
[Federal Register Volume 78, Number 79 (Wednesday, April 24, 2013)]
[Rules and Regulations]
[Pages 24073-24094]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[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

[[Page 24074]]

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 (202) 566-1744, 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: (919) 541-5430; Fax number (919) 541-5450; 
Email address: maxwell.bill@epa.gov. For the NSPS action: Mr. Christian 
Fellner, Energy Strategies Group, Sector Policies and Programs 
Division, (D243-01), Office of Air Quality Planning and Standards, U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711; Telephone number: (919) 541-4003; Fax number (919) 541-5450; 
Email address: fellner.christian@epa.gov.

SUPPLEMENTARY INFORMATION: 
    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:

------------------------------------------------------------------------
                                                 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.
------------------------------------------------------------------------
\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

[[Page 24075]]

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

[[Page 24076]]

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

[[Page 24077]]

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

[[Page 24078]]

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

    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

[[Page 24079]]

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

[[Page 24080]]

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 5.2.2.2 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 3.1.2.1.3 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

[[Page 24081]]

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

[[Page 24082]]

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

[[Page 24083]]

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

[[Page 24084]]

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

[[Page 24085]]

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



[[Page 24086]]


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.

[[Page 24087]]

[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:

[[Page 24088]]



               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..........

[[Page 24089]]

 
                                       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..........

[[Page 24090]]

 
                                       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:

[[Page 24091]]



     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.
                                                                                              3. Determine the
                                                                                               highest 1-hour
                                                                                               average PM CPMS
                                                                                               measured during
                                                                                               the performance
                                                                                               test
                                                                                               demonstrating
                                                                                               compliance with
                                                                                               the filterable PM
                                                                                               or HAP metals
                                                                                               emissions
                                                                                               limitations.

[[Page 24092]]

 
2. 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 a    emissions           CPMS output                             performance
 new 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 performance
                                                                                               test.
                                                                                              3. Determine the
                                                                                               PM CPMS operating
                                                                                               limit in
                                                                                               accordance with
                                                                                               the requirements
                                                                                               of Sec.
                                                                                               63.10023(b)(2)
                                                                                               from data
                                                                                               obtained during
                                                                                               the performance
                                                                                               test
                                                                                               demonstrating
                                                                                               compliance with
                                                                                               the filterable PM
                                                                                               or HAP metals
                                                                                               emissions
                                                                                               limitations.
----------------------------------------------------------------------------------------------------------------


0
23. Revise Table 7 to Subpart UUUUU of Part 63 to read as follows:

Table 7 to Subpart UUUUU of Part 63--Demonstrating Continuous Compliance
 [As stated in Sec.   63.10021, you must show continuous compliance with
     the emission limitations for affected sources according to the
                               following]
------------------------------------------------------------------------
If you use one of the following to
 meet applicable emissions limits,       You demonstrate continuous
operating limits, or work practice           compliance by . . .
          standards . . .
------------------------------------------------------------------------
1. CEMS to measure filterable PM,   Calculating the 30- (or 90-) boiler
 SO2, HCl, HF, or Hg emissions, or   operating day rolling arithmetic
 using a sorbent trap monitoring     average emissions rate in units of
 system to measure Hg.               the applicable emissions standard
                                     basis at the end of each boiler
                                     operating day using all of the
                                     quality assured hourly average CEMS
                                     or sorbent trap data for the
                                     previous 30- (or 90-) boiler
                                     operating days, excluding data
                                     recorded during periods of startup
                                     or shutdown.
2. PM CPMS to measure compliance    Calculating the 30- (or 90-) boiler
 with a parametric operating limit.  operating day rolling arithmetic
                                     average of all of the quality
                                     assured hourly average PM CPMS
                                     output data (e.g., milliamps, PM
                                     concentration, raw data signal)
                                     collected for all operating hours
                                     for the previous 30- (or 90-)
                                     boiler operating days, excluding
                                     data recorded during periods of
                                     startup or shutdown.
3. Site-specific monitoring using   If applicable, by conducting the
 CMS for liquid oil-fired EGUs for   monitoring in accordance with an
 HCl and HF emission limit           approved site-specific monitoring
 monitoring.                         plan.
4. Quarterly performance testing    Calculating the results of the
 for coal-fired, solid oil derived   testing in units of the applicable
 fired, or liquid oil-fired EGUs     emissions standard.
 to measure compliance with one or
 more non-PM (or its alternative
 emission limits) applicable
 emissions limit in Table 1 or 2,
 or PM (or its alternative
 emission limits) applicable
 emissions limit in Table 2.
5. Conducting periodic performance  Conducting periodic performance tune-
 tune-ups of your EGU(s).            ups of your EGU(s), as specified in
                                     Sec.   63.10021(e).
6. Work practice standards for      Operating in accordance with Table
 coal-fired, liquid oil-fired, or    3.
 solid oil-derived fuel-fired EGUs
 during startup.
7. Work practice standards for      Operating in accordance with Table
 coal-fired, liquid oil-fired, or    3.
 solid oil-derived fuel-fired EGUs
 during shutdown.
------------------------------------------------------------------------



0
24. Revise Table 9 to Subpart UUUUU of Part 63 to read as follows:

[[Page 24093]]



Table 9 to Subpart UUUUU of Part 63--Applicability of General Provisions
                            to Subpart UUUUU
   [As stated in Sec.   63.10040, you must comply with the applicable
             General Provisions according to the following]
------------------------------------------------------------------------
                                                     Applies to subpart
           Citation                  Subject               UUUUU
------------------------------------------------------------------------
Sec.   63.1...................  Applicability....  Yes.
Sec.   63.2...................  Definitions......  Yes. Additional terms
                                                    defined in Sec.
                                                    63.10042.
Sec.   63.3...................  Units and          Yes.
                                 Abbreviations.
Sec.   63.4...................  Prohibited         Yes.
                                 Activities and
                                 Circumvention.
Sec.   63.5...................  Preconstruction    Yes.
                                 Review and
                                 Notification
                                 Requirements.
Sec.   63.6(a), (b)(1)-(b)(5),  Compliance with    Yes.
 (b)(7), (c), (f)(2)-(3), (g),   Standards and
 (h)(2)-(h)(9), (i), (j).        Maintenance
                                 Requirements.
Sec.   63.6(e)(1)(i)..........  General Duty to    No. See Sec.
                                 minimize           63.10000(b) for
                                 emissions.         general duty
                                                    requirement.
Sec.   63.6(e)(1)(ii).........  Requirement to     No.
                                 correct
                                 malfunctions
                                 ASAP.
Sec.   63.6(e)(3).............  SSM Plan           No.
                                 requirements.
Sec.   63.6(f)(1).............  SSM exemption....  No.
Sec.   63.6(h)(1).............  SSM exemption....  No.
Sec.   63.7(a), (b), (c), (d),  Performance        Yes.
 (e)(2)-(e)(9), (f), (g), and    Testing
 (h).                            Requirements.
Sec.   63.7(e)(1).............  Performance        No. See Sec.
                                 testing.           63.10007.
Sec.   63.8...................  Monitoring         Yes.
                                 Requirements.
63.8(c)(1)(i).................  General duty to    No. See Sec.
                                 minimize           63.10000(b) for
                                 emissions and      general duty
                                 CMS operation.     requirement.
Sec.   63.8(c)(1)(iii)........  Requirement to     No.
                                 develop SSM Plan
                                 for CMS.
Sec.   63.8(d)(3).............  Written            Yes, except for last
                                 procedures for     sentence, which
                                 CMS.               refers to an SSM
                                                    plan. SSM plans are
                                                    not required.
Sec.   63.9...................  Notification       Yes, except for the
                                 requirements.      60-day notification
                                                    prior to conducting
                                                    a performance test
                                                    in Sec.   63.9(d);
                                                    instead use a 30-day
                                                    notification period
                                                    per Sec.
                                                    63.10030(d).
Sec.   63.10(a), (b)(1), (c),   Recordkeeping and  Yes, except for the
 (d)(1)-(2), (e), and (f).       Reporting          requirements to
                                 Requirements.      submit written
                                                    reports under Sec.
                                                    63.10(e)(3)(v).
Sec.   63.10(b)(2)(i).........  Recordkeeping of   No.
                                 occurrence and
                                 duration of
                                 startups and
                                 shutdowns.
Sec.   63.10(b)(2)(ii)........  Recordkeeping of   No. See 63.10001 for
                                 malfunctions.      recordkeeping of (1)
                                                    occurrence and
                                                    duration and (2)
                                                    actions taken during
                                                    malfunction.
Sec.   63.10(b)(2)(iii).......  Maintenance        Yes.
                                 records.
Sec.   63.10(b)(2)(iv)........  Actions taken to   No.
                                 minimize
                                 emissions during
                                 SSM.
Sec.   63.10(b)(2)(v).........  Actions taken to   No.
                                 minimize
                                 emissions during
                                 SSM.
Sec.   63.10(b)(2)(vi)........  Recordkeeping for  Yes.
                                 CMS malfunctions.
Sec.   63.10(b)(2)(vii)-(ix)..  Other CMS          Yes.
                                 requirements.
Sec.   63.10(b)(3),and (d)(3)-  .................  No.
 (5).
Sec.   63.10(c)(7)............  Additional         Yes.
                                 recordkeeping
                                 requirements for
                                 CMS--identifying
                                 exceedances and
                                 excess emissions.
Sec.   63.10(c)(8)............  Additional         Yes.
                                 recordkeeping
                                 requirements for
                                 CMS--identifying
                                 exceedances and
                                 excess emissions.
Sec.   63.10(c)(10)...........  Recording nature   No. See 63.10032(g)
                                 and cause of       and (h) for
                                 malfunctions.      malfunctions
                                                    recordkeeping
                                                    requirements.
Sec.   63.10(c)(11)...........  Recording          No. See 63.10032(g)
                                 corrective         and (h) for
                                 actions.           malfunctions
                                                    recordkeeping
                                                    requirements.
Sec.   63.10(c)(15)...........  Use of SSM Plan..  No.
Sec.   63.10(d)(5)............  SSM reports......  No. See 63.10021(h)
                                                    and (i) for
                                                    malfunction
                                                    reporting
                                                    requirements.
Sec.   63.11..................  Control Device     No.
                                 Requirements.
Sec.   63.12..................  State Authority    Yes.
                                 and Delegation.
Sec.   63.13-63.16............  Addresses,         Yes.
                                 Incorporation by
                                 Reference,
                                 Availability of
                                 Information,
                                 Performance
                                 Track Provisions.
Sec.   63.1(a)(5), (a)(7)-      Reserved.........  No.
 (a)(9), (b)(2), (c)(3)-(4),
 (d), 63.6(b)(6), (c)(3),
 (c)(4), (d), (e)(2),
 (e)(3)(ii), (h)(3),
 (h)(5)(iv), 63.8(a)(3),
 63.9(b)(3), (h)(4),
 63.10(c)(2)-(4), (c)(9).
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[[Page 24094]]


0
25. Revise sections 4.1 and 5.2.2.2 to Appendix A to Subpart UUUUU of 
Part 63 to read as follows:

Appendix A to Subpart UUUUU--Hg Monitoring Provisions

* * * * *
    4.1 Certification Requirements. All Hg CEMS and sorbent trap 
monitoring systems and the additional monitoring systems used to 
continuously measure Hg emissions in units of the applicable 
emissions standard in accordance with this appendix must be 
certified in a timely manner, such that the initial compliance 
demonstration is completed no later than the applicable date in 
Sec.  63.9984(f).
* * * * *
    5.2.2.2 The same RATA performance criteria specified in Table A-
2 for Hg CEMS also apply to the annual RATAs of the sorbent trap 
monitoring system.
* * * * *

0
26. Revise section 3.1.2.1.3 and the heading to section 5.3.4 to 
Appendix B to Subpart UUUUU of Part 63 to read as follows:

Appendix B to Subpart UUUUU--HCl and HF Monitoring Provisions

* * * * *
    3.1.2.1.3 For the ASTM D6348-03 test data to be acceptable for a 
target analyte, %R must be 70% <= R <= 130%; and
* * * * *
    5.3.3 Conditional Data Validation * * *
* * * * *

[FR Doc. 2013-07859 Filed 4-23-13; 8:45 am]
BILLING CODE 6560-50-P


