g) * * *
(1) You must use Equation 2a or 3a of
paragraph (b) of this section to calculate
the weighted average emissions rate
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using the actual heat input or gross
output for each existing unit
participating in the emissions averaging
option.
(2) If you are not capable of
monitoring heat input or gross output,
you may use Equation 2b or 3b of
paragraph (b) of this section as an
alternative to using Equation 2a of
paragraph (b) of this section to calculate
the average weighted emission rate
using the actual steam generation from
the units participating in the emissions
averaging option.
*
*
*
*
*
(j) * * *
(1) * * *
(ii) The process weighting parameter
(heat input, gross output, or steam
generated) that will be monitored for
each averaging group;
*
*
*
*
*
■ 11. Section 63.10010 is amended by:
■ a. Revising paragraph (a)(4);
■ b. Revising paragraph (f)(3);
■ c. Revising paragraphs (h)(6)(i) and
(ii);
■ d. Revising paragraphs (i)(5)(i)(A) and
(B);
■ e. Revising paragraph (j)(1)(i) and
(j)(4)(i)(A) and (B); and
■ f. Revising paragraph (l).
The revisions read as follows:
§ 63.10010 What are my monitoring,
installation, operation, and maintenance
requirements?
*
*
*
*
*
(a) * * *
(4) Unit with a main stack and a
bypass stack that exhausts to the
atmosphere independent of the main
stack. If the exhaust configuration of an
affected unit consists of a main stack
and a bypass stack, you shall install
CEMS on both the main stack and the
bypass stack. If it is not feasible to
certify and quality-assure the data from
a monitoring system on the bypass
stack, you shall:
(i) Route the exhaust from the bypass
through the main stack and its
monitoring so that bypass emissions are
measured, or
(ii) Install a CEMS only on the main
stack and count hours that the bypass
stack is in use as hours of deviation
from the monitoring requirements.
*
*
*
*
*
(f) * * *
(3) Calculate and record a 30-boiler
operating day rolling average SO2
emission rate in the units of the
standard, updated after each new boiler
operating day. Each 30-boiler operating
day rolling average emission rate is the
average of all of the valid hourly SO2
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emission rates in the preceding 30 boiler
operating days.
*
*
*
*
*
(h) * * *
(6) * * *
(i) Any data collected during periods
of monitoring system malfunctions,
repairs associated with monitoring
system malfunctions, or required
monitoring system quality assurance or
quality control activities conducted
during monitoring system malfunctions.
You must report any such periods in
your annual deviation report;
(ii) Any data collected during periods
when the monitoring system is out of
control as specified in your site-specific
monitoring plan, repairs associated with
periods when the monitoring system is
out of control, or required monitoring
system quality assurance or quality
control activities conducted during outof-control periods. You must report any
such periods in your annual deviation
report.
*
*
*
*
*
(i) * * *
(5) * * *
(i) * * *
(A) Any data collected during periods
of monitoring system malfunctions,
repairs associated with monitoring
system malfunctions, or required
monitoring system quality assurance or
quality control activities conducted
during monitoring system malfunctions.
You must report any such periods in
your annual deviation report;
(B) Any data collected during periods
when the monitoring system is out of
control as specified in your site-specific
monitoring plan, repairs associated with
periods when the monitoring system is
out of control, or required monitoring
system quality assurance or quality
control activities conducted during outof-control periods. You must report any
such periods in your annual deviation
report.
*
*
*
*
*
(j) * * *
(1) * * *
(i) Install, calibrate, operate, and
maintain your HAP metals CEMS
according to your CMS quality control
program, as described in § 63.8(d)(2).
The reportable measurement output
from the HAP metals CEMS must be
expressed in units of the applicable
emissions limit (e.g., lb/MMBtu, lb/
MWh) and in the form of a 30-boiler
operating day rolling average.
*
*
*
*
*
(4) * * *
(i) * * *
(A) Any data collected during periods
of monitoring system malfunctions,
repairs associated with monitoring
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tkelley on DSK3SPTVN1PROD with PROPOSALS3
system malfunctions, or required
monitoring system quality assurance or
quality control activities conducted
during monitoring system malfunctions.
You must report any such periods in
your annual deviation report;
(B) Any data collected during periods
when the monitoring system is out of
control as specified in your site-specific
monitoring plan, repairs associated with
periods when the monitoring system is
out of control, or required monitoring
system quality assurance or quality
control activities conducted during outof-control periods. You must report any
such periods in your annual deviation
report.
*
*
*
*
*
(l) Should you choose to rely on
paragraph (2) of the definition of
‘‘startup’’ in § 63.10042 for your EGU,
you must install, verify, operate,
maintain, and quality assure each
monitoring system necessary for
demonstrating compliance with the PM
or non-mercury metals work practice
standards required to comply with
§ 63.10020(e).
(1) You shall develop a site-specific
monitoring plan for PM or non-mercury
metals work practice monitoring during
startup periods.
(2) You shall submit the site-specific
monitoring plan upon request by the
Administrator.
(3) The provisions of the monitoring
plan must address the following items:
(i) Monitoring system installation;
(ii) Performance and equipment
specifications;
(iii) Schedule for initial and periodic
performance evaluations;
(iv) Performance evaluation
procedures and acceptance criteria;
(v) On-going operation and
maintenance procedures; and
(vi) On-going recordkeeping and
reporting procedures.
(4) You may rely on monitoring
system specifications or instructions or
manufacturer’s specifications to address
paragraphs (l)(3)(i) through (vi) of this
section.
(5) You must operate and maintain
the monitoring system according to the
site-specific monitoring plan.
■ 12. Section 63.10011 is amended by
revising paragraphs (b), (c), (e) and (g)
to read as follows:
§ 63.10011 How do I demonstrate initial
compliance with the emissions limits and
work practice standards?
*
*
*
*
*
(b) If you are subject to an operating
limit in Table 4 to this subpart, you
demonstrate initial compliance with
HAP metals or filterable PM emission
limit(s) through performance stack tests
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and you elect to use a PM CPMS to
demonstrate continuous performance, or
if, for a liquid oil-fired EGU, and you
use quarterly stack testing for HCl and
HF plus site-specific parameter
monitoring to demonstrate continuous
performance, you must also establish a
site-specific operating limit, in
accordance with § 63.10007 and Table 6
to this subpart. You may use only the
parametric data recorded during
successful performance tests (i.e., tests
that demonstrate compliance with the
applicable emissions limits) to establish
an operating limit.
(c)(1) If you use CEMS or sorbent trap
monitoring systems to measure a HAP
(e.g., Hg or HCl) directly, the initial
performance test, consisting of a 30boiler operating day (or, for certain coalfired, existing EGUs that use emissions
averaging for Hg, a 90-boiler operating
day) rolling average emissions rate
obtained with certified CEMS,
expressed in units of the standard, may
occur on or before the first averaging
period after the date that compliance
with the subpart is required but must
occur such that the averaging period is
completed on or before the date that
compliance must be demonstrated.
Initial compliance is demonstrated if the
results of the performance test meet the
applicable emission limit in Table 1 or
2 to this subpart.
(2) For an EGU that uses a CEMS to
measure SO2 or PM emission for initial
compliance, the initial performance test,
consisting of a 30-boiler operating day
average emission rate obtained with
certified CEMS, expressed in units of
the standard, may occur on or before the
first averaging period after the date that
compliance with the subpart is required
but must occur such that the averaging
period is completed on or before the
date that compliance must be
demonstrated. Initial compliance is
demonstrated if the results of the
performance test meet the applicable
SO2 or PM emission limit in Table 1 or
2 to this subpart.
*
*
*
*
*
(e) You must submit a Notification of
Compliance Status containing the
results of the initial compliance
demonstration, in accordance with
§ 63.10030(e).
*
*
*
*
*
(g) You must follow the startup or
shutdown requirements as established
in Table 3 to this subpart for each coalfired, liquid oil-fired, or solid oilderived fuel-fired EGU.
(1) You may use the diluent cap and
default electrical load values, as
described in § 63.10007(f), during
startup periods or shutdown periods.
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8455
(2) You must operate all CMS, collect
data, calculate pollutant emission rates,
and record data during startup periods
or shutdown periods.
(3) You must report the information as
required in § 63.10031.
(4) If you choose to use paragraph (2)
of the definition of ‘‘startup’’ in
§ 63.10042 and you find that you are
unable to safely engage and operate your
particulate matter (PM) control(s) within
1 hour of first firing of coal, residual oil,
or solid oil-derived fuel, you may
choose to rely on paragraph (1) of
definition of ‘‘startup’’ in § 63.10042 or
you may submit a request to use an
alternative non-opacity emissions
standard, as described below.
(i) As mentioned in § 63.6(g)(1), the
request will be published in the Federal
Register for notice and comment
rulemaking. Until promulgation in the
Federal Register of the final alternative
non-opacity emission standard, you
shall comply with paragraph (1) of the
definition of ‘‘startup’’ in § 63.10042.
You shall not implement the alternative
non-opacity emissions standard until
promulgation in the Federal Register of
the final alternative non-opacity
emission standard.
(ii) The request need not address the
items contained in § 63.6(g)(2).
(iii) The request shall provide
evidence of a documented
manufacturer-identified safety issue.
(iv) The request shall provide
information to document that the PM
control device is adequately designed
and sized to meet the PM emission limit
applicable to the EGU.
(v) In addition, the request shall
contain documentation that:
(A) The EGU is using clean fuels to
the maximum extent practicable, taking
into account considerations such as not
compromising boiler or control device
integrity, to bring the EGU and PM
control device up to the temperature
necessary to alleviate or prevent the
identified safety issues prior to the
combustion of primary fuel in the EGU;
(B) The EGU has explicitly followed
the manufacturer’s procedures to
alleviate or prevent the identified safety
issue; and
(C) Identifies with specificity the
details of the manufacturer’s statement
of concern.
(vi) The request shall specify the other
work practice standards the EGU owner
or operator will take to limit HAP
emissions during startup periods and
shutdown periods to ensure a control
level consistent with the work practice
standards of the final rule.
(vii) You must comply with all other
work practice requirements, including
but not limited to data collection,
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recordkeeping, and reporting
requirements.
■ 13. Section 63.10020 is amended by
revising paragraph (e) to read as follows:
§ 63.10020 How do I monitor and collect
data to demonstrate continuous
compliance?
tkelley on DSK3SPTVN1PROD with PROPOSALS3
*
*
*
*
*
(e) Additional requirements during
startup periods or shutdown periods if
you choose to rely on paragraph (2) of
the definition of ‘‘startup’’ in § 63.10042
for your EGU.
(1) During each period of startup, you
must record for each EGU:
(i) The date and time that clean fuels
being combusted for the purpose of
startup begins;
(ii) The quantity and heat input of
clean fuel for each hour of startup;
(iii) The gross output for each hour of
startup;
(iv) The date and time that non-clean
fuel combustion begins; and
(v) The date and time that clean fuels
being combusted for the purpose of
startup ends.
(2) During each period of shutdown,
you must record for each EGU:
(i) The date and time that clean fuels
being combusted for the purpose of
shutdown begins;
(ii) The quantity and heat input of
clean fuel for each hour of shutdown;
(iii) The gross output for each hour of
shutdown;
(iv) The date and time that non-clean
fuel combustion ends; and
(v) The date and time that clean fuels
being combusted for the purpose of
shutdown ends.
(3) For PM or non-mercury HAP
metals work practice monitoring during
startup periods, you must monitor and
collect data according to this section
and the site-specific monitoring plan
required by § 63.10010(l).
(i) Except for an EGU that uses PM
CEMS or PM CPMS to demonstrate
compliance with the PM emissions limit
or that has LEE status for filterable PM
or total non-Hg HAP metals for nonliquid oil-fired EGUs (or HAP metals
emissions for liquid oil-fired EGUs), or
individual non-mercury metals CEMS
you must:
(A) Record temperature and
combustion air flow or calculated flow
as determined from combustion
equations of post-combustion (exhaust)
gas, as well as amperage of forced draft
fan(s), upstream of the filterable PM
control devices during each hour of
startup.
(B) Record temperature and flow of
exhaust gas, as well as amperage of any
induced draft fan(s), downstream of the
filterable PM control devices during
each hour of startup.
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(C) For an EGU with an electrostatic
precipitator, record the number of fields
in service, as well as each field’s
secondary voltage and secondary
current during each hour of startup.
(D) For an EGU with a fabric filter,
record the number of compartments in
service, as well as the differential
pressure across the baghouse during
each hour of startup.
(E) For an EGU with a wet scrubber
needed for filterable PM control, record
the scrubber liquid to flue gas ratio and
the differential pressure across the
scrubber of the liquid during each hour
of startup.
■ 14. Section 63.10021 is amended by
revising paragraphs (d)(3), (e)
introductory text, and (e)(9)(i) and (ii) to
read as follows:
§ 63.10021 How do I demonstrate
continuous compliance with the emission
limitations, operating limits, and work
practice standards?
*
*
*
*
*
(d) * * *
(3) Must conduct site-specific
monitoring using CMS to demonstrate
compliance with the site-specific
monitoring requirements in Table 7 to
this subpart pertaining to HCl and HF
emissions from a liquid oil-fired EGU to
ensure compliance with the HCl and HF
emission limits in Tables 1 and 2 to this
subpart, in accordance with the
requirements of § 63.10000(c)(2)(iii).
The monitoring must meet the general
operating requirements provided in
§ 63.10020.
(e) Conduct periodic performance
tune-ups of your EGU(s), as specified in
paragraphs (e)(1) through (9) of this
section. For your first tune-up, you may
delay the burner inspection until the
next scheduled EGU outage provided
you meet the requirements of
§ 63.10005. Subsequently, you must
perform an inspection of the burner at
least once every 36 calendar months
unless your EGU employs neural
network combustion optimization
during normal operations in which case
you must perform an inspection of the
burner and combustion controls at least
once every 48 calendar months.
*
*
*
*
*
(9) * * *
(i) If the first tune-up is performed
prior to April 16, 2015, report the date
of the tune-up in hard copy (as specified
in § 63.10030) and electronically (as
specified in § 63.10031). Report the date
of each subsequent tune-up
electronically (as specified in
§ 63.10031).
(ii) If the first tune-up is performed on
or after April 16, 2015, report the date
of the tune-up and all subsequent tune-
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ups electronically, in accordance with
§ 63.10031.
*
*
*
*
*
■ 15. Section 63.10023 is amended by
removing and reserving paragraph (b)(1)
and revising (b)(2) introductory text to
read as follows:
§ 63.10023 How do I establish my PM
CPMS operating limit and determine
compliance with it?
*
*
*
*
*
(b) * * *
(2) Determine your operating limit as
follows:
*
*
*
*
*
■ 16. Section 63.10030 is amended by:
■ a. Revising paragraphs (e)(1) and
(e)(7)(i);
■ b. Adding paragraph (e)(7)(iii);
■ c. Revising paragraph (e)(8);
■ d. Adding paragraph (f).
The revisions and additions read as
follows:
§ 63.10030 What notifications must I
submit and when?
*
*
*
*
*
(e) * * *
(1) A description of the affected
source(s), including identification of the
subcategory of the source, the design
capacity of the source, a description of
the add-on controls used on the source,
description of the fuel(s) burned,
including whether the fuel(s) were
determined by you or EPA through a
petition process to be a non-waste under
40 CFR 241.3, whether the fuel(s) were
processed from discarded nonhazardous secondary materials within
the meaning of 40 CFR 241.3, and
justification for the selection of fuel(s)
burned during the performance test.
*
*
*
*
*
(7) * * *
(i) A summary of the results of the
annual performance tests and
documentation of any operating limits
that were reestablished during this test,
if applicable. If you are conducting stack
tests once every 3 years consistent with
§ 63.10006(b), the date of each stack test
conducted during the previous 3 years,
a comparison of emission level you
achieved in each stack test conducted
during the previous 3 years to the 50
percent emission limit threshold
required in § 63.10006(i), and a
statement as to whether there have been
any operational changes since the last
stack test that could increase emissions.
*
*
*
*
*
(iii) For each of your existing EGUs,
identification of each emissions limit as
specified in Table 2 to this subpart with
which you plan to comply.
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Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
(A) You may switch between mass per
heat input and mass per gross output
levels, provided:
(1) You submit a Notification of
Compliance Status that identifies for
each EGU or EGU emissions averaging
group involved in proposed switch both
the current and proposed emission
limit;
(2) Your submission arrives to the
Administrator at least 30 calendar days
prior to the date that the switch is
proposed to occur;
(3) Your submission demonstrates
through performance stack test results
conducted within 30 days prior to your
submission, compliance for each EGU or
EGU emissions averaging group with
both the mass per heat input and mass
per electric output limits;
(4) You revise and submit all other
applicable plans, e.g., monitoring and
emissions averaging, with your
submission; and
(5) You maintain records of all
information regarding your choice of
emission limits.
(B) You may begin to use the revised
emission limits the semi-annual
reporting period after receipt of written
acknowledgement from the
Administrator of the switch.
(C) From submission until the semiannual reporting period after receipt of
written acknowledgement from the
Administrator of the switch, you must
demonstrate compliance with both the
mass per heat input and mass per
electric output emission limits for each
pollutant for each EGU or EGU
emissions averaging group.
(8) Identification of whether you plan
to rely on paragraph (1) or (2) of the
definition of ‘‘startup’’ in § 63.10042.
(i) Should you choose to rely on
paragraph (2) of the definition of
‘‘startup’’ in § 63.10042 for your EGU,
you shall include a report that
identifies:
(A) The original EGU installation
date;
(B) The original EGU design
characteristics, including, but not
limited to, fuel mix and PM controls;
(C) Each design PM control device
efficiency established during
performance testing or while operating
in periods other than startup and
shutdown periods;
(D) The design PM emission rate from
the EGU in terms of pounds PM per
MMBtu and pounds PM per hour
established during performance testing
or while operating in periods other than
startup and shutdown periods;
(E) The design time from start of fuel
combustion to necessary conditions for
each PM control device startup;
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(F) Each design PM control device
efficiency upon startup of the PM
control device, if different from the
efficiency provided in paragraph
(e)(8)(i)(C) of this section;
(G) Current EGU PM producing
characteristics, including, but not
limited to, fuel mix and PM controls, if
different from the characteristics
provided in paragraph (e)(8)(i)(B) of this
section;
(H) Current PM control device
efficiency from each PM control device,
if different from the efficiency provided
in paragraph (e)(8)(i)(C) of this section;
(I) Current PM emission rate from the
EGU in terms of pounds PM per MMBtu
and pounds per hour, if different from
the rate provided in paragraph
(e)(8)(i)(D) of this section;
(J) Current time from start of fuel
combustion to conditions necessary for
each PM control device startup, if
different from the time provided in
paragraph (e)(8)(i)(E) of this section; and
(M) Current PM control device
efficiency upon startup of each PM
control device, if different from the
efficiency provided in paragraph
(e)(8)(i)(H) of this section.
(ii) The report shall be prepared,
signed, and sealed by a professional
engineer licensed in the state where
your EGU is located.
(f) You must submit the notifications
in § 63.10000(h)(2) and (i)(2) that may
apply to you by the dates specified.
■ 17. Section 63.10031 is amended by:
■ a. Revising paragraphs (c)(4) and (5);
■ b. Adding paragraph (c)(6); and
■ c. Revising paragraph (f)(5).
The revisions and addition read as
follows:
limits, include hourly average CEMS
values and hourly average flow values
during startup periods or shutdown
periods. Use units of milligrams per
cubic meter for PM CEMS values,
micrograms per cubic meter for Hg
CEMS values, and ppmv for HCl, HF, or
SO2 CEMS values. Use units of standard
cubic meters per hour on a wet basis for
flow values.
(iv) If you choose to use a separate
sorbent trap measurement system for
startup or shutdown reporting periods,
include hourly average mercury
concentration values in terms of
micrograms per cubic meter.
(v) If you choose to use a PM CPMS,
include hourly average operating
parameter values in terms of the
operating limit, as well as the operating
parameter to PM correlation equation.
(6) Emergency bypass reports from
EGUs with LEE status.
*
*
*
*
*
(f) * * *
(5) All reports required by this
subpart not subject to the requirements
in paragraphs (f)(1) through (4) of this
section must be sent to the
Administrator at the appropriate
address listed in § 63.13. If acceptable to
both the Administrator and the owner or
operator of an EGU, these reports may
be submitted on electronic media. The
Administrator retains the right to
require submittal of reports subject to
paragraphs (f)(1) through (4) of this
section in paper format.
*
*
*
*
*
■ 18. Section 63.10032 is amended by
revising paragraph (f) to read as follows:
§ 63.10031
when?
*
What reports must I submit and
*
*
*
*
*
(c) * * *
(4) Include the date of the most recent
tune-up for each EGU. For the first tuneup, include the date of the burner
inspection if it was delayed.
(5) Should you choose to rely on
paragraph (2) of the definition of
‘‘startup’’ in § 63.10042 for your EGU,
for each instance of startup or shutdown
you shall:
(i) Include the maximum clean fuel
storage capacity and the maximum
hourly heat input that can be provided
for each clean fuel determined
according to the requirements of
§ 63.10032(f).
(ii) Include the information required
to be monitored, collected, or recorded
according to the requirements of
§ 63.10020(e).
(iii) If you choose to use CEMS to
demonstrate compliance with numerical
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§ 63.10032
What records must I keep?
*
*
*
*
(f) Regarding startup periods or
shutdown periods:
(1) Should you choose to rely on
paragraph (1) of the definition of
‘‘startup’’ in § 63.10042 for your EGU,
you must keep records of the occurrence
and duration of each startup or
shutdown.
(2) Should you choose to rely on
paragraph (2) of the definition of
‘‘startup’’ in § 63.10042 for your EGU,
you must keep records of:
(i) The determination of the maximum
clean fuel capacity for each EGU;
(ii) The determination of the
maximum hourly clean fuel heat input
and of the hourly clean fuel heat input
for each EGU; and
(iii) The information required in
§ 63.10020(e).
*
*
*
*
*
■ 19. Section 63.10042 is amended by:
■ a. Revising the definitions of ‘‘Coalfired electric utility steam generating
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Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
unit,’’ ‘‘Coal refuse,’’ ‘‘Fossil fuel-fired,’’
‘‘Integrated gasification combined cycle
electric utility steam generating unit or
IGCC,’’ ‘‘Limited-use liquid oil-fired
subcategory,’’ and ‘‘Natural gas-fired
electric utility steam generating unit’’;
■ b. Adding, in alphabetical order, a
definition of ‘‘Neural network or neural
net’’; and
■ c. Revising the definition of ‘‘Oil-fired
electric utility steam generating unit.’’
The revisions and additions read as
follows:
§ 63.10042
subpart?
What definitions apply to this
*
*
*
*
*
Coal-fired electric utility steam
generating unit means an electric utility
steam generating unit meeting the
definition of ‘‘fossil fuel-fired’’ that
burns coal for more than 10.0 percent of
the average annual heat input during the
3 previous calendar years after the
compliance date for your facility in
§ 63.9984 or for more than 15.0 percent
of the annual heat input during any one
of those calendar years. EGU owners
and operators must estimate coal, oil,
and natural gas usage for the first 3
calendar years after the applicable
compliance date and they are solely
responsible for assuring compliance
with this final rule or other applicable
standard based on their fuel usage
projections.
Coal refuse means waste products of
coal mining, physical coal cleaning, and
coal preparation operations (e.g. culm,
gob, etc.) containing coal, matrix
material, clay, and other organic and
inorganic material.
*
*
*
*
*
Fossil fuel-fired means an electric
utility steam generating unit (EGU) that
is capable of combusting more than 25
MW of fossil fuels. To be ‘‘capable of
combusting’’ fossil fuels, an EGU would
need to have these fuels allowed in its
operating permit and have the
appropriate fuel handling facilities onsite or otherwise available (e.g., coal
handling equipment, including coal
storage area, belts and conveyers,
pulverizers, etc.; oil storage facilities). In
addition, fossil fuel-fired means any
EGU that fired fossil fuels for more than
10.0 percent of the average annual heat
input during the 3 previous calendar
years after the compliance date for your
facility in § 63.9984 or for more than
15.0 percent of the annual heat input
during any one of those calendar years.
EGU owners and operators must
estimate coal, oil, and natural gas usage
for the first 3 calendar years after the
applicable compliance date and they are
solely responsible for assuring
compliance with this final rule or other
applicable standard based on their fuel
usage projections.
*
*
*
*
*
Integrated gasification combined
cycle electric utility steam generating
unit or IGCC means an electric utility
steam generating unit meeting the
definition of ‘‘fossil fuel-fired’’ that
burns a synthetic gas derived from coal
and/or solid oil-derived fuel for more
than 10.0 percent of the average annual
heat input during the 3 previous
calendar years after the compliance date
for your facility in § 63.9984 or for more
than 15.0 percent of the annual heat
input during any one of those calendar
years in a combined-cycle gas turbine.
EGU owners and operators must
estimate coal, oil, and natural gas usage
for the first 3 calendar years after the
applicable compliance date and they are
solely responsible for assuring
compliance with this final rule or other
applicable standard based on their fuel
usage projections. No solid coal or solid
oil-derived fuel is directly burned in the
unit during operation.
*
*
*
*
*
Limited-use liquid oil-fired
subcategory means an oil-fired electric
utility steam generating unit with an
annual capacity factor when burning oil
of less than 8 percent of its maximum
or nameplate heat input, whichever is
greater, averaged over a 24-month block
contiguous period commencing April
16, 2015.
*
*
*
*
*
Natural gas-fired electric utility steam
generating unit means an electric utility
steam generating unit meeting the
definition of ‘‘fossil fuel-fired’’ that is
not a coal-fired, oil-fired, or IGCC
electric utility steam generating unit and
that burns natural gas for more than 10.0
percent of the average annual heat input
during the 3 previous calendar years
after the compliance date for your
facility in § 63.9984 or for more than
15.0 percent of the annual heat input
during any one of those calendar years.
EGU owners and operators must
estimate coal, oil, and natural gas usage
for the first 3 calendar years after the
applicable compliance date and they are
solely responsible for assuring
compliance with this final rule or other
applicable standard based on their fuel
usage projections.
*
*
*
*
*
Neural network or neural net for
purposes of this rule means an
automated boiler optimization system.
A neural network typically has the
ability to process data from many inputs
to develop, remember, update, and
enable algorithms for efficient boiler
operation.
*
*
*
*
*
Oil-fired electric utility steam
generating unit means an electric utility
steam generating unit meeting the
definition of ‘‘fossil fuel-fired’’ that is
not a coal-fired electric utility steam
generating unit and that burns oil for
more than 10.0 percent of the average
annual heat input during the 3 previous
calendar years after the compliance date
for your facility in § 63.9984 or for more
than 15.0 percent of the annual heat
input during any one of those calendar
years.
*
*
*
*
*
■ 20. Revise Table 1 to subpart UUUUU
of part 63 to read as follows:
TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS
[As stated in § 63.9991, you must comply with the following applicable emission limits:]
tkelley on DSK3SPTVN1PROD with PROPOSALS3
If your EGU is in this
subcategory . . .
For the following pollutants . . .
You must meet the following
emission limits and work practice
standards . . .
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5 to Subpart UUUUU of
Part 63—Performance Testing
Requirements . . .
1. Coal-fired unit not low rank virgin coal.
a.
9.0E–2 lb/MWh 1 ...........................
Collect a minimum of 4 dscm per
run.
19:45 Feb 13, 2015
OR
6.0E–2 lb/GWh .............................
OR
VerDate Sep<11>2014
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
OR
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Collect a minimum of 4 dscm per
run.
17FEP3
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8459
TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits:]
For the following pollutants . . .
.......................................................
Collect a minimum of 3 dscm per
run.
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
8.0E–3
3.0E–3
6.0E–4
4.0E–4
7.0E–3
2.0E–3
2.0E–2
4.0E–3
4.0E–2
5.0E–2
1.0E–2
OR
Sulfur dioxide (SO2) 3 ...................
c. Mercury (Hg) .............................
2. Coal-fired units low rank virgin
coal.
You must meet the following
emission limits and work practice
standards . . .
Individual HAP metals: .................
If your EGU is in this
subcategory . . .
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5 to Subpart UUUUU of
Part 63—Performance Testing
Requirements . . .
1.0 lb/MWh ...................................
3.0E–3 lb/GWh .............................
SO2 CEMS.
Hg CEMS or sorbent trap monitoring system only.
a.
9.0E–2 lb/MWh 1 ...........................
Collect a minimum of 4 dscm per
run.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
tkelley on DSK3SPTVN1PROD with PROPOSALS3
8.0E–3
3.0E–3
6.0E–4
4.0E–4
7.0E–3
2.0E–3
2.0E–2
4.0E–3
4.0E–2
5.0E–2
1.0E–2
OR
Sulfur dioxide (SO2) 3 ...................
c. Mercury (Hg) .............................
1.0 lb/MWh ...................................
4.0E–2 lb/GWh .............................
SO2 CEMS.
Hg CEMS or sorbent trap monitoring system only.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
7.0E–2 lb/MWh 4 ...........................
9.0E–2 lb/MWh 5 ...........................
OR
4.0E–1 lb/GWh .............................
Collect a minimum of 1 dscm per
run.
OR
Individual HAP metals: .................
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
19:45 Feb 13, 2015
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
VerDate Sep<11>2014
OR
6.0E–2 lb/GWh .............................
OR
Individual HAP metals: .................
3. IGCC unit ...................................
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
2.0E–2
2.0E–2
1.0E–3
2.0E–3
4.0E–2
4.0E–3
9.0E–3
a.
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lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
Collect a minimum of 4 dscm per
run.
Collect a minimum of 3 dscm per
run.
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 2 dscm per
run.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
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TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits:]
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5 to Subpart UUUUU of
Part 63—Performance Testing
Requirements . . .
For the following pollutants . . .
matter
3.0E–1 lb/MWh 1 ...........................
Collect a minimum of 1 dscm per
run.
OR
2.0E–4 lb/MWh .............................
OR
Collect
run.
1.0E–2
3.0E–3
5.0E–4
2.0E–4
2.0E–2
3.0E–2
8.0E–3
2.0E–2
9.0E–2
2.0E–2
1.0E–4
b. Hydrogen chloride (HCl) ...........
4.0E–4 lb/MWh .............................
c. Hydrogen fluoride (HF) .............
4.0E–4 lb/MWh .............................
a.
matter
2.0E–1 lb/MWh 1 ...........................
OR
Total HAP metals .........................
tkelley on DSK3SPTVN1PROD with PROPOSALS3
a.
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
Mercury (Hg) .................................
OR
7.0E–3 lb/MWh .............................
OR
Individual HAP metals: .................
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
19:45 Feb 13, 2015
SO2 CEMS.
Hg CEMS or sorbent trap monitoring system only.
OR
Individual HAP metals: .................
VerDate Sep<11>2014
4.0E–1 lb/MWh .............................
3.0E–3 lb/GWh .............................
OR
Total HAP metals .........................
5. Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units).
2.0E–2
7.0E–2
3.0E–1
2.0E–3
OR
Sulfur dioxide (SO2) 3 ...................
c. Mercury (Hg) .............................
4. Liquid oil-fired unit—continental
(excluding limited-use liquid oilfired subcategory units).
You must meet the following
emission limits and work practice
standards . . .
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
If your EGU is in this
subcategory . . .
8.0E–3
6.0E–2
2.0E–3
2.0E–3
2.0E–2
3.0E–1
Filterable
(PM).
Filterable
(PM).
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particulate
Frm 00020
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lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
Collect a minimum of 2 dscm per
run.
a minimum of 2 dscm per
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh .............................
For Method 30B sample volume
determination (Section 8.2.4),
the estimated Hg concentration
should nominally be <1⁄2 the
standard.
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 3 dscm per
run.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
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Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
8461
TABLE 1 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR NEW OR RECONSTRUCTED EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits:]
For the following pollutants . . .
3.0E–2 lb/GWh.
1.0E–1 lb/GWh.
4.1E0 lb/GWh.
2.0E–2 lb/GWh.
4.0E–4 lb/GWh .............................
b. Hydrogen chloride (HCl) ...........
2.0E–3 lb/MWh .............................
c. Hydrogen fluoride (HF) .............
6. Solid oil-derived fuel-fired unit ...
You must meet the following
emission limits and work practice
standards . . .
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
Mercury (Hg) .................................
If your EGU is in this
subcategory . . .
5.0E–4 lb/MWh .............................
a.
3.0E–2 lb/MWh 1 ...........................
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
OR
6.0E–1 lb/GWh .............................
OR
Individual HAP metals: .................
OR
.......................................................
Antimony (Sb) ...............................
Arsenic (As) ..................................
Beryllium (Be) ...............................
Cadmium (Cd) ..............................
Chromium (Cr) ..............................
Cobalt (Co) ...................................
Lead (Pb) ......................................
Manganese (Mn) ..........................
Nickel (Ni) .....................................
Selenium (Se) ...............................
b. Hydrogen chloride (HCl) ...........
8.0E–3
3.0E–3
6.0E–4
7.0E–4
6.0E–3
2.0E–3
2.0E–2
7.0E–3
4.0E–2
6.0E–3
4.0E–4
OR
Sulfur dioxide (SO2) 3 ...................
c. Mercury (Hg) .............................
1.0 lb/MWh ...................................
2.0E–3 lb/GWh .............................
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/GWh.
lb/MWh .............................
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5 to Subpart UUUUU of
Part 63—Performance Testing
Requirements . . .
For Method 30B sample volume
determination (Section 8.2.4),
the estimated Hg concentration
should nominally be <1⁄2 the
standard.
For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 3 dscm per
run.
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 2 or Method
320, sample for a minimum of 1
hour.
SO2 CEMS.
Hg CEMS or Sorbent trap monitoring system only.
1 Gross
output.
by reference, see § 63.14.
3 You may not use the alternate SO limit if your EGU does not have some form of FGD system (or, in the case of IGCC EGUs, some other
2
acid gas removal system either upstream or downstream of the combined cycle block) and SO2 CEMS installed.
4 Duct burners on syngas; gross output.
5 Duct burners on natural gas; gross output.
tkelley on DSK3SPTVN1PROD with PROPOSALS3
2 Incorporated
21. Revise Table 2 to subpart UUUUU
of part 63 to read as follows:
■
VerDate Sep<11>2014
19:45 Feb 13, 2015
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Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS
[As stated in § 63.9991, you must comply with the following applicable emission limits: 1]
If your EGU is in this
subcategory . . .
For the following pollutants . . .
1. Coal-fired unit not low rank virgin coal.
a.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
OR
Individual HAP metals: .................
Antimony (Sb) ........................
Arsenic (As) ...........................
Beryllium (Be) ........................
Cadmium (Cd) .......................
Chromium (Cr) .......................
Cobalt (Co) ............................
Lead (Pb) ...............................
Manganese (Mn) ...................
Nickel (Ni) ..............................
Selenium (Se) ........................
b. Hydrogen chloride (HCl) ...........
OR
Sulfur dioxide (SO2) 4 ...................
c. Mercury (Hg) .............................
You must meet the following
emission limits and work practice
standards . . .
3.0E–2 lb/MMBtu or 3.0E–1 lb/
MWh 2.
OR
5.0E–5 lb/MMBtu or 5.0E–1 lb/
GWh.
OR
.......................................................
8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.
1.1E0 lb/TBtu or 2.0E–2 lb/GWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 3.0E–3 lb/GWh.
2.8E0 lb/TBtu or 3.0E–2 lb/GWh.
8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.
1.2E0 lb/TBtu or 2.0E–2 lb/GWh.
4.0E0 lb/TBtu or 5.0E–2 lb/GWh.
3.5E0 lb/TBtu or 4.0E–2 lb/GWh.
5.0E0 lb/TBtu or 6.0E–2 lb/GWh.
2.0E–3 lb/MMBtu or 2.0E–2 lb/
MWh.
2.0E–1 lb/MMBtu or 1.5E0 lb/
MWh.
1.2E0 lb/TBtu or 1.3E–2 lb/GWh ..
OR
1.0E0 lb/TBtu or 1.1E–2 lb/GWh ..
2. Coal-fired unit low rank virgin
coal.
a.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
tkelley on DSK3SPTVN1PROD with PROPOSALS3
OR
Individual HAP metals: .................
Antimony (Sb) ........................
Arsenic (As) ...........................
Beryllium (Be) ........................
Cadmium (Cd) .......................
Chromium (Cr) .......................
Cobalt (Co) ............................
Lead (Pb) ...............................
Manganese (Mn) ...................
Nickel (Ni) ..............................
Selenium (Se) ........................
b. Hydrogen chloride (HCl) ...........
3.0E–2 lb/MMBtu or 3.0E–1 lb/
MWh 2.
OR
5.0E–5 lb/MMBtu or 5.0E–1 lb/
GWh.
OR
.......................................................
8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.
1.1E0 lb/TBtu or 2.0E–2 lb/GWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 3.0E–3 lb/GWh.
2.8E0 lb/TBtu or 3.0E–2 lb/GWh.
8.0E–1 lb/TBtu or 8.0E–3 lb/GWh.
1.2E0 lb/TBtu or 2.0E–2 lb/GWh.
4.0E0 lb/TBtu or 5.0E–2 lb/GWh.
3.5E0 lb/TBtu or 4.0E–2 lb/GWh.
5.0E0 lb/TBtu or 6.0E–2 lb/GWh.
2.0E–3 lb/MMBtu or 2.0E–2 lb/
MWh.
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5 to Subpart UUUUU of
Part 63—Performance Testing
Requirements . . .
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 3 dscm per
run.
For Method 26A, collect a minimum of 0.75 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
SO2 CEMS.
LEE Testing for 30 days with 10
days maximum per Method 30B
run or Hg CEMS or sorbent trap
monitoring system only.
LEE Testing for 90 days with 10
days maximum per Method 30B
run or Hg CEMS or sorbent trap
monitoring system only.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 3 dscm per
run.
For Method 26A, collect a minimum of 0.75 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
OR
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17FEP3
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
8463
TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits: 1]
If your EGU is in this
subcategory . . .
For the following pollutants . . .
Sulfur dioxide (SO2) 4 ...................
c. Mercury (Hg) .............................
3. IGCC unit ...................................
a.
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
OR
Individual HAP metals: .................
You must meet the following
emission limits and work practice
standards . . .
2.0E–1 lb/MMBtu or 1.5E0 lb/
MWh.
4.0E0 lb/TBtu or 4.0E–2 lb/GWh ..
4.0E–2 lb/MMBtu or 4.0E–1 lb/
MWh 2.
OR
6.0E–5 lb/MMBtu or 5.0E–1 lb/
GWh.
OR
.......................................................
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5 to Subpart UUUUU of
Part 63—Performance Testing
Requirements . . .
SO2 CEMS.
LEE Testing for 30 days with 10
days maximum per Method 30B
run or Hg CEMS or sorbent trap
monitoring system only.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 2 dscm per
run.
Antimony (Sb) ........................
Arsenic (As) ...........................
Beryllium (Be) ........................
Cadmium (Cd) .......................
Chromium (Cr) .......................
Cobalt (Co) ............................
Lead (Pb) ...............................
Manganese (Mn) ...................
Nickel (Ni) ..............................
Selenium (Se) ........................
b. Hydrogen chloride (HCl) ...........
c. Mercury (Hg) .............................
tkelley on DSK3SPTVN1PROD with PROPOSALS3
matter
3.0E–2 lb/MMBtu or 3.0E–1 lb/
MWh 2.
Collect a minimum of 1 dscm per
run.
OR
8.0E–4 lb/MMBtu or 8.0E–3 lb/
MWh.
OR
.......................................................
Collect a minimum of 1 dscm per
run.
Antimony (Sb) ........................
Arsenic (As) ...........................
Beryllium (Be) ........................
Cadmium (Cd) .......................
Chromium (Cr) .......................
Cobalt (Co) ............................
Lead (Pb) ...............................
Manganese (Mn) ...................
Nickel (Ni) ..............................
Selenium (Se) ........................
Mercury (Hg) .........................
1.3E+1 lb/TBtu or 2.0E–1 lb/GWh.
2.8E0 lb/TBtu or 3.0E–2 lb/GWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 2.0E–3 lb/GWh.
5.5E0 lb/TBtu or 6.0E–2 lb/GWh.
2.1E+1 lb/TBtu or 3.0E–1 lb/GWh.
8.1E0 lb/TBtu or 8.0E–2 lb/GWh.
2.2E+1 lb/TBtu or 3.0E–1 lb/GWh.
1.1E+2 lb/TBtu or 1.1E0 lb/GWh.
3.3E0 lb/TBtu or 4.0E–2 lb/GWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh
b. Hydrogen chloride (HCl) ...........
20:11 Feb 13, 2015
a.
OR
Individual HAP metals: .................
VerDate Sep<11>2014
2.5E0 lb/TBtu or 3.0E–2 lb/GWh ..
OR
Total HAP metals .........................
4. Liquid oil-fired unit—continental
(excluding limited-use liquid oilfired subcategory units).
1.4E0 lb/TBtu or 2.0E–2 lb/GWh.
1.5E0 lb/TBtu or 2.0E–2 lb/GWh.
1.0E–1 lb/TBtu or 1.0E–3 lb/GWh.
1.5E–1 lb/TBtu or 2.0E–3 lb/GWh.
2.9E0 lb/TBtu or 3.0E–2 lb/GWh.
1.2E0 lb/TBtu or 2.0E–2 lb/GWh.
1.9E+2 lb/TBtu or 1.8E0 lb/GWh.
2.5E0 lb/TBtu or 3.0E–2 lb/GWh.
6.5E0 lb/TBtu or 7.0E–2 lb/GWh.
2.2E+1 lb/TBtu or 3.0E–1 lb/GWh.
5.0E–4 lb/MMBtu or 5.0E–3 lb/
MWh.
2.0E–3 lb/MMBtu or 1.0E–2 lb/
MWh.
Filterable
(PM).
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For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
LEE Testing for 30 days with 10
days maximum per Method 30B
run or Hg CEMS or sorbent trap
monitoring system only.
Collect a minimum of 1 dscm per
run.
For Method 30B sample volume
determination (Section 8.2.4),
the estimated Hg concentration
should nominally be <1⁄2 the
standard.
For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
17FEP3
8464
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits: 1]
If your EGU is in this
subcategory . . .
For the following pollutants . . .
You must meet the following
emission limits and work practice
standards . . .
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5 to Subpart UUUUU of
Part 63—Performance Testing
Requirements . . .
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
c. Hydrogen fluoride (HF) .............
OR
6.0E–4 lb/MMBtu or 7.0E–3 lb/
MWh.
OR
.......................................................
Collect a minimum of 1 dscm per
run.
2.2E0 lb/TBtu or 2.0E–2 lb/GWh.
4.3E0 lb/TBtu or 8.0E–2 lb/GWh.
6.0E–1 lb/TBtu or 3.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 3.0E–3 lb/GWh.
3.1E+1 lb/TBtu or 3.0E–1 lb/GWh.
1.1E+2 lb/TBtu or 1.4E0 lb/GWh.
4.9E0 lb/TBtu or 8.0E–2 lb/GWh.
2.0E+1 lb/TBtu or 3.0E–1 lb/GWh.
4.7E+2 lb/TBtu or 4.1E0 lb/GWh.
9.8E0 lb/TBtu or 2.0E–1 lb/GWh.
4.0E–2 lb/TBtu or 4.0E–4 lb/GWh
2.0E–4 lb/MMBtu or 2.0E–3 lb/
MWh.
c. Hydrogen fluoride (HF) .............
6.0E–5 lb/MMBtu or 5.0E–4 lb/
MWh.
a.
OR
Individual HAP metals: .................
tkelley on DSK3SPTVN1PROD with PROPOSALS3
Collect a minimum of 1 dscm per
run.
b. Hydrogen chloride (HCl) ...........
8.0E–3 lb/MMBtu or 9.0E–2 lb/
MWh 2.
OR
4.0E–5 lb/MMBtu or 6.0E–1 lb/
GWh.
OR
.......................................................
Antimony (Sb) ........................
Arsenic (As) ...........................
Beryllium (Be) ........................
Cadmium (Cd) .......................
Chromium (Cr) .......................
Cobalt (Co) ............................
Lead (Pb) ...............................
Manganese (Mn) ...................
Nickel (Ni) ..............................
20:11 Feb 13, 2015
3.0E–2 lb/MMBtu or 3.0E–1 lb/
MWh 2.
Antimony (Sb) ........................
Arsenic (As) ...........................
Beryllium (Be) ........................
Cadmium (Cd) .......................
Chromium (Cr) .......................
Cobalt (Co) ............................
Lead (Pb) ...............................
Manganese (Mn) ...................
Nickel (Ni) ..............................
Selenium (Se) ........................
Mercury (Hg) .........................
VerDate Sep<11>2014
matter
OR
Individual HAP metals: .................
6. Solid oil-derived fuel-fired unit ...
a.
OR
Total HAP metals .........................
5. Liquid oil-fired unit—non-continental (excluding limited-use liquid oil-fired subcategory units).
4.0E–4 lb/MMBtu or 4.0E–3 lb/
MWh.
8.0E–1 lb/TBtu or 7.0E–3 lb/GWh.
3.0E–1 lb/TBtu or 5.0E–3 lb/GWh.
6.0E–2 lb/TBtu or 5.0E–4 lb/GWh.
3.0E–1 lb/TBtu or 4.0E–3 lb/GWh.
8.0E–1 lb/TBtu or 2.0E–2 lb/GWh.
1.1E0 lb/TBtu or 2.0E–2 lb/GWh.
8.0E–1 lb/TBtu or 2.0E–2 lb/GWh.
2.3E0 lb/TBtu or 4.0E–2 lb/GWh.
9.0E0 lb/TBtu or 2.0E–1 lb/GWh.
Filterable
(PM).
particulate
Filterable particulate matter
(PM).
OR
Total non-Hg HAP metals ............
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Collect a minimum of 2 dscm per
run.
For Method 30B sample volume
determination (Section 8.2.4),
the estimated Hg concentration
should nominally be <1⁄2 the
standard.
For Method 26A, collect a minimum of 1 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 2
hours.
For Method 26A, collect a minimum of 3 dscm per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 2
hours.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 1 dscm per
run.
Collect a minimum of 3 dscm per
run.
17FEP3
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
8465
TABLE 2 TO SUBPART UUUUU OF PART 63—EMISSION LIMITS FOR EXISTING EGUS—Continued
[As stated in § 63.9991, you must comply with the following applicable emission limits: 1]
For the following pollutants . . .
You must meet the following
emission limits and work practice
standards . . .
Selenium (Se) ........................
b. Hydrogen chloride (HCl) ...........
If your EGU is in this
subcategory . . .
1.2E0 lb/Tbtu or 2.0E–2 lb/GWh.
5.0E–3 lb/MMBtu or 8.0E–2 lb/
MWh.
OR
Sulfur dioxide (SO2) 4 ...................
c. Mercury (Hg) .............................
3.0E–1 lb/MMBtu or 2.0E0 lb/
MWh.
2.0E–1 lb/TBtu or 2.0E–3 lb/GWh
Using these requirements, as appropriate (e.g., specified sampling
volume or test run duration) and
limitations with the test methods
in Table 5 to Subpart UUUUU of
Part 63—Performance Testing
Requirements . . .
For Method 26A, collect a minimum of 0.75 dscm per run; for
Method 26, collect a minimum
of 120 liters per run.
For ASTM D6348–03 3 or Method
320, sample for a minimum of 1
hour.
SO2 CEMS.
LEE Testing for 30 days with 10
days maximum per Method 30B
run or Hg CEMS or Sorbent
trap monitoring system only.
1 For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required minimum sampling volume must
be increased nominally by a factor of two.
2 Gross output.
3 Incorporated by reference, see § 63.14.
4 You may not use the alternate SO limit if your EGU does not have some form of FGD system and SO CEMS installed.
2
2
22. Revise Table 3 to subpart UUUUU
of part 63 to read as follows:
■
TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS
[As stated in § 63.9991, you must comply with the following applicable work practice standards:]
You must meet the following . . .
1. An existing EGU ......
Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar
months if neural network combustion optimization software is employed, as specified in § 63.10021(e).
2. A new or reconstructed EGU.
Conduct a tune-up of the EGU burner and combustion controls at least each 36 calendar months, or each 48 calendar
months if neural network combustion optimization software is employed, as specified in § 63.10021(e).
3. A coal-fired, liquid
oil-fired (excluding
limited-use liquid oilfired subcategory
units), or solid oil-derived fuel-fired EGU
during startup.
tkelley on DSK3SPTVN1PROD with PROPOSALS3
If your EGU is . . .
You have the option of complying using either of the following work practice standards:
(1) If you choose to comply using paragraph (1) of the definition of ‘‘startup’’ in § 63.10042, you must operate all
CMS during startup. Startup means either the first-ever firing of fuel in a boiler for the purpose of producing
electricity, or the firing of fuel in a boiler after a shutdown event for any purpose. Startup ends when any of the
steam from the boiler is used to generate electricity for sale over the grid or for any other purpose (including on
site use). For startup of a unit, you must use clean fuels as defined in § 63.10042 for ignition. Once you convert
to firing coal, residual oil, or solid oil-derived fuel, you must engage all of the applicable control technologies except dry scrubber and SCR. You must start your dry scrubber and SCR systems, if present, appropriately to
comply with relevant standards applicable during normal operation. You must comply with all applicable emissions limits at all times except for periods that meet the applicable definitions of startup and shutdown in this
subpart. You must keep records during startup periods. You must provide reports concerning activities and
startup periods, as specified in § 63.10011(g) and § 63.10021(h) and (i).
(2) If you choose to comply using paragraph (2) of the definition of ‘‘startup’’ in § 63.10042, you must operate all
CMS during startup. You must also collect appropriate data, and you must calculate the pollutant emission rate
for each hour of startup.
For startup of an EGU, you must use one or a combination of the clean fuels defined in § 63.10042 to the maximum
extent practicable, taking into account considerations such as boiler or control device integrity, throughout the startup period. You must have sufficient clean fuel capacity to engage and operate your PM control device within one
hour of adding coal, residual oil, or solid oil-derived fuel to the unit. You must meet the startup period work practice
requirements as identified in § 63.10020(e).
Once you start firing coal, residual oil, or solid oil-derived fuel, you must vent emissions to the main stack(s). You must
comply with the applicable emission limits within 4 hours of start of electricity generation. You must engage and operate your particulate matter control(s) within 1 hour of first firing of coal, residual oil, or solid oil-derived fuel.
You must start all other applicable control devices as expeditiously as possible, considering safety and manufacturer/
supplier recommendations, but, in any case, when necessary to comply with other standards made applicable to the
EGU by a permit limit or a rule other than this Subpart that require operation of the control devices.
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20:11 Feb 13, 2015
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17FEP3
8466
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
TABLE 3 TO SUBPART UUUUU OF PART 63—WORK PRACTICE STANDARDS—Continued
[As stated in § 63.9991, you must comply with the following applicable work practice standards:]
If your EGU is . . .
You must meet the following . . .
Relative to the syngas not fired in the combustion turbine of an IGCC EGU during startup, you must either: (1) Flare
the syngas, or (2) route the syngas to duct burners, which may need to be installed, and route the flue gas from the
duct burners to the heat recovery steam generator.
You must collect monitoring data during startup periods, as specified in § 63.10020(a) and (e). You must keep records
during startup periods, as provided in §§ 63.10032 and 63.10021(h). Any fraction of an hour in which startup occurs
constitutes a full hour of startup. You must provide reports concerning activities and startup periods, as specified in
§§ 63.10011(g), 63.10021(i), and 63.10031.
4. A coal-fired, liquid
oil-fired (excluding
limited-use liquid oilfired subcategory
units), or solid oil-derived fuel-fired EGU
during shutdown.
You must operate all CMS during shutdown. You must also collect appropriate data, and you must calculate the pollutant emission rate for each hour of shutdown.
While firing coal, residual oil, or solid oil-derived fuel during shutdown, you must vent emissions to the main stack(s)
and operate all applicable control devices and continue to operate those control devices after the cessation of coal,
residual oil, or solid oil-derived fuel being fed into the EGU and for as long as possible thereafter considering operational and safety concerns. In any case, you must operate your controls when necessary to comply with other
standards made applicable to the EGU by a permit limit or a rule other than this Subpart and that require operation
of the control devices.
If, in addition to the fuel used prior to initiation of shutdown, another fuel must be used to support the shutdown process, that additional fuel must be one or a combination of the clean fuels defined in § 63.10042 and must be used to
the maximum extent practicable.
Relative to the syngas not fired in the combustion turbine of an IGCC EGU during shutdown, you must either: (1) Flare
the syngas, or (2) route the syngas to duct burners, which may need to be installed, and route the flue gas from the
duct burners to the heat recovery steam generator.
You must comply with all applicable emission limits at all times except during startup periods and shutdown periods at
which time you must meet this work practice. You must collect monitoring data during shutdown periods, as specified in § 63.10020(a). You must keep records during shutdown periods, as provided in §§ 63.10032 and 63.10021(h).
Any fraction of an hour in which shutdown occurs constitutes a full hour of shutdown. You must provide reports concerning activities and shutdown periods, as specified in §§ 63.10011(g), 63.10021(i), and 63.10031.
23. Revise Table 4 to subpart UUUUU
of part 63 to read as follows:
■
TABLE 4 TO SUBPART UUUUU OF PART 63—OPERATING LIMITS FOR EGUS
[As stated in § 63.9991, you must comply with the applicable operating limits:]
If you demonstrate
compliance using . . .
You must meet these operating limits . . .
PM CPMS ....................
Maintain the 30-boiler operating day rolling average PM CPMS output determined in accordance with the requirements
of § 63.10023(b)(2) and obtained during the most recent performance test run demonstrating compliance with the filterable PM, total non-mercury HAP metals (total HAP metals, for liquid oil-fired units), or individual non-mercury
HAP metals (individual HAP metals including Hg, for liquid oil-fired units) emissions limitation(s).
24. Revise Table 5 to subpart UUUUU
of part 63 to read as follows:
tkelley on DSK3SPTVN1PROD with PROPOSALS3
■
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19:45 Feb 13, 2015
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VerDate Sep<11>2014
Table 5 to Subpart UUUUU of Part 63 - Performance Testing Requirements
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To conduct a
performance
test for the~Using ...
following
pollutant
You must perform
the following
activities, as
~Using
applicable to
your input- or
output-based
emission limit
1.
!!Emissions
Filterable
Testing
Particulate
matter (PM)
a. Select
IIMethod 1 at Appendix A-1 to Part 60 of this
sampling ports
chapter.
location and the
number of
traverse points.
2
17FEP3
b. Determine
Method 2, 2A, 2C, 2F, 2G or 2H at Appendix A-1 or
velocity and
A-2 to Part 60 of this chapter.
!
volumetric flowrate of the
stack gas.
c. Determine
oxygen and
carbon dioxide
concentrations
of the stack
gas.
Method 3A or 3B at Appendix A-2 to Part 60 of
this chapter, or ANSI/ASME PTC 19.10-1981. 3
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
19:45 Feb 13, 2015
As stated in§ 63.10007, you must comply with the following requirements for performance
testing for existing, new or reconstructed affected sources: 1
8467
EP17FE15.006</GPH>
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8468
VerDate Sep<11>2014
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e. Measure the
filterable PM
concentration.
PO 00000
I
Frm 00028
I
I
Method 5 at Appendix A-3 to Part 60 of this
chapter. When using Method 5, use the average of
the final 2 filter weightings.
!For positive pressure fabric filters, Method SD
at Appendix A-3 to Part 60 of this chapter for
filterable PM emissions.
!Note that the Method 5 front half temperature
shall be 160° ± 14°C (320° ± 25°F).
Fmt 4701
Method 19 F-factor methodology at Appendix A-7 to
Part 60 of this chapter, or calculate using mass
emissions rate and electrical output data (see §
63.10007(e)).
loR
l oR
I
PM CEMS
a. Install,
certify,
operate, and
maintain the PM
CEMS.
Performance Specification 11 at Appendix B to
Part 60 of this chapter and Procedure 2 at
Appendix F to Part 60 of this chapter.
b. Install,
certify,
operate, and
maintain the
diluent gas,
Part 75 of this chapter and
(c), and (d).
Sfmt 4725
f. Convert
emissions
concentration to
lb/MMBtu or
lb/MWh emissions
rates.
E:\FR\FM\17FEP3.SGM
17FEP3
EP17FE15.007</GPH>
§§
63.10010 (a),
(b),
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
19:45 Feb 13, 2015
d. Measure the
Method 4 at Appendix A-3 to Part 60 of this
moisture content chapter.
of the stack
gas.
tkelley on DSK3SPTVN1PROD with PROPOSALS3
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2. Total or
individual
non-Hg HAP
metals
Emissions
Testing
Method 19
F-factor methodology at Appendix A-7 to Part 60
of this chapter, or calculate using mass
emissions rate and electrical output data (see §
63.10007 (e)) .
E:\FR\FM\17FEP3.SGM
a. Select
IIMethod 1 at Appendix A-1 to Part 60 of this
sampling ports
chapter.
location and the
number of
traverse points.
17FEP3
b. Determine
Method 2, 2A, 2C, 2F, 2G or 2H at Appendix A-1 or
velocity and
IA-2 to Part 60 of this chapter.
volumetric flowrate of the
stack gas.
c. Determine
oxygen and
carbon dioxide
concentrations
of the stack
gas.
Method 3A or 3B at Appendix A-2 to Part 60 of
this chapter, or ANSI/ASME PTC 19.10-1981. 3
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
Jkt 235001
c. Convert
hourly emissions
concentrations
to 30 boiler
operating day
rolling average
lb/MMBtu or
lb/MWh emissions
rates.
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19:45 Feb 13, 2015
flow rate,
and/or moisture
monitoring
systems.
8469
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8470
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17FEP3
e. Measure the
HAP metals
emissions
concentrations
and determine
each individual
HAP metals
emissions
concentration,
as well as the
total filterable
HAP metals
emissions
concentration
and total HAP
metals emissions
concentration.
Method 29 at Appendix A-8 to Part 60 of this
chapter. For liquid oil-fired units, Hg is
included in HAP metals and you may use Method 29,
Method 30B at Appendix A-8 to Part 60 of this
chapteri for Method 29, you must report the front
half and back half results separately. When using
Method 29, report metals matrix spike and
recovery levels.
f. Convert
emissions
concentrations
(individual HAP
metals, total
filterable HAP
metals, and
total HAP
metals) to
lb/MMBtu or
lb/MWh emissions
Method 19 F-factor methodology at Appendix A-7 to
Part 60 of this chapter, or calculate using mass
emissions rate and electrical output data (see §
63.10007(e)).
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
19:45 Feb 13, 2015
EP17FE15.009</GPH>
d. Measure the
Method 4 at Appendix A-3 to Part 60 of this
moisture content ~chapter.
of the stack
gas.
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VerDate Sep<11>2014
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3. Hydrogen
chloride
(HCl) and
hydrogen
fluoride
(HF)
Emissions
Testing
a. Select
IIMethod 1 at Appendix A-1 to Part 60 of this
sampling ports
chapter.
location and the
number of
traverse points.
PO 00000
Frm 00031
b. Determine
Method 2, 2A, 2C, 2F, 2G or 2H at Appendix A-1 or
velocity and
A-2 to Part 60 of this chapter.
volumetric flowrate of the
stack gas.
Fmt 4701
Sfmt 4725
E:\FR\FM\17FEP3.SGM
c. Determine
oxygen and
carbon dioxide
concentrations
of the stack
gas.
Method 3A or 3B at Appendix A-2 to Part 60 of
this chapter, or ANSI/ASME PTC 19.10-1981. 3
d. Measure the
Method 4 at Appendix A-3 to Part 60 of this
moisture content ~chapter.
of the stack
gas.
17FEP3
e. Measure the
HCl and HF
emissions
concentrations.
Method 26 or Method 26A at Appendix A-8 to Part
60 of this chapter or Method 320 at Appendix A to
Part 63 of this chapter or ASTM 6348-03 3 with (1)
the following conditions using ASTM D6348-03:
(A) The test plan preparation and implementation
in the Annexes to ASTM D6348-03, Sections Al
through A8 are mandatory; (B) For ASTM D6348-03
Annex A5 (Analyte Spiking Technique) , the percent
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
19:45 Feb 13, 2015
rates.
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PO 00000
...~- d R
(Measured Concentration in Stack)
Frm 00032
%R
x 100
Fmt 4701
and (2)spiking levels nominally no greater than
two times the level corresponding to the
applicable emission limit.
Method 26A must be used if there are entrained
water droplets in the exhaust stream.
Sfmt 4725
E:\FR\FM\17FEP3.SGM
f. Convert
emissions
concentration to
lb/MMBtu or
lb/MWh emissions
rates.
Method 19 F-factor methodology at Appendix A-7 to
Part 60 of this chapter, or calculate using mass
emissions rate and electrical output data (see §
63.10007 (e)) .
17FEP3
II OR
II OR
HCl and/or
HF CEMS
a. Install,
IIAppendix B of this subpart.
certify,
operate, and
maintain the HCl
or HF CEMS.
b. Install,
certify,
EP17FE15.011</GPH>
t
1
esu1, =
Part 75 of this chapter and§§ 63.10010 (a),
(c) , and (d) .
(b),
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
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R epo1 te
19:45 Feb 13, 2015
(%) R must be determined for each target analyte
(see Equation A5.5); (C) For the ASTM D6348-03
test data to be acceptable for a target analyte,
%R must be 70 % ~ R ~ 130%; and (D) The %R value
for each compound must be reported in the test
report and all field measurements corrected with
the calculated %R value for that compound using
the following equation:
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VerDate Sep<11>2014
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PO 00000
c. Convert
hourly emissions
concentrations
to 30 boiler
operating day
rolling average
lb/MMBtu or
lb/MWh emissions
rates.
Frm 00033
Fmt 4701
Sfmt 4725
4. Mercury
(Hg)
Emissions
Testing
Method 19
F-factor methodology at Appendix A-7 to Part 60
of this chapter, or calculate using mass
emissions rate and electrical output data (see §
63.10007 (e)) .
E:\FR\FM\17FEP3.SGM
a. Select
Method 1 at Appendix A-1 to Part 60 of this
sampling ports
chapter or Method 30B at Appendix A-8 for Method
location and the 30B point selection.
number of
traverse points.
17FEP3
b. Determine
Method 2, 2A, 2C, 2F, 2G or 2H at Appendix A-1 or
velocity and
A-2 to Part 60 of this chapter.
volumetric flowrate of the
stack gas.
c. Determine
oxygen and
carbon dioxide
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
19:45 Feb 13, 2015
operate, and
maintain the
diluent gas,
flow rate,
and/or moisture
monitoring
systems.
Method 3A or 3B at Appendix A-1 to Part 60 of
this chapter, or ANSI/ASME PTC 19.10-1981. 3
8473
EP17FE15.012</GPH>
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VerDate Sep<11>2014
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d. Measure the
Method 4 at Appendix A-3 to Part 60 of this
moisture content chapter.
of the stack
gas.
PO 00000
Method 30B at Appendix A-8 to Part 60 of this
chapter, ASTM D6784 3 or Method 29 at Appendix A8 to Part 60 of this chapter; for Method 29, you
must report the front half and back half results
separately.
f. Convert
emissions
concentration to
lb/TBtu or
lb/GWh emission
rates.
Method 19 F-factor methodology at Appendix A-7 to
Part 60 of this chapter, or calculate using mass
emissions rate and electrical output data (see §
63.10007 (e)) .
loR
I oR
I
Hg CEMS
a. Install,
certify,
operate, and
maintain the
CEMS.
Sections 3.2.1 and 5.1 of Appendix A of this
subpart.
b. Install,
certify,
operate, and
maintain the
diluent gas,
Part 75 of this chapter and §§ 63.10010 (a) ,
(c) , and (d) .
Frm 00034
e. Measure the
Hg emission
concentration.
Fmt 4701
Sfmt 4725
E:\FR\FM\17FEP3.SGM
17FEP3
EP17FE15.013</GPH>
I
(b)
1
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
19:45 Feb 13, 2015
concentrations
of the stack
gas.
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Frm 00035
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Sfmt 4725
E:\FR\FM\17FEP3.SGM
17FEP3
lOR
OR
Sorbent
trap
monitoring
system
a. Install,
certify,
operate, and
maintain the
sorbent trap
monitoring
system.
Sections 3.2.2 and 5.2 of Appendix A to this
subpart.
b. Install,
operate, and
maintain the
diluent gas,
flow rate,
and/or moisture
monitoring
systems.
Part 75 of this chapter and §§ 63.10010 (a) ,
(C)
and (d) .
1
(b)
1
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
Jkt 235001
Section 6 of Appendix A to this subpart.
c. Convert
hourly emissions
concentrations
to 30 boiler
operating day
rolling average
lb/TBtu or
lb/GWh emissions
rates.
PO 00000
19:45 Feb 13, 2015
flow rate,
and/or moisture
monitoring
systems.
8475
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OR
Frm 00036
LEE
OR
testing~a.
Fmt 4701
Select
sampling ports
location and the
number of
traverse points.
Single point located at the 10% centroidal area
of the duct at a port location per Method 1 at
!Appendix A-1 to Part 60 of this chapter or Method
30B at Appendix A-8 for Method 30B point
selection.
Sfmt 4725
E:\FR\FM\17FEP3.SGM
Method 2, 2A, 2C, 2F, 2G, or 2H at Appendix A-1
b. Determine
velocity and
or A-2 to Part 60 of this chapter or flow
volumetric flow- monitoring system certified per Appendix A of
rate of the
this subpart.
stack gas.
17FEP3
c. Determine
oxygen and
carbon dioxide
concentrations
of the stack
gas.
Method 3A or 3B at Appendix A-1 to Part 60 of
this chapter, or ANSI/ASME PTC 19.10-1981, 3 or
diluent gas monitoring systems certified
according to Part 75 of this chapter.
d. Measure the
Method 4 at Appendix A-3 to Part 60 of this
moisture content chapter, or moisture monitoring systems certified
of the stack
according to Part 75 of this chapter.
gas.
EP17FE15.015</GPH>
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
19:45 Feb 13, 2015
c. Convert
Section 6 of Appendix A to this subpart.
emissions
concentrations
to 30 boiler
operating day
rolling average
lb/TBtu or
lb/GWh emissions
rates.
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VerDate Sep<11>2014
Jkt 235001
Method 30B at Appendix A-8 to Part 60 of this
chapter; perform a 30 operating day test, with a
maximum of 10 operating days per run (i.e., per
pair of sorbent traps) or sorbent trap monitoring
system or Hg CEMS certified per Appendix A of
this subpart.
PO 00000
f. Convert
Method 19 F-factor methodology at Appendix A-7 to
Part 60 of this chapter, or calculate using mass
emissions
concentrations
emissions rate and electrical output data (see §
63.10007 (e)) .
from the LEE
test to lb/TBtu
or lb/GWh
emissions rates.
Frm 00037
Fmt 4701
Sfmt 4725
g. Convert
Potential maximum annual heat input in TBtu or
average
potential maximum electricity generated in GWh.
lb/TBtu or
lb/GWh Hg
emission rate to
lb/year, if you
are attempting
to meet the 29.0
lb/year
threshold.
E:\FR\FM\17FEP3.SGM
(802)
80 2
CEMS
a. Install,
certify,
operate, and
maintain the
CEMS.
Part 75 of this chapter and§§ 63.10010 (a) and
b. Install,
operate, and
maintain the
17FEP3
5. Sulfur
dioxide
Part 75 of this chapter and §§ 63.10010 (a),
(c), and (d) .
(f) .
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
19:45 Feb 13, 2015
e. Measure the
Hg emission
concentration.
(b),
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8478
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PO 00000
Frm 00038
Fmt 4701
Sfmt 4702
E:\FR\FM\17FEP3.SGM
17FEP3
c. Convert
Method 19 F-factor methodology at Appendix A-7 to
hourly emissions Part 60 of this chapter, or calculate using mass
concentrations
emissions rate and electrical output data (see §
to 30 boiler
63.10007(e)).
operating day
rolling average
lb/MMBtu or
lb/MWh emissions
rates.
1
Regarding emissions data collected during periods of startup or shutdown, see §§
63.10020(b) and (c) and 63.10021(h).
2
See Tables 1 and 2 to this subpart for required sample volumes and/or sampling run
times.
3
Incorporated by reference, see§ 63.14.
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
19:45 Feb 13, 2015
25. Revise Table 6 to subpart UUUUU
of part 63 to read as follows:
■
VerDate Sep<11>2014
EP17FE15.017</GPH>
diluent gas,
flow rate,
and/or moisture
monitoring
systems.
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
8479
TABLE 6 TO SUBPART UUUUU OF PART 63—ESTABLISHING PM CPMS OPERATING LIMITS
[As stated in § 63.10007, you must comply with the following requirements for establishing operating limits:]
If you have an applicable
emission limit for . . .
And you choose to establish PM
CPMS operating limits, you
must . . .
And . . .
Using . . .
According to the
following procedures
. . .
Filterable Particulate
matter (PM), total nonmercury HAP metals,
individual non-mercury
HAP metals, total HAP
metals, or individual
HAP metals for an
EGU.
Install, certify, maintain, and operate
a PM CPMS for monitoring emissions discharged to the atmosphere
according
to
§ 63.10010(h)(1).
Establish a site-specific
operating limit in units
of PM CPMS output
signal (e.g., milliamps,
mg/acm, or other raw
signal).
Data from the PM
CPMS and the PM or
HAP metals performance tests.
1. Collect PM CPMS
output data during the
entire period of the
performance tests.
2. Record the average
hourly PM CPMS output for each test run
in the performance
test.
3. Determine the PM
CPMS operating limit
in accordance with
the requirements of
§ 63.10023(b)(2) from
data obtained during
the performance test
demonstrating compliance with the filterable PM or HAP metals emissions limitations.
26. Revise Table 8 to subpart UUUUU
of part 63 to read as follows:
■
TABLE 8 TO SUBPART UUUUU OF PART 63—REPORTING REQUIREMENTS
[As stated in § 63.10031, you must comply with the following requirements for reports:]
You must submit a
The report must contain . . .
You must submit the report . . .
1. Compliance
report.
a. Information required in § 63.10031(c)(1) through (6); and
Semiannually according to the requirements in § 63.10031(b).
b. If there are no deviations from any emission limitation (emission limit and operating limit) that applies to you and there are no deviations from the requirements for work practice standards in Table 3 to this subpart that apply to you, a
statement that there were no deviations from the emission limitations and work
practice standards during the reporting period. If there were no periods during
which the CMSs, including continuous emissions monitoring system, and operating parameter monitoring systems, were out-of-control as specified in
§ 63.8(c)(7), a statement that there were no periods during which the CMSs
were out-of-control during the reporting period; and
c. If you have a deviation from any emission limitation (emission limit and operating limit) or work practice standard during the reporting period, the report must
contain the information in § 63.10031(d). If there were periods during which the
CMSs, including continuous emissions monitoring systems and continuous parameter monitoring systems, were out-of-control, as specified in § 63.8(c)(7), the
report must contain the information in § 63.10031(e).
27. Revise Table 9 to subpart UUUUU
of part 63 to read as follows:
■
TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU
tkelley on DSK3SPTVN1PROD with PROPOSALS3
[As stated in § 63.10040, you must comply with the applicable General Provisions according to the following:]
Citation
§ 63.1
§ 63.2
§ 63.3
§ 63.4
§ 63.5
Subject
..................................................................
..................................................................
..................................................................
..................................................................
..................................................................
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19:45 Feb 13, 2015
Jkt 235001
Applies to subpart UUUUU
Applicability ......................................................
Definitions ........................................................
Units and Abbreviations ...................................
Prohibited Activities and Circumvention ..........
Preconstruction Review and Notification Requirements.
PO 00000
Frm 00039
Fmt 4701
Sfmt 4702
Yes.
Yes. Additional terms defined in § 63.10042.
Yes.
Yes.
Yes.
E:\FR\FM\17FEP3.SGM
17FEP3
8480
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
TABLE 9 TO SUBPART UUUUU OF PART 63—APPLICABILITY OF GENERAL PROVISIONS TO SUBPART UUUUU—Continued
[As stated in § 63.10040, you must comply with the applicable General Provisions according to the following:]
Citation
Subject
§ 63.6(a), (b)(1) through (5), (b)(7), (c), (f)(2)
and (3), (h)(2) through (9), (i), (j).
§ 63.6(e)(1)(i) ......................................................
Compliance with Standards and Maintenance
Requirements.
General Duty to minimize emissions ...............
§ 63.6(e)(1)(ii) .....................................................
§ 63.6(e)(3) .........................................................
§ 63.6(f)(1) ..........................................................
§ 63.6(h)(1) .........................................................
§ 63.6(g) ..............................................................
§ 63.8(c)(1)(iii) .....................................................
§ 63.8(d)(3) .........................................................
Requirement to correct malfunctions ASAP ....
SSM Plan requirements ...................................
SSM exemption ................................................
SSM exemption ................................................
Compliance with Standards and Maintenance
Requirements, Use of an alternative nonopacity emission standard.
Performance testing .........................................
Monitoring Requirements .................................
General duty to minimize emissions and CMS
operation.
Requirement to develop SSM Plan for CMS ...
Written procedures for CMS ............................
§ 63.9 ..................................................................
Notification Requirements ................................
§ 63.10(a), (b)(1), (c), (d)(1) and—(2), (e), and
(f).
§ 63.10(b)(2)(i) ....................................................
Recordkeeping and Reporting Requirements
§ 63.7(e)(1) .........................................................
§ 63.8 ..................................................................
§ 63.8(c)(1)(i) ......................................................
§ 63.10(b)(2)(ii) ...................................................
§ 63.10(b)(2)(iii) ..................................................
§ 63.10(b)(2)(iv) ..................................................
Applies to subpart UUUUU
Recordkeeping of occurrence and duration of
startups and shutdowns.
Recordkeeping of malfunctions .......................
§ 63.10(c)(10) .....................................................
Maintenance records .......................................
Actions taken to minimize emissions during
SSM.
Actions taken to minimize emissions during
SSM.
Recordkeeping for CMS malfunctions .............
Other CMS requirements .................................
..........................................................................
Additional recordkeeping requirements for
CMS—identifying exceedances and excess
emissions.
Additional recordkeeping requirements for
CMS—identifying exceedances and excess
emissions.
Recording nature and cause of malfunctions ..
§ 63.10(c)(11) .....................................................
Recording corrective actions ...........................
§ 63.10(c)(15) .....................................................
§ 63.10(d)(5) .......................................................
Use of SSM Plan .............................................
SSM reports .....................................................
§ 63.11 ................................................................
§ 63.12 ................................................................
§§ 63.13 through—63.16 ....................................
Control Device Requirements ..........................
State Authority and Delegation ........................
Addresses, Incorporation by Reference, Availability of Information, Performance Track
Provisions.
Reserved ..........................................................
§ 63.10(b)(2)(v) ...................................................
§ 63.10(b)(2)(vi) ..................................................
§ 63.10(b)(2)(vii) through—(ix) ............................
§ 63.10(b)(3),and (d)(3) through—(5) .................
§ 63.10(c)(7) .......................................................
§ 63.10(c)(8) .......................................................
tkelley on DSK3SPTVN1PROD with PROPOSALS3
§§ 63.1(a)(5),(a)(7) through—(9), (b)(2), (c)(3)
and—(4), (d), 63.6(b)(6), (c)(3) and ), (c)(4),
(d), (e)(2), (e)(3)(ii), (h)(3), (h)(5)(iv),
63.8(a)(3), 63.9(b)(3), (h)(4), 63.10(c)(2)
through—(4), (c)(9).
28. Appendix A to subpart UUUUU of
part 63 is amended by:
■ a. Revising paragraph 3.2.1.2.1;
■ b. Revising paragraphs 4.1.1.1, 4.1.1.3,
4.1.1.5, and 4.1.1.5.2;
■ c. Revising Tables A–1 and A–2;
■
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19:45 Feb 13, 2015
Jkt 235001
d. Revising paragraphs 5.1.2.1, 5.1.2.3,
and 5.2.1; and
■ e. Adding paragraph 6.2.2.3 and
7.1.2.6.
The revisions and additions to read as
follows:
■
PO 00000
Frm 00040
Fmt 4701
Sfmt 4702
Yes.
No. See § 63.10000(b) for general duty requirement.
No.
No.
No.
No.
Yes.
See
§§ 63.10011(g)(4)
and
63.10021(h)(4) for additional requirements.
No. See § 63.10007.
Yes.
No. See § 63.10000(b) for general duty requirement.
No.
Yes, except for last sentence, which refers to
an SSM plan. SSM plans are not required.
Yes, except for the 60-day notification prior to
conducting a performance test in § 63.9(d);
instead use a 30-day notification period per
§ 63.10030(d).
Yes, except for the requirements to submit
written reports under § 63.10(e)(3)(v).
No.
No. See § 63.10001 for recordkeeping of (1)
occurrence and duration and (2) actions
taken during malfunction.
Yes.
No.
No.
Yes.
Yes.
No.
Yes.
Yes.
No. See § 63.10032(g) and (h) for malfunctions recordkeeping requirements.
No. See § 63.10032(g) and (h) for malfunctions recordkeeping requirements.
No.
No. See § 63.10021(h) and (i) for malfunction
reporting requirements.
No.
Yes.
Yes.
No.
Appendix A to Subpart UUUUU of Part
63—Hg Monitoring Provisions
*
*
*
*
*
3. Mercury Emissions Measurement Methods
*
E:\FR\FM\17FEP3.SGM
*
*
17FEP3
*
*
Federal Register / Vol. 80, No. 31 / Tuesday, February 17, 2015 / Proposed Rules
3.2.1.2.1 NIST Traceability. Only NISTcertified or NIST-traceable calibration gas
standards and reagents (as defined in
paragraphs 3.1.4 and 3.1.5 of this appendix),
and including, but not limited to, Hg gas
generators and Hg gas cylinders, shall be
used for the tests and procedures required
under this subpart. Calibration gases with
known concentrations of Hg0 and HgCl2 are
required. Special reagents and equipment
may be needed to prepare the Hg0 and HgCl2
gas standards (e.g., NIST-traceable solutions
of HgCl2 and gas generators equipped with
mass flow controllers).
*
*
*
*
*
4. Certification and Recertification
Requirements
*
*
*
*
*
4.1.1.1 7-Day Calibration Error Test.
Perform the 7-day calibration error test on 7
consecutive source operating days, using a
zero-level gas and either a high-level or a
mid-level calibration gas standard (as defined
in sections 3.1.8, 3.1.10, and 3.1.11 of this
appendix). Use a NIST-traceable elemental
Hg gas standard (as defined in section 3.1.4
of this appendix) for the test. If moisture and/
or chlorine is added to the calibration gas,
the dilution effect of the moisture and/or
chlorine addition on the calibration gas
concentration must be accounted for in an
appropriate manner. Operate the Hg CEMS in
its normal sampling mode during the test.
The calibrations should be approximately 24
Where:
RD = Relative Deviation between the Hg
concentrations of samples ‘‘a’’ and ‘‘b’’
(percent),
Ca = Hg concentration of Hg sample ‘‘a’’ (mg/
dscm), and
Cb = Hg concentration of Hg sample ‘‘b’’ (mg/
dscm).
*
*
*
*
*
hours apart, unless the 7-day test is
performed over non-consecutive calendar
days. On each day of the test, inject the zerolevel and upscale gases in sequence and
record the analyzer responses. Pass the
calibration gas through all filters, scrubbers,
conditioners, and other monitor components
used during normal sampling, and through as
much of the sampling probe as is practical.
Do not make any manual adjustments to the
monitor (i.e., resetting the calibration) until
after taking measurements at both the zero
and upscale concentration levels. If
automatic adjustments are made following
both injections, conduct the calibration error
test such that the magnitude of the
adjustments can be determined, and use only
the unadjusted analyzer responses in the
calculations. Calculate the calibration error
(CE) on each day of the test, as described in
Table A–1 of this appendix. The CE on each
day of the test must either meet the main
performance specification or the alternative
specification in Table A–1 of this appendix.
*
*
*
*
*
4.1.1.3 Three-Level System Integrity
Check. Perform the 3-level system integrity
check using low, mid, and high-level
calibration gas concentrations generated by a
NIST-traceable source of oxidized Hg. Follow
the same basic procedure as for the linearity
check. If moisture and/or chlorine is added
to the calibration gas, the dilution effect of
the moisture and/or chlorine addition on the
calibration gas concentration must be
4.1.1.5.2 Calculation of RATA Results.
Calculate the relative accuracy (RA) of the
monitoring system, on a mg/scm basis, as
described in section 12 of Performance
Specification (PS) 2 in Appendix B to part 60
of this chapter (see Equations 2–3 through 2–
6 of PS2) including the option to substitute
the emission limit value (in this case the
equivalent concentration) in the denominator
of Equation 2–6 in place of the average RM
8481
accounted for in an appropriate manner.
Calculate the system integrity error (SIE), as
described in Table A–1 of this appendix. The
SIE must either meet the main performance
specification or the alternative specification
in Table A–1 of this appendix.
*
*
*
*
*
4.1.1.5 Relative Accuracy Test Audit
(RATA). Perform the RATA of the Hg CEMS
at normal load. Acceptable Hg reference
methods for the RATA include ASTM
D6784–02 (Reapproved 2008), ‘‘Standard
Test Method for Elemental, Oxidized,
Particle-Bound and Total Mercury in Flue
Gas Generated from Coal-Fired Stationary
Sources (Ontario Hydro Method)’’
(incorporated by reference, see § 63.14) and
Methods 29, 30A, and 30B in appendix A–
8 to part 60 of this chapter. When Method 29
or ASTM D6784–02 is used, paired sampling
trains are required and the filterable portion
of the sample need not be included when
making comparisons to the Hg CEMS results
for purposes of a RATA. To validate a
Method 29 or ASTM D6784–02 test run,
calculate the relative deviation (RD) using
Equation A–1 of this section, and assess the
results as follows to validate the run. The RD
must not exceed 10 percent, when the
average Hg concentration is greater than 1.0
mg/dscm. If the RD specification is met, the
results of the two samples shall be averaged
arithmetically.
value when the average emissions for the test
are less than 50 percent of the applicable
emissions limit. For purposes of calculating
the relative accuracy, ensure that the
reference method and monitoring system
data are on a consistent basis, either wet or
dry. The CEMS must either meet the main
performance specification or the alternative
specification in Table A–1 of this appendix.
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TABLE A–1—REQUIRED CERTIFICATION TESTS AND PERFORMANCE SPECIFICATIONS FOR Hg CEMS
The main performance
specification 1 is . . .
The alternate performance
specification 1 is . . .
And the conditions of the
alternate specification are . . .
7-day calibration error test 2 ...........
|R ¥ A| ≤5.0% of span value, for
both the zero and upscale
gases, on each of the 7 days.
|R ¥ Aavg | ≤10.0% of the reference gas concentration at
each calibration gas level (low,
mid, or high).
|R ¥ Aavg | ≤10.0% of the reference gas concentration at
each calibration gas level.
20.0% RA .....................................
|R ¥ A| ≤1.0 μg/scm ....................
The alternate specification may
be used on any day of the test.
|R ¥ Aavg | ≤0.8 μg/scm ...............
The alternate specification may
be used at any gas level.
|R ¥ Aavg | ≤0.8 μg/scm ...............
The alternate specification may
be used at any gas level.
≤10% RA when concentration
equivalent of applicable emissions limit is used in place of
RMavg in Equation 2–6 of PS2
(see Section 4.1.1.5.2 of this
appendix).
RMavg <50% of applicable emissions limit.
Linearity check 3 .............................
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RATA .............................................
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TABLE A–1—REQUIRED CERTIFICATION TESTS AND PERFORMANCE SPECIFICATIONS FOR Hg CEMS—Continued
For this required certification test
. . .
The main performance
specification 1 is . . .
Cycle time test 2 .............................
And the conditions of the
alternate specification are . . .
The alternate performance
specification 1 is . . .
15 minutes where the stability criteria are readings change by
<2.0% of span or by ≤0.5 μg/
scm, for 2 minutes.
1 Note that |R ¥ A| is the absolute value of the difference between the reference gas value and the analyzer reading. |R ¥ A
avg| is the absolute value of the difference between the reference gas concentration and the average of the analyzer responses, at a particular gas level.
2 Use elemental Hg standards; a mid-level or high-level upscale gas may be used. The cycle time test is not required for Hg CEMS that use integrated batch sampling; however, those monitors must be capable of recording at least one Hg concentration reading every 15 minutes.
3 Use elemental Hg standards.
4 Use oxidized Hg standards.
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5. Ongoing Quality Assurance (QA) and Data
Validation
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TABLE A–2—ON-GOING QA TEST REQUIREMENTS FOR Hg CEMS
Perform this type of QA test . . .
At this frequency . . .
With these qualifications and exceptions . . .
Acceptance criteria . . .
Calibration error test ......................
Daily ..............................................
|R ¥ A| ≤5.0% of span value
or
|R ¥ A| ≤1.0 μg/scm.
Single-level system integrity check
Weekly 1 ........................................
• Use either a mid- or high-level
gas.
• Use elemental Hg
• Calibrations are not required
when the unit is not in operation.
• Use oxidized Hg—either mid- or
high-level.
Linearity check or 3-level system
integrity check.
Quarterly 3 .....................................
RATA .............................................
Annual 4 ........................................
• Required in each ‘‘QA operating
quarter’’ 2 and no less than
once every 4 calendar quarters.
• 168 operating hour grace period available.
• Use elemental Hg for linearity
check.
• Use oxidized Hg for system integrity check.
• Test deadline may be extended
for ‘‘non-QA operating quarters,’’ up to a maximum of 8
quarters from the quarter of the
previous test.
• 720 operating hour grace period available.
|Rn ¥ Aavg| ≤10.0% of the reference gas value
or
|R ¥ Aavg| ≤0.8 μg/scm.
|R ¥ Aavg | ≤10.0% of the reference gas value, at each calibration gas level or |R ¥ Aavg|
≤0.8 μg/scm.
≤20.0% RA when Cavg ≥50% of
the emissions limit
or
≤10.0% RA when Cavg <50% of
the emissions limit and the concentration equivalent of the applicable emission limit is used in
the denominator of Equation 2–
6 of PS2 (see Section 4.1.1.5.1
of this appendix).
1 ‘‘Weekly’’
means once every 7 operating days.
‘‘QA operating quarter’’ is a calendar quarter with at least 168 unit or stack operating hours.
3 ‘‘Quarterly’’ means once every QA operating quarter.
4 ‘‘Annual’’ means once every four QA operating quarters.
2A
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5.1.2.1 Calibration error tests of the Hg
CEMS are required daily, except during unit
outages. Use a NIST-traceable elemental Hg
gas standard for these calibrations. Both a
zero-level gas and either a mid-level or highlevel gas are required for these calibrations.
*
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5.1.2.3 Perform a single-level system
integrity check weekly, i.e., once every 7
operating days (see the third column in Table
A–2 of this appendix).
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5.2.1 Each sorbent trap monitoring
system shall be continuously operated and
maintained in accordance with Performance
Specification (PS) 12B in appendix B to part
60 of this chapter. The QA/QC criteria for
routine operation of the system are
summarized in Table 12B–1 of PS 12B. Each
pair of sorbent traps may be used to sample
the stack gas for up to 15 operating days.
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6. Data Reductions and Calculations
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6.2.2.3 The applicable gross output-based
Hg emission rate limit in Table 1 or 2 to this
subpart must be met on a 30- (or 90-) boiler
operating day rolling average basis, except as
otherwise provided in § 63.10009(a)(2). Use
Equation A–5 of this appendix to calculate
the Hg emission rate for each averaging
period.
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Eo = Hg emission rate for the averaging
period (lb/GWh),
Eho = Gross output-based hourly Hg emission
rate for unit or stack sampling hour ‘‘h’’
in the averaging period, from Equation
A–4 of this appendix (lb/GWh), and
n = Number of unit or stack operating hours
in the averaging period in which valid
data were obtained for all parameters.
(Note: Do not include non-operating hours
with zero emission rates in the average).
needed to convert pollutant concentrations to
units of the applicable emissions limit in
accordance with Performance Specification
15 (PS 15) of appendix B to part 60 of this
chapter for extractive Fourier Transform
Infrared Spectroscopy (FTIR) continuous
emissions monitoring systems and
§ 63.10010(a) or Performance Specification
18 (PS 18) of appendix B to part 60 of this
chapter for HCl CEMS and § 63.10010(a).
*
2.3 FTIR Monitoring System Equipment,
Supplies, Definitions, and General
Operation. The following provisions apply:
2.3.1 PS 15, Sections 2.0, 3.0, 4.0, 5.0, 6.0,
and 10.0 of appendix B to part 60 of this
chapter, or
2.3.2 PS 18, Sections 3.0, 6.0, and 11.0 of
appendix B to part 60 of this chapter.
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7. Recordkeeping and Reporting
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7.1.2.6 The EGUs that constitute an
emissions averaging group.
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29. Appendix B to subpart UUUUU of
part 63 is amended by:
■ a. Revising paragraph 2.1 and 2.3;
■ b. Adding paragraphs 2.3.1 and 2.3.2;
■ c. Revising paragraphs 3.1 and 3.2 and
adding paragraph 3.3;
■ d. Adding introductory text to section
5. On-Going Quality Assurance
Requirements;
■ e. Revising paragraphs 5.1, 5.2, and
5.3;
■ f. Adding paragraphs 5.4, 5.4.1, 5.4.2,
5.4.2.1, 5.4.2.2, 5.4.2.2.1, 5.4.2.2.2,
5.4.2.3, 5.4.2.3.1, 5.4.2.3.2, 5.4.2.3.3, and
5.4.3;
■ g. Revising section 8. introductory
text;
■ h. Revising paragraphs 10.1.8,
10.1.8.1, 10.1.8.1.1, and 10.1.8.1.2,
adding paragraph 10.1.8.1.2.1, and
adding and reserving paragraph
10.1.8.1.2.2;
■ i. Revising paragraph 10.1.8.1.3;
■ j. Revising paragraphs 11.4 and 11.4.2
and removing and reserving paragraphs
11.4.2.1 through 11.4.2.13;
■ k. Revising paragraphs 11.4.3 and
11.4.3.1 through 11.4.3.13;
■ l. Revising paragraph 11.4.4 and
adding and reserving paragraph
11.4.4.1;
■ m. Adding paragraph 11.4.5 and
adding and reserving paragraph
11.4.5.1;
■ n. Adding paragraph 11.4.6 and
adding and reserving paragraph
11.4.6.1;
■ o. Adding paragraphs 11.4.7, 11.4.7.1
through 11.4.7.13;
■ p. Revising paragraph 11.4.8 and
■ q. Revising paragraph 11.5.3.4.
■ The revisions and additions read as
follows:
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Appendix B to Subpart UUUUU of Part
63—HCL and HF Monitoring Provisions
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2. Monitoring of HCL and/or HF Emissions
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2.1 Monitoring System Installation
Requirements. Install HCl and/or HF CEMS
and any additional monitoring systems
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3. Initial Certification Procedures
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3.1 If you choose to follow Performance
Specification 15 (PS 15) of appendix B to part
60 of this chapter, then your HCl and/or HF
CEMS must be certified according to PS 15
using the procedures for gas auditing and
comparison to a reference method (RM) as
specified in sections 3.1.1 and 3.1.2 below.
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3.2 If you choose to follow Performance
Specification 18 (PS 18) of appendix B to part
60 of this chapter, then your HCl and/or HF
CEMS must be certified according to PS 18,
sections 7.0, 8.0, 11.0, 12.0, and 13.0.
3.3 Any additional stack gas flow rate,
diluent gas, and moisture monitoring
system(s) needed to express pollutant
concentrations in units of the applicable
emissions limit must be certified according to
part 75 of this chapter.
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5. On-Going Quality Assurance
Requirements
On-going QA test requirements for HCl and
HF CEMS must be implemented as follows:
5.1 If you choose to follow Performance
Specification 15 (PS 15) of appendix B to part
60 of this chapter, then the quality assurance/
quality control procedures of PS 15 shall
apply as set forth in sections 5.1.1 through
5.1.3 and 5.3.2 of this appendix.
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5.2 If you choose to follow Performance
Specification PS 18 of appendix B to part 60
of this chapter, then the quality assurance/
quality control procedures of Procedure 6 of
40 CFR part 60, appendix F shall apply.
5.3 Stack gas flow rate, diluent gas, and
moisture monitoring systems must meet the
applicable on-going QA test requirements of
part 75 of this chapter.
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5.4 Data Validation.
5.4.1 Out-of-Control Periods. An HCl or
HF CEMS that is used to provide data under
this appendix is considered to be out-ofcontrol, and data from the CEMS may not be
reported as quality-assured, when any
acceptance criteria for a required QA test is
not met. The HCl or HF CEMS is also
considered to be out-of-control when a
required QA test is not performed on
schedule or within an allotted grace period.
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To end an out-of-control period, the QA test
that was either failed or not done on time
must be performed and passed. Out-ofcontrol periods are counted as hours of
monitoring system downtime.
5.4.2 Grace Periods. For the purposes of
this appendix, a ‘‘grace period’’ is defined as
a specified number of unit or stack operating
hours after the deadline for a required
quality-assurance test of a continuous
monitor has passed, in which the test may be
performed and passed without loss of data.
5.4.2.1 For the flow rate, diluent gas, and
moisture monitoring systems described in
section 5.3 of this appendix, a 168 unit or
stack operating hour grace period is available
for quarterly linearity checks, and a 720 unit
or stack operating hour grace period is
available for RATAs, as provided,
respectively, in sections 2.2.4 and 2.3.3 of
appendix B to part 75 of this chapter.
5.4.2.2 For the purposes of this appendix,
if the deadline for a required gas audit/data
accuracy assessment or RATA of an HCl or
HF CEMS cannot be met due to
circumstances beyond the control of the
owner or operator:
5.4.2.2.1 A 168 unit or stack operating
hour grace period is available in which to
perform the gas audit/data accuracy
assessment; or
5.4.2.2.2 A 720 unit or stack operating
hour grace period is available in which to
perform the RATA.
5.4.2.3 If a required QA test is performed
during a grace period, the deadline for the
next test shall be determined as follows:
5.4.2.3.1 For a gas audit or RATA of the
monitoring systems required under in section
5.3 of this appendix, determine the deadline
for the next gas audit or RATA (as applicable)
in accordance with section 2.2.4(b) or
2.3.3(d) of appendix B to part 75 of this
chapter; treat a gas audit in the same manner
as a linearity check.
5.4.2.3.2 For the gas audit/data accuracy
assessment of an HCl or HF CEMS, the grace
period test only satisfies the audit
requirement for the calendar quarter in
which the test was originally due. If the
calendar quarter in which the grace period
audit is performed is a QA operating quarter,
an additional gas audit/data accuracy
assessment is required for that quarter.
5.4.2.3.3 For the RATA of an HCl or HF
CEMS, the next RATA is due within three
QA operating quarters after the calendar
quarter in which the grace period test is
performed.
5.4.3 Conditional Data Validation. For
recertification and diagnostic testing of the
monitoring systems that are used to provide
data under this appendix, and for the
required QA tests when non-redundant
backup monitoring systems or temporary
like-kind replacement analyzers are brought
into service, the conditional data validation
provisions in § 75.20(b)(3)(ii) through (ix) of
this chapter may be used to avoid or
minimize data loss. The allotted window of
time to complete calibration tests and RATAs
shall be as specified in § 75.20(b)(3)(iv) of
this chapter; the allotted window of time to
complete a gas audit or data accuracy
assessment shall be the same as for a linearity
check (i.e., 168 unit or stack operating hours).
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8. QA/QC Program Requirements
The owner or operator shall develop and
implement a quality assurance/quality
control (QA/QC) program for the HCl and/or
HF CEMS that are used to provide data under
this subpart. At a minimum, the program
shall include a written plan that describes in
detail (or that refers to separate documents
containing) complete, step-by-step
procedures and operations for the most
important QA/QC activities. Electronic
storage of the QA/QC plan is permissible,
provided that the information can be made
available in hard copy to auditors and
inspectors. The QA/QC program
requirements for the other monitoring
systems described in paragraph 5.3 of this
appendix are specified in section 1 of
appendix B to part 75 of this chapter.
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10. Recordkeeping Requirements
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10.1.8 Certification and Quality
Assurance Test Records. For the HCl and/or
HF CEMS used to provide data under this
subpart at each affected unit (or group of
units monitored at a common stack), record
the following information for all required
certification, recertification, diagnostic, and
quality-assurance tests:
10.1.8.1 HCl and HF CEMS.
10.1.8.1.1 For all required daily
calibrations and checks (including
calibration transfer standard tests) of the HCl
or HF CEMS, record the test dates and times,
reference values and their certification
information, action levels for integrated path
HCl CEMS, HCl or HF monitor responses,
and calculated calibration error values;
10.1.8.1.2 For quarterly gas audits of HCl
or HF CEMS certified under PS 15 of
appendix B to part 60 of this chapter follow
paragraph 10.1.8.1.2.1 of this appendix and
for quarterly data accuracy assessments
under PS 18 of appendix B to part 60 of this
chapter follow paragraph 10.1.8.1.2.2 of this
appendix.
10.1.8.1.2.1 Record the date and time of
each spiked and unspiked sample, the audit
gas reference values and uncertainties. Keep
records of all calculations and data analyses
required under sections 9.1 and 12.1 of P S
15 of appendix B to part 60 of this chapter,
and the results of those calculations and
analyses.
10.1.8.1.2.2 [Reserved]
10.1.8.1.3 For each RATA or RAA of a
HCl or HF CEMS, record the date and time
of each test run, the reference method(s)
used, and the reference method and HCl or
HF CEMS values. Keep records of the data
analyses and calculations used to determine
the relative accuracy.
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11.4 Certification, Recertification, and
Quality-Assurance Test Reporting
Requirements. Except for daily QA tests (e.g.,
calibrations and flow monitor interference
checks), which are included in each
electronic quarterly emissions report, use the
ECMPS Client Tool to submit the results of
all required certification, recertification,
quality-assurance, and diagnostic tests of the
monitoring systems required under this
appendix electronically, either prior to or
concurrent with the relevant quarterly
electronic emissions report.
*
*
*
*
*
11.4.2 For daily beam intensity checks for
integrated path HCl CEMS as specified by PS
18 of appendix B to part 60 of this chapter,
report:
11.4.2.1 through 11.4.2.13 [Reserved]
11.4.3 For each quarterly gas audit of an
HCl or HF CEMS under Performance
Specification 15, report:
11.4.3.1 Facility ID information;
11.4.3.2 Monitoring system ID number;
11.4.3.3 Type of test (e.g., quarterly gas
audit);
11.4.3.4 Reason for test;
11.4.3.5 Certified audit (spike) gas
concentration value (ppm);
11.4.3.6 Measured value of audit (spike)
gas, including date and time of injection;
11.4.3.7 Calculated dilution ratio for
audit (spike) gas;
11.4.3.8 Date and time of each spiked flue
gas sample;
11.4.3.9 Date and time of each unspiked
flue gas sample;
11.4.3.10 The measured values for each
spiked gas and unspiked flue gas sample
(ppm);
11.4.3.11 The mean values of the spiked
and unspiked sample concentrations and the
expected value of the spiked concentration as
specified in section 12.1 of PS 15 of appendix
B to part 60 of this chapter (ppm);
11.4.3.12 Bias at the spike level as
calculated using equation 3 in section 12.1 of
PS 15 of appendix B to part 60 of this
chapter; and
11.4.3.13 The correction factor (CF),
calculated using equation 6 in section 12.1 of
PS 15 of appendix B to part 60 of this
chapter.
11.4.4 For each quarterly parameter
verification check for an integrated path HCl
CEMS under PS 18 of appendix B to part 60
of this chapter, report:
11.4.4.1 [Reserved]
11.4.5 For each quarterly gas audit under
P S 18 of appendix B to part 60 of this
chapter, report:
11.4.5.1 [Reserved]
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11.4.6 For each quarterly dynamic
spiking audit as allowed by P S 18 of
appendix B to part 60 of this chapter, report:
11.4.6.1 [Reserved]
11.4.7 For each RATA or RAA of an HCl
or HF CEMS, report:
11.4.7.1 Facility ID information;
11.4.7.2 Monitoring system ID number;
11.4.7.3 Type of test (i.e., initial or annual
RATA or RAA);
11.4.7.4 Reason for test;
11.4.7.5 The reference method used;
11.4.7.6 Starting and ending date and
time for each test run;
11.4.7.7 Units of measure;
11.4.7.8 The measured reference method
and CEMS values for each test run, on a
consistent moisture basis, in appropriate
units of measure;
11.4.7.9 Flags to indicate which test runs
were used in the calculations;
11.4.7.10 Arithmetic mean of the CEMS
values, of the reference method values, and
of their differences;
11.4.7.11 Standard deviation, as specified
in Equation 2–4 of PS 2 or PS 18, as
applicable in appendix B to part 60 of this
chapter;
11.4.7.12 Confidence coefficient, as
specified in Equation 2–5 of PS 2 or PS 18,
as applicable in appendix B to part 60 of this
chapter; and
11.4.7.13 Relative accuracy calculated
using Equation 2–6 of PS 2 or PS 18, as
applicable in appendix B to part 60 of this
chapter or, if applicable, according to the
alternative procedure for low emitters
described in paragraph 3.1.2.2 of this
appendix. If applicable use a flag to indicate
that the alternative RA specification for low
emitters has been applied.
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11.4.8 Reporting Requirements for
Diluent Gas, Flow Rate, and Moisture
Monitoring Systems. For the certification,
recertification, diagnostic, and QA tests of
stack gas flow rate, moisture, and diluent gas
monitoring systems that are certified and
quality-assured according to part 75 of this
chapter, report the information in section
10.1.8.2 of this appendix.
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11.5.3.4 The results of all daily
calibrations (including calibration transfer
standard tests and beam intensity checks of
integrated path CEMS) of the HCl or HF
monitor as described in paragraph 10.1.8.1.1
of this appendix; and
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[FR Doc. 2015–01699 Filed 2–13–15; 8:45 am]
BILLING CODE 6560–50–P
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[Federal Register Volume 80, Number 31 (Tuesday, February 17, 2015)]
[Proposed Rules]
[Pages 8441-8484]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2015-01699]
[[Page 8441]]
Vol. 80
Tuesday,
No. 31
February 17, 2015
Part III
Environmental Protection Agency
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40 CFR Parts 60 and 63
National Emission Standards for Hazardous Air Pollutants From Coal- and
Oil-Fired Electric Utility Steam Generating Units and Standards of
Performance for Fossil-Fuel-Fired Electric Utility, Industrial-
Commercial-Institutional, and Small Industrial-Commercial-Institutional
Steam Generating Units; Revisions; Proposed Rule
Federal Register / Vol. 80 , No. 31 / Tuesday, February 17, 2015 /
Proposed Rules
[[Page 8442]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60 and 63
[EPA-HQ-OAR-2009-0234 and EPA-HQ-OAR-2011-0044; FRL-9921-04-OAR]
RIN 2060-AS41
National Emission Standards for Hazardous Air Pollutants From
Coal- and Oil-Fired Electric Utility Steam Generating Units and
Standards of Performance for Fossil-Fuel-Fired Electric Utility,
Industrial-Commercial-Institutional, and Small Industrial-Commercial-
Institutional Steam Generating Units; Revisions
AGENCY: Environmental Protection Agency.
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: The U.S. Environmental Protection Agency (EPA) is proposing
this action to correct and clarify certain text of the final action
titled ``National Emission Standards for Hazardous Air Pollutants From
Coal- and Oil-Fired Electric Utility Steam Generating Units and
Standards of Performance for Fossil-Fuel-Fired Electric Utility,
Industrial-Commercial-Institutional, and Small Industrial-Commercial-
Institutional Steam Generating Units,'' which was published in the
Federal Register of Thursday, February 16, 2012. We are also proposing
to remove rule provisions establishing an affirmative defense for
malfunction events in light of a recent court decision on the issue.
DATES: Comments. Comments must be received on or before April 3, 2015.
Public Hearing. If anyone contacts the EPA requesting a public
hearing by February 23, 2015, the EPA will hold a public hearing on
March 4, 2015 from 1 p.m. (Eastern Standard Time) to 5 p.m. (Eastern
Standard Time) at the U.S. Environmental Protection Agency building
located at 109 T.W. Alexander Drive, Research Triangle Park, NC 27711.
If the EPA holds a public hearing, the EPA will keep the record of the
hearing open for 30 days after completion of the hearing to provide an
opportunity for submission of rebuttal and supplementary information.
ADDRESSES: Submit your comments, identified by Docket ID. No. EPA-HQ-
OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-2009-0234
(NESHAP/MATS action), by one of the following methods:
Federal rulemaking portal: https://www.regulations.gov.
Follow the instructions for submitting comments.
Agency Web site: https://www.epa.gov/oar/docket.html.
Follow the instructions for submitting comments on the EPA Air and
Radiation Docket Web site.
Email: Comments may be sent by electronic mail (email) to
a-and-r-docket@epa.gov, Attention EPA-HQ-OAR-2011-0044 (NSPS action) or
EPA-HQ-OAR-2009-0234 (NESHAP/MATS action).
Fax: Fax your comments to: (202) 566-9744, Docket ID No.
EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-2009-
0234 (NESHAP/MATS action).
Mail: Send your comments on the NESHAP/MATS action to: EPA
Docket Center (EPA/DC), Environmental Protection Agency, Mailcode:
28221T, 1200 Pennsylvania Ave. NW., Washington, DC 20460, Docket ID No.
EPA-HQ-OAR-2009-0234. Send your comments on the NSPS action to: EPA
Docket Center (EPA/DC), Environmental Protection Agency, Mailcode:
2822T, 1200 Pennsylvania Ave. NW., Washington, DC 20460, Docket ID. No.
EPA-HQ-OAR-2011-0044.
Hand Delivery or Courier: Deliver your comments to: EPA
Docket Center, EPA WJC West Building, Room 3334, 1301 Constitution Ave.
NW., Washington, DC 20460. Such deliveries are only accepted during the
Docket's normal hours of operation (8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holiday), and special arrangements
should be made for deliveries of boxed information.
FOR FURTHER INFORMATION CONTACT: For the NESHAP action: Mr. Barrett
Parker, Measurement Policy Group, Sector Policies and Programs
Division, (D243-05), Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711; Telephone number: (919) 541-5635; Fax number (919) 541-3207;
email address: parker.barrett@epa.gov. For the NSPS action: Mr.
Christian Fellner, Energy Strategies Group, Sector Policies and
Programs Division, (D243-01), Office of Air Quality Planning and
Standards, U.S. Environmental Protection Agency, Research Triangle
Park, North Carolina 27711; Telephone number: (919) 541-4003; Fax
number (919) 541-5450; email address: fellner.christian@epa.gov.
SUPPLEMENTARY INFORMATION:
Comment Instructions. All submissions must include agency name and
respective docket number or Regulatory Information Number (RIN) for
this rulemaking. All comments will be posted without change and may be
made available online at https://www.regulations.gov, including any
personal information provided, unless the comment includes information
claimed to be confidential business information (CBI) or other
information whose disclosure is restricted by statute. Do not submit
information that you consider to be CBI or otherwise protected through
https://www.regulations.gov or email. The https://www.regulations.gov Web
site is an ``anonymous access'' system, which means the EPA will not
know your identity or contact information unless you provide it in the
body of your comment. If you send an email comment directly to the EPA
without going through https://www.regulations.gov, your email address
will be automatically captured and included as part of the comment that
is placed in the public docket and made available on the Internet. If
you submit an electronic comment, the EPA recommends that you include
your name and other contact information in the body of your comment and
with any disk or CD-ROM you submit. If the EPA cannot read your comment
due to technical difficulties and cannot contact you for clarification,
the EPA may not be able to consider your comment. Electronic files
should avoid the use of special characters, any form of encryption, and
be free of any defects or viruses.
Public Hearing. If requested by February 23, 2015, we will hold a
public hearing on March 4, 2015, from 1 p.m. (Eastern Standard Time) to
5 p.m. (Eastern Standard Time) at the U.S. Environmental Protection
Agency building located at 109 T.W. Alexander Drive, Research Triangle
Park, NC 27711. Please contact Ms. Pamela Garrett of the Sector
Policies and Programs Division (D243-01), Office of Air Quality
Planning and Standards, Environmental Protection Agency, Research
Triangle Park, NC 27711; telephone number: 919-541-7966; email address:
garrett.pamela@epa.gov; to request a hearing, register to speak at the
hearing or to inquire as to whether or not a hearing will be held. The
last day to pre-register in advance to speak at the hearing will be
March 2, 2015. Additionally, requests to speak will be taken the day of
the hearing at the hearing registration desk, although preferences on
speaking times may not be able to be fulfilled. If you require the
service of a translator or special accommodations such as audio
description, we ask that you pre-register for the hearing, as we may
not be able to arrange such accommodations without advance notice. The
hearing will provide interested parties the
[[Page 8443]]
opportunity to present data, views or arguments concerning the proposed
action. The EPA will make every effort to accommodate all speakers who
arrive and register. Because this hearing is being held at a U.S.
government facility, individuals planning to attend the hearing should
be prepared to show valid picture identification to the security staff
in order to gain access to the meeting room. Please note that the REAL
ID Act, passed by Congress in 2005, established new requirements for
entering federal facilities. If your driver's license is issued by
Alaska, American Samoa, Arizona, Kentucky, Louisiana, Maine,
Massachusetts, Minnesota, Montana, New York, Oklahoma or the State of
Washington, you must present an additional form of identification to
enter the federal building. Acceptable alternative forms of
identification include: Federal employee badges, passports, enhanced
driver's licenses and military identification cards. In addition, you
will need to obtain a property pass for any personal belongings you
bring with you. Upon leaving the building, you will be required to
return this property pass to the security desk. No large signs will be
allowed in the building, cameras may only be used outside of the
building and demonstrations will not be allowed on federal property for
security reasons. The EPA may ask clarifying questions during the oral
presentations, but will not respond to the presentations at that time.
Written statements and supporting information submitted during the
comment period will be considered with the same weight as oral comments
and supporting information presented at the public hearing. Verbatim
transcripts of the hearing and written statements will be included in
the docket for the rulemaking. The EPA will make every effort to follow
the schedule as closely as possible on the day of the hearing; however,
please plan for the hearing to run either ahead of schedule or behind
schedule. Again, a hearing will not be held on this rulemaking unless
requested. A hearing needs to be requested by February 23, 2015. Again,
please contact Ms. Pamela Garrett of the Sector Policies and Programs
Division (D243-01), Office of Air Quality Planning and Standards,
Environmental Protection Agency, Research Triangle Park, NC 27711;
telephone number: 919-541-7966; email address: garrett.pamela@epa.gov
to request a hearing.
Docket. All documents in the docket are listed in the https://www.regulations.gov index. Although listed in the index, some
information is not publicly available (e.g., CBI or other information
whose disclosure is restricted by statute). Certain other material,
such as copyrighted material, will be publicly available only in hard
copy form. Publicly available docket materials are available either
electronically in https://www.regulations.gov or in hard copy at the EPA
Docket Center, Room 3334, 1301 Constitution Avenue NW., Washington, DC.
The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holidays. The telephone number for the
Public Reading Room is (202) 566-1744, and the telephone number for the
Air Docket is (202) 566-1742.
I. Technical Corrections
The final Clean Air Act (CAA) rules published in the Federal
Register on February 16, 2012 (77 FR 9303), establish national emission
standards for hazardous air pollutants (NESHAP) from coal- and oil-
fired electric utility steam generating units (EGUs), referred to as
``the Mercury and Air Toxics Standards'' or ``MATS,'' and new source
performance standards (NSPS) for fossil-fuel-fired electric utility,
industrial-commercial-institutional, and small industrial-commercial-
institutional steam generating units, referred to as the Utility NSPS.
In this document, the EPA proposes to correct certain regulatory
text. The proposed corrections can be categorized generally as follows:
(a) Resolution of conflicts between preamble and regulatory text, (b)
corrections that we stated we would make in response to comments that
were inadvertently not made, and (c) clarification of language in
regulatory text. Below, we identify each proposed technical correction
to the regulatory text as found in the Code of Federal Regulations
(i.e., 40 CFR). The EPA is soliciting comments on all of these proposed
corrections.
1. Section 60.49Da(f) is revised to amend the procedures for
calculating compliance with the NSPS daily average particulate matter
(PM) emission limit for affected facilities using PM continuous
emission monitoring systems (CEMS) and that commenced construction,
modification, or reconstruction before May 4, 2011. Even though it was
not included in the proposal, in an effort to clarify certain language
in 40 CFR 60.48Da(f), we amended the procedure for calculating
compliance with the daily average PM limit for affected facilities for
which construction, modification, or reconstruction commenced before
May 4, 2011, using PM CEMS (78 FR 24073; April 24, 2013). The
amendments removed the provision that for operating days with less than
18 hours of PM CEMS data, the data for that day would be rolled into
the following operating day(s) until 18 hours of data are available.
The intent of the original language was to assure that compliance with
the daily PM emission rate was not determined with significantly less
than 24 hours of data, but that all emissions data would still be used.
The intent of the revised data was to eliminate the requirement to roll
emissions data recorded on days without sufficient data to determine a
daily average to the following operating day, but that a minimum of 18
hours would still be required to determine compliance with the daily PM
standard. Industry requested reconsideration stating that they did not
have an opportunity to comment on the issue, and that the revised
calculation procedures could in fact require compliance determinations
with significantly less than 24 hours of data. The proposed revisions
would undo those changes and return the calculation procedures to the
approach used prior to April 24, 2013. Specifically, for operating days
with less than 18 hours of PM CEMS data, that data would be rolled into
the following operating day(s) until over 18 hours of data are
available to determine compliance with the operating day standard. We
are soliciting comment on whether the intent of the current calculation
procedures should be maintained (i.e., data collected on days with less
than 18 hours of data would not be used to determine compliance with
the PM standard and would also not be rolled into the following
operating day(s)). If the current approach is maintained, the
regulatory language would be revised to avoid situations where
compliance calculations would be made with less than 18 hours of data.
2. Section 63.9983(a) is revised to clarify that MATS does not
apply to either major or area source combustion turbines, except for
integrated gasification combined cycle (IGCC) units. In the final MATS
rule, 40 CFR 63.9983(a) exempted from MATS ``any unit designated as a
stationary combustion turbine, except an integrated gasification
combined cycle (IGCC) unit, covered by 40 CFR part 63, subpart YYYY.''
Because area source stationary combustion turbines are not subject to
subpart YYYY, which is applicable to stationary combustion turbines
located at major sources, the Agency received questions concerning the
applicability of MATS to the area
[[Page 8444]]
source units in that category. The EPA intended by the exemption to
exempt all stationary source combustion turbines other than IGCC units
from the requirements of MATS, because the EPA does not interpret the
statute to include those units within the definition of EGU in CAA
section 112(a)(8). The proposed revisions to the regulations will
clarify the EPA's interpretation and intent and prevent future
confusion concerning the applicability of the MATS rule to stationary
combustion turbines located at area sources.
3. Section 63.9983(b) and (c) is revised consistent with the
definitional changes discussed below. The definitional changes are
being proposed so that sources will know the time period to consider
when determining whether their coal or oil utilization triggers
applicability of the MATS rule. As explained below, the change is
particularly important in the first 3 years after the compliance date
when sources will be required to estimate coal and oil utilization in
their EGUs to determine applicability of the MATS rule.
4. Section 63.9983(e) is added to clarify CAA section 112
applicability to the units that meet the definition of a natural gas-
fired EGU in MATS, and, because they combust greater than 10 percent
biomass, also meet the definition of a biomass-fired boiler in the
Industrial Boiler NESHAP (40 CFR part 63, subpart DDDDD). These
overlapping definitions led to confusion in the regulated community
about whether such units are natural gas-fired EGUS pursuant to MATS or
biomass-fired boilers subject to the Industrial Boiler NESHAP. We are
revising the MATS rule to make clear that such units are biomass-fired
boilers subject to the industrial boiler NESHAP. Similar revisions to
the applicability provisions of the Industrial Boiler NESHAP have been
proposed.\1\
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\1\ Prepublication version found at https://www.epa.gov/ttn/atw/boiler/boilerpg.html. The prepublication version will be replaced
with the Federal Register document when the proposal is published.
---------------------------------------------------------------------------
5. Section 63.9991(c)(1) and (2) is being revised to clarify the
conditions that are required in order to use the alternate sulfur
dioxide (SO2) limit.
6. Sections 63.10000(c)(1)(i)(A) and 63.10005(h) are revised to
clarify the provisions of units designated as being low emitting EGUs
(LEE) when an acid gas scrubber and a bypass stack are present.
7. Section 63.10000(c)(1)(i)(C) is added to allow EGUs the ability
to seek LEE status if their bypass stacks vent through stacks that are
able to measure emissions. In addition, the proposed language would
allow EGUs with LEE status the ability to bypass emissions control
devices during emergency periods provided certain fuel and time
restrictions, along with notification requirements, occur.
The final MATS rule did not allow EGUs whose emissions control
devices had bypasses to seek LEE status. Owners and operators of EGUs
whose emissions control devices had no bypass stacks, but instead
routed bypass emissions through main stacks equipped with emissions
measurement capability, requested that we allow their EGUs to seek LEE
status provided emissions were measured during bypass events. We
believe that EGU owners or operators that have the ability to measure
and report emissions during bypass events should be able to seek LEE
status as long as bypass emissions are included in the calculations
required to demonstrate the LEE status eligibility. For this reason, we
are proposing to allow this option.
Also, a number of EGU owners or operators requested that we allow
EGUs with LEE status the ability to bypass their emissions control
devices in emergency conditions, provided that the EGUs were combusting
clean fuels and that the bypass periods were of short duration.\2\ We
reviewed the requests and believe that control device bypass operation
for up to 2 percent of EGU operating hours while combusting clean fuel
during emergency periods is reasonable, provided a report detailing the
emergency event, its cause, the corrective action taken to alleviate
the emergency event, and estimates of the emissions released during the
emergency event are provided. In addition, an EGU owner or operator
must include these emergency emissions along with performance test
results in assessing whether its EGU maintains LEE status. We seek
comment on the adequacy of the restrictions associated with bypass
conditions regarding maintaining LEE status.
---------------------------------------------------------------------------
\2\ To the extent these EGUs bypassed their control devices
without measuring emissions, the hours of bypass operation would
need to be reported as hours of monitoring deviation and subject to
potential enforcement action.
---------------------------------------------------------------------------
8. Section 63.10000(c)(2)(iii) is revised to state that EGU owners
or operators who choose to use quarterly testing and parametric
monitoring for hydrogen fluoride (HF) or hydrogen chloride (HCl)
compliance must include the continuous monitoring systems (CMS) that
will be used in their site-specific monitoring plans to comply with the
monitoring requirements.
9. Section 63.10000(m) is added to clarify that EGU owners or
operators who choose to meet the work practice standards contained in
paragraph (2) of the definition of startup may verify, instead of
certify, monitoring systems used to generate data to meet the work
practice standards. Moreover, this addition clarifies that those
monitoring systems may be installed, verified, operated, maintained,
and quality assured using manufacturer's specifications.
10. Section 63.10001 is revised to remove the affirmative defense
provisions as explained in Section II below. The section is reserved.
11. Section 63.10005(a) is revised to clarify that different
compliance demonstrations may require different and additional types of
data collection and to clarify the date by which compliance must be
demonstrated for existing EGUs.
12. Section 63.10005(a)(2) is revised to clarify the date by which
compliance must be demonstrated for EGUs using CMS or sorbent trap
monitoring systems.
13. Section 63.10005(a)(2)(i) is revised to clarify applicability
of the provision to both the 30- and 90-boiler operating day
performance testing requirements.
14. Section 63.10005(b)(1) is revised to clarify the time period
allowed for existing EGUs to use stack test data collected prior to the
applicable compliance date.
15. Section 63.10005(b)(6) is added to clarify the date EGUs must
begin conducting required stack tests when stack test data collected
prior to the applicable compliance date are submitted to satisfy the
initial performance test requirement.
16. Section 63.10005(d)(3) and (d)(4)(i) is revised to more clearly
state when compliance must be demonstrated.
17. Section 63.10005(f) is revised to clarify when sources must
complete the initial boiler tune-up after the compliance date, and the
timing for subsequent tune-ups when a tune-up conducted prior to the
compliance date is used to satisfy the initial tune-up requirement.
18. Section 63.10005(h)(3) is revised to clarify that the alternate
30- and 90-day averaging provisions are both applicable to mercury (Hg)
emission limits, and to clarify the sampling probe location.
19. Section 63.10005(i)(4) is revised to delete paragraphs (iii)
and (iv). The identified test methods contain requirements for fuel
sampling, not determining fuel moisture content, as required in the
provision.
[[Page 8445]]
20. Section 63.10006(f) is revised to specify EGU operational
status with respect to performance testing; to identify the
requirements--including make-up testing and reporting--if the
performance testing schedule is missed apart from using existing skip
procedures; and to identify intervals between performance tests. The
final MATS rule had no provision that allowed an EGU owner or operator
to skip a required performance test if its EGU was otherwise not
operating; we did not believe the rule needed to be explicit in stating
that EGUs need not be turned on solely to conduct performance testing.
However, we have received questions regarding this circumstance. We
believe it is appropriate to allow an EGU owner or operator the ability
to skip a required performance test if its EGU is not otherwise
operating, and are proposing this in this action. The final MATS rule
had no provisions regarding make-up testing and reporting should a
regularly scheduled performance test be missed for reasons other than
the existing skip procedures. We believe it is appropriate to specify a
schedule for required make-up testing and reporting, and are proposing
such a schedule in this action. The final MATS rule specified the time
periods between performance tests, but EGU owners or operators
expressed concerns about being able to adhere to such a schedule. We
believe their concerns about having too tight a timeline for retesting
to occur and our concern about having a sufficient interval of time
between tests such that the results better reflect characteristics of
different periods can be addressed by specifying a minimum interval of
time between subsequent performance tests, which we are proposing in
this action. We welcome comments as to the need for, as well as
efficacy of, these proposed revisions, as well as on these proposed
intervals.
21. Section 63.10009(a)(2) and (a)(2)(i) is revised to clarify that
the 90-boiler operating day averaging period is available as an option
for Hg emissions from non-low rank virgin coal-fired EGUs (i.e., EGUs
in the subcategory ``unit designed for coal >=8,300 Btu/lb''). In the
final MATS (77 FR 9303 at 9385), we had indicated that we were
providing the 90-boiler operating day averaging period as an
alternative compliance approach (to the standard 30-boiler operating
day averaging period) for Hg emissions from EGUs in that subcategory.
However, the regulatory text in 40 CFR 63.10009(a)(2) did not clearly
reflect this option.
The term ``gross electric output'' is also corrected to ``gross
output'' which is the term defined in 40 CFR 63.10042.
22. Section 63.10009(b)(1) is revised to clarify group eligibility
equations 1a and 1b. These equations were developed to provide EGU
owners or operators a quick method for determining if their emissions
averaging group could meet the emissions limit when operated at the
maximum rated heat input and, in some cases, steam production.
Commenters reported difficulty in using the equations in the final
rule, so the equations have been revised so that individual EGU
characteristics, whether from CEMS or stack testing results, are easier
to input. We request comment on the proposed revisions concerning their
usefulness in calculating the maximum potential emissions rate from an
emissions averaging group. The term ``gross electric output'' is also
corrected to ``gross output'' which is the term defined in 40 CFR
63.10042.
23. Section 63.10009(b)(2) and (3) is revised to correct the term
``gross electric output'' to ``gross output'' which is the term defined
in 40 CFR 63.10042.
24. Section 63.10009(f) is revised to clarify the conditions for
determining the ability of the emissions averaging group to meet the
emissions limit and to clarify use of the alternate Hg emission limit.
Instead of relying on the maximum normal operating load of each EGU in
determining the ability of the emissions averaging group to demonstrate
initial compliance, as was contained in the final MATS rule, we are
proposing in this action to use the maximum possible heat input or
gross output of each EGU in determining the ability of the emission
averaging group to demonstrate initial compliance. In addition, instead
of calculating the maximum weighted average emissions rate, as used in
the final MATS rule, we are proposing in this action to calculate the
initial weighted average emissions rate. Finally, instead of specifying
just one date for submitting an emissions averaging plan, as was done
in the final MATS rule, we are proposing in this action to allow an EGU
owner or operator the flexibility to choose other dates to begin using
an emissions averaging plan by allowing the submission of an emissions
averaging plan at least 120 days before the date on which emissions
averaging is to begin. We believe these changes will provide additional
flexibility without undermining the enforceability of the final
standards.
25. Section 63.10009(f)(2), (g)(1), (g)(2), and (j)(1)(ii) is
revised to correct the term ``gross electric output'' to ``gross
output'' which is the term defined in 40 CFR 63.10042.
26. Section 63.10010(a)(4) is revised to add a requirement to route
exhaust gases that bypass emissions control devices through stacks that
contain monitoring so that emissions can be measured and to clarify
that hours that a bypass stack is in use are to be counted as hours of
deviation from monitoring requirements.
27. Section 63.10010(f)(3) is revised to clarify that 30-boiler
operating day rolling averages are to be based only on valid hourly
SO2 emission rates.
28. Section 63.10010(h)(6)(i) and (ii), (i)(5)(A) and (B), and
(j)(4)(i)(A) and (B) is revised to clarify that data collected during
certain periods are not to be included in compliance assessments but
such periods are to be included in annual deviation reports. The final
MATS rule established that all data collected with PM CPMS, PM CEMS,
and HAP metals CEMS during all boiler operating hours were to be used
in assessing compliance except those data collected during monitoring
system malfunctions, repairs associated with monitoring system
malfunctions, required quality assurance or quality control activities,
or monitoring out-of-control periods. In addition, the final MATS rule
sections combined the requirement to report the periods when data
collected during these operating periods as deviations into one long
sentence. In this action, we are proposing to separate these
requirements into two sentences to ease readability.
29. Section 63.10010(l)(i) is revised to replace the incorrect
reference to Sec. 63.7(e) with the correct reference to Sec.
63.8(d)(2).
30. Section 63.10010(l) and (l)(4) is revised to clarify that EGU
owners or operators who choose to meet the work practice standards
contained in paragraph (2) of the definition of startup may verify,
instead of certify, monitoring systems used to generate data to meet
the work practice standards. Moreover, this revision clarifies that
those monitoring systems may be installed, verified, operated,
maintained, and quality assured using manufacturer's specifications.
31. Section 63.10011(b) is revised to remove the incorrect
reference to Table 4 and to replace the incorrect reference to Table 7
with the correct reference to Table 6.
32. Section 63.10011(c)(1) and (2) is revised to clarify the date
by which compliance must be demonstrated by EGUs that use CEMS or
sorbent trap monitoring systems. In addition, Sec. 63.10011(c)(1) is
revised to clarify that
[[Page 8446]]
the alternate Hg emission limit may be used.
33. Section 63.10011(e) is revised to replace ``according to'' with
``in accordance with.''
34. Section 63.10011(g)(4)(v)(A) and Table 3 are revised to clarify
our intent regarding clean fuel use ``to the maximum extent possible.''
Our goal in the work practice is to minimize HAP emissions during
startup and shutdown periods, and that goal can be accomplished by
minimizing primary fuel use and maximizing clean fuel use because of
the inherently low HAP content of the defined ``clean fuels.'' As
stated in the preamble to the final startup and shutdown
reconsideration rule, EGUs that chose to comply with the alternative
work practice will be required to have sufficient clean fuel capacity
to startup and warm the facility to the point where the primary PM
controls can be brought on line at the same time as, or within 1 hour
of, the addition of the primary fuel to the EGU. 79 FR 68777 at 68779,
November 19, 2014. We recognize that the clean fuel requirement may
require sources to increase clean fuel capacity, modify the startup
burners, and/or take additional actions to comply with the final rule.
79 FR 68777 at 68779, November 19, 2014. Thus, we expect clean fuels to
be combusted in at least the amount needed to bring the emissions
control devices to operational levels necessary to comply with the
numeric standards at the end of startup. We do not expect clean fuel
use to the extent that it compromises the integrity of the boiler or
its control devices; neither do we expect clean fuel to be combusted in
excess of the amount needed to bring the emissions control devices to
expected operational levels. We have determined that it is appropriate
to slightly revise the language in the November 19, 2014, final rule.
79 FR 68777. The proposed revision would change the language from ``to
the maximum extent possible'' to ``to the maximum extent practicable,
taking into account boiler or control device integrity.''
35. Section 63.10020(e) is revised to clarify that it applies only
to those EGU owners or operators who choose to meet the work practice
standards contained in paragraph (2) of the definition of startup. In
addition, the undefined term ``electrical load'' has been replaced with
the defined term ``gross output'' and the incorrect terms ``liquid to
fuel ratio'' and ``the differential pressure of the liquid'' in Sec.
63.10020(e)(3)(i)(E) have been replaced with the correct terms ``liquid
to flue gas ratio'' and ``the pressure drop across the scrubber.''
Finally, in order to clarify our intent that existing instrumentation
or engineering calculations can be used to provide flow information,
Sec. 63.10020(e)(3)(i)(A) and (B) is revised to remove the term
``rate'' and to acknowledge the use of existing combustion air flow
monitors or combustion equations.
36. Section 63.10021(d)(3) is revised to clarify the type of
monitoring that is to be used to demonstrate compliance.
37. Section 63.10021(e) is revised to clarify the condition that
allows delay of burner inspections for initial boiler tune-ups.
38. Section 63.10021(e)(9)(i) and (ii) is revised to clarify the
dates that tune-ups must be reported.
39. Section 63.10023(b) and Table 6 are revised to clarify that all
EGUs using PM continuous parametric monitoring systems (CPMS) for
compliance purposes are to follow the same procedure for determining
the operating limit. The final rule allowed existing EGUs to determine
the operating limit based on the highest 1-hour average PM CPMS value
recorded during a performance test, even if that average time was
associated with a test run in excess of the numeric standards, while
new EGUs were required to use a scaling factor or the average PM CPMS
value recorded during the PM compliance test demonstrating compliance
with the PM limit to establish the operating limit.\3\ We believe all
EGUs should use a consistent set of procedures for both new and
existing EGUs for establishing an operating PM limit, so we are
proposing in this action to revise the procedures for existing EGUs.
The procedures for existing EGUs, contained in Sec. 63.10023(b)(1) are
reserved, and Sec. 63.10023(b)(2) and Table 6 are revised so that all
EGUs are to follow the operating limit development procedures for new
EGUs (i.e., use a scaling factor or the average PM CPMS value recorded
during the PM compliance test demonstrating compliance with the PM
limit to establish the operating limit).
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\3\ See the description of the ``third approach'' at 79 FR 24708
(April 24, 2013).
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40. Section 63.10030(e)(1) is revised to replace the phrase
``identification of which subcategory the source is in'' with
``identification of the subcategory of the source.''
41. Section 63.10030(e)(7)(i) is revised to clarify that the date
of each stack test conducted for purposes of demonstrating LEE
eligibility is to be provided. The final rule establishes that each
test for pollutants other than Hg conducted over a 3-year period must
meet the LEE emission limit in order for an EGU to be eligible for LEE
status.
42. Section 63.10030(e)(7)(iii) is added to establish the
procedures by which an EGU owner or operator may switch between mass
per heat input and mass per gross output emission limits. The EPA has
received questions about how frequently an existing EGU could alternate
between the two compliance formats. Although we did not envision that
an owner or operator of an existing EGU would want to change the basis
of the EGU's emission limits, we believe it is reasonable to allow such
action provided certain conditions, including performance testing
demonstrating compliance with the new format, submission of a written
request to change formats, and receipt of permission from the
Administrator to change formats, are met. We request comment on these
procedures, as well as on the concept of switching emission limits,
particularly during performance averaging periods.
43. Section 63.10030(e)(8)(i) is revised to clarify that it applies
only to those EGU owners or operators who choose to meet the work
practice standards contained in paragraph (2) of the definition of
startup. Moreover, the provisions requiring a description of PM control
device efficiencies and PM emission rates are revised to clarify that
such efficiencies and emission rates are those of periods other than
startup and shutdown periods. As the uncontrolled emission rates can be
calculated from control device efficiencies and corresponding emission
rates, the provisions requiring reporting of uncontrolled emission
rates have been removed.
In addition, as current EGU characteristics are most relevant for
compliance with the MATS rule, the requirements concerning
identification of intermediate changes to the EGU design have been
removed. In order to reduce redundant reporting, the rule has been
revised to require no additional identification if no changes to the
EGU's design characteristics have occurred.
Finally, Sec. 63.10030(e)(8)(ii)(A) has been revised to remove the
requirement for use of an independent professional engineer. Consistent
with the discussion contained in 71 FR 16869 (April 4, 2006), we
believe that a professional engineer, regardless of whether they are
independent, is able to give a fair technical review because of the
programs established by the state licensing boards, which serve to
enforce objectivity from each registrant. We believe that the revision
will allow EGUs to reduce burden without compromising environmental
safety by
[[Page 8447]]
using in-house expertise. Professional engineers employed by an EGU
should be more familiar with its design and operational characteristics
and should be in a position to expedite collection and submission of
required information.
44. Section 63.10030(f) is revised to add notification requirements
for EGUs that move in and out of MATS applicability.
45. Section 63.10031(c)(4) is revised to clarify the reporting
requirements for EGU tune-ups.
46. Section 63.10031(c)(5) is revised to clarify that it applies
only to those EGU owners or operators who choose to meet the work
practice standards contained in paragraph (2) of the definition of
startup.
47. Section 63.10031(c)(6) is revised to add emergency bypass
reporting for EGUs with LEE status.
48. Section 63.10031(f)(5) is revised to state that the
Administrator retains the right to require submittal of reports subject
to paragraph (f)(4), as well as paragraphs (f)(1) through (3).
49. Section 63.10032(f) is revised to clarify that the requirements
of Sec. 63.10032(f)(1) apply only to those EGU owners or operators who
choose to meet the work practice standards contained in paragraph (1)
of the definition of startup, while the requirements of Sec.
63.10032(f)(2) apply only to those EGU owners or operators who choose
to meet the work practice standards contained in paragraph (2) of the
definition of startup.
50. The definitions of ``Coal-fired electric utility steam
generating unit,'' ``Coal refuse,'' ``Fossil fuel-fired,'' ``Integrated
gasification combined cycle electric utility steam generating unit or
IGCC,'' ``Limited-use liquid oil-fired subcategory,'' ``Natural gas-
fired electric utility steam generating unit,'' and ``Oil-fired
electric utility steam generating unit'' in Sec. 63.10042 are revised
to clarify the period of time to be included in determining the
source's applicability to the MATS.
During the comment period on the proposed MATS rule, industry noted
that many EGUs would convert to natural gas or other non-fossil fuel
prior to the compliance date and those sources would remain subject to
MATS because the proposed rule required sources to determine
applicability based on the 3 calendar years prior to the compliance
date. See, e.g., 40 CFR 63.10042 (definition of ``fossil fuel-fired'').
The EPA agreed that this was not the EPA's intent and in the final MATS
rule revised several definitions, including the definition of fossil
fuel-fired, that required sources to evaluate usage after the
applicable compliance date.
The EPA inadvertently created confusion in its attempt to address
industry concerns in the final MATS rule. The confusion is best
illustrated by an analysis of the proposed and final definitions of
``fossil fuel-fired.'' The EPA's proposed definition stated, in part,
that ``[i]n addition, fossil fuel-fired means any EGU that fired fossil
fuel for more than 10.0 percent of the average annual heat input during
the previous 3 calendar years or for more than 15.0 percent of the
annual heat input during any one of those calendar year.'' See 76 FR
24975 at 25123 (emphasis added). The intent in this definition was to
require sources to look at the usage from the 3 previous years to
determine if the average or the single year usage from those 3 years
exceeded either of the thresholds.
To address the commenters' concern, the EPA revised the definition
of ``fossil fuel-fired'' in the final rule to state, in part, that
``[i]n addition, fossil fuel-fired means any EGU that fired fossil
fuels for more than 10.0 percent of the average annual year input
during any 3 consecutive calendar years or for more than 15.0 percent
of the annual heat input during any one calendar year after the
applicable compliance date.'' 40 CFR 63.10042 (emphasis added). This
definition creates at least two potential compliance issues: (1) It
creates confusion as to how sources are to determine MATS applicability
during the first 3 years after the applicable compliance date; and (2)
it subjects sources to MATS in perpetuity if the usage thresholds are
ever exceeded after the compliance date--``any 3 consecutive calendar
years'' or ``any one calendar year'' ``after the applicable compliance
date.''
The proposed revisions to the definitions address both issues.
Concerning applicability in the first 3 years after the applicable
compliance date, this proposed rule states that sources must project
their coal and oil usage for the first 3 years to determine whether the
EGU will exceed either the 10.0 or 15.0 percent threshold. The EPA's
understanding is that sources know with sufficient specificity the
fuels they will use in advance, and requiring sources to project their
usage accommodates industry concerns that the sources that are
converting to natural gas or biomass prior to the compliance date not
be subject to MATS. The EPA is also proposing that sources that
permanently convert to natural gas or biomass after the compliance date
are no longer subject to MATS, notwithstanding the coal or oil usage
the previous 3 calendar years.
The EPA is also proposing to revise the definitions to make clear
that after the first 3 years of compliance, EGUs are required to
evaluate applicability based on coal or oil usage from the 3 previous
calendar years on an annual rolling basis, consistent with the
definition of ``fossil fuel-fired'' proposed in the MATS rule. This
proposed change will prevent EGUs from being subject to MATS in
perpetuity if they exceed the 10 or 15 percent threshold at any time
after the compliance date.
A definition of ``neural network'' is also being added because the
term is used in 40 CFR 63.10005(f), 63.10006(i), and 63.10021(e) and
Table 3 to subpart UUUUU of Part 63 but is not defined.
51. Table 1 to subpart UUUUU of Part 63 is revised to correct the
term ``gross electric output'' to ``gross output'' which is the term
defined in 40 CFR 63.10042 in footnotes 1, 4, and 5.
52. Table 2 to subpart UUUUU of Part 63 is revised to correct the
term ``gross electric output'' to ``gross output'' which is the term
defined in 40 CFR 63.10042 in footnote 2. Provision 1(c) (the Hg limit
for EGUs in the subcategory ``unit designed for coal >=8,300 Btu/lb'')
is also revised to clarify the applicability of the alternate 90-boiler
operating day compliance option.
53. Table 3 to subpart UUUUU of Part 63 is revised as described
earlier to clarify the term ``maximum extent possible.''
In addition, we have received questions concerning the
interpretation of the definition of startup, particularly the language
defining the end of startup. Industry has inquired whether the
triggering action is either the generation of electricity or of steam
for any useful purpose under both definitions of startup. The EPA does
interpret the end of startup in a consistent manner as between the two
definitions. Specifically, we interpret the phrase ``. . . when any of
the steam from the boiler is used . . . for any other purpose,''
contained in paragraph (1) of the definition of startup, to have the
same meaning as the phrase ``for industrial, commercial, heating, or
cooling purposes (other than the first-ever firing of fuel in a boiler
following construction of the boiler,'' as provided in paragraph (2) of
the definition of startup. EGUs trigger the end of startup whenever
they use either electricity or steam for any useful purpose either on
or offsite.
54. Table 4 to subpart UUUUU of Part 63 is revised to clarify that
existing as well as new EGUs using PM CPMS share the same procedures
for
[[Page 8448]]
developing operating limits (i.e., those that are based on the higher
of a parameter scaled from all values obtained during an individual
emissions test to 75 percent of the emissions limit or the average
parameter value obtained from all runs of an individual emission test
as the operating limit provided that the result of the individual
emissions test met the emissions limit requirements).
55. Table 5 to subpart UUUUU of Part 63 is revised to state that
when using Method 5, you are to report the average of the final 2
filter weighings, and to clarify that when using Method 29, you are to
report the metals matrix spike and recovery levels. These provisions
are needed for the required electronic reporting.
56. Table 6 to subpart UUUUU of Part 63 is revised to clarify that
existing, as well as new, EGUs using PM CPMS share the same procedures
for developing operating limits (i.e., those that are based on the
higher of a parameter scaled from all values obtained during an
individual emissions test to 75 percent of the emissions limit or the
average parameter value obtained from all runs of an individual
emission test as the operating limit provided that the result of the
individual emissions test met the emissions limit).
57. Table 8 to subpart UUUUU of Part 63 is revised to clarify that
compliance reports are to include information required by Sec.
63.10031(c)(5) and (6).
58. Table 9 to subpart UUUUU of Part 63 is revised to correct an
inadvertent omission of 30-day notification requirements of Sec. 63.9.
59. Paragraphs 4.1.1.3 and 5.1.2.3 and Tables A-1 and A-2 to
Appendix A to subpart UUUUU of Part 63 are revised to adjust Hg CEMS
language regarding converters. Research has shown that all Hg CEMS need
weekly single-level system integrity checks.
60. Paragraph 7.1.2.5 to Appendix A to subpart UUUUU of Part 63 is
added to require that owners or operators flag EGUs that are part of
emission averaging groups.
61. Paragraph 3.2.1.2.1 of Appendix A to subpart UUUUU of Part 63
is revised to specifically indicate that Hg gas generators and
cylinders are allowed.
62. Paragraphs 4.1.1.1, Table A-1, Table A-2, 5.1.2.1, and 4.1.1.3
of Appendix A to subpart UUUUU of Part 63 are revised to exclude use of
oxidized Hg gas standards for daily calibration of Hg CEMS.
63. Paragraph 5.1.2.3 of Appendix A to subpart UUUUU of Part 63 is
revised to make the weekly single level system integrity check
mandatory.
64. Paragraphs 4.1.1.5.2, Table A-1, Table A-2, and 4.1.1.5 of
Appendix A to subpart UUUUU of Part 63 are revised to provide an
alternative relative accuracy test audit (RATA) procedure for EGUs with
low emissions that is related specifically to the emission standard.
65. Paragraph 5.2.1 of Appendix A to subpart UUUUU of Part 63 is
revised to correct the number of days for sorbent trap use from 14 to
15.
66. Paragraph 6.2.2.3 of Appendix A to subpart UUUUU of Part 63 is
revised to clarify that the 90-day alternative Hg standard may be used
and that electrical output is gross output.
67. Paragraph 7.1.2.6 of Appendix A to subpart UUUUU of Part 63 is
added to clarify that EGU owners or operators are to keep records of
their EGUs that constitute emissions averaging groups.
68. Paragraphs 2.1, 2.3, 2.3.1, 2.3.2, 3.1, 3.2, 3.3, 5, 5.1, 5.2,
and 5.3 of Appendix B to subpart UUUUU of Part 63 are revised to
clarify that use of Performance Specification (PS) 18, a proposed
technology-neutral PS for HCl CEMS which will soon be promulgated, will
be allowed. Consistent with our statements in the final rule, we expect
that PS 18 will likely be promulgated in advance of the rule's
compliance date. An EGU owner or operator who wishes to use proposed PS
18, along with quality assurance (QA) procedure 6, prior to their
promulgation dates is welcome to submit an alternative monitoring
request in accordance with the requirements of Sec. 63.8(f) for use of
proposed PS 18 and QA Procedure 6 to us.
69. Paragraph 5.4 of Appendix B to subpart UUUUU of Part 63 is
added as part of the renumbering due to the addition of PS 18.
70. Paragraph 8 of Appendix B to subpart UUUUU of Part 63 is
revised to accommodate use of PS 18.
71. Paragraphs 10.1.8, 10.1.8.1, 10.1.8.1.1, and 10.1.8.1.2 of
Appendix B to Subpart UUUUU of Part 63 are revised as part of the
renumbering due to the addition of PS 18.
72. Paragraph 10.1.8.1.3 of Appendix B to Subpart UUUUU of Part 63
is revised to clarify that records of relative accuracy audits (RAAs)
are also required.
73. Paragraphs 10.1.8.2, 10.1.8.1.2.1, and 10.1.8.1.2.2 of Appendix
B to Subpart UUUUU of Part 63 are revised to clarify the quarterly gas
audit recordkeeping requirements for PS 15 and the quarterly data
accuracy assessments for PS 18 (which are reserved).
74. Paragraph 11.4 of Appendix B to Subpart UUUUU of Part 63 is
revised to replace the incorrect abbreviation ``i.e.'' with ``e.g.''
75. Paragraph 11.4.2 of Appendix B to Subpart UUUUU of Part 63 is
revised to specify the requirements of the daily beam intensity checks
for EGUs using PS 18.
76. Paragraphs 11.4.2.1, 11.4.2.2, 11.4.2.3, 11.4.2.4, 11.4.2.5,
11.4.2.6, 11.4.2.7, 11.4.2.8, 11.4.2.9, 11.4.2.10, 11.4.2.11,
11.4.2.12, and 11.4.2.13 of Appendix B to Subpart UUUUU of Part 63 are
revised to hold the requirements of the daily beam intensity checks for
PS 18 (which are reserved).
77. Paragraph 11.4.3 of Appendix B to Subpart UUUUU of Part 63 is
revised to reflect the reporting requirements for PS 15.
78. Paragraphs 11.4.3.1, 11.4.3.2, 11.4.3.3, 11.4.3.4, 11.4.3.5,
11.4.3.6, 11.4.3.7, 11.4.3.8, 11.4.3.9, 11.4.3.10, 11.4.3.11,
11.4.3.12, and 11.4.3.13 of Appendix B to Subpart UUUUU of Part 63 are
revised to include PS 15 reporting requirements.
79. Paragraph 11.4.4 of Appendix B to Subpart UUUUU of Part 63 is
revised to reserve the reporting requirements for quarterly parameter
verification checks for PS 18.
80. Paragraphs 11.4.4.1, 11.4.5, 11.4.5.1, 11.4.6, 11.4.6.1 of
Appendix B to Subpart UUUUU of Part 63 are added to reserve the
reporting requirements for quarterly gas audit information and for
quarterly dynamic spiking for PS 18.
81. Paragraph 11.4.7 of Appendix B to Subpart UUUUU of Part 63 is
added to include reporting requirements for RAAs.
82. Paragraphs 11.4.7.1, 11.4.7.2, 11.4.7.3, 11.4.7.4, 11.4.7.5,
11.4.7.6, 11.4.7.7, 11.4.7.8, 11.4.7.9, 11.4.7.10, 11.4.7.11,
11.4.7.12, and 11.4.7.13 of Appendix B to Subpart UUUUU of Part 63 are
added as part of the renumbering due to the addition of PS 18.
83. Paragraph 11.5.3.4 of Appendix B to Subpart UUUUU of Part 63 is
revised to include reporting requirements for beam intensity checks for
PS 18.
II. Affirmative Defense for Violation of Emission Standards During
Malfunction
In several prior CAA section 112 and CAA section 129 rules,
including this rule, the EPA included an affirmative defense to civil
penalties for violations caused by malfunctions in an effort to create
a system that incorporates some flexibility, recognizing that there is
a tension, inherent in many types of air regulation, to ensure adequate
compliance while simultaneously recognizing that despite the most
diligent of efforts, emission standards may be violated under
circumstances
[[Page 8449]]
entirely beyond the control of the source. Although the EPA recognized
that its case-by-case enforcement discretion provides sufficient
flexibility in these circumstances, it included the affirmative defense
to provide a more formalized approach and more regulatory clarity. See
Weyerhaeuser Co. v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978)
(holding that an informal case-by-case enforcement discretion approach
is adequate); but see Marathon Oil Co. v. EPA, 564 F.2d 1253, 1272-73
(9th Cir. 1977) (requiring a more formalized approach to consideration
of ``upsets beyond the control of the permit holder.''). Under the
EPA's regulatory affirmative defense provisions, if a source could
demonstrate in a judicial or administrative proceeding that it had met
the requirements of the affirmative defense in the regulation, civil
penalties would not be assessed. Recently, the United States Court of
Appeals for the District of Columbia Circuit vacated an affirmative
defense in one of the EPA's CAA section 112 regulations. NRDC v. EPA,
749 F.3d 1055 (D.C. Cir., 2014) (vacating affirmative defense
provisions in CAA section 112 rule establishing emission standards for
Portland cement kilns). The court found that the 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 in
such cases lies exclusively with the courts, not the EPA. Specifically,
the court found: ``As the language of the statute makes clear, the
courts determine, on a case-by-case basis, whether civil penalties are
`appropriate.' '' See NRDC, 749 F.3d at 1063 (``[U]nder this statute,
deciding whether penalties are `appropriate' . . . is a job for the
courts, not EPA.'').
In light of NRDC, the EPA is proposing to remove the regulatory
affirmative defense provision in the current rule. As explained above,
if a source is unable to comply with emissions standards as a result of
a malfunction, the EPA may use its case-by-case enforcement discretion
to provide flexibility, 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. Cf. NRDC, at 1064 (arguments that violation
were caused by unavoidable technology failure can be made to the courts
in future civil cases when the issue arises). The same is true for the
presiding officer in EPA administrative enforcement actions.
III. Statutory and Executive Order Reviews
Additional information about these statutes and Executive Orders
can be found at https://www2.epa.gov/laws-regulations/laws-and-executive-orders.
A. Executive Order 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review
This action is not a significant regulatory action and was,
therefore, not subject to review by the Office of Management and Budget
(OMB).
B. Paperwork Reduction Act (PRA)
This action does not impose any new information collection burden.
This action clarifies but does not change the information collection
requirements previously finalized and, as a result, does not impose any
additional burden on industry. The OMB has previously approved the
information collection requirements contained in the existing
regulations (see 77 FR 9303, February 16, 2012) under the provisions of
the PRA, 44 U.S.C. 3501 et seq. and has assigned OMB control number
2060-0567. The OMB control numbers for the EPA's regulations are listed
in 40 CFR part 9.
C. Regulatory Flexibility Act (RFA)
I certify that this action will not have a significant economic
impact on a substantial number of small entities. The EPA has
determined that none of the small entities will experience a
significant impact because the action imposes no additional regulatory
requirements on owners or operators of affected sources.
D. Unfunded Mandates Reform Act (UMRA)
This action does not contain an unfunded mandate as described in 2
U.S.C. 1531-1538, and does not significantly or uniquely affect small
governments. The action imposes no enforceable duty on any state,
local, or tribal governments or the private sector.
E. Executive Order 13132: Federalism
This action does not have federalism implications. It 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.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications as specified in
Executive Order 13175. This action does not significantly or uniquely
affect the communities of tribal governments. Thus, Executive Order
13175, does not apply to this action.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action is not subject to
Executive Order 13045 because it does not concern an environmental
health risk or safety risk.
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution or Use
This action is not subject to Executive Order 13211 because it is
not a significant regulatory action under Executive Order 12866.
I. National Technology Transfer and Advancement Act (NTTAA)
This rulemaking does not involve technical standards.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA believes the human health or environmental risk addressed
by this action will not have potential disproportionately high and
adverse human health or environmental effects on minority, low-income
or indigenous populations. The corrections do not involve special
consideration of environmental justice-related issues as required by
Executive Order 12898, and an evaluation was not necessary for this
action.
The EPA's compliance with the above statutes and Executive Orders
for the underlying rule is discussed in the February 16, 2012, Federal
Register document containing ``National Emission Standards for
Hazardous Air Pollutants from Coal- and Oil-fired Electric Utility
Steam Generating Units and Standards of Performance for Fossil-Fuel-
Fired Electric Utility, Industrial-Commercial-Institutional, and Small
Industrial-Commercial-
[[Page 8450]]
Institutional Steam Generating Units.'' (77 FR 9303).
List of Subjects
40 CFR Part 60
Environmental protection, Administrative practice and procedure,
Air pollution control, Incorporation by reference, Intergovernmental
relations, Reporting and recordkeeping requirements.
40 CFR Part 63
Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Incorporation by
reference, Intergovernmental relations, Reporting and recordkeeping
requirements.
Dated: December 19, 2014.
Gina McCarthy,
Administrator.
For the reasons discussed in the preamble, the EPA proposes to
correct and amend 40 CFR parts 60 and 63 to read as follows:
PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES
0
1. The authority citation for part 60 continues to read as follows:
Authority: 42 U.S.C. 7401 et seq.
0
2. Section 60.48Da is amended by revising paragraph (f) to read as
follows:
Sec. 60.48Da Compliance provisions.
* * * * *
(f) For affected facilities for which construction, modification,
or reconstruction commenced before May 4, 2011, compliance with the
applicable daily average PM emissions limit is determined by
calculating the arithmetic average of all hourly emission rates each
boiler operating day, except for data obtained during startup,
shutdown, or malfunction periods. Daily averages are only calculated
for boiler operating days that have non-out-of-control data for at
least 18 hours of unit operation during which the standard applies.
Instead, all of the non-out-of-control hourly emission rates of the
operating day(s) not meeting the minimum 18 hours non-out-of-control
data daily average requirement are averaged with all of the non-out-of-
control hourly emission rates of the next boiler operating day with 18
hours or more of non-out-of-control PM CEMS data to determine
compliance. For affected facilities for which construction or
reconstruction commenced after May 3, 2011 that elect to demonstrate
compliance using PM CEMS, compliance with the applicable PM emissions
limit in Sec. 60.42Da is determined on a 30-boiler operating day
rolling average basis by calculating the arithmetic average of all
hourly PM emission rates for the 30 successive boiler operating days,
except for data obtained during periods of startup and shutdown.
* * * * *
PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES
0
3. The authority citation for part 63 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
0
4. Section 63.9983 is amended by:
0
a. Revising the section heading and paragraphs (a), (b), and (c); and
0
Adding paragraph (e).
The revisions and addition read as follows:
Sec. 63.9983 Are any fossil fuel-fired electric generating units not
subject to this subpart?
* * * * *
(a) Any unit designated as a major source stationary combustion
turbine subject to 40 CFR part 63, subpart YYYY and any unit designated
as an area source stationary combustion turbine, other than an
integrated gasification combined cycle (IGCC) unit.
(b) Any electric utility steam generating unit that is not a coal-
or oil-fired EGU and that meets the definition of a natural gas-fired
EGU in Sec. 63.10042.
(c) Any electric utility steam generating unit that has the
capability of combusting more than 25 MW of coal or oil but does not
meet the definition of a coal- or oil-fired EGU because it did not fire
sufficient coal or oil to satisfy the average annual heat input
requirement set forth in the definitions for coal-fired and oil-fired
EGUs in Sec. 63.10042. Heat input means heat derived from combustion
of fuel in an EGU and does not include the heat derived from preheated
combustion air, recirculated flue gases or exhaust gases from other
sources (such as stationary gas turbines, internal combustion engines,
and industrial boilers).
* * * * *
(e) Any electric utility steam generating unit that meets the
definition of a natural gas-fired EGU under this subpart and that fires
at least 10 percent biomass is an industrial boiler subject to
standards established under 40 CFR part 63, subpart DDDDD, if it
otherwise meets the applicability provisions in that rule.
0
5. Section 63.9991 is amended by revising paragraphs (c)(1) and (2) to
read as follows:
Sec. 63.9991 What emission limitations, work practice standards, and
operating limits must I meet?
* * * * *
(c) * * *
(1) Has a system using wet or dry flue gas desulfurization
technology and an SO2 continuous emissions monitoring system
(CEMS) installed on the EGU; and
(2) At all times, you operate the wet or dry flue gas
desulfurization technology and the SO2 CEMS installed on the
EGU consistent with Sec. 63.10000(b).
0
6. Section 63.10000 is amended by:
0
a. Revising paragraph (c)(1)(i);
0
b. Revising paragraph (c)(2)(iii); and
0
c. Adding paragraph (m).
The revisions and additions read as follows:
Sec. 63.10000 What are my general requirements for complying with
this subpart?
* * * * *
(c)(1) * * *
(i) For a coal-fired or solid oil-derived fuel-fired EGU or IGCC
EGU, you may conduct initial performance testing in accordance with
Sec. 63.10005(h), to determine whether the EGU qualifies as a low
emitting EGU (LEE) for one or more applicable emission limits, except:
(A) You may not pursue the LEE option if your coal-fired, IGCC, or
solid oil-derived fuel-fired EGU is equipped with a main stack and a
bypass stack exhaust configuration that allows the EGU to bypass any
pollutant control device.
(B) You may not pursue the LEE option for Hg if your coal-fired,
solid oil-derived fuel-fired EGU or IGCC EGU is new.
(C) Notwithstanding paragraph (c)(1)(i)(A) of this section, you may
pursue the LEE option provided:
(1) Your control device bypass stack is routed through the EGU main
stack so that emissions are measured during the bypass event; or
(2) You bypass your EGU control device only during emergency
periods for no more than a total of 2 percent of your EGU's annual
operating hours; you use clean fuels to the maximum extent practicable
during an emergency period; and you prepare and submit a report
describing the emergency event, its cause, corrective action taken, and
estimates of emissions released during the emergency event. You must
include these emergency emissions along with performance test results
in assessing
[[Page 8451]]
whether your EGU maintains LEE status.
* * * * *
(2) * * *
(iii) If your existing liquid oil-fired unit does not qualify as a
LEE for hydrogen chloride (HCl) or for hydrogen fluoride (HF), you may
demonstrate initial and continuous compliance through use of an HCl
CEMS, an HF CEMS, or an HCl and HF CEMS, installed and operated in
accordance with Appendix B to this rule. As an alternative to HCl CEMS,
HF CEMS, or HCl and HF CEMS, you may demonstrate initial and continuous
compliance through quarterly performance testing and parametric
monitoring for HCl and HF. If you choose to use quarterly testing and
parametric monitoring, then you must also develop a site-specific
monitoring plan that identifies the CMS you will use to ensure that the
operations of the EGU remains consistent with those during the
performance test. As another alternative, you may measure or obtain,
and keep records of, fuel moisture content; as long as fuel moisture
does not exceed 1.0 percent by weight, you need not conduct other HCl
or HF monitoring or testing.
* * * * *
(m) Should you choose to rely on paragraph (2) of the definition of
``startup'' in Sec. 63.10042 for your EGU, on or before the date your
EGU is subject to this subpart, you must install, verify, operate,
maintain, and quality assure each monitoring system necessary for
demonstrating compliance with the work practice standards for PM or
non-mercury HAP metals controls during startup periods and shutdown
periods required to comply with Sec. 63.10020(e).
(1) You may rely on monitoring system specifications or
instructions or manufacturer's specifications when installing,
verifying, operating, maintaining, and quality assuring each monitoring
system.
(2) You must collect, record, report, and maintain data obtained
from these monitoring systems during startup periods and shutdown
periods.
Sec. 63.10001 [Removed and reserved]
0
7. Section 63.10001 is removed and reserved.
0
8. Section 63.10005 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(2) introductory text
and (a)(2)(i);
0
b. Revising paragraph (b)(1);
0
c. Adding paragraph (b)(6);
0
d. Revising paragraphs (d)(3), (d)(4)(i);
0
f. Revising paragraph (f);
0
g. Revising paragraph (h) introductory text, and (h)(3) introductory
text;
0
h. Removing paragraphs (i)(4)(iii) and (iv).
The revisions and additions read as follows:
Sec. 63.10005 What are my initial compliance requirements and by what
date must I conduct them?
(a) General requirements. For each of your affected EGUs, you must
demonstrate initial compliance with each applicable emissions limit in
Table 1 or 2 of this subpart through performance testing. Where two
emissions limits are specified for a particular pollutant (e.g., a heat
input-based limit in lb/MMBtu and an electrical output-based limit in
lb/MWh), you may demonstrate compliance with either emission limit. For
a particular compliance demonstration, you may be required to conduct
one or more of the following activities in conjunction with performance
testing: collection of data, e.g., hourly electrical load data
(megawatts); establishment of operating limits according to Sec.
63.10011 and Tables 4 and 7 to this subpart; and CMS performance
evaluations. In all cases, you must demonstrate initial compliance no
later than the date in paragraph (f) of this section for tune-up work
practices for existing EGUs; the date that compliance must be
demonstrated, as given in Sec. 63.9984 for other requirements for
existing EGUs; and in paragraph (g) of this section for all
requirements for new EGUs.
(1) * * *
(2) To demonstrate initial compliance using either a CMS that
measures HAP concentrations directly (i.e., an Hg, HCl, or HF CEMS, or
a sorbent trap monitoring system) or an SO2 or PM CEMS, the
initial performance test may occur on or before the first averaging
period (30- or, for certain coal-fired existing EGUs that use emissions
averaging for Hg, 90-boiler operating days) after the date that
compliance with this subpart is required but must occur such that the
averaging period is completed on or before the date that compliance
must be demonstrated.
(i) The CMS performance test must demonstrate compliance with the
applicable Hg, HCl, HF, PM, or SO2 emissions limit in Table
1 or 2 to this subpart.
* * * * *
(b) * * *
(1) For a performance test of an existing EGU based on stack test
data, the test was conducted between 180 and 365 calendar days prior to
the date that compliance must be demonstrated as specified in Sec.
63.9984.
* * * * *
(6) If the performance test data that are collected prior to the
date that compliance must be demonstrated are used to demonstrate
initial compliance with applicable emissions limits, the interval for
subsequent stack tests begins on the date that compliance must be
demonstrated.
* * * * *
(d) * * *
(3) For affected EGUs that are either required to or elect to
demonstrate initial compliance with the applicable Hg emission limit in
Table 1 or 2 of this subpart using Hg CEMS or sorbent trap monitoring
systems, initial compliance must be demonstrated no later than the
applicable date specified in Sec. 63.9984(f) for existing EGUs and in
paragraph (g) of this section for new EGUs. Initial compliance is
achieved if the arithmetic average of 30- (or 90-) boiler operating
days of quality-assured CEMS (or sorbent trap monitoring system) data,
expressed in units of the standard (see section 6.2 of appendix A to
this subpart), meets the applicable Hg emission limit in Table 1 or 2
to this subpart.
(4) * * *
(i) You must demonstrate initial compliance no later than the
applicable date specified in Sec. 63.9984(f) for existing EGUs and in
paragraph (g) of this section for new EGUs.
* * * * *
(f) For an existing EGU without a neural network, a tune-up must
occur on or before 180 days after April 16, 2015. For an existing EGU
with a neural network, a tune-up must occur on or before 180 days after
April 16, 2016. If a tune-up occurs prior to April 16, 2015, you must
keep records showing that the operating conditions remain the same and
that the tune-up met all rule requirements.
* * * * *
(h) Low emitting EGUs. The provisions of this paragraph (h) apply
to pollutants with emissions limits from new EGUs except Hg and to all
pollutants with emissions limits from existing EGUs. You may pursue
this compliance option unless prohibited pursuant to Sec.
63.10000(c)(1)(i).
* * * * *
(3) For Hg, you must conduct a 30- (or 90-) boiler operating day
performance test using Method 30B in appendix A-8 to part 60 of this
chapter to determine whether a unit qualifies for LEE status. Locate
the Method 30B sampling probe tip at a point within 10 percent of the
duct area centered about the duct's
[[Page 8452]]
centroid at a location that meets Method 1 in appendix A-1 to part 60
of this chapter and conduct at least three nominally equal length test
runs over the 30-boiler operating day test period. Collect Hg emissions
data continuously over the entire test period (except when changing
sorbent traps or performing required reference method QA procedures).
As an alternative to constant rate sampling per Method 30B, you may use
proportional sampling per section 8.2.2 of Performance Specification 12
B in appendix B to part 60 of this chapter.
* * * * *
0
9. Section 63.10006 is amended by revising paragraph (f) to read as
follows:
Sec. 63.10006 When must I conduct subsequent performance tests or
tune-ups?
* * * * *
(f) Time between performance tests. (1) Notwithstanding the
provisions of Sec. 63.10021(d)(1), the requirements listed in
paragraphs (g) and (h) of this section, and the requirements of
paragraph (f)(3) of this section, you must complete performance tests
for your EGU as follows:
(i) At least 45 calendar days must separate performance tests
conducted every quarter;
(ii) At least 370 calendar days must separate performance tests
conducted every year; and
(iii) At least 1,050 calendar days must separate performance tests
conducted every 3 years.
(2) Although you are not required to operate your EGU solely in
order to conduct a performance test, you must conduct a performance
test in the 4th quarter of a calendar year if your EGU has skipped
performance tests in the 3 quarters of the calendar year.
(3) If your EGU misses a performance test deadline due to being
inoperative and if you have at least 168 boiler operating hours in the
next test period, you must complete an additional performance test in
that period as follows:
(i) At least 15 calendar days must separate two performance tests
conducted in the same quarter.
(ii) At least 107 calendar days must separate two performance tests
conducted in the same calendar year.
(iii) At least 350 calendar days must separate two performance
tests conducted in the same 3 year period.
* * * * *
0
10. Section 63.10009 is amended by:
0
a. Revising paragraphs (a)(2) introductory text and (a)(2)(i);
0
b. Revising paragraphs (b)(1) through (3);
0
c. Revising paragraphs (f) introductory text and paragraph (f)(2);
0
d. Revising paragraphs (g)(1) and (2); and
0
e. Revising paragraph (j)(1)(ii).
The revisions read as follows:
Sec. 63.10009 May I use emissions averaging to comply with this
subpart?
(a) * * *
(2) You may demonstrate compliance by emissions averaging among the
existing EGUs in the same subcategory, if your averaged Hg emissions
for EGUs in the ``unit designed for coal >=8,300 Btu/lb'' subcategory
are equal to or less than 1.2 lb/TBtu or 1.3E-2 lb/GWh on a 30-boiler
operating day basis or if your averaged emissions of individual, other
pollutants from other subcategories of such EGUs are equal to or less
than the applicable emissions limit in Table 2 to this subpart,
according to the procedures in this section. Note that except for the
alternate Hg emissions limit from EGUs in the ``unit designed for coal
>=8,300 Btu/lb'' subcategory, the averaging time for emissions
averaging for pollutants is 30 days (rolling daily) using data from
CEMS or a combination of data from CEMS and manual performance testing.
The averaging time for emissions averaging for the alternate Hg limit
(equal to or less than 1.0 lb/TBtu or 1.1E-2 lb/GWh) from EGUs in the
``unit designed for coal >=8,300 Btu/lb'' subcategory is 90-boiler
operating days (rolling daily) using data from CEMS, sorbent trap
monitoring, or a combination of monitoring data and data from manual
performance testing. For the purposes of this paragraph, 30- (or 90-)
group boiler operating days is defined as a period during which at
least one unit in the emissions averaging group has operated 30 (or 90)
days. You must calculate the weighted average emissions rate for the
group in accordance with the procedures in this paragraph using the
data from all units in the group including any that operate fewer than
30 (or 90) days during the preceding 30 (or 90) group boiler days.
(i) You may choose to have your EGU emissions averaging group meet
either the heat input basis (MMBtu or TBtu, as appropriate for the
pollutant) or gross output basis (MWh or GWh, as appropriate for the
pollutant).
* * * * *
(b) * * *
(1) Group eligibility equations.
[GRAPHIC] [TIFF OMITTED] TP17FE15.000
Where:
WAERm = Maximum Weighted Average Emission Rate in terms
of lb/heat input or lb/gross output,
Hermi,j = hourly emission rate (e.g., lb/MMBtu, lb/MWh)
from CEMS or sorbent trap monitoring for hour i from EGU j,
Rmmj = Maximum rated heat input, MMBtu/h, or maximum
rated gross output, MWh/h, for EGU j,
p = number of EGUs in emissions averaging group that rely on CEMS,
n = hours in an averaging period (e.g., 720 for a 30-group boiler
operating day averaging period or 2160 for a 90-group boiler
operating day averaging period),
qj = hours in an averaging period for EGU j (e.g., 720
for a 30-group boiler operating day averaging period or 2160 for a
90-group boiler operating day averaging period),
Terk = Emissions rate (lb/MMBTU or lb/MWh) from the most
recent test of EGU k,
Rmtk = Maximum rated heat input, MMBtu/h, or maximum
rated gross output, MWh/h, for EGU k,
rk = hours in an averaging period for EGU k (e.g., 720
for a 30-group boiler operating day averaging period or 2160 for a
90-group boiler operating day averaging period), and
m = number of EGUs in emissions averaging group that rely on
emissions testing.
[[Page 8453]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.001
Where:
Variables with the similar names share the descriptions for Equation
1a,
Smmj = maximum steam generation, lbsteam/h or
lb/gross output, for EGU j,
Cfmj = conversion factor, calculated from the most recent
compliance test results, in terms units of heat input or electrical
output per pound of steam generated (MMBtu/lbsteam or
MWh/lbsteam) from EGU j,
Smtk = maximum steam generation, lbsteam/h or
lb/gross output, for EGU k, and
Cfmk = conversion factor, calculated from the most recent
compliance test results, in terms units of heat input or electrical
output per pound of steam generated (MMBtu/lbsteam or
MWh/lbsteam) from EGU k.
(2) Weighted 30-boiler operating day rolling average emissions rate
equations for pollutants other than Hg. Use equation 2a or 2b to
calculate the 30 day rolling average emissions daily.
[GRAPHIC] [TIFF OMITTED] TP17FE15.002
Where:
Heri = hourly emission rate (e.g., lb/MMBtu, lb/MWh) from
unit i's CEMS for the preceding 30-group boiler operating days,
Rmi = hourly heat input or gross output from unit i for
the preceding 30-group boiler operating days,
p = number of EGUs in emissions averaging group that rely on CEMS or
sorbent trap monitoring,
n = number of hours that hourly rates are collected over 30-group
boiler operating days,
Teri = Emissions rate from most recent emissions test of
unit i in terms of lb/heat input or lb/gross output,
Rti = Total heat input or gross output of unit i for the
preceding 30-boiler operating days, and
m = number of EGUs in emissions averaging group that rely on
emissions testing.
[GRAPHIC] [TIFF OMITTED] TP17FE15.003
Where:
variables with similar names share the descriptions for Equation 2a,
Smi = steam generation in units of pounds from unit i
that uses CEMS for the preceding 30-group boiler operating days,
Cfmi = conversion factor, calculated from the most recent
compliance test results, in units of heat input per pound of steam
generated or gross output per pound of steam generated, from unit i
that uses CEMS from the preceding 30 group boiler operating days,
Sti = steam generation in units of pounds from unit i
that uses emissions testing, and
Cfti = conversion factor, calculated from the most recent
compliance test results, in units of heat input per pound of steam
generated or gross output per pound of steam generated, from unit i
that uses emissions testing.
(3) Weighted 90-boiler operating day rolling average emissions rate
equations for Hg emissions from EGUs in the ``coal-fired unit not low
rank virgin coal'' subcategory. Use equation 3a or 3b to calculate the
90-day rolling average emissions daily.
[GRAPHIC] [TIFF OMITTED] TP17FE15.004
Where:
Heri = hourly emission rate from unit i's CEMS or Hg
sorbent trap monitoring system for the preceding 90-group boiler
operating days,
Rmi = hourly heat input or gross output from unit i for
the preceding 90-group boiler operating days,
p = number of EGUs in emissions averaging group that rely on CEMS,
n = number of hours that hourly rates are collected over the 90-
group boiler operating days,
Teri = Emissions rate from most recent emissions test of
unit i in terms of lb/heat input or lb/gross output,
Rti = Total heat input or gross output of unit i for the
preceding 90-boiler operating days, and
m = number of EGUs in emissions averaging group that rely on
emissions testing.
[GRAPHIC] [TIFF OMITTED] TP17FE15.005
Where:
variables with similar names share the descriptions for Equation 2a,
Smi = steam generation in units of pounds from unit i
that uses CEMS or a Hg
[[Page 8454]]
sorbent trap monitoring for the preceding 90-group boiler operating
days,
Cfmi = conversion factor, calculated from the most recent
compliance test results, in units of heat input per pound of steam
generated or gross output per pound of steam generated, from unit i
that uses CEMS or sorbent trap monitoring from the preceding 90-
group boiler operating days,
Sti = steam generation in units of pounds from unit i
that uses emissions testing, and
Cfti = conversion factor, calculated from the most recent
emissions test results, in units of heat input per pound of steam
generated or gross output per pound of steam generated, from unit i
that uses emissions testing.
* * * * *
(f) Emissions averaging group eligibility demonstration. You must
demonstrate the ability for the EGUs included in the emissions
averaging group to demonstrate initial compliance according to
paragraph (f)(1) or (2) of this section using the maximum possible heat
input or gross output over a 30- (or 90-) boiler operating day period
of each EGU and the results of the initial performance tests. For this
demonstration and prior to preparing your emissions averaging plan, you
must conduct required emissions monitoring for 30- (or 90-) days of
boiler operation and any required manual performance testing to
calculate maximum weighted average emissions rate in accordance with
this section. Should the Administrator require approval, you must
submit your proposed emissions averaging plan and supporting data at
least 120 days before the date on which you plan to being using
emissions averaging. If the Administrator requires approval of your
plan, you may not begin using emissions averaging until the
Administrator approves your plan.
* * * * *
(2) If you are not capable of monitoring heat input or gross
output, and the EGU generates steam for purposes other than generating
electricity, you may use Equation 1b of this section as an alternative
to using Equation 1a of this section to demonstrate that the maximum
weighted average emissions rates of filterable PM, HF, SO2,
HCl, non-Hg HAP metals, or Hg emissions from the existing units
participating in the emissions averaging group do not exceed the
emission limits in Table 2 to this subpart.
* * * * *
(g) * * *
(1) You must use Equation 2a or 3a of paragraph (b) of this section
to calculate the weighted average emissions rate using the actual heat
input or gross output for each existing unit participating in the
emissions averaging option.
(2) If you are not capable of monitoring heat input or gross
output, you may use Equation 2b or 3b of paragraph (b) of this section
as an alternative to using Equation 2a of paragraph (b) of this section
to calculate the average weighted emission rate using the actual steam
generation from the units participating in the emissions averaging
option.
* * * * *
(j) * * *
(1) * * *
(ii) The process weighting parameter (heat input, gross output, or
steam generated) that will be monitored for each averaging group;
* * * * *
0
11. Section 63.10010 is amended by:
0
a. Revising paragraph (a)(4);
0
b. Revising paragraph (f)(3);
0
c. Revising paragraphs (h)(6)(i) and (ii);
0
d. Revising paragraphs (i)(5)(i)(A) and (B);
0
e. Revising paragraph (j)(1)(i) and (j)(4)(i)(A) and (B); and
0
f. Revising paragraph (l).
The revisions read as follows:
Sec. 63.10010 What are my monitoring, installation, operation, and
maintenance requirements?
* * * * *
(a) * * *
(4) Unit with a main stack and a bypass stack that exhausts to the
atmosphere independent of the main stack. If the exhaust configuration
of an affected unit consists of a main stack and a bypass stack, you
shall install CEMS on both the main stack and the bypass stack. If it
is not feasible to certify and quality-assure the data from a
monitoring system on the bypass stack, you shall:
(i) Route the exhaust from the bypass through the main stack and
its monitoring so that bypass emissions are measured, or
(ii) Install a CEMS only on the main stack and count hours that the
bypass stack is in use as hours of deviation from the monitoring
requirements.
* * * * *
(f) * * *
(3) Calculate and record a 30-boiler operating day rolling average
SO2 emission rate in the units of the standard, updated
after each new boiler operating day. Each 30-boiler operating day
rolling average emission rate is the average of all of the valid hourly
SO2 emission rates in the preceding 30 boiler operating
days.
* * * * *
(h) * * *
(6) * * *
(i) Any data collected during periods of monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
or required monitoring system quality assurance or quality control
activities conducted during monitoring system malfunctions. You must
report any such periods in your annual deviation report;
(ii) Any data collected during periods when the monitoring system
is out of control as specified in your site-specific monitoring plan,
repairs associated with periods when the monitoring system is out of
control, or required monitoring system quality assurance or quality
control activities conducted during out-of-control periods. You must
report any such periods in your annual deviation report.
* * * * *
(i) * * *
(5) * * *
(i) * * *
(A) Any data collected during periods of monitoring system
malfunctions, repairs associated with monitoring system malfunctions,
or required monitoring system quality assurance or quality control
activities conducted during monitoring system malfunctions. You must
report any such periods in your annual deviation report;
(B) Any data collected during periods when the monitoring system is
out of control as specified in your site-specific monitoring plan,
repairs associated with periods when the monitoring system is out of
control, or required monitoring system quality assurance or quality
control activities conducted during out-of-control periods. You must
report any such periods in your annual deviation report.
* * * * *
(j) * * *
(1) * * *
(i) Install, calibrate, operate, and maintain your HAP metals CEMS
according to your CMS quality control program, as described in Sec.
63.8(d)(2). The reportable measurement output from the HAP metals CEMS
must be expressed in units of the applicable emissions limit (e.g., lb/
MMBtu, lb/MWh) and in the form of a 30-boiler operating day rolling
average.
* * * * *
(4) * * *
(i) * * *
(A) Any data collected during periods of monitoring system
malfunctions, repairs associated with monitoring
[[Page 8455]]
system malfunctions, or required monitoring system quality assurance or
quality control activities conducted during monitoring system
malfunctions. You must report any such periods in your annual deviation
report;
(B) Any data collected during periods when the monitoring system is
out of control as specified in your site-specific monitoring plan,
repairs associated with periods when the monitoring system is out of
control, or required monitoring system quality assurance or quality
control activities conducted during out-of-control periods. You must
report any such periods in your annual deviation report.
* * * * *
(l) Should you choose to rely on paragraph (2) of the definition of
``startup'' in Sec. 63.10042 for your EGU, you must install, verify,
operate, maintain, and quality assure each monitoring system necessary
for demonstrating compliance with the PM or non-mercury metals work
practice standards required to comply with Sec. 63.10020(e).
(1) You shall develop a site-specific monitoring plan for PM or
non-mercury metals work practice monitoring during startup periods.
(2) You shall submit the site-specific monitoring plan upon request
by the Administrator.
(3) The provisions of the monitoring plan must address the
following items:
(i) Monitoring system installation;
(ii) Performance and equipment specifications;
(iii) Schedule for initial and periodic performance evaluations;
(iv) Performance evaluation procedures and acceptance criteria;
(v) On-going operation and maintenance procedures; and
(vi) On-going recordkeeping and reporting procedures.
(4) You may rely on monitoring system specifications or
instructions or manufacturer's specifications to address paragraphs
(l)(3)(i) through (vi) of this section.
(5) You must operate and maintain the monitoring system according
to the site-specific monitoring plan.
0
12. Section 63.10011 is amended by revising paragraphs (b), (c), (e)
and (g) to read as follows:
Sec. 63.10011 How do I demonstrate initial compliance with the
emissions limits and work practice standards?
* * * * *
(b) If you are subject to an operating limit in Table 4 to this
subpart, you demonstrate initial compliance with HAP metals or
filterable PM emission limit(s) through performance stack tests and you
elect to use a PM CPMS to demonstrate continuous performance, or if,
for a liquid oil-fired EGU, and you use quarterly stack testing for HCl
and HF plus site-specific parameter monitoring to demonstrate
continuous performance, you must also establish a site-specific
operating limit, in accordance with Sec. 63.10007 and Table 6 to this
subpart. You may use only the parametric data recorded during
successful performance tests (i.e., tests that demonstrate compliance
with the applicable emissions limits) to establish an operating limit.
(c)(1) If you use CEMS or sorbent trap monitoring systems to
measure a HAP (e.g., Hg or HCl) directly, the initial performance test,
consisting of a 30-boiler operating day (or, for certain coal-fired,
existing EGUs that use emissions averaging for Hg, a 90-boiler
operating day) rolling average emissions rate obtained with certified
CEMS, expressed in units of the standard, may occur on or before the
first averaging period after the date that compliance with the subpart
is required but must occur such that the averaging period is completed
on or before the date that compliance must be demonstrated. Initial
compliance is demonstrated if the results of the performance test meet
the applicable emission limit in Table 1 or 2 to this subpart.
(2) For an EGU that uses a CEMS to measure SO2 or PM
emission for initial compliance, the initial performance test,
consisting of a 30-boiler operating day average emission rate obtained
with certified CEMS, expressed in units of the standard, may occur on
or before the first averaging period after the date that compliance
with the subpart is required but must occur such that the averaging
period is completed on or before the date that compliance must be
demonstrated. Initial compliance is demonstrated if the results of the
performance test meet the applicable SO2 or PM emission
limit in Table 1 or 2 to this subpart.
* * * * *
(e) You must submit a Notification of Compliance Status containing
the results of the initial compliance demonstration, in accordance with
Sec. 63.10030(e).
* * * * *
(g) You must follow the startup or shutdown requirements as
established in Table 3 to this subpart for each coal-fired, liquid oil-
fired, or solid oil-derived fuel-fired EGU.
(1) You may use the diluent cap and default electrical load values,
as described in Sec. 63.10007(f), during startup periods or shutdown
periods.
(2) You must operate all CMS, collect data, calculate pollutant
emission rates, and record data during startup periods or shutdown
periods.
(3) You must report the information as required in Sec. 63.10031.
(4) If you choose to use paragraph (2) of the definition of
``startup'' in Sec. 63.10042 and you find that you are unable to
safely engage and operate your particulate matter (PM) control(s)
within 1 hour of first firing of coal, residual oil, or solid oil-
derived fuel, you may choose to rely on paragraph (1) of definition of
``startup'' in Sec. 63.10042 or you may submit a request to use an
alternative non-opacity emissions standard, as described below.
(i) As mentioned in Sec. 63.6(g)(1), the request will be published
in the Federal Register for notice and comment rulemaking. Until
promulgation in the Federal Register of the final alternative non-
opacity emission standard, you shall comply with paragraph (1) of the
definition of ``startup'' in Sec. 63.10042. You shall not implement
the alternative non-opacity emissions standard until promulgation in
the Federal Register of the final alternative non-opacity emission
standard.
(ii) The request need not address the items contained in Sec.
63.6(g)(2).
(iii) The request shall provide evidence of a documented
manufacturer-identified safety issue.
(iv) The request shall provide information to document that the PM
control device is adequately designed and sized to meet the PM emission
limit applicable to the EGU.
(v) In addition, the request shall contain documentation that:
(A) The EGU is using clean fuels to the maximum extent practicable,
taking into account considerations such as not compromising boiler or
control device integrity, to bring the EGU and PM control device up to
the temperature necessary to alleviate or prevent the identified safety
issues prior to the combustion of primary fuel in the EGU;
(B) The EGU has explicitly followed the manufacturer's procedures
to alleviate or prevent the identified safety issue; and
(C) Identifies with specificity the details of the manufacturer's
statement of concern.
(vi) The request shall specify the other work practice standards
the EGU owner or operator will take to limit HAP emissions during
startup periods and shutdown periods to ensure a control level
consistent with the work practice standards of the final rule.
(vii) You must comply with all other work practice requirements,
including but not limited to data collection,
[[Page 8456]]
recordkeeping, and reporting requirements.
0
13. Section 63.10020 is amended by revising paragraph (e) to read as
follows:
Sec. 63.10020 How do I monitor and collect data to demonstrate
continuous compliance?
* * * * *
(e) Additional requirements during startup periods or shutdown
periods if you choose to rely on paragraph (2) of the definition of
``startup'' in Sec. 63.10042 for your EGU.
(1) During each period of startup, you must record for each EGU:
(i) The date and time that clean fuels being combusted for the
purpose of startup begins;
(ii) The quantity and heat input of clean fuel for each hour of
startup;
(iii) The gross output for each hour of startup;
(iv) The date and time that non-clean fuel combustion begins; and
(v) The date and time that clean fuels being combusted for the
purpose of startup ends.
(2) During each period of shutdown, you must record for each EGU:
(i) The date and time that clean fuels being combusted for the
purpose of shutdown begins;
(ii) The quantity and heat input of clean fuel for each hour of
shutdown;
(iii) The gross output for each hour of shutdown;
(iv) The date and time that non-clean fuel combustion ends; and
(v) The date and time that clean fuels being combusted for the
purpose of shutdown ends.
(3) For PM or non-mercury HAP metals work practice monitoring
during startup periods, you must monitor and collect data according to
this section and the site-specific monitoring plan required by Sec.
63.10010(l).
(i) Except for an EGU that uses PM CEMS or PM CPMS to demonstrate
compliance with the PM emissions limit or that has LEE status for
filterable PM or total non-Hg HAP metals for non- liquid oil-fired EGUs
(or HAP metals emissions for liquid oil-fired EGUs), or individual non-
mercury metals CEMS you must:
(A) Record temperature and combustion air flow or calculated flow
as determined from combustion equations of post-combustion (exhaust)
gas, as well as amperage of forced draft fan(s), upstream of the
filterable PM control devices during each hour of startup.
(B) Record temperature and flow of exhaust gas, as well as amperage
of any induced draft fan(s), downstream of the filterable PM control
devices during each hour of startup.
(C) For an EGU with an electrostatic precipitator, record the
number of fields in service, as well as each field's secondary voltage
and secondary current during each hour of startup.
(D) For an EGU with a fabric filter, record the number of
compartments in service, as well as the differential pressure across
the baghouse during each hour of startup.
(E) For an EGU with a wet scrubber needed for filterable PM
control, record the scrubber liquid to flue gas ratio and the
differential pressure across the scrubber of the liquid during each
hour of startup.
0
14. Section 63.10021 is amended by revising paragraphs (d)(3), (e)
introductory text, and (e)(9)(i) and (ii) to read as follows:
Sec. 63.10021 How do I demonstrate continuous compliance with the
emission limitations, operating limits, and work practice standards?
* * * * *
(d) * * *
(3) Must conduct site-specific monitoring using CMS to demonstrate
compliance with the site-specific monitoring requirements in Table 7 to
this subpart pertaining to HCl and HF emissions from a liquid oil-fired
EGU to ensure compliance with the HCl and HF emission limits in Tables
1 and 2 to this subpart, in accordance with the requirements of Sec.
63.10000(c)(2)(iii). The monitoring must meet the general operating
requirements provided in Sec. 63.10020.
(e) Conduct periodic performance tune-ups of your EGU(s), as
specified in paragraphs (e)(1) through (9) of this section. For your
first tune-up, you may delay the burner inspection until the next
scheduled EGU outage provided you meet the requirements of Sec.
63.10005. Subsequently, you must perform an inspection of the burner at
least once every 36 calendar months unless your EGU employs neural
network combustion optimization during normal operations in which case
you must perform an inspection of the burner and combustion controls at
least once every 48 calendar months.
* * * * *
(9) * * *
(i) If the first tune-up is performed prior to April 16, 2015,
report the date of the tune-up in hard copy (as specified in Sec.
63.10030) and electronically (as specified in Sec. 63.10031). Report
the date of each subsequent tune-up electronically (as specified in
Sec. 63.10031).
(ii) If the first tune-up is performed on or after April 16, 2015,
report the date of the tune-up and all subsequent tune-ups
electronically, in accordance with Sec. 63.10031.
* * * * *
0
15. Section 63.10023 is amended by removing and reserving paragraph
(b)(1) and revising (b)(2) introductory text to read as follows:
Sec. 63.10023 How do I establish my PM CPMS operating limit and
determine compliance with it?
* * * * *
(b) * * *
(2) Determine your operating limit as follows:
* * * * *
0
16. Section 63.10030 is amended by:
0
a. Revising paragraphs (e)(1) and (e)(7)(i);
0
b. Adding paragraph (e)(7)(iii);
0
c. Revising paragraph (e)(8);
0
d. Adding paragraph (f).
The revisions and additions read as follows:
Sec. 63.10030 What notifications must I submit and when?
* * * * *
(e) * * *
(1) A description of the affected source(s), including
identification of the subcategory of the source, the design capacity of
the source, a description of the add-on controls used on the source,
description of the fuel(s) burned, including whether the fuel(s) were
determined by you or EPA through a petition process to be a non-waste
under 40 CFR 241.3, whether the fuel(s) were processed from discarded
non-hazardous secondary materials within the meaning of 40 CFR 241.3,
and justification for the selection of fuel(s) burned during the
performance test.
* * * * *
(7) * * *
(i) A summary of the results of the annual performance tests and
documentation of any operating limits that were reestablished during
this test, if applicable. If you are conducting stack tests once every
3 years consistent with Sec. 63.10006(b), the date of each stack test
conducted during the previous 3 years, a comparison of emission level
you achieved in each stack test conducted during the previous 3 years
to the 50 percent emission limit threshold required in Sec.
63.10006(i), and a statement as to whether there have been any
operational changes since the last stack test that could increase
emissions.
* * * * *
(iii) For each of your existing EGUs, identification of each
emissions limit as specified in Table 2 to this subpart with which you
plan to comply.
[[Page 8457]]
(A) You may switch between mass per heat input and mass per gross
output levels, provided:
(1) You submit a Notification of Compliance Status that identifies
for each EGU or EGU emissions averaging group involved in proposed
switch both the current and proposed emission limit;
(2) Your submission arrives to the Administrator at least 30
calendar days prior to the date that the switch is proposed to occur;
(3) Your submission demonstrates through performance stack test
results conducted within 30 days prior to your submission, compliance
for each EGU or EGU emissions averaging group with both the mass per
heat input and mass per electric output limits;
(4) You revise and submit all other applicable plans, e.g.,
monitoring and emissions averaging, with your submission; and
(5) You maintain records of all information regarding your choice
of emission limits.
(B) You may begin to use the revised emission limits the semi-
annual reporting period after receipt of written acknowledgement from
the Administrator of the switch.
(C) From submission until the semi-annual reporting period after
receipt of written acknowledgement from the Administrator of the
switch, you must demonstrate compliance with both the mass per heat
input and mass per electric output emission limits for each pollutant
for each EGU or EGU emissions averaging group.
(8) Identification of whether you plan to rely on paragraph (1) or
(2) of the definition of ``startup'' in Sec. 63.10042.
(i) Should you choose to rely on paragraph (2) of the definition of
``startup'' in Sec. 63.10042 for your EGU, you shall include a report
that identifies:
(A) The original EGU installation date;
(B) The original EGU design characteristics, including, but not
limited to, fuel mix and PM controls;
(C) Each design PM control device efficiency established during
performance testing or while operating in periods other than startup
and shutdown periods;
(D) The design PM emission rate from the EGU in terms of pounds PM
per MMBtu and pounds PM per hour established during performance testing
or while operating in periods other than startup and shutdown periods;
(E) The design time from start of fuel combustion to necessary
conditions for each PM control device startup;
(F) Each design PM control device efficiency upon startup of the PM
control device, if different from the efficiency provided in paragraph
(e)(8)(i)(C) of this section;
(G) Current EGU PM producing characteristics, including, but not
limited to, fuel mix and PM controls, if different from the
characteristics provided in paragraph (e)(8)(i)(B) of this section;
(H) Current PM control device efficiency from each PM control
device, if different from the efficiency provided in paragraph
(e)(8)(i)(C) of this section;
(I) Current PM emission rate from the EGU in terms of pounds PM per
MMBtu and pounds per hour, if different from the rate provided in
paragraph (e)(8)(i)(D) of this section;
(J) Current time from start of fuel combustion to conditions
necessary for each PM control device startup, if different from the
time provided in paragraph (e)(8)(i)(E) of this section; and
(M) Current PM control device efficiency upon startup of each PM
control device, if different from the efficiency provided in paragraph
(e)(8)(i)(H) of this section.
(ii) The report shall be prepared, signed, and sealed by a
professional engineer licensed in the state where your EGU is located.
(f) You must submit the notifications in Sec. 63.10000(h)(2) and
(i)(2) that may apply to you by the dates specified.
0
17. Section 63.10031 is amended by:
0
a. Revising paragraphs (c)(4) and (5);
0
b. Adding paragraph (c)(6); and
0
c. Revising paragraph (f)(5).
The revisions and addition read as follows:
Sec. 63.10031 What reports must I submit and when?
* * * * *
(c) * * *
(4) Include the date of the most recent tune-up for each EGU. For
the first tune-up, include the date of the burner inspection if it was
delayed.
(5) Should you choose to rely on paragraph (2) of the definition of
``startup'' in Sec. 63.10042 for your EGU, for each instance of
startup or shutdown you shall:
(i) Include the maximum clean fuel storage capacity and the maximum
hourly heat input that can be provided for each clean fuel determined
according to the requirements of Sec. 63.10032(f).
(ii) Include the information required to be monitored, collected,
or recorded according to the requirements of Sec. 63.10020(e).
(iii) If you choose to use CEMS to demonstrate compliance with
numerical limits, include hourly average CEMS values and hourly average
flow values during startup periods or shutdown periods. Use units of
milligrams per cubic meter for PM CEMS values, micrograms per cubic
meter for Hg CEMS values, and ppmv for HCl, HF, or SO2 CEMS
values. Use units of standard cubic meters per hour on a wet basis for
flow values.
(iv) If you choose to use a separate sorbent trap measurement
system for startup or shutdown reporting periods, include hourly
average mercury concentration values in terms of micrograms per cubic
meter.
(v) If you choose to use a PM CPMS, include hourly average
operating parameter values in terms of the operating limit, as well as
the operating parameter to PM correlation equation.
(6) Emergency bypass reports from EGUs with LEE status.
* * * * *
(f) * * *
(5) All reports required by this subpart not subject to the
requirements in paragraphs (f)(1) through (4) of this section must be
sent to the Administrator at the appropriate address listed in Sec.
63.13. If acceptable to both the Administrator and the owner or
operator of an EGU, these reports may be submitted on electronic media.
The Administrator retains the right to require submittal of reports
subject to paragraphs (f)(1) through (4) of this section in paper
format.
* * * * *
0
18. Section 63.10032 is amended by revising paragraph (f) to read as
follows:
Sec. 63.10032 What records must I keep?
* * * * *
(f) Regarding startup periods or shutdown periods:
(1) Should you choose to rely on paragraph (1) of the definition of
``startup'' in Sec. 63.10042 for your EGU, you must keep records of
the occurrence and duration of each startup or shutdown.
(2) Should you choose to rely on paragraph (2) of the definition of
``startup'' in Sec. 63.10042 for your EGU, you must keep records of:
(i) The determination of the maximum clean fuel capacity for each
EGU;
(ii) The determination of the maximum hourly clean fuel heat input
and of the hourly clean fuel heat input for each EGU; and
(iii) The information required in Sec. 63.10020(e).
* * * * *
0
19. Section 63.10042 is amended by:
0
a. Revising the definitions of ``Coal-fired electric utility steam
generating
[[Page 8458]]
unit,'' ``Coal refuse,'' ``Fossil fuel-fired,'' ``Integrated
gasification combined cycle electric utility steam generating unit or
IGCC,'' ``Limited-use liquid oil-fired subcategory,'' and ``Natural
gas-fired electric utility steam generating unit'';
0
b. Adding, in alphabetical order, a definition of ``Neural network or
neural net''; and
0
c. Revising the definition of ``Oil-fired electric utility steam
generating unit.''
The revisions and additions read as follows:
Sec. 63.10042 What definitions apply to this subpart?
* * * * *
Coal-fired electric utility steam generating unit means an electric
utility steam generating unit meeting the definition of ``fossil fuel-
fired'' that burns coal for more than 10.0 percent of the average
annual heat input during the 3 previous calendar years after the
compliance date for your facility in Sec. 63.9984 or for more than
15.0 percent of the annual heat input during any one of those calendar
years. EGU owners and operators must estimate coal, oil, and natural
gas usage for the first 3 calendar years after the applicable
compliance date and they are solely responsible for assuring compliance
with this final rule or other applicable standard based on their fuel
usage projections.
Coal refuse means waste products of coal mining, physical coal
cleaning, and coal preparation operations (e.g. culm, gob, etc.)
containing coal, matrix material, clay, and other organic and inorganic
material.
* * * * *
Fossil fuel-fired means an electric utility steam generating unit
(EGU) that is capable of combusting more than 25 MW of fossil fuels. To
be ``capable of combusting'' fossil fuels, an EGU would need to have
these fuels allowed in its operating permit and have the appropriate
fuel handling facilities on-site or otherwise available (e.g., coal
handling equipment, including coal storage area, belts and conveyers,
pulverizers, etc.; oil storage facilities). In addition, fossil fuel-
fired means any EGU that fired fossil fuels for more than 10.0 percent
of the average annual heat input during the 3 previous calendar years
after the compliance date for your facility in Sec. 63.9984 or for
more than 15.0 percent of the annual heat input during any one of those
calendar years. EGU owners and operators must estimate coal, oil, and
natural gas usage for the first 3 calendar years after the applicable
compliance date and they are solely responsible for assuring compliance
with this final rule or other applicable standard based on their fuel
usage projections.
* * * * *
Integrated gasification combined cycle electric utility steam
generating unit or IGCC means an electric utility steam generating unit
meeting the definition of ``fossil fuel-fired'' that burns a synthetic
gas derived from coal and/or solid oil-derived fuel for more than 10.0
percent of the average annual heat input during the 3 previous calendar
years after the compliance date for your facility in Sec. 63.9984 or
for more than 15.0 percent of the annual heat input during any one of
those calendar years in a combined-cycle gas turbine. EGU owners and
operators must estimate coal, oil, and natural gas usage for the first
3 calendar years after the applicable compliance date and they are
solely responsible for assuring compliance with this final rule or
other applicable standard based on their fuel usage projections. No
solid coal or solid oil-derived fuel is directly burned in the unit
during operation.
* * * * *
Limited-use liquid oil-fired subcategory means an oil-fired
electric utility steam generating unit with an annual capacity factor
when burning oil of less than 8 percent of its maximum or nameplate
heat input, whichever is greater, averaged over a 24-month block
contiguous period commencing April 16, 2015.
* * * * *
Natural gas-fired electric utility steam generating unit means an
electric utility steam generating unit meeting the definition of
``fossil fuel-fired'' that is not a coal-fired, oil-fired, or IGCC
electric utility steam generating unit and that burns natural gas for
more than 10.0 percent of the average annual heat input during the 3
previous calendar years after the compliance date for your facility in
Sec. 63.9984 or for more than 15.0 percent of the annual heat input
during any one of those calendar years. EGU owners and operators must
estimate coal, oil, and natural gas usage for the first 3 calendar
years after the applicable compliance date and they are solely
responsible for assuring compliance with this final rule or other
applicable standard based on their fuel usage projections.
* * * * *
Neural network or neural net for purposes of this rule means an
automated boiler optimization system. A neural network typically has
the ability to process data from many inputs to develop, remember,
update, and enable algorithms for efficient boiler operation.
* * * * *
Oil-fired electric utility steam generating unit means an electric
utility steam generating unit meeting the definition of ``fossil fuel-
fired'' that is not a coal-fired electric utility steam generating unit
and that burns oil for more than 10.0 percent of the average annual
heat input during the 3 previous calendar years after the compliance
date for your facility in Sec. 63.9984 or for more than 15.0 percent
of the annual heat input during any one of those calendar years.
* * * * *
0
20. Revise Table 1 to subpart UUUUU of part 63 to read as follows:
Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or Reconstructed EGUs
[As stated in Sec. 63.9991, you must comply with the following applicable emission limits:]
----------------------------------------------------------------------------------------------------------------
Using these
requirements, as
appropriate (e.g.,
specified sampling
You must meet the volume or test run
If your EGU is in this subcategory . For the following following emission duration) and
. . pollutants . . . limits and work limitations with the
practice standards . . test methods in Table 5
. to Subpart UUUUU of
Part 63--Performance
Testing Requirements .
. .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank a. Filterable 9.0E-2 lb/MWh \1\...... Collect a minimum of 4
virgin coal. particulate matter dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 6.0E-2 lb/GWh.......... Collect a minimum of 4
dscm per run.
OR OR
[[Page 8459]]
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh..........
Arsenic (As)........... 3.0E-3 lb/GWh..........
Beryllium (Be)......... 6.0E-4 lb/GWh..........
Cadmium (Cd)........... 4.0E-4 lb/GWh..........
Chromium (Cr).......... 7.0E-3 lb/GWh..........
Cobalt (Co)............ 2.0E-3 lb/GWh..........
Lead (Pb).............. 2.0E-2 lb/GWh..........
Manganese (Mn)......... 4.0E-3 lb/GWh..........
Nickel (Ni)............ 4.0E-2 lb/GWh..........
Selenium (Se).......... 5.0E-2 lb/GWh..........
b. Hydrogen chloride 1.0E-2 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 1.0 lb/MWh............. SO2 CEMS.
\3\.
c. Mercury (Hg)........ 3.0E-3 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired units low rank virgin a. Filterable 9.0E-2 lb/MWh \1\...... Collect a minimum of 4
coal. particulate matter dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 6.0E-2 lb/GWh.......... Collect a minimum of 4
dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh..........
Arsenic (As)........... 3.0E-3 lb/GWh..........
Beryllium (Be)......... 6.0E-4 lb/GWh..........
Cadmium (Cd)........... 4.0E-4 lb/GWh..........
Chromium (Cr).......... 7.0E-3 lb/GWh..........
Cobalt (Co)............ 2.0E-3 lb/GWh..........
Lead (Pb).............. 2.0E-2 lb/GWh..........
Manganese (Mn)......... 4.0E-3 lb/GWh..........
Nickel (Ni)............ 4.0E-2 lb/GWh..........
Selenium (Se).......... 5.0E-2 lb/GWh..........
b. Hydrogen chloride 1.0E-2 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 1.0 lb/MWh............. SO2 CEMS.
\3\.
c. Mercury (Hg)........ 4.0E-2 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit......................... a. Filterable 7.0E-2 lb/MWh \4\...... Collect a minimum of 1
particulate matter 9.0E-2 lb/MWh \5\...... dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 4.0E-1 lb/GWh.......... Collect a minimum of 1
dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 2.0E-2 lb/GWh..........
Arsenic (As)........... 2.0E-2 lb/GWh..........
Beryllium (Be)......... 1.0E-3 lb/GWh..........
Cadmium (Cd)........... 2.0E-3 lb/GWh..........
Chromium (Cr).......... 4.0E-2 lb/GWh..........
Cobalt (Co)............ 4.0E-3 lb/GWh..........
Lead (Pb).............. 9.0E-3 lb/GWh..........
[[Page 8460]]
Manganese (Mn)......... 2.0E-2 lb/GWh..........
Nickel (Ni)............ 7.0E-2 lb/GWh..........
Selenium (Se).......... 3.0E-1 lb/GWh..........
b. Hydrogen chloride 2.0E-3 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 4.0E-1 lb/MWh.......... SO2 CEMS.
\3\.
c. Mercury (Hg)........ 3.0E-3 lb/GWh.......... Hg CEMS or sorbent trap
monitoring system
only.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit--continental a. Filterable 3.0E-1 lb/MWh \1\...... Collect a minimum of 1
(excluding limited-use liquid oil- particulate matter dscm per run.
fired subcategory units). (PM).
OR OR
Total HAP metals....... 2.0E-4 lb/MWh.......... Collect a minimum of 2
dscm per run.
OR OR
Individual HAP metals:. Collect a minimum of 2
dscm per run.
Antimony (Sb).......... 1.0E-2 lb/GWh..........
Arsenic (As)........... 3.0E-3 lb/GWh..........
Beryllium (Be)......... 5.0E-4 lb/GWh..........
Cadmium (Cd)........... 2.0E-4 lb/GWh..........
Chromium (Cr).......... 2.0E-2 lb/GWh..........
Cobalt (Co)............ 3.0E-2 lb/GWh..........
Lead (Pb).............. 8.0E-3 lb/GWh..........
Manganese (Mn)......... 2.0E-2 lb/GWh..........
Nickel (Ni)............ 9.0E-2 lb/GWh..........
Selenium (Se).......... 2.0E-2 lb/GWh..........
Mercury (Hg)........... 1.0E-4 lb/GWh.......... For Method 30B sample
volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be <\1/2\
the standard.
b. Hydrogen chloride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
c. Hydrogen fluoride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HF). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
----------------------------------------------------------------------------------------------------------------
5. Liquid oil-fired unit--non- a. Filterable 2.0E-1 lb/MWh \1\...... Collect a minimum of 1
continental (excluding limited-use particulate matter dscm per run.
liquid oil-fired subcategory units). (PM).
OR OR
Total HAP metals....... 7.0E-3 lb/MWh.......... Collect a minimum of 1
dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh..........
Arsenic (As)........... 6.0E-2 lb/GWh..........
Beryllium (Be)......... 2.0E-3 lb/GWh..........
Cadmium (Cd)........... 2.0E-3 lb/GWh..........
Chromium (Cr).......... 2.0E-2 lb/GWh..........
Cobalt (Co)............ 3.0E-1 lb/GWh..........
[[Page 8461]]
Lead (Pb).............. 3.0E-2 lb/GWh..........
Manganese (Mn)......... 1.0E-1 lb/GWh..........
Nickel (Ni)............ 4.1E0 lb/GWh...........
Selenium (Se).......... 2.0E-2 lb/GWh..........
Mercury (Hg)........... 4.0E-4 lb/GWh.......... For Method 30B sample
volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be <\1/2\
the standard.
b. Hydrogen chloride 2.0E-3 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
c. Hydrogen fluoride 5.0E-4 lb/MWh.......... For Method 26A, collect
(HF). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
----------------------------------------------------------------------------------------------------------------
6. Solid oil-derived fuel-fired unit. a. Filterable 3.0E-2 lb/MWh \1\...... Collect a minimum of 1
particulate matter dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 6.0E-1 lb/GWh.......... Collect a minimum of 1
dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb).......... 8.0E-3 lb/GWh..........
Arsenic (As)........... 3.0E-3 lb/GWh..........
Beryllium (Be)......... 6.0E-4 lb/GWh..........
Cadmium (Cd)........... 7.0E-4 lb/GWh..........
Chromium (Cr).......... 6.0E-3 lb/GWh..........
Cobalt (Co)............ 2.0E-3 lb/GWh..........
Lead (Pb).............. 2.0E-2 lb/GWh..........
Manganese (Mn)......... 7.0E-3 lb/GWh..........
Nickel (Ni)............ 4.0E-2 lb/GWh..........
Selenium (Se).......... 6.0E-3 lb/GWh..........
b. Hydrogen chloride 4.0E-4 lb/MWh.......... For Method 26A, collect
(HCl). a minimum of 3 dscm
per run.
For ASTM D6348-03 \2\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 1.0 lb/MWh............. SO2 CEMS.
\3\.
c. Mercury (Hg)........ 2.0E-3 lb/GWh.......... Hg CEMS or Sorbent trap
monitoring system
only.
----------------------------------------------------------------------------------------------------------------
\1\ Gross output.
\2\ Incorporated by reference, see Sec. 63.14.
\3\ You may not use the alternate SO2 limit if your EGU does not have some form of FGD system (or, in the case
of IGCC EGUs, some other acid gas removal system either upstream or downstream of the combined cycle block)
and SO2 CEMS installed.
\4\ Duct burners on syngas; gross output.
\5\ Duct burners on natural gas; gross output.
0
21. Revise Table 2 to subpart UUUUU of part 63 to read as follows:
[[Page 8462]]
Table 2 to Subpart UUUUU of Part 63--Emission Limits for Existing EGUs
[As stated in Sec. 63.9991, you must comply with the following applicable emission limits: \1\]
----------------------------------------------------------------------------------------------------------------
Using these
requirements, as
appropriate (e.g.,
specified sampling
You must meet the volume or test run
If your EGU is in this subcategory . For the following following emission duration) and
. . pollutants . . . limits and work limitations with the
practice standards . . test methods in Table 5
. to Subpart UUUUU of
Part 63--Performance
Testing Requirements .
. .
----------------------------------------------------------------------------------------------------------------
1. Coal-fired unit not low rank a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
virgin coal. particulate matter 1 lb/MWh \2\. dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb)....... 8.0E-1 lb/TBtu or 8.0E-
3 lb/GWh.
Arsenic (As)........ 1.1E0 lb/TBtu or 2.0E-2
lb/GWh.
Beryllium (Be)...... 2.0E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Cadmium (Cd)........ 3.0E-1 lb/TBtu or 3.0E-
3 lb/GWh.
Chromium (Cr)....... 2.8E0 lb/TBtu or 3.0E-2
lb/GWh.
Cobalt (Co)......... 8.0E-1 lb/TBtu or 8.0E-
3 lb/GWh.
Lead (Pb)........... 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Manganese (Mn)...... 4.0E0 lb/TBtu or 5.0E-2
lb/GWh.
Nickel (Ni)......... 3.5E0 lb/TBtu or 4.0E-2
lb/GWh.
Selenium (Se)....... 5.0E0 lb/TBtu or 6.0E-2
lb/GWh.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 0.75 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 2.0E-1 lb/MMBtu or SO2 CEMS.
\4\. 1.5E0 lb/MWh.
c. Mercury (Hg)........ 1.2E0 lb/TBtu or 1.3E-2 LEE Testing for 30 days
lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.
OR .......................
1.0E0 lb/TBtu or 1.1E-2 LEE Testing for 90 days
lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.
----------------------------------------------------------------------------------------------------------------
2. Coal-fired unit low rank virgin a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
coal. particulate matter 1 lb/MWh \2\. dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 5.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb)....... 8.0E-1 lb/TBtu or 8.0E-
3 lb/GWh.
Arsenic (As)........ 1.1E0 lb/TBtu or 2.0E-2
lb/GWh.
Beryllium (Be)...... 2.0E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Cadmium (Cd)........ 3.0E-1 lb/TBtu or 3.0E-
3 lb/GWh.
Chromium (Cr)....... 2.8E0 lb/TBtu or 3.0E-2
lb/GWh.
Cobalt (Co)......... 8.0E-1 lb/TBtu or 8.0E-
3 lb/GWh.
Lead (Pb)........... 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Manganese (Mn)...... 4.0E0 lb/TBtu or 5.0E-2
lb/GWh.
Nickel (Ni)......... 3.5E0 lb/TBtu or 4.0E-2
lb/GWh.
Selenium (Se)....... 5.0E0 lb/TBtu or 6.0E-2
lb/GWh.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or 2.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 0.75 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
OR
[[Page 8463]]
Sulfur dioxide (SO2) 2.0E-1 lb/MMBtu or SO2 CEMS.
\4\. 1.5E0 lb/MWh.
c. Mercury (Hg)........ 4.0E0 lb/TBtu or 4.0E-2 LEE Testing for 30 days
lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.
----------------------------------------------------------------------------------------------------------------
3. IGCC unit......................... a. Filterable 4.0E-2 lb/MMBtu or 4.0E- Collect a minimum of 1
particulate matter 1 lb/MWh \2\. dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 6.0E-5 lb/MMBtu or 5.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 2
dscm per run.
Antimony (Sb)....... 1.4E0 lb/TBtu or 2.0E-2
lb/GWh.
Arsenic (As)........ 1.5E0 lb/TBtu or 2.0E-2
lb/GWh.
Beryllium (Be)...... 1.0E-1 lb/TBtu or 1.0E-
3 lb/GWh.
Cadmium (Cd)........ 1.5E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Chromium (Cr)....... 2.9E0 lb/TBtu or 3.0E-2
lb/GWh.
Cobalt (Co)......... 1.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Lead (Pb)........... 1.9E+2 lb/TBtu or 1.8E0
lb/GWh.
Manganese (Mn)...... 2.5E0 lb/TBtu or 3.0E-2
lb/GWh.
Nickel (Ni)......... 6.5E0 lb/TBtu or 7.0E-2
lb/GWh.
Selenium (Se)....... 2.2E+1 lb/TBtu or 3.0E-
1 lb/GWh.
b. Hydrogen chloride 5.0E-4 lb/MMBtu or 5.0E- For Method 26A, collect
(HCl). 3 lb/MWh. a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
c. Mercury (Hg)........ 2.5E0 lb/TBtu or 3.0E-2 LEE Testing for 30 days
lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or sorbent
trap monitoring system
only.
----------------------------------------------------------------------------------------------------------------
4. Liquid oil-fired unit--continental a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
(excluding limited-use liquid oil- particulate matter 1 lb/MWh \2\. dscm per run.
fired subcategory units). (PM).
OR OR
Total HAP metals....... 8.0E-4 lb/MMBtu or 8.0E- Collect a minimum of 1
3 lb/MWh. dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 1
dscm per run.
Antimony (Sb)....... 1.3E+1 lb/TBtu or 2.0E-
1 lb/GWh.
Arsenic (As)........ 2.8E0 lb/TBtu or 3.0E-2
lb/GWh.
Beryllium (Be)...... 2.0E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Cadmium (Cd)........ 3.0E-1 lb/TBtu or 2.0E-
3 lb/GWh.
Chromium (Cr)....... 5.5E0 lb/TBtu or 6.0E-2
lb/GWh.
Cobalt (Co)......... 2.1E+1 lb/TBtu or 3.0E-
1 lb/GWh.
Lead (Pb)........... 8.1E0 lb/TBtu or 8.0E-2
lb/GWh.
Manganese (Mn)...... 2.2E+1 lb/TBtu or 3.0E-
1 lb/GWh.
Nickel (Ni)......... 1.1E+2 lb/TBtu or 1.1E0
lb/GWh.
Selenium (Se)....... 3.3E0 lb/TBtu or 4.0E-2
lb/GWh.
Mercury (Hg)........ 2.0E-1 lb/TBtu or 2.0E- For Method 30B sample
3 lb/GWh. volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be <\1/2\
the standard.
b. Hydrogen chloride 2.0E-3 lb/MMBtu or 1.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
[[Page 8464]]
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
c. Hydrogen fluoride 4.0E-4 lb/MMBtu or 4.0E- For Method 26A, collect
(HF). 3 lb/MWh. a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
----------------------------------------------------------------------------------------------------------------
5. Liquid oil-fired unit--non- a. Filterable 3.0E-2 lb/MMBtu or 3.0E- Collect a minimum of 1
continental (excluding limited-use particulate matter 1 lb/MWh \2\. dscm per run.
liquid oil-fired subcategory units). (PM).
OR OR
Total HAP metals....... 6.0E-4 lb/MMBtu or 7.0E- Collect a minimum of 1
3 lb/MWh. dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 2
dscm per run.
Antimony (Sb)....... 2.2E0 lb/TBtu or 2.0E-2
lb/GWh.
Arsenic (As)........ 4.3E0 lb/TBtu or 8.0E-2
lb/GWh.
Beryllium (Be)...... 6.0E-1 lb/TBtu or 3.0E-
3 lb/GWh.
Cadmium (Cd)........ 3.0E-1 lb/TBtu or 3.0E-
3 lb/GWh.
Chromium (Cr)....... 3.1E+1 lb/TBtu or 3.0E-
1 lb/GWh.
Cobalt (Co)......... 1.1E+2 lb/TBtu or 1.4E0
lb/GWh.
Lead (Pb)........... 4.9E0 lb/TBtu or 8.0E-2
lb/GWh.
Manganese (Mn)...... 2.0E+1 lb/TBtu or 3.0E-
1 lb/GWh.
Nickel (Ni)......... 4.7E+2 lb/TBtu or 4.1E0
lb/GWh.
Selenium (Se)....... 9.8E0 lb/TBtu or 2.0E-1
lb/GWh.
Mercury (Hg)........ 4.0E-2 lb/TBtu or 4.0E- For Method 30B sample
4 lb/GWh. volume determination
(Section 8.2.4), the
estimated Hg
concentration should
nominally be <\1/2\
the standard.
b. Hydrogen chloride 2.0E-4 lb/MMBtu or 2.0E- For Method 26A, collect
(HCl). 3 lb/MWh. a minimum of 1 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 2
hours.
c. Hydrogen fluoride 6.0E-5 lb/MMBtu or 5.0E- For Method 26A, collect
(HF). 4 lb/MWh. a minimum of 3 dscm
per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 2
hours.
----------------------------------------------------------------------------------------------------------------
6. Solid oil-derived fuel-fired unit. a. Filterable 8.0E-3 lb/MMBtu or 9.0E- Collect a minimum of 1
particulate matter 2 lb/MWh \2\. dscm per run.
(PM).
OR OR
Total non-Hg HAP metals 4.0E-5 lb/MMBtu or 6.0E- Collect a minimum of 1
1 lb/GWh. dscm per run.
OR OR
Individual HAP metals:. ....................... Collect a minimum of 3
dscm per run.
Antimony (Sb)....... 8.0E-1 lb/TBtu or 7.0E-
3 lb/GWh.
Arsenic (As)........ 3.0E-1 lb/TBtu or 5.0E-
3 lb/GWh.
Beryllium (Be)...... 6.0E-2 lb/TBtu or 5.0E-
4 lb/GWh.
Cadmium (Cd)........ 3.0E-1 lb/TBtu or 4.0E-
3 lb/GWh.
Chromium (Cr)....... 8.0E-1 lb/TBtu or 2.0E-
2 lb/GWh.
Cobalt (Co)......... 1.1E0 lb/TBtu or 2.0E-2
lb/GWh.
Lead (Pb)........... 8.0E-1 lb/TBtu or 2.0E-
2 lb/GWh.
Manganese (Mn)...... 2.3E0 lb/TBtu or 4.0E-2
lb/GWh.
Nickel (Ni)......... 9.0E0 lb/TBtu or 2.0E-1
lb/GWh.
[[Page 8465]]
Selenium (Se)....... 1.2E0 lb/Tbtu or 2.0E-2
lb/GWh.
b. Hydrogen chloride 5.0E-3 lb/MMBtu or 8.0E- For Method 26A, collect
(HCl). 2 lb/MWh. a minimum of 0.75 dscm
per run; for Method
26, collect a minimum
of 120 liters per run.
For ASTM D6348-03 \3\
or Method 320, sample
for a minimum of 1
hour.
OR
Sulfur dioxide (SO2) 3.0E-1 lb/MMBtu or SO2 CEMS.
\4\. 2.0E0 lb/MWh.
c. Mercury (Hg)........ 2.0E-1 lb/TBtu or 2.0E- LEE Testing for 30 days
3 lb/GWh. with 10 days maximum
per Method 30B run or
Hg CEMS or Sorbent
trap monitoring system
only.
----------------------------------------------------------------------------------------------------------------
\1\ For LEE emissions testing for total PM, total HAP metals, individual HAP metals, HCl, and HF, the required
minimum sampling volume must be increased nominally by a factor of two.
\2\ Gross output.
\3\ Incorporated by reference, see Sec. 63.14.
\4\ You may not use the alternate SO2 limit if your EGU does not have some form of FGD system and SO2 CEMS
installed.
0
22. Revise Table 3 to subpart UUUUU of part 63 to read as follows:
Table 3 to Subpart UUUUU of Part 63--Work Practice Standards
[As stated in Sec. 63.9991, you must comply with the following
applicable work practice standards:]
------------------------------------------------------------------------
If your EGU is . . . You must meet the following . . .
------------------------------------------------------------------------
1. An existing EGU................ Conduct a tune-up of the EGU burner
and combustion controls at least
each 36 calendar months, or each 48
calendar months if neural network
combustion optimization software is
employed, as specified in Sec.
63.10021(e).
------------------------------------------------------------------------
2. A new or reconstructed EGU..... Conduct a tune-up of the EGU burner
and combustion controls at least
each 36 calendar months, or each 48
calendar months if neural network
combustion optimization software is
employed, as specified in Sec.
63.10021(e).
------------------------------------------------------------------------
3. A coal-fired, liquid oil-fired You have the option of complying
(excluding limited-use liquid oil- using either of the following work
fired subcategory units), or practice standards:
solid oil-derived fuel-fired EGU (1) If you choose to comply using
during startup. paragraph (1) of the definition of
``startup'' in Sec. 63.10042, you
must operate all CMS during
startup. Startup means either the
first-ever firing of fuel in a
boiler for the purpose of producing
electricity, or the firing of fuel
in a boiler after a shutdown event
for any purpose. Startup ends when
any of the steam from the boiler is
used to generate electricity for
sale over the grid or for any other
purpose (including on site use).
For startup of a unit, you must use
clean fuels as defined in Sec.
63.10042 for ignition. Once you
convert to firing coal, residual
oil, or solid oil-derived fuel, you
must engage all of the applicable
control technologies except dry
scrubber and SCR. You must start
your dry scrubber and SCR systems,
if present, appropriately to comply
with relevant standards applicable
during normal operation. You must
comply with all applicable
emissions limits at all times
except for periods that meet the
applicable definitions of startup
and shutdown in this subpart. You
must keep records during startup
periods. You must provide reports
concerning activities and startup
periods, as specified in Sec.
63.10011(g) and Sec. 63.10021(h)
and (i).
(2) If you choose to comply using
paragraph (2) of the definition
of ``startup'' in Sec.
63.10042, you must operate all
CMS during startup. You must
also collect appropriate data,
and you must calculate the
pollutant emission rate for each
hour of startup.
For startup of an EGU, you must use
one or a combination of the clean
fuels defined in Sec. 63.10042 to
the maximum extent practicable,
taking into account considerations
such as boiler or control device
integrity, throughout the startup
period. You must have sufficient
clean fuel capacity to engage and
operate your PM control device
within one hour of adding coal,
residual oil, or solid oil-derived
fuel to the unit. You must meet the
startup period work practice
requirements as identified in Sec.
63.10020(e).
Once you start firing coal, residual
oil, or solid oil-derived fuel, you
must vent emissions to the main
stack(s). You must comply with the
applicable emission limits within 4
hours of start of electricity
generation. You must engage and
operate your particulate matter
control(s) within 1 hour of first
firing of coal, residual oil, or
solid oil-derived fuel.
You must start all other applicable
control devices as expeditiously as
possible, considering safety and
manufacturer/supplier
recommendations, but, in any case,
when necessary to comply with other
standards made applicable to the
EGU by a permit limit or a rule
other than this Subpart that
require operation of the control
devices.
[[Page 8466]]
Relative to the syngas not fired in
the combustion turbine of an IGCC
EGU during startup, you must
either: (1) Flare the syngas, or
(2) route the syngas to duct
burners, which may need to be
installed, and route the flue gas
from the duct burners to the heat
recovery steam generator.
You must collect monitoring data
during startup periods, as
specified in Sec. 63.10020(a) and
(e). You must keep records during
startup periods, as provided in
Sec. Sec. 63.10032 and
63.10021(h). Any fraction of an
hour in which startup occurs
constitutes a full hour of startup.
You must provide reports concerning
activities and startup periods, as
specified in Sec. Sec.
63.10011(g), 63.10021(i), and
63.10031.
------------------------------------------------------------------------
4. A coal-fired, liquid oil-fired You must operate all CMS during
(excluding limited-use liquid oil- shutdown. You must also collect
fired subcategory units), or appropriate data, and you must
solid oil-derived fuel-fired EGU calculate the pollutant emission
during shutdown. rate for each hour of shutdown.
While firing coal, residual oil, or
solid oil-derived fuel during
shutdown, you must vent emissions
to the main stack(s) and operate
all applicable control devices and
continue to operate those control
devices after the cessation of
coal, residual oil, or solid oil-
derived fuel being fed into the EGU
and for as long as possible
thereafter considering operational
and safety concerns. In any case,
you must operate your controls when
necessary to comply with other
standards made applicable to the
EGU by a permit limit or a rule
other than this Subpart and that
require operation of the control
devices.
If, in addition to the fuel used
prior to initiation of shutdown,
another fuel must be used to
support the shutdown process, that
additional fuel must be one or a
combination of the clean fuels
defined in Sec. 63.10042 and must
be used to the maximum extent
practicable.
Relative to the syngas not fired in
the combustion turbine of an IGCC
EGU during shutdown, you must
either: (1) Flare the syngas, or
(2) route the syngas to duct
burners, which may need to be
installed, and route the flue gas
from the duct burners to the heat
recovery steam generator.
You must comply with all applicable
emission limits at all times except
during startup periods and shutdown
periods at which time you must meet
this work practice. You must
collect monitoring data during
shutdown periods, as specified in
Sec. 63.10020(a). You must keep
records during shutdown periods, as
provided in Sec. Sec. 63.10032
and 63.10021(h). Any fraction of an
hour in which shutdown occurs
constitutes a full hour of
shutdown. You must provide reports
concerning activities and shutdown
periods, as specified in Sec. Sec.
63.10011(g), 63.10021(i), and
63.10031.
------------------------------------------------------------------------
0
23. Revise Table 4 to subpart UUUUU of part 63 to read as follows:
Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
[As stated in Sec. 63.9991, you must comply with the applicable
operating limits:]
------------------------------------------------------------------------
If you demonstrate compliance You must meet these operating limits
using . . . . . .
------------------------------------------------------------------------
PM CPMS........................... Maintain the 30-boiler operating day
rolling average PM CPMS output
determined in accordance with the
requirements of Sec.
63.10023(b)(2) and obtained during
the most recent performance test
run demonstrating compliance with
the filterable PM, total non-
mercury HAP metals (total HAP
metals, for liquid oil-fired
units), or individual non-mercury
HAP metals (individual HAP metals
including Hg, for liquid oil-fired
units) emissions limitation(s).
------------------------------------------------------------------------
0
24. Revise Table 5 to subpart UUUUU of part 63 to read as follows:
[[Page 8467]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.006
[[Page 8468]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.007
[[Page 8469]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.008
[[Page 8470]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.009
[[Page 8471]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.010
[[Page 8472]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.011
[[Page 8473]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.012
[[Page 8474]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.013
[[Page 8475]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.014
[[Page 8476]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.015
[[Page 8477]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.016
[[Page 8478]]
[GRAPHIC] [TIFF OMITTED] TP17FE15.017
0
25. Revise Table 6 to subpart UUUUU of part 63 to read as follows:
[[Page 8479]]
Table 6 to Subpart UUUUU of Part 63--Establishing PM CPMS Operating Limits
[As stated in Sec. 63.10007, you must comply with the following requirements for establishing operating
limits:]
----------------------------------------------------------------------------------------------------------------
And you choose to
If you have an applicable establish PM CPMS According to the
emission limit for . . . operating limits, you must And . . . Using . . . following
. . . procedures . . .
----------------------------------------------------------------------------------------------------------------
Filterable Particulate matter Install, certify, Establish a site- Data from the PM 1. Collect PM
(PM), total non-mercury HAP maintain, and operate a specific CPMS and the PM CPMS output
metals, individual non- PM CPMS for monitoring operating limit or HAP metals data during the
mercury HAP metals, total emissions discharged to in units of PM performance entire period
HAP metals, or individual the atmosphere according CPMS output tests. of the
HAP metals for an EGU. to Sec. 63.10010(h)(1). signal (e.g., performance
milliamps, mg/ tests.
acm, or other 2. Record the
raw signal). average hourly
PM CPMS output
for each test
run in the
performance
test.
3. Determine the
PM CPMS
operating limit
in accordance
with the
requirements of
Sec.
63.10023(b)(2)
from data
obtained during
the performance
test
demonstrating
compliance with
the filterable
PM or HAP
metals
emissions
limitations.
----------------------------------------------------------------------------------------------------------------
0
26. Revise Table 8 to subpart UUUUU of part 63 to read as follows:
Table 8 to Subpart UUUUU of Part 63--Reporting Requirements
[As stated in Sec. 63.10031, you must comply with the following
requirements for reports:]
------------------------------------------------------------------------
The report must You must submit
You must submit a contain . . . the report . . .
------------------------------------------------------------------------
1. Compliance report.......... a. Information Semiannually
required in Sec. according to
63.10031(c)(1) the
through (6); and requirements in
Sec.
63.10031(b).
b. If there are no
deviations from any
emission limitation
(emission limit and
operating limit) that
applies to you and
there are no
deviations from the
requirements for work
practice standards in
Table 3 to this
subpart that apply to
you, a statement that
there were no
deviations from the
emission limitations
and work practice
standards during the
reporting period. If
there were no periods
during which the
CMSs, including
continuous emissions
monitoring system,
and operating
parameter monitoring
systems, were out-of-
control as specified
in Sec. 63.8(c)(7),
a statement that
there were no periods
during which the CMSs
were out-of-control
during the reporting
period; and
c. If you have a
deviation from any
emission limitation
(emission limit and
operating limit) or
work practice
standard during the
reporting period, the
report must contain
the information in
Sec. 63.10031(d).
If there were periods
during which the
CMSs, including
continuous emissions
monitoring systems
and continuous
parameter monitoring
systems, were out-of-
control, as specified
in Sec. 63.8(c)(7),
the report must
contain the
information in Sec.
63.10031(e).
------------------------------------------------------------------------
0
27. Revise Table 9 to subpart UUUUU of part 63 to read as follows:
Table 9 to Subpart UUUUU of Part 63--Applicability of General Provisions
to Subpart UUUUU
[As stated in Sec. 63.10040, you must comply with the applicable
General Provisions according to the following:]
------------------------------------------------------------------------
Applies to subpart
Citation Subject UUUUU
------------------------------------------------------------------------
Sec. 63.1................. Applicability....... Yes.
Sec. 63.2................. Definitions......... Yes. Additional
terms defined in
Sec. 63.10042.
Sec. 63.3................. Units and Yes.
Abbreviations.
Sec. 63.4................. Prohibited Yes.
Activities and
Circumvention.
Sec. 63.5................. Preconstruction Yes.
Review and
Notification
Requirements.
[[Page 8480]]
Sec. 63.6(a), (b)(1) Compliance with Yes.
through (5), (b)(7), (c), Standards and
(f)(2) and (3), (h)(2) Maintenance
through (9), (i), (j). Requirements.
Sec. 63.6(e)(1)(i)........ General Duty to No. See Sec.
minimize emissions. 63.10000(b) for
general duty
requirement.
Sec. 63.6(e)(1)(ii)....... Requirement to No.
correct
malfunctions ASAP.
Sec. 63.6(e)(3)........... SSM Plan No.
requirements.
Sec. 63.6(f)(1)........... SSM exemption....... No.
Sec. 63.6(h)(1)........... SSM exemption....... No.
Sec. 63.6(g).............. Compliance with Yes. See Sec. Sec.
Standards and 63.10011(g)(4) and
Maintenance 63.10021(h)(4) for
Requirements, Use additional
of an alternative requirements.
non-opacity
emission standard.
Sec. 63.7(e)(1)........... Performance testing. No. See Sec.
63.10007.
Sec. 63.8................. Monitoring Yes.
Requirements.
Sec. 63.8(c)(1)(i)........ General duty to No. See Sec.
minimize emissions 63.10000(b) for
and CMS operation. general duty
requirement.
Sec. 63.8(c)(1)(iii)...... Requirement to No.
develop SSM Plan
for CMS.
Sec. 63.8(d)(3)........... Written procedures Yes, except for last
for CMS. sentence, which
refers to an SSM
plan. SSM plans are
not required.
Sec. 63.9................. Notification Yes, except for the
Requirements. 60-day notification
prior to conducting
a performance test
in Sec. 63.9(d);
instead use a 30-
day notification
period per Sec.
63.10030(d).
Sec. 63.10(a), (b)(1), Recordkeeping and Yes, except for the
(c), (d)(1) and--(2), (e), Reporting requirements to
and (f). Requirements. submit written
reports under Sec.
63.10(e)(3)(v).
Sec. 63.10(b)(2)(i)....... Recordkeeping of No.
occurrence and
duration of
startups and
shutdowns.
Sec. 63.10(b)(2)(ii)...... Recordkeeping of No. See Sec.
malfunctions. 63.10001 for
recordkeeping of
(1) occurrence and
duration and (2)
actions taken
during malfunction.
Sec. 63.10(b)(2)(iii)..... Maintenance records. Yes.
Sec. 63.10(b)(2)(iv)...... Actions taken to No.
minimize emissions
during SSM.
Sec. 63.10(b)(2)(v)....... Actions taken to No.
minimize emissions
during SSM.
Sec. 63.10(b)(2)(vi)...... Recordkeeping for Yes.
CMS malfunctions.
Sec. 63.10(b)(2)(vii) Other CMS Yes.
through--(ix). requirements.
Sec. 63.10(b)(3),and .................... No.
(d)(3) through--(5).
Sec. 63.10(c)(7).......... Additional Yes.
recordkeeping
requirements for
CMS--identifying
exceedances and
excess emissions.
Sec. 63.10(c)(8).......... Additional Yes.
recordkeeping
requirements for
CMS--identifying
exceedances and
excess emissions.
Sec. 63.10(c)(10)......... Recording nature and No. See Sec.
cause of 63.10032(g) and (h)
malfunctions. for malfunctions
recordkeeping
requirements.
Sec. 63.10(c)(11)......... Recording corrective No. See Sec.
actions. 63.10032(g) and (h)
for malfunctions
recordkeeping
requirements.
Sec. 63.10(c)(15)......... Use of SSM Plan..... No.
Sec. 63.10(d)(5).......... SSM reports......... No. See Sec.
63.10021(h) and (i)
for malfunction
reporting
requirements.
Sec. 63.11................ Control Device No.
Requirements.
Sec. 63.12................ State Authority and Yes.
Delegation.
Sec. Sec. 63.13 through-- Addresses, Yes.
63.16. Incorporation by
Reference,
Availability of
Information,
Performance Track
Provisions.
Sec. Sec. Reserved............ No.
63.1(a)(5),(a)(7) through--
(9), (b)(2), (c)(3) and--
(4), (d), 63.6(b)(6),
(c)(3) and ), (c)(4), (d),
(e)(2), (e)(3)(ii), (h)(3),
(h)(5)(iv), 63.8(a)(3),
63.9(b)(3), (h)(4),
63.10(c)(2) through--(4),
(c)(9).
------------------------------------------------------------------------
0
28. Appendix A to subpart UUUUU of part 63 is amended by:
0
a. Revising paragraph 3.2.1.2.1;
0
b. Revising paragraphs 4.1.1.1, 4.1.1.3, 4.1.1.5, and 4.1.1.5.2;
0
c. Revising Tables A-1 and A-2;
0
d. Revising paragraphs 5.1.2.1, 5.1.2.3, and 5.2.1; and
0
e. Adding paragraph 6.2.2.3 and 7.1.2.6.
The revisions and additions to read as follows:
Appendix A to Subpart UUUUU of Part 63--Hg Monitoring Provisions
* * * * *
3. Mercury Emissions Measurement Methods
* * * * *
[[Page 8481]]
3.2.1.2.1 NIST Traceability. Only NIST-certified or NIST-
traceable calibration gas standards and reagents (as defined in
paragraphs 3.1.4 and 3.1.5 of this appendix), and including, but not
limited to, Hg gas generators and Hg gas cylinders, shall be used
for the tests and procedures required under this subpart.
Calibration gases with known concentrations of Hg\0\ and
HgCl2 are required. Special reagents and equipment may be
needed to prepare the Hg\0\ and HgCl2 gas standards
(e.g., NIST-traceable solutions of HgCl2 and gas
generators equipped with mass flow controllers).
* * * * *
4. Certification and Recertification Requirements
* * * * *
4.1.1.1 7-Day Calibration Error Test. Perform the 7-day
calibration error test on 7 consecutive source operating days, using
a zero-level gas and either a high-level or a mid-level calibration
gas standard (as defined in sections 3.1.8, 3.1.10, and 3.1.11 of
this appendix). Use a NIST-traceable elemental Hg gas standard (as
defined in section 3.1.4 of this appendix) for the test. If moisture
and/or chlorine is added to the calibration gas, the dilution effect
of the moisture and/or chlorine addition on the calibration gas
concentration must be accounted for in an appropriate manner.
Operate the Hg CEMS in its normal sampling mode during the test. The
calibrations should be approximately 24 hours apart, unless the 7-
day test is performed over non-consecutive calendar days. On each
day of the test, inject the zero-level and upscale gases in sequence
and record the analyzer responses. Pass the calibration gas through
all filters, scrubbers, conditioners, and other monitor components
used during normal sampling, and through as much of the sampling
probe as is practical. Do not make any manual adjustments to the
monitor (i.e., resetting the calibration) until after taking
measurements at both the zero and upscale concentration levels. If
automatic adjustments are made following both injections, conduct
the calibration error test such that the magnitude of the
adjustments can be determined, and use only the unadjusted analyzer
responses in the calculations. Calculate the calibration error (CE)
on each day of the test, as described in Table A-1 of this appendix.
The CE on each day of the test must either meet the main performance
specification or the alternative specification in Table A-1 of this
appendix.
* * * * *
4.1.1.3 Three-Level System Integrity Check. Perform the 3-level
system integrity check using low, mid, and high-level calibration
gas concentrations generated by a NIST-traceable source of oxidized
Hg. Follow the same basic procedure as for the linearity check. If
moisture and/or chlorine is added to the calibration gas, the
dilution effect of the moisture and/or chlorine addition on the
calibration gas concentration must be accounted for in an
appropriate manner. Calculate the system integrity error (SIE), as
described in Table A-1 of this appendix. The SIE must either meet
the main performance specification or the alternative specification
in Table A-1 of this appendix.
* * * * *
4.1.1.5 Relative Accuracy Test Audit (RATA). Perform the RATA of
the Hg CEMS at normal load. Acceptable Hg reference methods for the
RATA include ASTM D6784-02 (Reapproved 2008), ``Standard Test Method
for Elemental, Oxidized, Particle-Bound and Total Mercury in Flue
Gas Generated from Coal-Fired Stationary Sources (Ontario Hydro
Method)'' (incorporated by reference, see Sec. 63.14) and Methods
29, 30A, and 30B in appendix A-8 to part 60 of this chapter. When
Method 29 or ASTM D6784-02 is used, paired sampling trains are
required and the filterable portion of the sample need not be
included when making comparisons to the Hg CEMS results for purposes
of a RATA. To validate a Method 29 or ASTM D6784-02 test run,
calculate the relative deviation (RD) using Equation A-1 of this
section, and assess the results as follows to validate the run. The
RD must not exceed 10 percent, when the average Hg concentration is
greater than 1.0 [micro]g/dscm. If the RD specification is met, the
results of the two samples shall be averaged arithmetically.
[GRAPHIC] [TIFF OMITTED] TP17FE15.018
Where:
RD = Relative Deviation between the Hg concentrations of samples
``a'' and ``b'' (percent),
Ca = Hg concentration of Hg sample ``a'' ([micro]g/dscm),
and
Cb = Hg concentration of Hg sample ``b'' ([micro]g/dscm).
* * * * *
4.1.1.5.2 Calculation of RATA Results. Calculate the relative
accuracy (RA) of the monitoring system, on a [micro]g/scm basis, as
described in section 12 of Performance Specification (PS) 2 in
Appendix B to part 60 of this chapter (see Equations 2-3 through 2-6
of PS2) including the option to substitute the emission limit value
(in this case the equivalent concentration) in the denominator of
Equation 2-6 in place of the average RM value when the average
emissions for the test are less than 50 percent of the applicable
emissions limit. For purposes of calculating the relative accuracy,
ensure that the reference method and monitoring system data are on a
consistent basis, either wet or dry. The CEMS must either meet the
main performance specification or the alternative specification in
Table A-1 of this appendix.
* * * * *
Table A-1--Required Certification Tests and Performance Specifications for Hg CEMS
----------------------------------------------------------------------------------------------------------------
The alternate
For this required certification test The main performance performance And the conditions of
. . . specification \1\ is . specification \1\ is . the alternate
. . . . specification are . . .
----------------------------------------------------------------------------------------------------------------
7-day calibration error test \2\..... [verbar]R - A[verbar] [verbar]R - A[verbar] The alternate
<=5.0% of span value, <=1.0 [mu]g/scm. specification may be
for both the zero and used on any day of the
upscale gases, on each test.
of the 7 days.
Linearity check \3\.................. [verbar]R - Aavg [verbar]R - Aavg The alternate
[verbar] <=10.0% of [verbar] <=0.8 [mu]g/ specification may be
the reference gas scm. used at any gas level.
concentration at each
calibration gas level
(low, mid, or high).
3-level system integrity check \4\... [verbar]R - Aavg [verbar]R - Aavg The alternate
[verbar] <=10.0% of [verbar] <=0.8 [mu]g/ specification may be
the reference gas scm. used at any gas level.
concentration at each
calibration gas level.
RATA................................. 20.0% RA............... <=10% RA when RMavg <50% of
concentration applicable emissions
equivalent of limit.
applicable emissions
limit is used in place
of RMavg in Equation 2-
6 of PS2 (see Section
4.1.1.5.2 of this
appendix).
[[Page 8482]]
Cycle time test \2\.................. 15 minutes where the
stability criteria are
readings change by
<2.0% of span or by
<=0.5 [mu]g/scm, for 2
minutes.
----------------------------------------------------------------------------------------------------------------
\1\ Note that [verbar]R - A[verbar] is the absolute value of the difference between the reference gas value and
the analyzer reading. [verbar]R - Aavg[verbar] is the absolute value of the difference between the reference
gas concentration and the average of the analyzer responses, at a particular gas level.
\2\ Use elemental Hg standards; a mid-level or high-level upscale gas may be used. The cycle time test is not
required for Hg CEMS that use integrated batch sampling; however, those monitors must be capable of recording
at least one Hg concentration reading every 15 minutes.
\3\ Use elemental Hg standards.
\4\ Use oxidized Hg standards.
* * * * *
5. Ongoing Quality Assurance (QA) and Data Validation
* * * * *
Table A-2--On-Going QA Test Requirements for Hg CEMS
----------------------------------------------------------------------------------------------------------------
With these
Perform this type of QA test . . . At this frequency . . . qualifications and Acceptance criteria . .
exceptions . . . .
----------------------------------------------------------------------------------------------------------------
Calibration error test............... Daily.................. Use either a [verbar]R - A[verbar]
mid- or high-level gas. <=5.0% of span value
Use elemental or
Hg. [verbar]R - A[verbar]
Calibrations <=1.0 [mu]g/scm.
are not required when
the unit is not in
operation.
Single-level system integrity check.. Weekly \1\............. Use oxidized [verbar]Rn -
Hg--either mid- or Aavg[verbar] <=10.0%
high-level. of the reference gas
value
or
[verbar]R -
Aavg[verbar] <=0.8
[mu]g/scm.
Linearity check or 3-level system Quarterly \3\.......... Required in [verbar]R - Aavg
integrity check. each ``QA operating [verbar] <=10.0% of
quarter'' \2\ and no the reference gas
less than once every 4 value, at each
calendar quarters. calibration gas level
168 operating or [verbar]R -
hour grace period Aavg[verbar] <=0.8
available. [mu]g/scm.
Use elemental
Hg for linearity check.
Use oxidized
Hg for system
integrity check.
RATA................................. Annual \4\............. Test deadline <=20.0% RA when Cavg
may be extended for >=50% of the emissions
``non-QA operating limit
quarters,'' up to a or
maximum of 8 quarters <=10.0% RA when Cavg
from the quarter of <50% of the emissions
the previous test. limit and the
720 operating concentration
hour grace period equivalent of the
available. applicable emission
limit is used in the
denominator of
Equation 2-6 of PS2
(see Section 4.1.1.5.1
of this appendix).
----------------------------------------------------------------------------------------------------------------
\1\ ``Weekly'' means once every 7 operating days.
\2\ A ``QA operating quarter'' is a calendar quarter with at least 168 unit or stack operating hours.
\3\ ``Quarterly'' means once every QA operating quarter.
\4\ ``Annual'' means once every four QA operating quarters.
* * * * *
5.1.2.1 Calibration error tests of the Hg CEMS are required
daily, except during unit outages. Use a NIST-traceable elemental Hg
gas standard for these calibrations. Both a zero-level gas and
either a mid-level or high-level gas are required for these
calibrations.
* * * * *
5.1.2.3 Perform a single-level system integrity check weekly,
i.e., once every 7 operating days (see the third column in Table A-2
of this appendix).
* * * * *
5.2.1 Each sorbent trap monitoring system shall be continuously
operated and maintained in accordance with Performance Specification
(PS) 12B in appendix B to part 60 of this chapter. The QA/QC
criteria for routine operation of the system are summarized in Table
12B-1 of PS 12B. Each pair of sorbent traps may be used to sample
the stack gas for up to 15 operating days.
* * * * *
6. Data Reductions and Calculations
* * * * *
6.2.2.3 The applicable gross output-based Hg emission rate limit
in Table 1 or 2 to this subpart must be met on a 30- (or 90-) boiler
operating day rolling average basis, except as otherwise provided in
Sec. 63.10009(a)(2). Use Equation A-5 of this appendix to calculate
the Hg emission rate for each averaging period.
[GRAPHIC] [TIFF OMITTED] TP17FE15.019
Where:
[[Page 8483]]
Eo = Hg emission rate for the averaging period (lb/GWh),
Eho = Gross output-based hourly Hg emission rate for unit
or stack sampling hour ``h'' in the averaging period, from Equation
A-4 of this appendix (lb/GWh), and
n = Number of unit or stack operating hours in the averaging period
in which valid data were obtained for all parameters.
(Note: Do not include non-operating hours with zero emission rates
in the average).
* * * * *
7. Recordkeeping and Reporting
* * * * *
7.1.2.6 The EGUs that constitute an emissions averaging group.
* * * * *
0
29. Appendix B to subpart UUUUU of part 63 is amended by:
0
a. Revising paragraph 2.1 and 2.3;
0
b. Adding paragraphs 2.3.1 and 2.3.2;
0
c. Revising paragraphs 3.1 and 3.2 and adding paragraph 3.3;
0
d. Adding introductory text to section 5. On-Going Quality Assurance
Requirements;
0
e. Revising paragraphs 5.1, 5.2, and 5.3;
0
f. Adding paragraphs 5.4, 5.4.1, 5.4.2, 5.4.2.1, 5.4.2.2, 5.4.2.2.1,
5.4.2.2.2, 5.4.2.3, 5.4.2.3.1, 5.4.2.3.2, 5.4.2.3.3, and 5.4.3;
0
g. Revising section 8. introductory text;
0
h. Revising paragraphs 10.1.8, 10.1.8.1, 10.1.8.1.1, and 10.1.8.1.2,
adding paragraph 10.1.8.1.2.1, and adding and reserving paragraph
10.1.8.1.2.2;
0
i. Revising paragraph 10.1.8.1.3;
0
j. Revising paragraphs 11.4 and 11.4.2 and removing and reserving
paragraphs 11.4.2.1 through 11.4.2.13;
0
k. Revising paragraphs 11.4.3 and 11.4.3.1 through 11.4.3.13;
0
l. Revising paragraph 11.4.4 and adding and reserving paragraph
11.4.4.1;
0
m. Adding paragraph 11.4.5 and adding and reserving paragraph 11.4.5.1;
0
n. Adding paragraph 11.4.6 and adding and reserving paragraph 11.4.6.1;
0
o. Adding paragraphs 11.4.7, 11.4.7.1 through 11.4.7.13;
0
p. Revising paragraph 11.4.8 and
0
q. Revising paragraph 11.5.3.4.
0
The revisions and additions read as follows:
Appendix B to Subpart UUUUU of Part 63--HCL and HF
Monitoring Provisions
* * * * *
2. Monitoring of HCL and/or HF Emissions
* * * * *
2.1 Monitoring System Installation Requirements. Install HCl
and/or HF CEMS and any additional monitoring systems needed to
convert pollutant concentrations to units of the applicable
emissions limit in accordance with Performance Specification 15 (PS
15) of appendix B to part 60 of this chapter for extractive Fourier
Transform Infrared Spectroscopy (FTIR) continuous emissions
monitoring systems and Sec. 63.10010(a) or Performance
Specification 18 (PS 18) of appendix B to part 60 of this chapter
for HCl CEMS and Sec. 63.10010(a).
* * * * *
2.3 FTIR Monitoring System Equipment, Supplies, Definitions, and
General Operation. The following provisions apply:
2.3.1 PS 15, Sections 2.0, 3.0, 4.0, 5.0, 6.0, and 10.0 of
appendix B to part 60 of this chapter, or
2.3.2 PS 18, Sections 3.0, 6.0, and 11.0 of appendix B to part
60 of this chapter.
3. Initial Certification Procedures
* * * * *
3.1 If you choose to follow Performance Specification 15 (PS 15)
of appendix B to part 60 of this chapter, then your HCl and/or HF
CEMS must be certified according to PS 15 using the procedures for
gas auditing and comparison to a reference method (RM) as specified
in sections 3.1.1 and 3.1.2 below.
* * * * *
3.2 If you choose to follow Performance Specification 18 (PS 18)
of appendix B to part 60 of this chapter, then your HCl and/or HF
CEMS must be certified according to PS 18, sections 7.0, 8.0, 11.0,
12.0, and 13.0.
3.3 Any additional stack gas flow rate, diluent gas, and
moisture monitoring system(s) needed to express pollutant
concentrations in units of the applicable emissions limit must be
certified according to part 75 of this chapter.
* * * * *
5. On-Going Quality Assurance Requirements
On-going QA test requirements for HCl and HF CEMS must be
implemented as follows:
5.1 If you choose to follow Performance Specification 15 (PS 15)
of appendix B to part 60 of this chapter, then the quality
assurance/quality control procedures of PS 15 shall apply as set
forth in sections 5.1.1 through 5.1.3 and 5.3.2 of this appendix.
* * * * *
5.2 If you choose to follow Performance Specification PS 18 of
appendix B to part 60 of this chapter, then the quality assurance/
quality control procedures of Procedure 6 of 40 CFR part 60,
appendix F shall apply.
5.3 Stack gas flow rate, diluent gas, and moisture monitoring
systems must meet the applicable on-going QA test requirements of
part 75 of this chapter.
* * * * *
5.4 Data Validation.
5.4.1 Out-of-Control Periods. An HCl or HF CEMS that is used to
provide data under this appendix is considered to be out-of-control,
and data from the CEMS may not be reported as quality-assured, when
any acceptance criteria for a required QA test is not met. The HCl
or HF CEMS is also considered to be out-of-control when a required
QA test is not performed on schedule or within an allotted grace
period. To end an out-of-control period, the QA test that was either
failed or not done on time must be performed and passed. Out-of-
control periods are counted as hours of monitoring system downtime.
5.4.2 Grace Periods. For the purposes of this appendix, a
``grace period'' is defined as a specified number of unit or stack
operating hours after the deadline for a required quality-assurance
test of a continuous monitor has passed, in which the test may be
performed and passed without loss of data.
5.4.2.1 For the flow rate, diluent gas, and moisture monitoring
systems described in section 5.3 of this appendix, a 168 unit or
stack operating hour grace period is available for quarterly
linearity checks, and a 720 unit or stack operating hour grace
period is available for RATAs, as provided, respectively, in
sections 2.2.4 and 2.3.3 of appendix B to part 75 of this chapter.
5.4.2.2 For the purposes of this appendix, if the deadline for a
required gas audit/data accuracy assessment or RATA of an HCl or HF
CEMS cannot be met due to circumstances beyond the control of the
owner or operator:
5.4.2.2.1 A 168 unit or stack operating hour grace period is
available in which to perform the gas audit/data accuracy
assessment; or
5.4.2.2.2 A 720 unit or stack operating hour grace period is
available in which to perform the RATA.
5.4.2.3 If a required QA test is performed during a grace
period, the deadline for the next test shall be determined as
follows:
5.4.2.3.1 For a gas audit or RATA of the monitoring systems
required under in section 5.3 of this appendix, determine the
deadline for the next gas audit or RATA (as applicable) in
accordance with section 2.2.4(b) or 2.3.3(d) of appendix B to part
75 of this chapter; treat a gas audit in the same manner as a
linearity check.
5.4.2.3.2 For the gas audit/data accuracy assessment of an HCl
or HF CEMS, the grace period test only satisfies the audit
requirement for the calendar quarter in which the test was
originally due. If the calendar quarter in which the grace period
audit is performed is a QA operating quarter, an additional gas
audit/data accuracy assessment is required for that quarter.
5.4.2.3.3 For the RATA of an HCl or HF CEMS, the next RATA is
due within three QA operating quarters after the calendar quarter in
which the grace period test is performed.
5.4.3 Conditional Data Validation. For recertification and
diagnostic testing of the monitoring systems that are used to
provide data under this appendix, and for the required QA tests when
non-redundant backup monitoring systems or temporary like-kind
replacement analyzers are brought into service, the conditional data
validation provisions in Sec. 75.20(b)(3)(ii) through (ix) of this
chapter may be used to avoid or minimize data loss. The allotted
window of time to complete calibration tests and RATAs shall be as
specified in Sec. 75.20(b)(3)(iv) of this chapter; the allotted
window of time to complete a gas audit or data accuracy assessment
shall be the same as for a linearity check (i.e., 168 unit or stack
operating hours).
* * * * *
[[Page 8484]]
8. QA/QC Program Requirements
The owner or operator shall develop and implement a quality
assurance/quality control (QA/QC) program for the HCl and/or HF CEMS
that are used to provide data under this subpart. At a minimum, the
program shall include a written plan that describes in detail (or
that refers to separate documents containing) complete, step-by-step
procedures and operations for the most important QA/QC activities.
Electronic storage of the QA/QC plan is permissible, provided that
the information can be made available in hard copy to auditors and
inspectors. The QA/QC program requirements for the other monitoring
systems described in paragraph 5.3 of this appendix are specified in
section 1 of appendix B to part 75 of this chapter.
* * * * *
10. Recordkeeping Requirements
* * * * *
10.1.8 Certification and Quality Assurance Test Records. For the
HCl and/or HF CEMS used to provide data under this subpart at each
affected unit (or group of units monitored at a common stack),
record the following information for all required certification,
recertification, diagnostic, and quality-assurance tests:
10.1.8.1 HCl and HF CEMS.
10.1.8.1.1 For all required daily calibrations and checks
(including calibration transfer standard tests) of the HCl or HF
CEMS, record the test dates and times, reference values and their
certification information, action levels for integrated path HCl
CEMS, HCl or HF monitor responses, and calculated calibration error
values;
10.1.8.1.2 For quarterly gas audits of HCl or HF CEMS certified
under PS 15 of appendix B to part 60 of this chapter follow
paragraph 10.1.8.1.2.1 of this appendix and for quarterly data
accuracy assessments under PS 18 of appendix B to part 60 of this
chapter follow paragraph 10.1.8.1.2.2 of this appendix.
10.1.8.1.2.1 Record the date and time of each spiked and
unspiked sample, the audit gas reference values and uncertainties.
Keep records of all calculations and data analyses required under
sections 9.1 and 12.1 of P S 15 of appendix B to part 60 of this
chapter, and the results of those calculations and analyses.
10.1.8.1.2.2 [Reserved]
10.1.8.1.3 For each RATA or RAA of a HCl or HF CEMS, record the
date and time of each test run, the reference method(s) used, and
the reference method and HCl or HF CEMS values. Keep records of the
data analyses and calculations used to determine the relative
accuracy.
* * * * *
11. Reporting Requirements
* * * * *
11.4 Certification, Recertification, and Quality-Assurance Test
Reporting Requirements. Except for daily QA tests (e.g.,
calibrations and flow monitor interference checks), which are
included in each electronic quarterly emissions report, use the
ECMPS Client Tool to submit the results of all required
certification, recertification, quality-assurance, and diagnostic
tests of the monitoring systems required under this appendix
electronically, either prior to or concurrent with the relevant
quarterly electronic emissions report.
* * * * *
11.4.2 For daily beam intensity checks for integrated path HCl
CEMS as specified by PS 18 of appendix B to part 60 of this chapter,
report:
11.4.2.1 through 11.4.2.13 [Reserved]
11.4.3 For each quarterly gas audit of an HCl or HF CEMS under
Performance Specification 15, report:
11.4.3.1 Facility ID information;
11.4.3.2 Monitoring system ID number;
11.4.3.3 Type of test (e.g., quarterly gas audit);
11.4.3.4 Reason for test;
11.4.3.5 Certified audit (spike) gas concentration value (ppm);
11.4.3.6 Measured value of audit (spike) gas, including date and
time of injection;
11.4.3.7 Calculated dilution ratio for audit (spike) gas;
11.4.3.8 Date and time of each spiked flue gas sample;
11.4.3.9 Date and time of each unspiked flue gas sample;
11.4.3.10 The measured values for each spiked gas and unspiked
flue gas sample (ppm);
11.4.3.11 The mean values of the spiked and unspiked sample
concentrations and the expected value of the spiked concentration as
specified in section 12.1 of PS 15 of appendix B to part 60 of this
chapter (ppm);
11.4.3.12 Bias at the spike level as calculated using equation 3
in section 12.1 of PS 15 of appendix B to part 60 of this chapter;
and
11.4.3.13 The correction factor (CF), calculated using equation
6 in section 12.1 of PS 15 of appendix B to part 60 of this chapter.
11.4.4 For each quarterly parameter verification check for an
integrated path HCl CEMS under PS 18 of appendix B to part 60 of
this chapter, report:
11.4.4.1 [Reserved]
11.4.5 For each quarterly gas audit under P S 18 of appendix B
to part 60 of this chapter, report:
11.4.5.1 [Reserved]
11.4.6 For each quarterly dynamic spiking audit as allowed by P
S 18 of appendix B to part 60 of this chapter, report:
11.4.6.1 [Reserved]
11.4.7 For each RATA or RAA of an HCl or HF CEMS, report:
11.4.7.1 Facility ID information;
11.4.7.2 Monitoring system ID number;
11.4.7.3 Type of test (i.e., initial or annual RATA or RAA);
11.4.7.4 Reason for test;
11.4.7.5 The reference method used;
11.4.7.6 Starting and ending date and time for each test run;
11.4.7.7 Units of measure;
11.4.7.8 The measured reference method and CEMS values for each
test run, on a consistent moisture basis, in appropriate units of
measure;
11.4.7.9 Flags to indicate which test runs were used in the
calculations;
11.4.7.10 Arithmetic mean of the CEMS values, of the reference
method values, and of their differences;
11.4.7.11 Standard deviation, as specified in Equation 2-4 of PS
2 or PS 18, as applicable in appendix B to part 60 of this chapter;
11.4.7.12 Confidence coefficient, as specified in Equation 2-5
of PS 2 or PS 18, as applicable in appendix B to part 60 of this
chapter; and
11.4.7.13 Relative accuracy calculated using Equation 2-6 of PS
2 or PS 18, as applicable in appendix B to part 60 of this chapter
or, if applicable, according to the alternative procedure for low
emitters described in paragraph 3.1.2.2 of this appendix. If
applicable use a flag to indicate that the alternative RA
specification for low emitters has been applied.
* * * * *
11.4.8 Reporting Requirements for Diluent Gas, Flow Rate, and
Moisture Monitoring Systems. For the certification, recertification,
diagnostic, and QA tests of stack gas flow rate, moisture, and
diluent gas monitoring systems that are certified and quality-
assured according to part 75 of this chapter, report the information
in section 10.1.8.2 of this appendix.
* * * * *
11.5.3.4 The results of all daily calibrations (including
calibration transfer standard tests and beam intensity checks of
integrated path CEMS) of the HCl or HF monitor as described in
paragraph 10.1.8.1.1 of this appendix; and
* * * * *
[FR Doc. 2015-01699 Filed 2-13-15; 8:45 am]
BILLING CODE 6560-50-P
