[Federal Register Volume 80, Number 31 (Tuesday, February 17, 2015)]
[Proposed Rules]
[Pages 8441-8484]
[FR Doc No: 2015-01699]

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

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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.

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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: http://www.regulations.gov.
Follow the instructions for submitting comments.
     Agency Web site: http://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
<EMAIL_ADDRESS>Attention EPA-HQ-OAR-2011-0044 (NSPS action) or
EPA-HQ-OAR-2009-0234 (NESHAP/MATS action).
     Fax: Fax your comments to:<PHONE_NUMBER>, 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:<PHONE_NUMBER>; Fax number<PHONE_NUMBER>;
email address<EMAIL_ADDRESS>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:<PHONE_NUMBER>; Fax
number<PHONE_NUMBER>; email address<EMAIL_ADDRESS>
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 http://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
http://www.regulations.gov or email. The http://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 http://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:<PHONE_NUMBER>; email address:
<EMAIL_ADDRESS>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

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:<PHONE_NUMBER>; email address<EMAIL_ADDRESS>to request a hearing.
    Docket. All documents in the docket are listed in the http://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 http://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<PHONE_NUMBER>, and the telephone number for the
Air Docket is<PHONE_NUMBER>.

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

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 http://www.epa.gov/ttn/atw/boiler/boilerpg.html. The prepublication version will be replaced
with the Federal Register document when the proposal is published.
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    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.
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    \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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    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.

    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

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).
---------------------------------------------------------------------------

    \3\ See the description of the ``third approach'' at 79 FR 24708
(April 24, 2013).
---------------------------------------------------------------------------

    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

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

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 <IP_ADDRESS> and <IP_ADDRESS> 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 <IP_ADDRESS> 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 <IP_ADDRESS>.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 <IP_ADDRESS>, Table A-1, Table A-2, <IP_ADDRESS>, and <IP_ADDRESS>
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 <IP_ADDRESS> of Appendix A to subpart UUUUU of Part 63 is
revised to make the weekly single level system integrity check
mandatory.
    64. Paragraphs <IP_ADDRESS>.2, Table A-1, Table A-2, and <IP_ADDRESS> 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 <IP_ADDRESS> 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 <IP_ADDRESS> 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, <IP_ADDRESS>, <IP_ADDRESS>.1, and <IP_ADDRESS>.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 <IP_ADDRESS>.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 <IP_ADDRESS>, <IP_ADDRESS>.2.1, and <IP_ADDRESS>.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 <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>,
<IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>,
<IP_ADDRESS>, and <IP_ADDRESS> 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 <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>,
<IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>,
<IP_ADDRESS>, and <IP_ADDRESS> 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 <IP_ADDRESS>, 11.4.5, <IP_ADDRESS>, 11.4.6, <IP_ADDRESS> 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 <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>,
<IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>, <IP_ADDRESS>,
<IP_ADDRESS>, and <IP_ADDRESS> 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 <IP_ADDRESS> 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

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 http://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-

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

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

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.

[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

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

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,

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.

    (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

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

                                       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..........

                                       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