[Federal Register Volume 78, Number 79 (Wednesday, April 24, 2013)]
[Rules and Regulations]
[Pages 24073-24094]
[FR Doc No: 2013-07859]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044; FRL-9789-5]
RIN 2060-AR62

Reconsideration of Certain New Source Issues: 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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule; notice of final action on reconsideration.

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SUMMARY: The EPA is taking final action on its reconsideration of
certain issues in the final rules 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.'' The
National Emission Standards for Hazardous Air Pollutants (NESHAP) rule
issued pursuant to Clean Air Act (CAA) section 112 is referred to as
the Mercury and Air Toxics Standards (MATS) NESHAP, and the New Source
Performance Standards rule issued pursuant to CAA section 111 is
referred to as the Utility NSPS. The Administrator received petitions
for reconsideration of certain aspects of the MATS NESHAP and the
Utility NSPS.
    On November 30, 2012, the EPA granted reconsideration of, proposed,
and requested comment on a limited set of issues. We also proposed
certain technical corrections to both the MATS NESHAP and the Utility
NSPS. The EPA is now taking final action on the revised new source
numerical standards in the MATS NESHAP and the definitional and
monitoring provisions in the Utility NSPS that were addressed in the

proposed reconsideration rule. As part of this action, the EPA is also
making certain technical corrections to both the MATS NESHAP and the
Utility NSPS. The EPA is not taking final action on requirements
applicable during periods of startup and shutdown in the MATS NESHAP or
on startup and shutdown provisions related to the PM standard in the
Utility NSPS.

DATES: The effective date of the rule is April 24, 2013.
    Docket. The EPA established two dockets for this action: Docket ID
EPA-HQ-OAR-2011-0044 (NSPS action) and Docket ID EPA-HQ-OAR-2009-0234
(MATS NESHAP action). All documents in the dockets are listed in the
http://www.regulations.gov index. Although listed in the index, some
information is not publicly available (e.g., confidential business
information (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
(202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For the MATS NESHAP action: Mr.
William Maxwell, 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>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:
    Outline. The information presented in this preamble is organized as
follows:

I. General Information
    A. Does this action apply to me?
    B. How do I obtain a copy of this document?
    C. Judicial Review
II. Background
III. Summary of Today's Action
IV. Summary of Final Action and Changes Since Proposal--MATS NESHAP
New Source Issues
V. Summary of Final Action and Changes Since Proposal--Utility NSPS
VI. Technical Corrections and Clarifications
VII. Impacts of This Final Rule
    A. Summary of Emissions Impacts, Costs and Benefits
    B. What are the air impacts?
    C. What are the energy impacts?
    D. What are the compliance costs?
    E. What are the economic and employment impacts?
    F. What are the benefits of the final standards?
VIII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
    K. Congressional Review Act

I. General Information

A. Does this action apply to me?

    Categories and entities potentially affected by today's action
include:

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                                                 Examples of potentially
            Category              NAICS code\1\     regulated entities
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Industry.......................          221112  Fossil fuel-fired
                                                  electric utility steam
                                                  generating units.
Federal government.............      \2\ 221122  Fossil fuel-fired
                                                  electric utility steam
                                                  generating units owned
                                                  by the Federal
                                                  government.
State/local/Tribal government..      \2\ 221122  Fossil fuel-fired
                                                  electric utility steam
                                                  generating units owned
                                                  by municipalities.
                                         921150  Fossil fuel-fired
                                                  electric utility steam
                                                  generating units in
                                                  Indian country.
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\1\ North American Industry Classification System.
\2\ Federal, State, or local government-owned and operated
  establishments are classified according to the activity in which they
  are engaged.

    This table is not intended to be exhaustive but rather to provide a
guide for readers regarding entities likely to be affected by this
action. To determine whether your facility, company, business,
organization, etc. would be regulated by this action, you should
examine the applicability criteria in 40 CFR 60.40, 60.40Da, or 60.40c
or in 40 CFR 63.9982. If you have any questions regarding the
applicability of this action to a particular entity, consult either the
air permitting authority for the entity or your EPA regional
representative as listed in 40 CFR 60.4 or 40 CFR 63.13 (General
Provisions).

B. How do I obtain a copy of this document?

    In addition to being available in the docket, electronic copies of
these final rules will be available on the Worldwide Web (WWW) through
the Technology Transfer Network (TTN). Following signature, a copy of
the action will be posted on the TTN's policy and guidance page for
newly proposed or promulgated rules at the following address: http://www.epa.gov/ttn/oarpg/. The TTN provides information and technology
exchange in various areas of air pollution control.

C. Judicial Review

    Under the CAA section 307(b)(1), judicial review of this final rule
is available only by filing a petition for review in the U.S. Court of
Appeals for the District of Columbia Circuit by June 24, 2013. Under
CAA section 307(d)(7)(B), only an objection to this final rule that was
raised with reasonable specificity during the period for public comment
can be raised during judicial review. Note, under CAA section
307(b)(2), the requirements established by this final rule may not be
challenged separately in any civil or criminal proceedings brought by
the EPA to enforce these requirements.

II. Background

    The final MATS NESHAP and the Utility NSPS rules were published in
the Federal Register at 77 FR 9304 on

February 16, 2012. Following promulgation of the final rules, the
Administrator received petitions for reconsideration of numerous
provisions of both the MATS NESHAP and the Utility NSPS pursuant to CAA
section 307(d)(7)(B). Copies of the MATS NESHAP petitions are provided
in rulemaking docket EPA-HQ-OAR-2009-0234. Copies of the Utility NSPS
petitions are provided in rulemaking docket EPA-HQ-OAR-2011-0044. On
November 30, 2012, the proposal granting reconsideration of certain
issues in the MATS NESHAP and Utility NSPS was published in the Federal
Register at 77 FR 71323.

III. Summary of Today's Action

    This final action amends certain provisions of the final rule
issued by the EPA on February 16, 2012. Through an August 2, 2012,
notice (77 FR 45967), the EPA delayed the effective date of the
February 2012 MATS rule for new sources only. That stay was limited to
90 days and has since expired. The February 2012 final rule is and
remains in effect for all sources.
    The November 30, 2012, proposed reconsideration rule proposed: (1)
Certain revised new source numerical standards in the MATS NESHAP, (2)
requirements applicable during periods of startup and shutdown in the
MATS NESHAP, (3) startup and shutdown provisions related to the
particulate matter (PM) standard in the Utility NSPS, and (4)
definitional and monitoring provisions in the Utility NSPS. We also
proposed certain technical corrections to both the MATS NESHAP and the
Utility NSPS. We are taking final action today on the revised numerical
new source MATS NESHAP limits, the definitional and monitoring issues
in the Utility NSPS, and all of the technical corrections not related
to startup/shutdown issues.
    This summary of the final rule reflects the changes to 40 CFR Part
63, subpart UUUUU, and 40 CFR Part 60, subpart Da (77 FR 9304; February
16, 2012) made in this regard.
    As noted above, in the proposed reconsideration rule, the EPA took
comment on the requirements in the MATS NESHAP applicable during
startup and shutdown, including the definitions of startup and
shutdown. The EPA also took comment on the startup and shutdown
provisions relating to the PM standard in the Utility NSPS. The EPA
received considerable comments regarding these startup and shutdown
provisions, including data and information relevant to the proposed
work practice standard that applies in such periods. The EPA is not
taking final action on the startup and shutdown provisions at this time
as it needs additional time to consider and evaluate the comments and
data provided.\1\ The Agency is currently reviewing all of the comments
received on the startup and shutdown issues and intends to act promptly
to address these issues. We note that no existing sources will have to
comply with the existing source MATS standards before April 16, 2015.
Further, no new sources are currently under construction and it takes
years to complete construction. 77 FR 71330, fn. 7. As such, there will
be sufficient time for the Agency to review the comments submitted
concerning the proposed startup and shutdown provisions and take
appropriate action well in advance of any new source being subject to
those provisions.
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    \1\ The EPA is also still reviewing the other issues raised in
the petitions for reconsideration and is not taking any action at
this time with respect to those issues.
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    As described below, on the basis of information provided since the
reconsideration proposal, today's action revises certain new source
numerical limits in the MATS NESHAP. Specifically, the EPA is
finalizing revised hydrogen chloride (HCl), filterable PM (fPM),\2\
sulfur dioxide (SO2), lead (Pb), and selenium emission
limits for all new coal-fired EGUs; the mercury (Hg) emission limit for
the ``unit designed for coal >= 8,300 Btu/lb subcategory;'' fPM and
SO2 emission limits for new solid oil-derived fuel-fired
EGUs; fPM emission limits for new continental liquid oil-fired EGUs;
and most of the emission limits for new integrated gasification
combined cycle (IGCC) units.
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    \2\ As the final MATS rule established a filterable PM (fPM)
limit, every reference in this preamble to a PM limit means
filterable PM.
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    The fPM, HCl, and Hg limits that we are finalizing in this action
are provided in table 1; the alternate limits that we are finalizing
are provided in table 2.\3\
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    \3\ The final rule included certain alternative limits (see 77
FR 9367-9369).

                               Table 1--Revised Emission Limitations for New EGUs
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                                     Filterable particulate    Hydrogen chloride, lb/
           Subcategory                   matter, lb/MWh                  MWh                 Mercury, lb/GWh
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New--Unit not designed for low     9.0E-2...................  1.0E-2 \a\..............  3.0E-3.
 rank virgin coal.
New--Unit designed for low rank    9.0E-2...................  1.0E-2 \a\..............  NR.
 virgin coal.
New--IGCC........................  7.0E-2 \b\...............  2.0E-3..................  3.0E-3.
                                   9.0E-2 \c\...............
New--Solid oil-derived...........  3.0E-2...................  NR......................  NR.
New--Liquid oil--continental.....  3.0E-1...................  NR......................  NR.
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Note: lb/MWh = pounds pollutant per megawatt-hour electric output (gross).
lb/GWh = pounds pollutant per gigawatt-hour electric output (gross).
NR = limit not opened for reconsideration (77 FR 9304; February 16, 2012).
\a\ Beyond-the-floor value.
\b\ Duct burners on syngas; based on permit levels in comments received.
\c\ Duct burners on natural gas; based on permit levels in comments received.

                          Table 2--Revised Alternate Emission Limitations for New EGUs
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      Subcategory/pollutant             Coal-fired EGUs               IGCC \a\              Solid oil-derived
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SO2..............................  1.0 lb/MWh...............  4.0E-1 lb/MWh \b\.......  1.0 lb/MWh
Total non-mercury metals.........  NR.......................  4.0E-1 lb/GWh...........  NR
Antimony, Sb.....................  NR.......................  2.0E-2 lb/GWh...........  NR
Arsenic, As......................  NR.......................  2.0E-2 lb/GWh...........  NR

Beryllium, Be....................  NR.......................  1.0E-3 lb/GWh...........  NR
Cadmium, Cd......................  NR.......................  2.0E-3 lb/GWh...........  NR
Chromium, Cr.....................  NR.......................  4.0E-2 lb/GWh...........  NR
Cobalt, Co.......................  NR.......................  4.0E-3 lb/GWh...........  NR
Lead, Pb.........................  2.0E-2 lb/GWh............  9.0E-3 lb/GWh...........  NR
Mercury, Hg......................  NA.......................  NA......................  NR
Manganese, Mn....................  NR.......................  2.0E-2 lb/GWh...........  NR
Nickel, Ni.......................  NR.......................  7.0E-2 lb/GWh...........  NR
Selenium, Se.....................  5.0E-2 lb/GWh............  3.0E-1 lb/GWh...........  NR
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NA = not applicable.
NR = limit not opened for reconsideration (77 FR 9304; February 16, 2012).
\a\ Based on best-performing similar source.
\b\ Based on DOE information.

    In addition, in the MATS NESHAP the EPA is removing quarterly stack
testing as an option to demonstrate compliance with the new source fPM
emission limits; revising the way in which an owner or operator of a
new EGU who chooses to use PM continuous parameter monitoring systems
(CPMS) establishes an operating limit; requiring inspections and
retesting within 45 days of an exceedance of the operating limit for
those new EGU owners or operators who choose to use PM CPMS as a
compliance option; and finalizing the presumption of violation of the
emissions limit if more than 4 emissions tests are required in a 12-
month period.
    The final changes to the numerical emissions limits noted above
incorporate information about the variability of the best performing
EGUs and more accurately reflect the capabilities of emission control
equipment for new EGUs. The final changes should also address
commenters' concerns that vendors of EGU emission controls had been
unwilling to provide guarantees regarding the ability to meet all of
the standards for new EGUs as originally finalized in February 2012.
    We expect that source owners and operators will install and operate
the same or similar control technologies to meet the revised standards
in this reconsideration action as they would have chosen to comply with
the standards in the February 2012 final rule. Consistent with CAA
section 112(a)(4), we are maintaining the new source trigger date for
the MATS NESHAP rule as May 3, 2011. See 77 FR 71330, fn. 7. New
sources must comply with the revised MATS emission standards described
in section IV below by April 24, 2013, or startup, whichever is later.
    In the February 2012 final Utility NSPS rule, the EPA adopted a
definition of natural gas that excludes coal-derived synthetic natural
gas consistent with the definition in MATS. In the Utility NSPS
reconsideration proposal, we re-proposed and requested comment on that
definition. Based on review of the comments received in response to the
reconsideration proposal, the EPA has concluded that the definition of
natural gas in the final Utility NSPS is appropriate and, therefore, is
not making any changes to that definition. We are also finalizing as
proposed one conforming amendment and two amendments related to EGUs
burning desulfurized coal-derived synthetic natural gas. First, we
amended the definition of coal to make it clear that coal-derived
synthetic natural gas is considered to be coal. In addition, in
recognition of the fact that emissions from the burning of desulfurized
coal-derived synthetic natural gas are very similar to those from the
burning of natural gas, we amended the opacity and SO2
monitoring provisions so that facilities burning desulfurized coal-
derived synthetic natural gas will have opacity and SO2
monitoring requirements similar to those of facilities burning natural
gas. Further, we are finalizing certain revisions to the definition of
IGCC in the Utility NSPS. We are also finalizing as proposed the
revised procedures for calculating PM emission rates intended to make
the Utility NSPS procedures consistent with those in the MATS NESHAP.
We did not receive any adverse comments regarding this proposed change.
Finally, we are finalizing as proposed the technical corrections to the
PM standards for facilities that commenced construction before March 1,
2005, and for facilities that commence modification after May 3, 2011.
    The impacts of today's revisions on the costs and the benefits of
the final rule are minor. As noted above, we expect that source owners
and operators will install and operate the same or similar control
technologies to meet the revised standards in this action as they would
have chosen to comply with the standards in the February 2012 final
rule.

IV. Summary of Final Action and Changes Since Proposal--MATS NESHAP New
Source Issues

    After consideration of the public comments received, the EPA has
made certain changes in this final action from the reconsideration
proposal. We address the most significant comments in this preamble.
However for a complete summary of the comments received on the issues
we are finalizing today and our responses thereto, please refer to the
memorandum ``National Emission Standards For Hazardous Air Pollutants
From Coal- And Oil-Fired Electric Utility Steam Generating Units--
Reconsideration; Summary Of Public Comments And Responses'' (March
2013) in rulemaking docket EPA-HQ-OAR-2009-0234.
    In this action, we are finalizing certain new source emission
limits for the MATS NESHAP, as discussed below.

1. Changes to Certain New Source MATS NESHAP Limits

    Commenters noted that in two instances, Pb emissions from coal-
fired EGUs and the fPM emissions from continental liquid oil-fired
EGUs, the EPA had proposed new source emission limits that were less
stringent than those in the final MATS NESHAP for the respective
existing sources. This approach was inconsistent with that taken in the
final MATS NESHAP.\4\ Although CAA section 112(d)(3) allows existing
source MACT floor limits to be less stringent than new source limits,
the EPA interprets this provision as

precluding new source limits from being less stringent than existing
source limits. See CAA section 112(d)(3). Thus, for Pb emissions from
coal-fired EGUs and fPM emissions from continental liquid oil-fired
EGUs, the EPA is finalizing new source limits that are equivalent to
the final existing-source limits.
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    \4\ See ``National Emission Standards for Hazardous Air
Pollutants (NESHAP) Maximum Achievable Control Technology (MACT)
Floor Analysis for Coal- and Oil-fired Electric Utility Steam
Generating Units for Final Rule,'' Docket ID EPA-HQ-OAR-2009-0234-
20132, p. 13.
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    Next, commenters noted that when evaluating SO2
emissions data from coal-fired EGUs, the EPA had not selected the
lowest emitting source upon which to base the emission limit and that
its rationale for excluding certain data was unlawful and arbitrary.
Although the EPA disagrees with commenters on several of the excluded
data sets (i.e., some of the data sets suggested by commenters
comprised only a single 3-run average for each EGU with no individual
run data, making assessment of variability impossible), it agrees that
it inadvertently omitted the data from Stanton Unit 10 in the proposal
analyses. Stanton Unit 10 does have a lower ``lowest'' 3-run data
average than does the EGU selected for the new source floor analysis
(Sandow Unit 5A) in the proposed reconsideration rule.
    In this final action, the EPA used the Stanton data to calculate
the MACT floor using the same statistical analyses used in the proposed
rule (i.e., 99 percent upper predictive limit (UPL)), and the resulting
MACT floor emission limit is 1.3 pounds per megawatt-hour (lb/MWh).
Because this limit is less stringent than the new source performance
standard (NSPS) finalized in the Utility NSPS (77 FR 9451; February 16,
2012), the EPA is finalizing a beyond-the-floor (BTF) MACT standard of
1.0 lb/MWh, which is the same level required by the CAA section 111
NSPS for these same sources.\5\ See 40 CFR 60.43Da(l)(1)(i). Cost is a
required consideration in establishing CAA section 111 rules and in
going BTF in establishing CAA section 112 rules. We evaluated cost in
assessing whether to go BTF for this standard and concluded that it was
appropriate to go BTF to a level of 1.0 lb/MWh. Moreover, the NSPS
limit (also 1.0 lb/MWh) is in place and coal-fired EGUs are required to
comply with that limit. As such, there is no additional cost to these
sources.\6\ Furthermore, we have not identified any non-air quality
health or environmental impacts or energy requirements associated with
the final standard set at this level. In addition, in support of the
proposed reconsideration rule, we evaluated an emissions level more
stringent than 1.0 lb/MWh and found that level to not be cost
effective.\7\ For these reasons, we are finalizing 1.0 lb/MWh as the
new source MATS NESHAP limit.
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    \5\ The CAA section 111 standard is based on the performance of
EGUs with the best performing SO2 controls, a reasonable
incremental cost effectiveness of less than $1,000 per ton of
SO2 controlled, and controls that result in minimal
secondary environmental and energy impacts.
    \6\ The final Utility NSPS limit was not challenged and coal-
fired EGUs constructed after May 3, 2011, must meet that limit.
    \7\ See Docket ID EPA-HQ-OAR-2009-0234-20221 and National
Emission Standards for Hazardous Air Pollutants (NESHAP) Beyond the
Maximum Achievable Control Technology (MACT) Floor (`Beyond-the-
Floor') Analysis for Revised Emission Standards for New Source Coal-
and Oil-fired Electric Utility Steam Generating Units also in the
rulemaking docket.
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    In the proposed reconsideration rule, we indicated that detection
level issues may arise from using a sorbent trap when short sampling
periods (e.g., 30 minutes) are used. As such, the EPA solicited comment
on its establishment of a Representative Detection Level (RDL)
associated with Hg sorbent traps. The EPA also solicited comment on
whether the UPL calculated floor should be compared against the 3XRDL
value for Hg to account for the shorter sampling periods (the 3XRDL
approach). The EPA received several comments, ranging from strong
support for the Hg RDL and the proposed emission limit because, at that
level, the commenters asserted that vendors would be able to provide
commercial guarantees, to concerns about the specific inputs to the
3XRDL calculation and the application of the 3xRDL approach. See
section 2.2.1 of the response to comments document (RTC) for a more
complete discussion and response to these comments.
    In the proposed reconsideration rule, the EPA recognized that 30
minutes of sample collection is the shortest reasonable amount of time
available for collecting and changing sorbent tubes to provide the
quick, reliable feedback that will allow sources to react to changing
Hg emissions levels and assure compliance with the final Hg limit. Some
commenters pointed out that the EPA's memorandum entitled
``Determination of Representative Detection Level (RDL) and 3 X RDL
Values for Mercury Measured Using Sorbent Trap Technologies,'' \8\
contains a 30-minute sample collection time in the 3XRDL calculation,
but the text of the memorandum references a 20-minute sample collection
time. The EPA has revised the text of the memorandum to reflect its
original intent, which was to focus on a sample collection period of 30
minutes (not 20 minutes). The revised memorandum focuses on the 30-
minute sample collection period. Given that it takes 5 minutes for
sorbent trap insertion and removal, it would take a total of 40 minutes
to secure the requisite sample collection (30 minutes for sample
collection, 5 minutes to remove the sorbent trap, and 5 minutes to re-
insert the trap). We are finalizing the Hg limit using the 3XRDL
approach assuming a 30-minute sampling time.
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    \8\ The EPA developed the memorandum to determine appropriate
RDL and 3XRDL values for sorbent trap monitoring systems, as well as
calculate an emissions limit, in order to determine the shortest,
reasonable sample collection period for those systems. See EPA
Docket ID EPA-HQ-OAR-2009-0234-20222.
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2. Filterable PM Testing, Monitoring, and Compliance

Certification for New EGUs in the MATS NESHAP Rule
    Several monitoring options for the fPM standard for new sources
were provided in the MATS NESHAP final rule, including quarterly stack
testing, PM CEMS, and PM CPMS with annual testing.
    The EPA sought comment on whether to retain the quarterly stack
testing compliance option for new EGUs, given that continuous, direct
measurement of fPM or a correlated parameter is available, is
preferable for determining compliance on a continuous basis, and is
likely to be used by most new EGUs to monitor compliance with the
proposed new source standards. As mentioned above, this final action
does not retain the quarterly fPM performance testing option for new
EGUs. New EGUs can be designed to incorporate PM CEMS or PM CPMS from
the outset, without being impeded by retrofit location installation
constraints that could impact existing EGUs. This final action now
requires new sources to use either PM CEMS or PM CPMS as options for
determining compliance with the new source fPM limits.
    The EPA requested comment on a number of issues associated with PM
CPMS. The EPA first solicited comment on three approaches to establish
an operating limit based on emissions testing for those EGU owners or
operators who choose to use PM CPMS as the means of demonstrating
compliance with the fPM emission limit. The first approach would
require an EGU owner or operator to use the highest parameter value
obtained during any run of an individual emissions test as the
operating limit when the result of that individual test was below the
limit. The second approach would require an EGU owner or operator to
use the average parameter value obtained from

all runs of an individual emissions test as the operating limit,
provided that the result of the individual emissions test met the
emissions limit. The third approach, which the EPA is finalizing in
this final action, would require an EGU owner or operator to use the
higher of the following: (1) A parameter scaled from all values
obtained during an individual emissions test to 75 percent of the
emissions limit or (2) the average parameter value obtained from all
runs of an individual emissions test as the operating limit provided
that the result of the individual emissions test met the emissions
limit. As established and reaffirmed in the recent Sewage Sludge
Incineration, Major Source Industrial Boiler, and Portland Cement
rules,\9\ it is appropriate to provide increased operational
flexibility and reduced emissions testing for sources that emit at or
below 75 percent of a standard--whether an emissions or operating
limit--as these are the lowest emitting sources. Reduced emissions
testing is available in this final rule for those owners or operators
whose EGU emissions do not exceed this 75 percent threshold. This 75
percent threshold allows for compliance flexibility and is
simultaneously protective of the emission standards. The EPA believes
well performing EGUs, i.e., those whose emissions do not exceed 75
percent of the emissions limit, should not face additional scrutiny or
testing consequences provided their emissions remain equivalent to or
below the 75 percent threshold. In this final action, the EPA uses the
75 percent threshold so as not to impose unintended and costly retest
requirements for the lowest emitting sources and to provide for more
cost effective, continuous, PM parametric monitoring across the EGU
sector. This approach was selected from the options considered as it
provides the greatest amount of EGU owner or operator flexibility while
demonstrating continuous compliance for EGUs. With this parametric
monitoring approach in place, the EPA expects EGUs to evaluate control
options that provide excellent fPM emissions control and provide them
greater operational flexibility.
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    \9\ See Standards of Performance for New Stationary Sources and
Emission Guidelines for Existing Sources: Commercial and Industrial
Solid Waste Incineration Units, 76 FR 15736 (March 21, 2011);
Subpart DDDDD--National Emission Standards for Hazardous Air
Pollutants for Major Sources: Industrial, Commercial, and
Institutional Boilers and Process Heaters, 40 CFR 63.7515(b); and
National Emission Standards for Hazardous Air Pollutants for the
Portland Cement Manufacturing Industry and Standards of Performance
for Portland Cement Plants, 78 FR 10014 (February 12, 2013).
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    Moreover, after each exceedance of the operating limit, the EPA
proposed to require emissions testing to verify or re-adjust the
operating limit, consistent with the approach contained in the
recently-promulgated Portland cement MACT standard (see 78 FR 10014).
One commenter objected to potential frequent emissions testing to
reassess the operating limit and then being subject to a violation of
the emissions limit. The EPA does not believe that too-frequent testing
will be required. As discussed in section 4.3.5 of the RTC, the EPA
believes well-designed emissions testing will provide an operating
limit corresponding with EGU operation, and such testing should yield
an operating limit that would not be expected to be exceeded during the
course of EGU operation. Therefore, an operating limit developed from
well-designed emissions testing should have little, if any, need for
frequent reassessment via emissions testing more frequently than the
mandated annual reassessment because the source will be able to meet
the limit on an ongoing basis.
    Finally, the EPA proposed that PM CPMS exceedances leading to more
than 4 required emissions tests in a 12-month period (rolling monthly)
would be presumed (subject to the possibility of rebuttal by the EGU
owner or operator) to be a violation of the emissions limit, consistent
with the approach contained in the newly-promulgated Portland cement
MACT standard (see 78 FR 10014). The EPA received a number of comments
on this proposed provision, including comments supporting and opposing
the establishment of such a presumption.
    The EPA disagrees with those comments opposing the presumptive
violation, and believes the presumptive violation provision in the
final rule is a reasonable and appropriate approach to ensure
compliance with the standard. First, the EPA may permissibly establish
such an approach by rule, assuming there is a reasonable factual basis
to do so. See Hazardous Waste Treatment Council v. EPA, 886 F. 2d 355,
367-68 (DC Cir. 1989) (explaining that such presumptions can
legitimately establish the elements of the EPA's prima facie case in an
enforcement action). Second, there is a reasonable basis here for the
presumption that four exceedances (i.e., increases over the parametric
operating limit) in a calendar year are a violation of the emission
standard. The parametric monitoring limit is established as a 30-day
average of the averaged test value in the performance test, or the 75th
percentile value if that is higher. In either instance, the 30-day
averaging feature provides significant leeway to the EGU owner or
operator not to deviate from the parametric operating level because the
impact of transient peaks or valleys is limited due to the length of
the rule's averaging period--30 boiler operating days, rolled daily.
See 77 FR 42377/2 and sources there cited. See also 78 FR 10015, 10019;
February, 12, 2013 (Portland Cement MACT) and the RTC for today's
action.
    The EPA also received comments addressing the re-testing
requirements following an exceedance. Some commenters expressed concern
about the burden of requiring sources to conduct performance tests in
order to demonstrate compliance and to reassess the parameter level. In
contrast, other commenters supported a requirement to require re-
testing but claimed that the time period between observing a parameter
exceedance and retesting is too long. The EPA believes that the re-
testing requirements are reasonable and appropriate to identify non-
compliance without imposing undue burden. For even a single exceedance
to occur, the 30-day average would have to be higher than the operating
limit established for the PM CPMS during normal EGU operation. If that
occurs, then the EGU owner or operator is required to conduct an
inspection to determine any abnormalities and an emissions test to re-
establish or generate a new operating limit. Given that EGUs and their
emissions control devices are designed to operate at known, specific
conditions, deviations from these conditions are not expected and are
indicative of problems with load, controls, or some combination of
both. Where these sorts of problems result in an exceedance of the
source's operating limit, it is reasonable to require re-testing in
order to identify and then correct problems. More than four such
exceedances of the 30-day average would mean that the EGU owner or
operator was unable to determine or correct the problem, since
inspection and re-calculation of the operating limit is required after
each exceedance. This indicates an ongoing problem with maintaining
process control and/or control device operation, which would be the
basis for a presumptive violation of the emissions standard. Moreover,
the EPA disagrees that the period between exceedance of the operating
limit and retesting is too long and could result in possible excessive
emissions. Specifically, some commenters claimed that the final rule
should not limit the number of exceedances of the PM CPMS limit that
require follow-up performance tests in any 12-month period. These
commenters alleged that to do so does

not ensure continuous compliance because the time period between an
exceedance and testing could be too long, and a source could be
exceeding the emission limit during that time period. The EPA believes
that the re-testing requirements reflect a reasonable balance between
ensuring compliance and limiting unnecessary testing burden on
regulated sources. An EGU owner or operator is required to visually
inspect the air pollution control device within 48 hours of the
exceedance, and corrective action must be taken as soon as possible to
return the PM CPMS measurement to within the established value. A
performance test is also required within 45 days of the exceedance to
determine compliance and verify or re-establish the PM CPMS limit.
Thus, the EPA finds it unlikely that there will be long periods of
noncompliance with the underlying fPM standard given the inspection and
performance testing requirements.
    The EPA also received comments stating that an EGU owner or
operator should not be labeled a ``violator'' of the fPM standard as a
result of a fourth compliance test in a 12-month period. First, the EPA
notes that the rule identifies more than 4 compliance tests over a 12-
month period as only a presumptive violation of the emissions limit. A
presumption of a violation is just that--a presumption--and can be
rebutted in any particular case.
    Moreover, in determining whether the presumption has been
successfully rebutted, a Court may consider relevant information such
as data or other information showing that the EGU's operating process
remained in control during the period of operating parameter
exceedance, that the ongoing operation and maintenance conducted on the
EGU ensured its emissions control devices remained in proper operating
condition during the period of operating parameter exceedance, and that
results of emissions tests conducted while replicating the conditions
observed during the period of operating parameter exceedance remained
below the emission limit.
    For the reasons explained above, this final action includes the
presumption of violation of the emissions limit if more than 4
emissions tests are required in a 12-month period.

V. Summary of Final Action and Changes Since Proposal--Utility NSPS

    The EPA has made a number of changes from the reconsideration
proposal in this final action after consideration of the public
comments received. Most of the changes to the Utility NSPS clarify
applicability and implementation issues raised by the commenters. The
public comments received on the matters proposed for reconsideration
and the responses to them can be viewed in the memorandum ``Summary of
EGU NSPS Public Comments and Responses on Amendments Proposed November
30, 2012 (77 FR 71323)'' in rulemaking docket EPA-HQ-OAR-2011-0044.
    In the proposed reconsideration rule, the EPA proposed a new
definition for IGCC which would be consistent with the MATS NESHAP
definition. However, as an alternative we requested comment on whether
to retain a definition similar, but not identical, to the IGCC
definition in the February 2012 final Utility NSPS. We have concluded
that the alternative approach is most appropriate and are adopting a
slightly revised definition that is consistent with the Agency's
statements on IGCC contained in the RTC in support of the final Utility
NSPS rule published on February 16, 2012 (77 FR 9304). Commenters
generally supported amending the final Utility NSPS definition of IGCC,
and this final action amends that definition consistent with the
statements made in the RTC for the Utility NSPS. The Utility NSPS IGCC
definition deals with the intent of an IGCC facility and is, thus,
broader than the definition in the MATS NESHAP. The facility would
still be subject to the same criteria pollutant emission standards even
when burning natural gas for extended periods of time. The MATS NESHAP
applicability is determined based on the EGU's utilization of coal and
oil and the rule may not apply depending on the extent of natural gas
usage.
    The EPA proposed that the NSPS PM monitoring procedures be
consistent with the MATS NESHAP requirements and included the use of
quarterly stack testing, PM CPMS, or PM CEMS. In addition, the EPA
sought comment on whether to include the quarterly stack testing
compliance option for new EGUs, given that continuous, direct
measurement of PM or a correlated parameter is available. EGUs
complying with an output-based emissions standard can be designed to
incorporate PM CEMS or PM CPMS from the outset, without being impeded
by retrofit location installation constraints that would impact
existing EGUs. This final action requires EGUs complying with an
output-based standard to use either PM CEMS or PM CPMS as options for
determining compliance with the PM limits. Therefore, the EPA is
finalizing the same monitoring procedures for PM for the Utility NSPS
as for new sources subject to the MATS NESHAP, and is not finalizing
the quarterly stack testing option.
    The EPA proposed that facilities using PM CPMS would be able to use
either a continuous opacity monitoring system or a periodic alternate
monitoring approach to monitor opacity. This final action does not
require facilities using a PM CPMS to conduct opacity monitoring. The
EPA has concluded that the use of a PM CPMS at the level of the
emissions standard required in subpart Da is sufficient to demonstrate
compliance with the opacity standard and that additional monitoring is
an unnecessary burden.

VI. Technical Corrections and Clarifications

    On April 19, 2012 (77 FR 23399), the EPA issued a technical
corrections notice addressing certain corrections to the February 16,
2012 (77 FR 9304), MATS NESHAP and Utility NSPS. In the November 30,
2012, reconsideration proposal, we proposed several additional
technical corrections. Specific to the NSPS, we proposed correcting the
PM standard for facilities that commenced construction before March 1,
2005, to remove the extra significant digit that was inadvertently
added and to correct the PM standard for facilities that commence
modification after May 3, 2011, to be consistent with the original
intent as expressed in the RTC of the final rule published on February
16, 2012 (77 FR 9304). We did not receive any negative comments on
these issues and are finalizing them as proposed. Specific details are
included in Table 3.
    Specific to the MATS NESHAP, the EPA requested comment on whether
the proposed technical corrections in Table 4 of the preamble provide
the intended accuracy, clarity, and consistency. As mentioned in
section 6.3 of the RTC, commenters supported the proposed changes on
equations 2a and 3a and this final action contains those changes. As
mentioned in section 6.3 of the RTC, commenters did not support the
change from a 30 to 60-day notification period for performance testing,
and that change was not made to the rule; however, a change to the
General Provisions applicability table was made to provide a consistent
30-day notification period. Commenters suggested changes to certain
definitions to make them more consistent with the Acid Rain rule
provisions, but, as described in section 6.4 of the RTC, these rule
changes were not made. These amendments are now being finalized to
correct inaccuracies and other inadvertent errors in the final rule and
to make the rule language

consistent with provisions addressed through this reconsideration.
    The final technical changes are described in tables 3 and 4 of this
preamble.

 Table 3--Miscellaneous Technical Corrections to 40 CFR Part 60, Subpart
                                   Da
------------------------------------------------------------------------
       Section of subpart Da              Description of correction
------------------------------------------------------------------------
40 CFR 60.42Da(a).................  Correct the erroneous ``0.030'' to
                                     the correct ``0.03''.
40 CFR 60.42Da(e)(1)(ii)..........  Correct the erroneous conversion
                                     ``13 ng/J (0.015 lb/MMBtu)'' to the
                                     correct ``6.4 ng/J (0.015 lb/
                                     MMBtu)'' by amending the regulatory
                                     text to specify that the
                                     requirements in 40 CFR 60.42Da(c)
                                     or (d), which includes two
                                     additional alternative limits, are
                                     available compliance alternatives
                                     for modified facilities.
------------------------------------------------------------------------

 Table 4--Miscellaneous Technical Corrections to 40 CFR Part 63, Subpart
                                  UUUUU
------------------------------------------------------------------------
     Section of subpart UUUUU             Description of correction
------------------------------------------------------------------------
40 CFR 63.9982(a).................  Clarify the language to use the word
                                     ``or'' instead of ``and.''
40 CFR 63.9982(b) and (c).........  Correct the discrepancy between
                                     63.9982(b) and (c) and 63.9985(a).
40 CFR 63.10005(d)(2)(ii).........  Correct the typographical error by
                                     replacing the incorrect
                                     ``corresponding'' with the correct
                                     ``corresponds.''
40 CFR 63.10005(i)(4)(ii) and       Revise to clarify the determination
 (i)(5) and add 63.10005(i)(6).      and measurement of fuel moisture
                                     content.
40 CFR 63.10006(c)................  Correct the omission of solid oil-
                                     derived fuel- and coal-fired EGUs
                                     and IGCC EGUs and the omission of
                                     section 10000(c).
40 CFR 63.10007(c)................  Correct the omission of section
                                     63.10023 from the list of sections
                                     to be followed in establishing an
                                     operating limit.
40 CFR 63.10009(b)(2).............  Correct omission of the term
                                     ``boiler operating'' and clarify
                                     the term ``Rti'' in Equation 2a.
40 CFR 63.10009(b)(3).............  Correct omission of the term
                                     ``system'' and clarify the term
                                     ``Rti'' in Equation 3a.
40 CFR 63.10010(j)(1)(i)..........  Correct the typographical error to
                                     use the correct word ``your''
                                     instead of ``you.''
40 CFR 63.10030(b), (c), and (d)..  Clarify the affected-source
                                     language.
                                    Change the period by which a
                                     Notification of Intent to conduct a
                                     performance test must be submitted
                                     to conform to the General
                                     Provisions.
40 CFR Section 63.10042...........  Correct the typographical error in
                                     the intended definition of ``unit
                                     designed for coal >= 8,300 Btu/lb
                                     subcategory'' by replacing the
                                     erroneous ``>'' with the correct
                                     ``>=.''
Table 5 to Subpart UUUUU of Part    Correct the typographical error in
 63.                                 footnote 4 by replacing the
                                     erroneous ``>='' with the correct
                                     ``<=.''
Table 7 to Subpart UUUUU of Part    Clarify the applicability of the
 63.                                 alternate 90-day average for Hg in
                                     item 1.
                                    Revise item 3 in the table to
                                     clarify use of CMS for liquid oil-
                                     fired EGUs.
Table 9 to Subpart UUUUU of Part    Revise to clarify the period for
 63.                                 notification of conducting a
                                     performance test from 60 to 30
                                     days.
Section 4.1 to Appendix A to        Correct the typographical error by
 Subpart UUUUU of Part 63.           replacing the incorrect citation to
                                     ``Sec.   63.10005(g)'' with the
                                     correct ``Sec.   63.9984(f).''
Section <IP_ADDRESS> to Appendix A to    Correct the typographical error by
 Subpart UUUUU of Part 63.           replacing the incorrect citation to
                                     ``Table A-4'' with the correct
                                     ``Table A-2''
Section <IP_ADDRESS>.3 to Appendix B to  Correct the typographical error by
 Subpart UUUUU of Part 63.           replacing the erroneous ``>='' with
                                     the correct ``<=.''
Section 5.3.4 to Appendix B to      Correct the section number from the
 Subpart UUUUU of Part 63.           incorrect ``5.3.4'' to the correct
                                     ``5.3.3.''
------------------------------------------------------------------------

VII. Impacts of This Final Rule

A. Summary of Emissions Impacts, Costs and Benefits

    Our analysis shows that new EGUs would choose to install and
operate the same or similar air pollution control technologies in order
to meet the revised emission limits as would have been necessary to
meet the previously finalized standards. We project that this final
action will result in no significant change in costs, emission
reductions, or benefits.\10\ Even if there were changes in costs for
these EGUs, such changes would likely be small relative to both the
overall costs of the individual projects and the overall costs and
benefits of the final rule. Further, we believe that EGUs would put on
the same controls for this final action that they would have for the
original final MATS rule, so there should not be any incremental costs
related to this revision.
---------------------------------------------------------------------------

    \10\ See Regulatory Impact Analysis for the Final Mercury and
Air Toxics Standards [EPA-452/R-11-011] (docket entry EPA-HQ-OAR-
2009-0234-20131) and Economic Impact Analysis for the Final
Reconsideration of the Mercury and Air Toxics Standards in
rulemaking docket EPA-HQ-OAR-2009-0234. As noted earlier, because on
an individual EGU-by-EGU basis we anticipate very similar costs, any
changes to the baseline since we finalized MATS (e.g., potential
impacts of the CSAPR decision) would not impact this determination.
---------------------------------------------------------------------------

B. What are the air impacts?

    We believe that electric power companies will install the same or
similar control technologies to comply with the final standards in this
action as they would have installed to comply with the previously
finalized MATS standards. Accordingly, we believe that this final
action will not result in significant changes in emissions of any of
the regulated pollutants.

C. What are the energy impacts?

    This final action is not anticipated to have an effect on the
supply, distribution, or use of energy. As previously stated, we
believe that electric power companies would install the same or similar
control technologies as they would have installed to comply with the
previously finalized MATS standards.

D. What are the compliance costs?

    We believe there will be no significant change in compliance costs
as a result of this final action because electric

power companies would install the same or similar control technologies
as they would have installed to comply with the previously finalized
MATS standards. Moreover, we find no additional monitoring costs are
necessary to comply with this final action; however, as in any other
rule, EGU owners or operators may choose to conduct additional
monitoring (and incur its expense) for their own purposes.

E. What are the economic and employment impacts?

    Because we expect that electric power companies would install the
same or similar control technologies to meet the standards finalized in
this action as they would have chosen to comply with the previously
finalized MATS standards, we do not anticipate that this final action
will result in significant changes in emissions, energy impacts, costs,
benefits, or economic impacts. Likewise, we believe this action will
not have any impacts on the price of electricity, employment or labor
markets, or the U.S. economy.

F. What are the benefits of the final standards?

    As previously stated, the EPA anticipates the power sector will not
incur significant compliance costs or savings as a result of this
action and we do not anticipate any significant emission changes
resulting from this action. Therefore, there are no direct monetized
benefits or disbenefits associated with this action.

VIII. Statutory and Executive Order Reviews

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

    Under Executive Order (EO) 12866 (58 FR 51735; October 4, 1993),
this action is a ``significant regulatory action'' because it ``raises
novel legal or policy issues.'' Accordingly, the EPA submitted this
action to the Office of Management and Budget (OMB) for review under
Executive Orders 12866 and 13563 (76 FR 3821; January 21, 2011) and any
changes made in response to OMB recommendations have been documented in
the docket for this action.
    In addition, the EPA prepared an analysis of the potential costs
and benefits associated with this action. This analysis is contained in
the ``Economic Impact Analysis for the Final Reconsideration of the
Mercury and Air Toxics Standards'' found in rulemaking docket EPA-HQ-
OAR-2009-0234. Because our analysis shows that new electricity
generating units would choose to install the same control technology in
order to meet the revised emission limits as would have been necessary
to meet the previously finalized MATS standards, we project that this
action will result in no significant change in costs, emission
reductions, or benefits.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden.
Today's action does not change the information collection requirements
previously finalized and, as a result, does not impose any additional
burden on industry. However, OMB has previously approved the
information collection requirements contained in the existing
regulations (see 77 FR 9304) under the provisions of the Paperwork
Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control
number 2060-0567. The OMB control numbers for EPA's regulations are
listed in 40 CFR part 9 and 48 CFR chapter 15.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute unless the agency certifies that the rule will
not have a significant economic impact on a substantial number of small
entities. Small entities include small businesses, small not-for-profit
enterprises, and small governmental jurisdictions.
    For purposes of assessing the impacts of today's action on small
entities, a small entity is defined as: (1) A small business as defined
by the Small Business Administration's (SBA) regulations at 13 CFR
121.201; (2) a small governmental jurisdiction that is a government of
a city, county, town, school district, or special district with a
population of less that 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field. Categories and entities potentially
regulated by the final rule with applicable NAICS codes are provided in
the Supplementary Information section of this action.
    According to the SBA size standards for NAICS code 221122
Utilities-Fossil Fuel Electric Power Generation, a firm is small if,
including its affiliates, it is primarily engaged in the generation,
transmission, and or distribution of electric energy for sale and its
total electric output for the preceding fiscal year did not exceed 4
million MWh.
    After considering the economic impacts of today's action on small
entities, I certify that the notice 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. We have therefore concluded that today's action will not
result in a significant economic impact on a substantial number of
small entities.

D. Unfunded Mandates Reform Act

    This action contains no Federal mandates under the provisions of
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for State, local, or tribal governments or the private
sector. The action imposes no enforceable duty on any State, local, or
tribal governments or the private sector. Therefore, this action is not
subject to the requirements of UMRA sections 202 or 205.
    This action is also not subject to the requirements of UMRA section
203 because it contains no regulatory requirements that might
significantly or uniquely affect small governments because it contains
no requirements that apply to such governments or impose obligations
upon them.

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, as
specified in EO 13132. None of the affected facilities are owned or
operated by state governments, and the requirements discussed in
today's notice will not supersede state regulations that are more
stringent. Thus, EO 13132 does not apply to today's notice of
reconsideration.

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

    This action does not have tribal implications. It will not have
substantial direct effects on tribal governments, on the relationship
between the Federal government and Indian tribes, or on the
distribution of power and responsibilities between the Federal
government and Indian tribes, as specified in EO 13175. No affected

facilities are owned or operated by Indian tribal governments. Thus, EO
13175 does not apply to today's action.

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

    This action is not subject to EO 13045 (62 FR 19885; April 23,
1997) because it is not economically significant as defined in EO
12866. The EPA has evaluated the environmental health or safety effects
of the final MATS on children. The results of the evaluation are
discussed in that final rule (77 FR 9304; February 16, 2012) and are
contained in rulemaking docket EPA-HQ-OAR-2009-0234.

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

    This action is not a ``significant energy action'' as defined in EO
13211 (66 FR 28355; May 22, 2001) because it is not likely to have a
significant adverse effect on the supply, distribution, or use of
energy. Further, we conclude that today's action is not likely to have
any adverse energy effects because it is not expected to impose any
additional regulatory requirements on the owners of affected
facilities.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995 (Pub. L. 104-113; 15 U.S.C. 272 note) directs EPA
to use voluntary consensus standards in their regulatory and
procurement activities unless to do so would be inconsistent with
applicable law or otherwise impracticable. Voluntary consensus
standards are technical standards (e.g., material specifications, test
methods, sampling procedures, business practices) developed or adopted
by one or more voluntary consensus bodies. The NTTAA requires EPA to
provide Congress, through the OMB, with explanations when EPA decides
not to use available and applicable voluntary consensus standards.
    During the development of the final MATS rule, the EPA searched for
voluntary consensus standards that might be applicable. The search
identified three voluntary consensus standards that were considered
practical alternatives to the specified EPA test methods. An assessment
of these and other voluntary consensus standards is presented in the
preamble to the final MATS rule (77 FR 9441; February 16, 2012).
Today's action does not make use of any additional technical standards
beyond those cited in the final MATS rule. Therefore, the EPA is not
considering the use of any additional voluntary consensus standards for
this action.

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

    Executive Order 12898 (59 FR 7629; February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    The EPA has determined that this action will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. Our analysis shows that new EGUs would choose to install
the same control technology in order to meet the revised emission
limits as would have been necessary to meet the previously finalized
standard. Under the relevant assumptions, we project that this action
will result in no significant change in emission reductions.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996, generally
provides that before a rule may take effect, the agency promulgating
the rule must submit a rule report, which includes a copy of the rule,
to each House of the Congress and to the Comptroller General of the
United States. The EPA will submit a report containing this final
action and other required information to the U.S. Senate, the U.S.
House of Representatives, and the Comptroller General of the United
States prior to publication of the rule in the Federal Register. A
major rule cannot take effect until 60 days after it is published in
the Federal Register. This action is not a ``major rule'' as defined by
5 U.S.C. 804(2). This rule will be effective April 24, 2013.

List of Subjects in 40 CFR Parts 60 and 63

    Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances, Intergovernmental
relations, Reporting and recordkeeping requirements.

    Dated: March 28, 2013.
Bob Perciasepe,
Acting Administrator.

    For the reasons discussed in the preamble, 40 CFR parts 60 and 63
are amended 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. Amend Sec.  60.41Da by revising the definitions of ``Coal'' and
``Integrated gasification combined cycle electric utility steam
generating unit,'' and by adding the definition of ``Natural gas'' in
alphabetical order to read as follows:

Sec.  60.41Da  Definitions.

* * * * *
    Coal means all solid fuels classified as anthracite, bituminous,
subbituminous, or lignite by the American Society of Testing and
Materials in ASTM D388 (incorporated by reference, see Sec.  60.17) and
coal refuse. Synthetic fuels derived from coal for the purpose of
creating useful heat, including but not limited to solvent-refined
coal, gasified coal, coal-oil mixtures, and coal-water mixtures are
included in this definition for the purposes of this subpart.
* * * * *
    Integrated gasification combined cycle electric utility steam
generating unit or IGCC electric utility steam generating unit means an
electric utility combined cycle gas turbine that is designed to burn
fuels containing 50 percent (by heat input) or more solid-derived fuel
not meeting the definition of natural gas. The Administrator may waive
the 50 percent solid-derived fuel requirement during periods of the
gasification system construction, startup and commissioning, shutdown,
or repair. No solid fuel is directly burned in the unit during
operation.
* * * * *
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane,
ethane, or propane), composed of at least 70 percent methane by volume
or that has a gross calorific value between 35 and 41 megajoules (MJ)
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic
foot), that maintains a gaseous state under ISO conditions. In
addition, natural gas contains 20.0 grains or less of total sulfur per
100 standard cubic feet. Finally, natural gas

does not include the following gaseous fuels: landfill gas, digester
gas, refinery gas, sour gas, blast furnace gas, coal-derived gas,
producer gas, coke oven gas, or any gaseous fuel produced in a process
which might result in highly variable sulfur content or heating value.
* * * * *

0
3. Amend Sec.  60.42Da by revising paragraphs (a), (b)(2), and (e)(1)
to read as follows:

Sec.  60.42Da  Standards for particulate matter (PM).

    (a) Except as provided in paragraph (f) of this section, on and
after the date on which the initial performance test is completed or
required to be completed under Sec.  60.8, whichever date comes first,
an owner or operator of an affected facility shall not cause to be
discharged into the atmosphere from any affected facility for which
construction, reconstruction, or modification commenced before March 1,
2005, any gases that contain PM in excess of 13 ng/J (0.03 lb/MMBtu)
heat input.
    (b) * * *
    (2) An owner or operator of an affected facility that combusts only
natural gas and/or synthetic natural gas that chemically meets the
definition of natural gas is exempt from the opacity standard specified
in paragraph (b) of this section.
* * * * *
    (e) * * *
    (1) On and after the date on which the initial performance test is
completed or required to be completed under Sec.  60.8, whichever date
comes first, the owner or operator shall not cause to be discharged
into the atmosphere from that affected facility any gases that contain
PM in excess of the applicable emissions limit specified in paragraphs
(e)(1)(i) or (ii) of this section.
    (i) For an affected facility which commenced construction or
reconstruction:
    (A) 11 ng/J (0.090 lb/MWh) gross energy output; or
    (B) 12 ng/J (0.097 lb/MWh) net energy output.
* * * * *
    (ii) For an affected facility which commenced modification, the
emission limits specified in paragraphs (c) or (d) of this section.
* * * * *

0
4. Amend Sec.  60.48Da by revising paragraphs (f), (o) introductory
text, (o)(1), (o)(2) introductory text, (o)(3) introductory text,
(o)(3)(i), and (o)(4) introductory text 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 must be calculated for
boiler operating days that have out-of-control periods totaling no more
than 6 hours of unit operation during which the standard applies. 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 or shutdown.
* * * * *
    (o) Compliance provisions for sources subject to Sec.
60.42Da(c)(2), (d), or (e)(1)(ii). Except as provided for in paragraph
(p) of this section, the owner or operator must demonstrate compliance
with each applicable emissions limit according to the requirements in
paragraphs (o)(1) through (o)(5) of this section.
    (1) You must conduct a performance test to demonstrate initial
compliance with the applicable PM emissions limit in Sec.  60.42Da by
the applicable date specified in Sec.  60.8(a). Thereafter, you must
conduct each subsequent performance test within 12 calendar months
following the date the previous performance test was required to be
conducted. You must conduct each performance test according to the
requirements in Sec.  60.8 using the test methods and procedures in
Sec.  60.50Da. The owner or operator of an affected facility that has
not operated for 60 consecutive calendar days prior to the date that
the subsequent performance test would have been required had the unit
been operating is not required to perform the subsequent performance
test until 30 calendar days after the next boiler operating day.
Requests for additional 30 day extensions shall be granted by the
relevant air division or office director of the appropriate Regional
Office of the U.S. EPA.
    (2) You must monitor the performance of each electrostatic
precipitator or fabric filter (baghouse) operated to comply with the
applicable PM emissions limit in Sec.  60.42Da using a continuous
opacity monitoring system (COMS) according to the requirements in
paragraphs (o)(2)(i) through (vi) unless you elect to comply with one
of the alternatives provided in paragraphs (o)(3) and (o)(4) of this
section, as applicable to your control device.
* * * * *
    (3) As an alternative to complying with the requirements of
paragraph (o)(2) of this section, an owner or operator may elect to
monitor the performance of an electrostatic precipitator (ESP) operated
to comply with the applicable PM emissions limit in Sec.  60.42Da using
an ESP predictive model developed in accordance with the requirements
in paragraphs (o)(3)(i) through (v) of this section.
    (i) You must calibrate the ESP predictive model with each PM
control device used to comply with the applicable PM emissions limit in
Sec.  60.42Da operating under normal conditions. In cases when a wet
scrubber is used in combination with an ESP to comply with the PM
emissions limit, the wet scrubber must be maintained and operated.
* * * * *
    (4) As an alternative to complying with the requirements of
paragraph (o)(2) of this section, an owner or operator may elect to
monitor the performance of a fabric filter (baghouse) operated to
comply with the applicable PM emissions limit in Sec.  60.42Da by using
a bag leak detection system according to the requirements in paragraphs
(o)(4)(i) through (v) of this section.
* * * * *

0
5. Amend Sec.  60.49Da by:
0
a. Revising paragraphs (a) introductory text;
0
b. Adding paragraph (a)(3)(iv); and
0
c. Revising paragraphs (a)(4), (b) introductory text, and (t).
    The revised and added text reads as follows:

Sec.  60.49Da  Emission monitoring.

    (a) An owner or operator of an affected facility subject to the
opacity standard in Sec.  60.42Da must monitor the opacity of emissions
discharged from the affected facility to the atmosphere according to
the applicable requirements in paragraphs (a)(1) through (4) of this
section.
* * * * *
    (3) * * *
    (iv) If the maximum 6-minute opacity is less than 10 percent during
the most recent Method 9 of appendix A-4 of this part performance test,
the owner or operator may, as an alternative to

performing subsequent Method 9 of appendix A-4 performance tests, elect
to perform subsequent monitoring using a digital opacity compliance
system according to a site-specific monitoring plan approved by the
Administrator. The observations must be similar, but not necessarily
identical, to the requirements in paragraph (a)(3)(iii) of this
section. For reference purposes in preparing the monitoring plan, see
OAQPS ``Determination of Visible Emission Opacity from Stationary
Sources Using Computer-Based Photographic Analysis Systems.'' This
document is available from the U.S. Environmental Protection Agency
(U.S. EPA); Office of Air Quality and Planning Standards; Sector
Policies and Programs Division; Measurement Policy Group (D243-02),
Research Triangle Park, NC 27711. This document is also available on
the Technology Transfer Network (TTN) under Emission Measurement Center
Preliminary Methods.
* * * * *
    (4) An owner or operator of an affected facility that is subject to
an opacity standard under Sec.  60.42Da is not required to operate a
COMS provided that affected facility meets the conditions in either
paragraph (a)(4)(i) or (ii) of this section.
    (i) The affected facility combusts only gaseous and/or liquid fuels
(excluding residue oil) where the potential SO2 emissions
rate of each fuel is no greater than 26 ng/J (0.060 lb/MMBtu), and the
unit operates according to a written site-specific monitoring plan
approved by the permitting authority. This monitoring plan must include
procedures and criteria for establishing and monitoring specific
parameters for the affected facility indicative of compliance with the
opacity standard. For testing performed as part of this site-specific
monitoring plan, the permitting authority may require as an alternative
to the notification and reporting requirements specified in Sec. Sec.
60.8 and 60.11 that the owner or operator submit any deviations with
the excess emissions report required under Sec.  60.51Da(d).
    (ii) The owner or operator of the affected facility installs,
calibrates, operates, and maintains a particulate matter continuous
parametric monitoring system (PM CPMS) according to the requirements
specified in subpart UUUUU of part 63.
* * * * *
    (b) The owner or operator of an affected facility must install,
calibrate, maintain, and operate a CEMS, and record the output of the
system, for measuring SO2 emissions, except where only
gaseous and/or liquid fuels (excluding residual oil) where the
potential SO2 emissions rate of each fuel is 26 ng/J (0.060
lb/MMBtu) or less are combusted, as follows:
* * * * *
    (t) The owner or operator of an affected facility demonstrating
compliance with the output-based emissions limit under Sec.  60.42Da
must either install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v)
of this section or install, calibrate, operate, and maintain a PM CPMS
according to the requirements for new facilities specified in subpart
UUUUU of part 63 of this chapter. An owner or operator of an affected
facility demonstrating compliance with the input-based emissions limit
in Sec.  60.42Da may install, certify, operate, and maintain a CEMS for
measuring PM emissions according to the requirements of paragraph (v)
of this section.
* * * * *

0
6. Revise Sec.  60.50Da(f) to read as follows:

Sec.  60.50Da  Compliance determination procedures and methods.

* * * * *
    (f) The owner or operator of an electric utility combined cycle gas
turbine that does not meet the definition of an IGCC must conduct
performance tests for PM, SO2, and NOX using the
procedures of Method 19 of appendix A-7 of this part. The
SO2 and NOX emission rates calculations from the
gas turbine used in Method 19 of appendix A-7 of this part are
determined when the gas turbine is performance tested under subpart GG
of this part. The potential uncontrolled PM emission rate from a gas
turbine is defined as 17 ng/J (0.04 lb/MMBtu) heat input.
* * * * *

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES

0
7. The authority citation for 40 CFR Part 63 continues to read as
follows:

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

0
8. In Sec.  63.9982, revise paragraphs (a) introductory text, (b), and
(c) to read as follows:

Sec.  63.9982  What is the affected source of this subpart?

    (a) This subpart applies to each individual or group of two or more
new, reconstructed, or existing affected source(s) as described in
paragraphs (a)(1) and (2) of this section within a contiguous area and
under common control.
* * * * *
    (b) An EGU is new if you commence construction of the coal- or oil-
fired EGU after May 3, 2011.
    (c) An EGU is reconstructed if you meet the reconstruction criteria
as defined in Sec.  63.2, and if you commence reconstruction after May
3, 2011.
* * * * *

0
9. In Sec.  63.10000, revise paragraphs (c)(1)(iv) and (c)(2)(ii) to
read as follows:

Sec.  63.10000  What are my general requirements for complying with
this subpart?

* * * * *
    (c) * * *
    (1) * * *
    (iv) If your coal-fired or solid oil derived fuel-fired EGU or IGCC
EGU does not qualify as a LEE for total non-mercury HAP metals,
individual non-mercury HAP metals, or filterable particulate matter
(PM), you must demonstrate compliance through an initial performance
test and you must monitor continuous performance through either use of
a particulate matter continuous parametric monitoring system (PM CPMS),
a PM CEMS, or, for an existing EGU, compliance performance testing
repeated quarterly.
* * * * *
    (c) * * *
    (2) * * *
    (ii) If your liquid oil-fired unit does not qualify as a LEE for
total HAP metals (including mercury), individual metals (including
mercury), or filterable PM you must demonstrate compliance through an
initial performance test and you must monitor continuous performance
through either use of a PM CPMS, a PM CEMS, or, for an existing EGU,
performance testing conducted quarterly.
* * * * *

0
10. Amend Sec.  63.10005 by:
0
a. Revising paragraphs (d)(2)(ii), (i)(4)(ii) and (i)(5);
0
b. Adding paragraph (i)(6).
    The revised and added text read as follows:

Sec.  63.10005  What are my initial compliance requirements and by what
date must I conduct them?

* * * * *
    (d) * * *
    (2) * * *
    (ii) You must demonstrate continuous compliance with the PM CPMS
site-specific operating limit that corresponds to the results of the
performance test

demonstrating compliance with the emission limit with which you choose
to comply.
* * * * *
    (i) * * *
    (4) * * *
    (ii) ASTM D4006-11, ``Standard Test Method for Water in Crude Oil
by Distillation,'' including Annex A1 and Appendix A1.
* * * * *
    (5) Use one of the following methods to obtain fuel moisture
samples:
    (i) ASTM D4177-95 (Reapproved 2010), ``Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products,'' including
Annexes A1 through A6 and Appendices X1 and X2, or
    (ii) ASTM D4057-06 (Reapproved 2011), ``Standard Practice for
Manual Sampling of Petroleum and Petroleum Products,'' including Annex
A1.
    (6) Should the moisture in your liquid fuel be more than 1.0
percent by weight, you must
    (i) Conduct HCl and HF emissions testing quarterly (and monitor
site-specific operating parameters as provided in Sec.
63.10000(c)(2)(iii) or
    (ii) Use an HCl CEMS and/or HF CEMS.
* * * * *

0
11. In Sec.  63.10006, revise paragraph (c) to read as follows:

Sec.  63.10006  When must I conduct subsequent performance tests or
tune-ups?

* * * * *
    (c) Except where paragraphs (a) or (b) of this section apply, or
where you install, certify, and operate a PM CEMS to demonstrate
compliance with a filterable PM emissions limit, for liquid oil-, solid
oil-derived fuel-, coal-fired and IGCC EGUs, you must conduct all
applicable periodic emissions tests for filterable PM, individual, or
total HAP metals emissions according to Table 5 to this subpart, Sec.
63.10007, and Sec.  63.10000(c), except as otherwise provided in Sec.
63.10021(d)(1).
* * * * *

0
12. In Sec.  63.10007, revise paragraph (c) to read as follows:

Sec.  63.10007  What methods and other procedures must I use for the
performance tests?

* * * * *
    (c) If you choose the filterable PM method to comply with the PM
emission limit and demonstrate continuous performance using a PM CPMS
as provided for in Sec.  63.10000(c), you must also establish an
operating limit according to Sec.  63.10011(b), Sec.  63.10023, and
Tables 4 and 6 to this subpart. Should you desire to have operating
limits that correspond to loads other than maximum normal operating
load, you must conduct testing at those other loads to determine the
additional operating limits.
* * * * *

0
13. In Sec.  63.10009, revise paragraphs (b)(2) and (b)(3) to read as
follows:

Sec.  63.10009  May I use emissions averaging to comply with this
subpart?

* * * * *
    (b) * * *
    (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] TR24AP13.006

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 electrical 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 hourly rates 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 electrical output,
Rti = Total heat input or gross electrical 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] TR24AP13.007

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 electrical 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 electrical 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] TR24AP13.008

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 electrical 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 hourly rates 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 electrical output,
Rti = Total heat input or gross electrical 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] TR24AP13.009

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 electrical 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 electrical output per pound of steam generated,
from unit i that uses emissions testing.
* * * * *

0
14. In Sec.  63.10010, revise paragraph (j)(1)(i) to read as follows:

Sec.  63.10010  What are my monitoring, installation, operation, and
maintenance requirements?

* * * * *
    (j) * * *
    (1) * * *
    (i) Install and certify your HAP metals CEMS according to the
procedures and requirements in your approved site-specific test plan as
required in Sec.  63.7(e). 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.
* * * * *

0
15. Amend Sec.  63.10021 by adding paragraphs (c)(1) and (2) to read as
follows:

Sec.  63.10021  How do I demonstrate continuous compliance with the
emission limitations, operating limits, and work practice standards?

* * * * *
    (c) * * *
    (1) For any exceedance of the 30-boiler operating day PM CPMS
average value from the established operating parameter limit for an EGU
subject to the emissions limits in Table 1 to this subpart, you must:
    (i) Within 48 hours of the exceedance, visually inspect the air
pollution control device (APCD);
    (ii) If the inspection of the APCD identifies the cause of the
exceedance, take corrective action as soon as possible, and return the
PM CPMS measurement to within the established value; and
    (iii) Within 45 days of the exceedance or at the time of the annual
compliance test, whichever comes first, conduct a PM emissions
compliance test to determine compliance with the PM emissions limit and
to verify or re-establish the CPMS operating limit. You are not
required to conduct any additional testing for any exceedances that
occur between the time of the original exceedance and the PM emissions
compliance test required under this paragraph.
    (2) PM CPMS exceedances of the operating limit for an EGU subject
to the emissions limits in Table 1 of this subpart leading to more than
four required performance tests in a 12-month period (rolling monthly)
constitute a separate violation of this subpart.
* * * * *

0
16. In Sec.  63.10023, revise paragraph (b) to read as follows:

Sec.  63.10023  How do I establish my PM CPMS operating limit and
determine compliance with it?

* * * * *
    (b) Determine your operating limit as provided in paragraph (b)(1)
or (b)(2) of this section. You must verify an existing or establish a
new operating limit after each repeated performance test.
    (1) For an existing EGU, determine your operating limit based on
the highest 1-hour average PM CPMS output value recorded during the
performance test.
    (2) For a new EGU, determine your operating limit as follows.
    (i) If your PM performance test demonstrates your PM emissions do
not exceed 75 percent of your emissions limit, you will use the average
PM CPMS value recorded during the PM compliance test, the milliamp
equivalent of zero output from your PM CPMS, and the average PM result
of your compliance test to establish your operating limit. Calculate
the operating limit by establishing a relationship of PM CPMS signal to
PM concentration using the PM CPMS instrument zero, the average PM CPMS
values corresponding to the three compliance test runs, and the average
PM concentration from the Method 5 compliance test with the procedures
in (b)(2)(i)(A) through (D) of this section.
    (A) Determine your PM CPMS instrument zero output with one of the
following procedures.
    (1) Zero point data for in-situ instruments should be obtained by
removing the instrument from the stack and monitoring ambient air on a
test bench.
    (2) Zero point data for extractive instruments should be obtained
by removing the extractive probe from the stack and drawing in clean
ambient air.
    (3) The zero point can also can be obtained by performing manual
reference method measurements when the flue gas is free of PM emissions
or contains very low PM concentrations (e.g., when your process is not
operating, but the fans are operating or your source is combusting only
natural gas) and plotting these with the compliance data to find the
zero intercept.
    (4) If none of the steps in paragraphs (A)(1) through (3) of this
section are possible, you must use a zero output value provided by the
manufacturer.
    (B) Determine your PM CPMS instrument average (x) in milliamps, and
the average of your corresponding three PM compliance test runs (y),
using equation 10.

[GRAPHIC] [TIFF OMITTED] TR24AP13.010

Where:

Xi = the PM CPMS data points for run i of the performance
test,
Yi = the PM emissions value (in lb/MWh) for run i of the
performance test, and
n = the number of data points.

    (C) With your PM CPMS instrument zero expressed in milliamps, your
three run average PM CPMS milliamp value, and your three run average PM
emissions value (in lb/MWh) from your compliance runs, determine a
relationship of PM lb/MWh per milliamp with equation 11.
[GRAPHIC] [TIFF OMITTED] TR24AP13.011

Where:

R = the relative PM lb/MWh per milliamp for your PM CPMS,
y = the three run average PM lb/MWh,
x = the three run average milliamp output from your PM CPMS, and
z = the milliamp equivalent of your instrument zero determined from
(b)(2)(i)(A) of this section.

    (D) Determine your source specific 30-day rolling average operating
limit using the PM lb/MWh per milliamp value from equation 11 in
equation 12, below. This sets your operating limit at the PM CPMS
output value corresponding to 75 percent of your emission limit.
[GRAPHIC] [TIFF OMITTED] TR24AP13.012

Where:

OL = the operating limit for your PM CPMS on a 30-day
rolling average, in milliamps,
L = your source PM emissions limit in lb/MWh,
z = your instrument zero in milliamps, determined from (b)(2)(i)(A)
of this section, and
R = the relative PM lb/MWh per milliamp for your PM CPMS, from
equation 11.

    (ii) If your PM compliance test demonstrates your PM emissions
exceed 75 percent of your emissions limit, you will use the average PM
CPMS value recorded during the PM compliance test demonstrating
compliance with the PM limit to establish your operating limit.
    (A) Determine your operating limit by averaging the PM CPMS
milliamp output corresponding to your three PM performance test runs
that demonstrate compliance with the emission limit using equation 13.
[GRAPHIC] [TIFF OMITTED] TR24AP13.013

Where:

Xi = the PM CPMS data points for all runs i,
n = the number of data points, and
Oh = your site specific operating limit, in milliamps.

    (iii) Your PM CPMS must provide a 4-20 milliamp output and the
establishment of its relationship to manual reference method
measurements must be determined in units of milliamps.
    (iv) Your PM CPMS operating range must be capable of reading PM
concentrations from zero to a level equivalent to two times your
allowable emission limit. If your PM CPMS is an auto-ranging instrument
capable of multiple scales, the primary range of the instrument must be
capable of reading PM concentration from zero to a level equivalent to
two times your allowable emission limit.
    (v) During the initial performance test or any such subsequent
performance test that demonstrates compliance with the PM limit, record
and average all milliamp output values from the PM CPMS for the periods
corresponding to the compliance test runs.
    (vi) For PM performance test reports used to set a PM CPMS
operating limit, the electronic submission of the test report must also
include the make and model of the PM CPMS instrument, serial number of
the instrument, analytical principle of the instrument (e.g. beta
attenuation), span of the instruments primary analytical range,
milliamp value equivalent to the instrument zero output, technique by
which this zero value was determined, and the average milliamp signal
corresponding to each PM compliance test run.
* * * * *

0
17. In Sec.  63.10030, revise paragraphs (b), (c), and (d) to read as
follows:

Sec.  63.10030  What notifications must I submit and when?

* * * * *
    (b) As specified in Sec.  63.9(b)(2), if you startup your EGU that
is an affected source before April 16, 2012, you must submit an Initial
Notification not later than 120 days after April 16, 2012.
    (c) As specified in Sec.  63.9(b)(4) and (b)(5), if you startup
your new or reconstructed EGU that is an affected source on or after
April 16, 2012, you must submit an Initial Notification not later than
15 days after the actual date of startup of the EGU that is an affected
source.
    (d) When you are required to conduct a performance test, you must
submit a Notification of Intent to conduct a performance test at least
30 days before the performance test is scheduled to begin.
* * * * *

0
18. Amend Sec.  63.10042 by revising the definition of ``Unit designed
for coal > 8,300 Btu/lb subcategory'' to read as follows:

Sec.  63.10042  What definitions apply to this subpart?

* * * * *
    Unit designed for coal = 8,300 Btu/lb subcategory means
any coal-fired EGU that is not a coal-fired EGU in the ``unit designed
for low rank virgin coal'' subcategory.
* * * * *

0
19. 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 limit]
----------------------------------------------------------------------------------------------------------------
                                                                                Using these
                                                                                requirements, as
                                                                   You must meet the        appropriate (e.g.,
                                          For the following        following emission       specified sampling
  If your EGU is in this subcategory          pollutants            limits and work         volume or test run
                                                                   practice standards         duration) and
                                                                                limitations with the
                                                                                test methods in Table 5
----------------------------------------------------------------------------------------------------------------
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
                                                                                monitoring system
                                                                                only.
4. Liquid oil-fired unit--continental  a. Filterable            3.0E-1 lb/MWh \1\......  Collect a minimum of 1
 (excluding limited-use liquid oil-     particulate matter                                dscm per run.
 fired subcategory units).              (PM).
                                       OR                       OR                       .......................
                                       Total HAP metals.......  2.0E-4 lb/MWh..........  Collect a minimum of 2
                                                                                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 2
                                                                                dscm per run.
                                       Antimony (Sb)..........  1.0E-2 lb/GWh..........
                                       Arsenic (As)...........  3.0E-3 lb/GWh..........
                                       Beryllium (Be).........  5.0E-4 lb/GWh..........
                                       Cadmium (Cd)...........  2.0E-4 lb/GWh..........
                                       Chromium (Cr)..........  2.0E-2 lb/GWh..........
                                       Cobalt (Co)............  3.0E-2 lb/GWh..........
                                       Lead (Pb)..............  8.0E-3 lb/GWh..........
                                       Manganese (Mn).........  2.0E-2 lb/GWh..........
                                       Nickel (Ni)............  9.0E-2 lb/GWh..........
                                       Selenium (Se)..........  2.0E-2 lb/GWh..........
                                       Mercury (Hg)...........  1.0E-4 lb/GWh..........  For Method 30B sample
                                                                                volume determination
                                                                                (Section 8.2.4), the
                                                                                estimated Hg
                                                                                concentration should
                                                                                nominally be < \1/2\
                                                                                the standard.
                                       b. Hydrogen chloride     4.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HCl).                                            a minimum of 3 dscm
                                                                                per run.
                                                                                For ASTM D6348-03 \2\
                                                                                or Method 320, sample
                                                                                for a minimum of 1
                                                                                hour.
                                       c. Hydrogen fluoride     4.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HF).                                             a minimum of 3 dscm
                                                                                per run.
                                                                                For ASTM D6348-03 \2\
                                                                                or Method 320, sample
                                                                                for a minimum of 1
                                                                                hour.
5. Liquid oil-fired unit--non-         a. Filterable            2.0E-1 lb/MWh \1\......  Collect a minimum of 1
 continental (excluding limited-use     particulate matter                                dscm per run.
 liquid oil-fired subcategory units).   (PM).
                                       OR                       OR                       .......................
                                       Total HAP metals.......  7.0E-3 lb/MWh..........  Collect a minimum of 1
                                                                                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 3
                                                                                dscm per run.
                                       Antimony (Sb)..........  8.0E-3 lb/GWh..........
                                       Arsenic (As)...........  6.0E-2 lb/GWh..........
                                       Beryllium (Be).........  2.0E-3 lb/GWh..........
                                       Cadmium (Cd)...........  2.0E-3 lb/GWh..........
                                       Chromium (Cr)..........  2.0E-2 lb/GWh..........
                                       Cobalt (Co)............  3.0E-1 lb/GWh..........
                                       Lead (Pb)..............  3.0E-2 lb/GWh..........
                                       Manganese (Mn).........  1.0E-1 lb/GWh..........

                                       Nickel (Ni)............  4.1E0 lb/GWh...........
                                       Selenium (Se)..........  2.0E-2 lb/GWh..........
                                       Mercury (Hg)...........  4.0E-4 lb/GWh..........  For Method 30B sample
                                                                                volume determination
                                                                                (Section 8.2.4), the
                                                                                estimated Hg
                                                                                concentration should
                                                                                nominally be < \1/2\
                                                                                the standard.
                                       b. Hydrogen chloride     2.0E-3 lb/MWh..........  For Method 26A, collect
                                        (HCl).                                            a minimum of 1 dscm
                                                                                per run; for Method
                                                                                26, collect a minimum
                                                                                of 120 liters per run.
                                                                                For ASTM D6348-03 \2\
                                                                                or Method 320, sample
                                                                                for a minimum of 1
                                                                                hour.
                                       c. Hydrogen fluoride     5.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HF).                                             a minimum of 3 dscm
                                                                                per run.
                                                                                For ASTM D6348-03 \2\
                                                                                or Method 320, sample
                                                                                for a minimum of 1
                                                                                hour.
6. Solid oil-derived fuel-fired unit.  a. Filterable            3.0E-2 lb/MWh \1\......  Collect a minimum of 1
                                        particulate matter                                dscm per run.
                                        (PM).
                                       OR                       OR                       .......................
                                       Total non-Hg HAP metals  6.0E-1 lb/GWh..........  Collect a minimum of 1
                                                                                dscm per run.
                                       OR                       OR                       .......................
                                       Individual HAP metals:.  .......................  Collect a minimum of 3
                                                                                dscm per run.
                                       Antimony (Sb)..........  8.0E-3 lb/GWh..........
                                       Arsenic (As)...........  3.0E-3 lb/GWh..........
                                       Beryllium (Be).........  6.0E-4 lb/GWh..........
                                       Cadmium (Cd)...........  7.0E-4 lb/GWh..........
                                       Chromium (Cr)..........  6.0E-3 lb/GWh..........
                                       Cobalt (Co)............  2.0E-3 lb/GWh..........
                                       Lead (Pb)..............  2.0E-2 lb/GWh..........
                                       Manganese (Mn).........  7.0E-3 lb/GWh..........
                                       Nickel (Ni)............  4.0E-2 lb/GWh..........
                                       Selenium (Se)..........  6.0E-3 lb/GWh..........
                                       b. Hydrogen chloride     4.0E-4 lb/MWh..........  For Method 26A, collect
                                        (HCl).                                            a minimum of 3 dscm
                                                                                per run.
                                                                                For ASTM D6348-03 \2\
                                                                                or Method 320, sample
                                                                                for a minimum of 1
                                                                                hour.
                                       OR                       .......................  .......................
                                       Sulfur dioxide (SO2)     1.0 lb/MWh.............  SO2 CEMS.
                                        \3\.
                                       c. Mercury (Hg)........  2.0E-3 lb/GWh..........  Hg CEMS or Sorbent trap
                                                                                monitoring system
                                                                                only.
----------------------------------------------------------------------------------------------------------------
\1\ Gross electric output.
\2\ Incorporated by reference, see Sec.   63.14.
\3\ You may not use the alternate SO2 limit if your EGU does not have some form of FGD system (or, in the case
  of IGCC EGUs, some other acid gas removal system either upstream or downstream of the combined cycle block)
  and SO2 CEMS installed.
\4\ Duct burners on syngas; gross electric output.
\5\ Duct burners on natural gas; gross electric output.

0
20. Revise Table 4 to Subpart UUUUU of Part 63 to read as follows:

     Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs
 [As stated in Sec.  Sec.   63.9991, you must comply with the applicable
                            operating limits]
------------------------------------------------------------------------
   If you demonstrate compliance    You must meet these operating limits
            using . . .                             . . .
------------------------------------------------------------------------
1. PM CPMS for an existing EGU....  Maintain the 30-boiler operating day
                                     rolling average PM CPMS output at
                                     or below the highest 1-hour average
                                     measured during the most recent
                                     performance test demonstrating
                                     compliance with the filterable PM,
                                     total non-mercury HAP metals (total
                                     HAP metals, for liquid oil-fired
                                     units), or individual non-mercury
                                     HAP metals (individual HAP metals
                                     including Hg, for liquid oil-fired
                                     units) emissions limitation(s).
2. PM CPMS for a new EGU..........  Maintain the 30-boiler operating day
                                     rolling average PM CPMS output
                                     determined in accordance with the
                                     requirements of Sec.
                                     63.10023(b)(2) and obtained during
                                     the most recent performance test
                                     run demonstrating compliance with
                                     the filterable PM, total non-
                                     mercury HAP metals (total HAP
                                     metals, for liquid oil-fired
                                     units), or individual non-mercury
                                     HAP metals (individual HAP metals
                                     including Hg, for liquid oil-fired
                                     units) emissions limitation(s).
------------------------------------------------------------------------

0
21. Revise footnote 4 of Table 5 to Subpart UUUUU of Part 63 to read as
follows:

  Table 5 to Subpart UUUUU of Part 63--Performance Testing Requirements
------------------------------------------------------------------------

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

                              * * * * * * *
------------------------------------------------------------------------
\4\ When using ASTM D6348-03, the following conditions must be met: (1)
  The test plan preparation and implementation in the Annexes to ASTM
  D6348-03, Sections A1 through A8 are mandatory; (2) For ASTM D6348-03
  Annex A5 (Analyte Spiking Technique), the percent (%)R must be
  determined for each target analyte (see Equation A5.5); (3) For the
  ASTM D6348-03 test data to be acceptable for a target analyte, %R must
  be 70% <= R <= 130%; and (4) The %R value for each compound must be
  reported in the test report and all field measurements corrected with
  the calculated %R value for that compound using the following
  equation:

0
22. Revise Table 6 to Subpart UUUUU of Part 63 to read as follows:

                   Table 6 to Subpart UUUUU of Part 63--Establishing PM CPMS Operating Limits
    [As stated in Sec.   63.10007, you must comply with the following requirements for establishing operating
                                                     limits]
----------------------------------------------------------------------------------------------------------------
                                   And you choose to
    If you have an applicable      establish PM CPMS                                           According to the
    emission limit for . . .       operating limits,       And . . .          Using . . .          following
                                    you must . . .                                             procedures . . .
----------------------------------------------------------------------------------------------------------------
1. Filterable Particulate matter  Install, certify,   Establish a site-   Data from the PM    1. Collect PM CPMS
 (PM), total non-mercury HAP       maintain, and       specific            CPMS and the PM     output data
 metals, individual non-mercury    operate a PM CPMS   operating limit     or HAP metals       during the entire
 HAP metals, total HAP metals,     for monitoring      in units of PM      performance tests.  period of the
 or individual HAP metals for an   emissions           CPMS output                             performance
 existing EGU.                     discharged to the   signal (e.g.,                           tests.
                                   atmosphere          milliamps, mg/                         2. Record the
                                   according to Sec.   acm, or other raw                       average hourly PM
                                     63.10010(h)(1).   signal).                                CPMS output for
                                                                                each test run in
                                                                                the three run
                                                                                performance test.