Document ID: EPA-HQ-OAR-2011-0044-5778
Agency: epa
Document Type: Rule
Title: Reconsideration of Certain New Source and Startup/Shutdown 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;
Posted Date: 2012-11-30T05:00Z

[Federal Register Volume 77, Number 231 (Friday, November 30, 2012)]
[Rules and Regulations]
[Pages 71323-71344]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-28729]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2009-0234; EPA-HQ-OAR-2011-0044; FRL-9733-2]
RIN 2060-AR62

Reconsideration of Certain New Source and Startup/Shutdown 
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: Proposed rules; notice of public hearing.

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SUMMARY: On February 16, 2012, pursuant to sections 111 and 112 of the 
Clean Air Act (CAA), the EPA published 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 CAA section 112 is 
referred to as the Mercury and Air Toxics Standards (MATS), 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 MATS and the Utility NSPS. In 
this notice, the EPA is announcing reconsideration of certain new 
source standards for MATS, the requirements applicable during periods 
of startup and shutdown for MATS, the startup and shutdown provisions 
related to the particulate matter (PM) standard in the Utility NSPS, 
and certain revisions to the definitional and monitoring provisions of 
the Utility NSPS. We are also proposing certain technical corrections 
to both MATS and the Utility NSPS.
    We seek comment only on the aspects of the final MATS and Utility 
NSPS rules specifically identified in this notice. We are not opening 
for reconsideration any other provisions of MATS or the Utility NSPS at 
this time.

DATES: Comments. Comments must be received on or before December 31, 
2012. Because of the need to resolve the issues identified in this 
notice in a timely manner, the EPA does not intend to grant requests 
for extensions beyond this date.
    Public Hearing. If anyone contacts the EPA by December 10, 2012 
requesting to speak at a public hearing, the EPA will hold a public 
hearing on December 18, 2012. If a public hearing is held, it will be 
held from 9:00 a.m. to 7:00 p.m., Eastern time, in Room 1153 EPA East 
Hearing room, 1201 Constitution Avenue NW., Washington, DC 20460, (202) 
564-1657. For further information on the public hearing and requests to 
speak, see the ADDRESSES section of this preamble.

ADDRESSES: Comments. Submit your comments, identified by Docket ID. No. 
EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-2009-
0234 (NESHAP/MATS action), by one of the following methods:
     http://www.regulations.gov. Follow the instructions for 
submitting comments.
     http://www.epa.gov/oar/docket.html. Follow the 
instructions for submitting comments on the EPA Air and Radiation 
Docket Web Site.
     Email: Comments may be sent by electronic mail (email) to 
a-and-r-docket@epa.gov, Attention EPA-HQ-OAR-2011-0044 (NSPS action) or 
EPA-HQ-OAR-2009-0234 (NESHAP/MATS action).
     Fax: Fax your comments to: (202) 566-9744, Docket ID No. 
EPA-HQ-OAR-2011-0044 (NSPS action) or Docket ID No. EPA-HQ-OAR-2009-
0234 (NESHAP/MATS action).
     Mail: Send your comments on the NESHAP/MATS action to: EPA 
Docket Center (EPA/DC), Environmental Protection Agency, Mailcode: 
2822T, 1200 Pennsylvania Ave. NW., Washington, DC 20460, Docket ID No. 
EPA-HQ-OAR-2009-0234. Send your comments on the NSPS action to: EPA 
Docket Center (EPA/DC), Environmental Protection Agency, Mailcode: 
2822T, 1200 Pennsylvania Ave. NW., Washington, DC 20460, Docket ID. 
EPA-HQ-OAR-2011-0044. Please include a total of two copies. In 
addition, please mail a copy of your comments on the information 
collection provisions to the Office of Information and Regulatory 
Affairs, OMB, Attn: Desk Officer for EPA, 725 17th St. NW., Washington, 
DC 20503.
     Hand Delivery or Courier: Deliver your comments to: EPA 
Docket Center, EPA West, Room 3334, 1301 Constitution Ave. NW., 
Washington, DC 20460. Please include a total of two copies. Such 
deliveries are only accepted during the Docket's normal hours of 
operation (8:30 a.m. to 4:30 p.m., Monday through Friday, excluding 
legal holiday), and special arrangements should be made for deliveries 
of boxed information.
    Instructions. All submissions must include agency name and 
respective docket number or Regulatory Information Number (RIN) for 
this rulemaking. All comments will be posted without change and may be 
made available online at http://www.regulations.gov, including any 
personal information provided, unless the comment includes information 
claimed to be confidential business information (CBI) or other 
information whose disclosure is restricted by statute. Do not submit 
information that you consider to be CBI or otherwise protected through 
http://www.regulations.gov or email. The http://www.regulations.gov Web 
site is an ``anonymous access'' system, which means the EPA will not 
know your identity or contact information unless you provide it in the 
body of your comment. If you send an email comment directly to the EPA 
without going through http://www.regulations.gov, your email address 
will be automatically captured and included as part of the comment that 
is placed in the public docket and made available on the Internet. If 
you submit an electronic comment, the EPA recommends that you include 
your name and other contact information in the body of your comment and 
with any disk or CD-ROM you submit. If the EPA cannot read your comment 
due to technical difficulties and cannot contact you for clarification, 
the EPA may not be able to consider your comment. Electronic files 
should avoid the use of special characters, any form of encryption, and 
be free of any defects or viruses.
    Public Hearing. If anyone contacts EPA by December 10, 2012 
requesting to speak at a public hearing, the EPA will hold a public 
hearing on December 18, 2012. If a public hearing is held, it will be 
held from 9:00 a.m. to 7:00 p.m., Eastern time in Room 1153 EPA East 
Hearing room, 1201 Constitution

[[Page 71324]]

Avenue NW., Washington, DC 20460, 202-564-1657. A lunch break is 
scheduled from 12:00 p.m.-1:00 p.m. Visitors must go through a metal 
detector, sign in with the security desk, be accompanied by an employee 
and show identification to enter the building. Contact Pamela Garrett 
at (919) 541-7966 or at garrett.pamela@epa.gov to request a hearing, to 
determine if a hearing will be held and to register to speak if a 
hearing is held. If no one contacts the EPA requesting to speak at a 
public hearing concerning this proposed rule by December 10, 2012, the 
hearing will be cancelled without further notice. If a hearing is held, 
the last day to register to present oral testimony in advance will be 
Friday, December 14, 2012. The public hearing will provide interested 
parties the opportunity to present data, views, or arguments concerning 
this notice. The record for this action will remain open for 30 days 
after the date of the hearing to provide an opportunity for submission 
of rebuttal and supplementary information. We will also specify the 
date and time of the public hearings on http://www.epa.gov/airquality/powerplanttoxics/actions.html and http://www.epa.gov/ttn/atw/utility/utilitypg.html.
    Docket. All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some 
information is not publicly available (e.g., CBI or other information 
whose disclosure is restricted by statute). Certain other material, 
such as copyrighted material, will be publicly available only in hard 
copy form. Publicly available docket materials are available either 
electronically in http://www.regulations.gov or in hard copy at the EPA 
Docket Center, Room 3334, 1301 Constitution Avenue NW., Washington, DC. 
The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holidays. The telephone number for the 
Public Reading Room is (202) 566-1744, and the telephone number for the 
Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For the 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 reconsideration notice apply to me?
    B. What should I consider as I prepare my comments to the EPA?
    C. How do I obtain a copy of this document and other related 
information?
II. Background
III. Today's Action
IV. Discussion of Provisions Subject to Reconsideration--NESHAP/MATS
    A. New Source MATS Emission Limits
    B. Eligibility To Be a New Source
    C. Startup and Shutdown Provisions
V. Discussion of Provisions Subject to Reconsideration--Utility NSPS
VI. Technical Corrections and Clarifications
VII. Impacts of This Proposed Rule
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the compliance costs?
    D. What are the economic and employment impacts?
    E. What are the benefits of the proposed 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

I. General Information

A. Does this reconsideration notice apply to me?

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

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                   Category                     NAICS code \1\     Examples of potentially regulated entities
----------------------------------------------------------------------------------------------------------------
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. What should I consider as I prepare my comments to the EPA?

    Do not submit information containing CBI to the EPA through http://www.regulations.gov or email. Send or deliver information identified as 
CBI only to the following address: Roberto Morales, OAQPS Document 
Control Officer (C404-02), Office of Air Quality Planning and 
Standards, U.S. Environmental Protection Agency, Research Triangle 
Park, North Carolina 27711, Attention: Docket ID EPA-HQ-OAR-2011-0044 
(Utility NSPS) or Docket ID EPA-HQ-OAR-2009-0234 (NESHAP/MATS). Clearly 
mark the part or all of the information that you claim to be CBI. For 
CBI information in a disk or CD-ROM that you mail to the EPA, mark the 
outside of the disk or CD-ROM as CBI and then identify electronically 
within the disk or CD-ROM the specific information that is claimed as 
CBI. In addition to one complete version of the comment that includes 
information

[[Page 71325]]

claimed as CBI, a copy of the comment that does not contain the 
information claimed as CBI must be submitted for inclusion in the 
public docket. Information so marked will not be disclosed except in 
accordance with procedures set forth in 40 CFR part 2.

C. How do I obtain a copy of this document and other related 
information?

    In addition to being available in the docket, electronic copies of 
these proposed rules will be available on the Worldwide Web (WWW) 
through the Technology Transfer Network (TTN). Following signature, a 
copy of each proposed rule 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.

II. Background

    The Administrator signed MATS and the Utility NSPS on December 16, 
2011, and the final rules were published in the Federal Register at 77 
FR 9304, February 16, 2012. Following promulgation of the final rules, 
the Administrator received petitions for reconsideration of numerous 
provisions of both MATS and the Utility NSPS pursuant to CAA section 
307(d)(7)(B). Copies of the MATS 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.

III. Today's Action

    Today, we are granting reconsideration of, proposing, and 
requesting comment on the following limited set of issues: (1) Certain 
revised new source standards in MATS, (2) requirements applicable 
during periods of startup and shutdown in MATS, (3) startup and 
shutdown provisions related to the PM standard in the Utility NSPS, and 
(4) definitional and monitoring provisions in the Utility NSPS. We are 
also proposing certain technical corrections to both MATS and the 
Utility NSPS.
    This notice is limited to the specific issues identified in this 
notice. We will not respond to any comments addressing any other 
provisions of MATS or the Utility NSPS.\1\
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    \1\ The recent decision by the U.S. Court of Appeals for the 
D.C. Circuit regarding the Cross State Air Pollution Rule (CSAPR) 
has no impact on the issues being reconsidered in this action.
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    The impacts of today's proposed revisions on the costs and the 
benefits of the final rule are minor. We expect that source owners and 
operators will install and operate the same or similar control 
technologies to meet the proposed revised standards in this notice as 
they would have chosen to comply with the standards in the February 
2012 final rule.\2\
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    \2\ 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.
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IV. Discussion of Provisions Subject to Reconsideration--NESHAP/MATS

A. New Source MATS Emission Limits

    The EPA received petitions requesting reconsideration of aspects of 
the new source emission limits in the final MATS rule. We are granting 
reconsideration of certain new source emission limits, as discussed 
below, and we invite comment on the proposed provisions in today's 
notice.
1. Certain New Source Limits--Use of Data in the Record
    The EPA received petitions for reconsideration asserting that the 
Agency did not use all the data in the record from the best performing 
sources in establishing certain final new source emission limits for 
coal- and oil-fired electric utility steam generating units (EGUs). 
Specifically, the petitioners maintained that the EPA did not consider 
all of the data in the record when establishing emission standards for 
filterable PM and hydrogen chloride (HCl) applicable to new coal-fired 
EGUs and for filterable PM applicable to new solid oil-derived fuel-
fired EGUs.
    In light of petitioners' assertions, we reviewed the available 
emissions information in the record for all the new source standards. 
We determined that we did not use all the data in the record in 
establishing the new source emission limits for filterable PM and HCl 
applicable to new coal-fired EGUs and for filterable PM applicable to 
new solid oil-derived fuel-fired EGUs. We also identified a few 
additional new source limits for which we did not use all of the data 
in the record when setting the standards in the final rule. We are 
proposing to revise the sulfur dioxide (SO2) limit 
applicable to solid oil-derived fuel-fired EGUs, the filterable PM 
limit applicable to continental liquid oil-fired EGUs, and the lead and 
selenium limits applicable to coal-fired EGUs based on consideration of 
all the data in the record from the best performing sources for the 
pollutants at issue. We solicit comment on the revised standards. 
Additional details on the proposed emission limits can be found in the 
memo ``Reconsideration of the 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, Proposed Rule'' in rulemaking docket EPA-HQ-OAR-2009-
0234.
    We also solicit comment on possible revisions to the Hg limit 
applicable to low rank virgin coal-fired EGUs based on additional data 
in the record. See ``Reconsideration of the 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, Proposed Rule'' in rulemaking docket 
EPA-HQ-OAR-2009-0234; ``MATS Reconsideration: Beyond-the-Floor 
Memorandum'' available in rulemaking docket EPA-HQ-OAR-2009-0234.
    The proposed revised new source CAA section 112(d) emission 
standards are presented in tables 1 and 2 of this preamble. The Agency 
derived these limits by first calculating the floor standards and then 
assessing whether a more stringent beyond-the-floor standard is 
appropriate.\3\ As explained further below, as to the standards we are 
proposing to revise, we are proposing a beyond-the-floor standard for 
HCl for new coal-fired EGUs, but we are not proposing beyond-the-floor 
standards for the other pollutants and subcategories.
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    \3\ CAA section 112(d)(2) requires the EPA to consider whether 
more stringent beyond-the-floor standards should be established.
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2. SO2 Limit for New Coal-Fired EGUs--Reliance on Industrial 
Boiler Emission Data
    We are also reconsidering the SO2 standard for new coal-
fired EGUs. The Agency received a petition asserting that the final 
alternative SO2 emission limit was developed using, as the 
best performing source, a unit that is 25 MW in capacity. In order to 
be classified as an EGU, and thus subject to MATS, a unit must be 
greater than 25 MW in capacity. A unit that is 25 MW or less is likely 
an industrial boiler and would be subject to the Industrial-Commercial-
Institutional Boiler NESHAP, not MATS.
    At the time of the final rule, we believed the unit on which we 
based the SO2 standard for new coal-fired EGUs was an EGU. 
After we received the petition for reconsideration, we re-

[[Page 71326]]

examined the record and determined that the unit was, in fact, an 
industrial boiler and not an EGU.
    As an initial matter, nothing in the CAA precludes the EPA from 
identifying a source in another source category as the best controlled 
similar source. However, we believe that it is appropriate in this 
case, where we have considerable data on EGUs, to base the new source 
standard on the best performing unit that is an EGU. This is also 
consistent with our intent in the final rule, as we thought the unit we 
had selected was, in fact, an EGU. For these reasons, we are 
reconsidering the SO2 standard for new coal-fired EGUs. We 
have reviewed the emissions data and identified the best performing EGU 
upon which to base the proposed SO2 standard. The proposed 
limit is presented in table 2 of this preamble. We solicit comment on 
the revised limit and the methods used to establish this limit.
3. Hg Limit for New Coal-Fired EGUs Designed for Coal >= 8300 Btu/lb--
Measurement Issues
    The EPA is also reconsidering the emission limit for Hg for new 
coal-fired EGUs in the units designed for the coal >= 8300 Btu/lb (non-
low rank virgin coal) subcategory. Some petitioners asserted that this 
limit, as finalized, was too low for emissions to be reliably measured 
in a manner that would allow sources to operate their control 
technology in a way that ensures compliance with the standard. 
Specifically, petitioners maintained that sorbent trap monitoring 
systems could not provide sufficiently timely Hg data at the new source 
level for sources to make adjustments to the EGUs and attendant air 
pollution control devices (ACPDs) to ensure compliance with the 
standard and that Hg continuous emissions monitoring systems (CEMS) 
were not capable of measuring Hg at the new source limit. The 
petitioners indicated that reliable and frequent emission measurements 
are needed to maintain the operation of Hg control technology at 
performance levels set in the final rule.
    As we explained in the record to the final rule, owners and 
operators of new EGUs in the non-low rank virgin coal subcategory could 
use the sorbent trap monitoring systems to demonstrate compliance with 
the new source Hg standard because of the potential for a longer sample 
collection period associated with sorbent traps and their inherent 
lower emissions detection capability.
    As described in the final rule, when establishing emission limits 
for pollutants, we calculated a representative detection limit (RDL) 
and then compared the UPL-determined emission floor with a value three 
times the RDL (3 X RDL), and we set the final limit at the higher of 
the two numbers. We did not follow that procedure for sorbent trap 
monitoring systems when setting Hg emission limits as we did not 
believe sorbent trap monitoring systems were constrained by method 
detection limits, since operators could increase the sample collection 
time up to 14 days to guarantee collection of a measurable quantity of 
mercury with appropriate accuracy. We continue to believe that the 
promulgated Hg limit for the non-low rank virgin coal subcategory is 
measurable using a sorbent trap monitoring system.
    As noted, however, petitioners have indicated that the long sorbent 
trap sampling times that may be necessary to measure at the final new 
source level do not allow sufficiently frequent emissions feedback such 
that a source could take corrective action and avoid violations of the 
emission limit within the prescribed compliance time.
    We understand that Hg emissions can vary over time, and we 
acknowledge the value of frequent feedback of emission measurements. We 
also understand that frequent feedback may be desirable and, at times, 
necessary to optimize the operation of generation or control technology 
in order to maintain emissions at or below the standard. The sorbent 
trap monitoring method required in the MATS rule allows sampling for as 
long as 14 days. In the final rule, we assumed that most sources would 
leave the sorbent traps in as long as needed--up to 14 days--to ensure 
they had no measurement issues. Based on the petitions for 
reconsideration, we understand that sources will most likely use a 
shorter sampling period, perhaps as short as 30 minutes. The shorter 
sampling periods will provide more constant feedback on Hg emissions, 
which will help the source ensure that it is in compliance with the Hg 
emission limit, for which compliance is determined on a 30-day rolling 
average.
    Given the petitioners' stated need for more frequent Hg emissions 
information, we re-evaluated whether detection level issues arise when 
shorter sampling periods, such as 30 minutes, are employed by sorbent 
trap monitoring systems. Although the shorter sampling period is 
adequate to provide information needed to optimize the operation of Hg 
control technology, we believe the reduced sampling period results in a 
reduced quantity of collected Hg which constrains the sorbent trap 
monitoring system by a minimum detection limit. For additional 
information, see ``Determination of Representative Detection Level 
(RDL) and 3 X RDL Values for Mercury Measured Using Sorbent Trap 
Technologies'' in rulemaking docket EPA-HQ-OAR-2009-0234. Specifically, 
we believe detection level issues may arise from using a sorbent trap 
when short sampling periods (e.g., 30 minutes) are used, and that, as 
such, the UPL-calculated floor value should be compared against the 3 X 
RDL value to account for the shorter sampling periods. We solicit 
comment on this proposed revised approach in light of the information 
provided by petitioners regarding the need for prompt Hg emissions 
information.
    Our review of the data in the record shows that for reasonable, 
shorter sampling conditions--30-minute samples obtained at a sampling 
rate of 0.5 liter per minute--the UPL-determined new source Hg limit is 
less than the 3 X RDL value. Therefore, we are proposing to set the Hg 
limit for the non-low rank virgin coal subcategory at the 3 X RDL 
value.
    Although the value of the resulting limit we are proposing today is 
higher than that in the final rule, we do not expect this change to 
alter the emission control strategy of a new EGU, as both emission 
limits result in Hg removal efficiency in excess of 97 percent. 
However, the proposed change will improve EGU owners' and operators' 
ability to track emissions and take preemptive actions to ensure 
compliance. Based on information provided by the petitioners, our 
experience, and the National Institute of Standards and Technology's 
recently confirmed capability to certify Hg calibration gas generators 
down to 0.2 micrograms per cubic meter ([mu]g/m\3\), the proposed 
change in the Hg limit will also allow the option of using a Hg CEMS 
for process control and for determining compliance.
    Please refer to the memo ``Data and Procedure for Handling Below 
Detection Level Data in Analyzing Various Pollutant Emissions Databases 
for MACT and RTR Emissions Limits'' (docket entry EPA-HQ-OAR-2009-0234-
20062) for a discussion of the RDL approach generally, and the memo 
``Determination of Representative Detection Level (RDL) and 3 X RDL 
Values for Mercury Measured Using Sorbent Trap Technologies'' 
(rulemaking docket EPA-HQ-OAR-2009-0234) for a discussion of our 
approach for establishing an RDL for Hg. The proposed limit is 
presented in table 1 of this preamble.

[[Page 71327]]

4. Limits for New IGCC EGUs--Use of Permit Limits From Unconstructed 
IGCC EGUs
    We are granting reconsideration of the finalized new source 
integrated gasification combined cycle (IGCC) limits. The EPA used the 
permit limits from IGCC EGUs that are permitted but not yet constructed 
as the basis for some of the final new source IGCC emission limits. 
Some petitioners asserted that the EPA did not use this approach in the 
notice of proposed rulemaking and that they therefore were deprived of 
the opportunity to comment on this approach.
    Although we indicated that we considered establishing standards 
based on IGCC permits at proposal, we are granting reconsideration on 
the new source IGCC limits so that the public has an additional 
opportunity to comment on the limits and the approach.
    Specifically, we request comment on the proposed new source IGCC 
standards, which are unchanged from the final standards promulgated for 
these units on February 16, 2012. These proposed new source limits are 
presented in tables 1 and 2 of this preamble.
5. Beyond-the-Floor Analysis
    The MACT floor level of control for new EGUs is based on the 
emission control that is achieved in practice by the best controlled 
similar source, as determined by the Agency, of each HAP for the 
different subcategories. After the EPA establishes MACT floor levels, 
CAA section 112(d)(2) requires the EPA to consider whether more 
stringent beyond-the-floor standards should be established. Under that 
section, the Agency must consider ``the cost of achieving such emission 
reduction, and any non-air quality health and environmental impacts and 
energy requirements'' before it may establish a standard that is based 
on a beyond-the-floor level of control.
    For most of the new source standards addressed in this proposal, we 
have not identified additional technologies or HAP emission reduction 
approaches that would achieve HAP reductions greater than the new 
source floors for the subcategories, other than multiple controls in 
series (e.g., multiple scrubbers in series or multiple PM controls in 
series), which we consider to be unreasonable from a cost perspective. 
We are therefore proposing to adopt the floor level of control for all 
but one of these standards. We are proposing a beyond-the-floor 
standard for HCl emissions from coal-fired EGUs. Summaries of the EPA's 
beyond-the-floor evaluations for the new source standards addressed in 
this proposal are provided below. Additional detail of these analyses, 
including a discussion of costs and non-air quality health and 
environmental impacts, is provided in the ``MATS Reconsideration: 
Beyond-the-Floor Memorandum'' available in rulemaking docket EPA-HQ-
OAR-2009-0234. We request comment on all aspects of our beyond-the-
floor analysis. Specifically, we solicit comment on whether there are 
any control technologies or HAP emission reduction practices that have 
been demonstrated to achieve HAP reductions at levels lower than the 
standards proposed in this notice consistently and in a cost-effective 
manner. Comments should include information on emissions, pollutant 
control efficiencies, operational reliability, current demonstrated 
applications, and costs.
    a. Beyond-the-floor analysis for PM from coal-fired EGUs. It is 
commonly accepted that a baghouse fabric filter (FF) is the technology 
that provides the best level of PM emission reduction for coal-fired 
EGUs. Newly constructed coal-fired EGUs will be expected to install FFs 
to meet the new source NESHAP PM limit that we are proposing in this 
notice and the applicable NSPS limit. We have considered available 
options that would allow a new source to achieve greater emission 
reductions than those achieved in practice by the best controlled 
source. The EPA is aware that some EGUs have installed downstream 
secondary ``polishing'' PM control devices to provide for incremental 
PM reductions beyond what is achieved by the primary PM control device. 
However, those ``polishing'' PM control devices are most often 
installed for one of two purposes: (1) To augment the control of an 
underperforming or undersized primary control device or (2) to allow 
for injection of activated carbon or other powdered sorbent so that the 
fly ash and the sorbent remain separated for eventual storage, 
disposal, or re-use. Given that a new coal-fired EGU would have the 
opportunity to design the primary PM control device to meet the new 
source emission limit, we can see no justification for including in the 
design a secondary downstream ``polishing'' PM control device. Such a 
device would add considerable cost to the project, and the incremental 
cost-effectiveness would not be reasonable. See ``MATS Reconsideration: 
Beyond-the-Floor Memorandum'' in rulemaking docket EPA-HQ-OAR-2009-
0234.
    b. Beyond-the-floor analysis for Hg from new coal-fired EGUs 
designed for coal >= 8300 Btu/lb. The proposed new source Hg emission 
limit for EGUs firing non-low rank virgin coal is based on the use of 
the 3 X RDL approach. As explained above, there is concern that a lower 
emission limit could not be reliably measured with sufficient frequency 
to allow consistent and timely compliance. For this reason, we are not 
proposing a limit based on a beyond-the-floor level of control, and, 
instead, we are proposing to establish the standard at the MACT floor 
level.
    c. Beyond-the-floor analysis for SO2 emissions from 
coal-fired EGUs. The best performing source for SO2 
emissions from a coal-fired EGU is a circulating fluidized bed 
combustor (CFB) with limestone injection for SO2 control and 
a downstream circulating dry scrubber (CDS) for supplemental 
SO2 control. Because the EGU already employs a downstream 
``polishing'' SO2 control device, we do not believe that 
installation of an additional ``polishing'' control device would result 
in cost-effective reduction (in $/ton of incremental SO2 
reduction) that would justify setting a beyond-the-floor emission 
limit. See ``MATS Reconsideration: Beyond-the-Floor Memorandum'' in 
rulemaking docket EPA-HQ-OAR-2009-0234.
    d. Beyond-the-floor analysis for PM from solid oil-derived fuel-
fired EGUs. This analysis is very similar to that which was presented 
earlier for PM emissions from coal-fired EGUs. Given that a new solid 
oil-derived fuel-fired EGU would have the opportunity to design the 
primary PM control device to meet the new source emission limit, we can 
see no justification for including in the design a secondary downstream 
``polishing'' PM control device. As with the coal-fired source, such a 
device would add considerable costs to the project, and the incremental 
cost-effectiveness would not be reasonable.
    e. Beyond-the-floor analysis for SO2 from solid oil-
derived fuel-fired EGUs. The best performing source for SO2 
emissions from solid oil-derived fuel-fired EGUs is a CFB combustor 
with limestone injection for SO2 control. Additional 
SO2 control, beyond that which is obtained by the best 
controlled source, may be obtained by installing a downstream 
SO2 control device such as a spray drier absorber (SDA) or 
wet-flue gas desulfurization (wet-FGD) scrubber or, as was the case 
with the best performing coal-fired unit, a CDS. However, as stated 
earlier, we believe that, in this case, the installation of additional 
downstream ``polishing'' control technologies does not result in

[[Page 71328]]

cost-effective control (in $/ton of incremental SO2 
reduction) that would justify setting a beyond-the-floor emission 
limit.
    f. Beyond-the-floor analysis for PM from continental liquid oil 
fuel-fired EGUs. The proposed new source filterable PM emission limit 
for continental liquid oil-fired fuel is based on an EGU which uses an 
electrostatic precipitator (ESP). Distillate oil-fired facilities do 
not need add-on PM controls, as their emissions are inherently low, and 
residual oil-fired units cannot use FFs for PM control due to concerns 
about bag contamination and fire safety. ESPs are the best filterable 
PM control technology for liquid oil fuel-fired EGUs. Given that a new 
continental liquid-oil fuel-fired EGU would have the opportunity to 
design the primary PM control device to meet the new source emission 
limit, we can see no justification for including in the design a 
secondary downstream ``polishing'' PM control device. Such a device 
would add considerable costs to the project, and the incremental cost-
effectiveness would not be reasonable.
    g. Beyond-the-floor analysis for HAP emissions from IGCC EGUs. We 
have no data upon which to assess whether or not technologies exist 
that can provide additional HAP control beyond the proposed new source 
emission limits for new IGCC units. Accordingly, we are not proposing 
to establish beyond-the-floor emission limitations for these pollutants 
for new IGCC units. We request comment on whether the use of any 
control technologies or practices have been demonstrated to 
consistently achieve in a cost-effective manner, emission levels for 
similar sources that are lower than those proposed for new IGCC sources 
in this proposal. Comments should include information on emissions, 
pollutant control efficiencies, operational reliability, current 
demonstrated applications, and costs.
    h. Beyond-the-floor analysis for HCl emissions from coal-fired 
EGUs. For HCl, the EPA's revised floor analysis for coal units--
discussed above--resulted in a revised MACT floor of 2.0E-2 pound per 
megawatt-hour (lb/MWh). We have estimated that a new coal-fired EGU 
would need to remove HCl in the range of 81.0 to 96.6 percent 
(depending upon the initial chlorine (Cl) content of the fuel) in order 
to meet this revised MACT floor level of control for HCl emissions. We 
also note that it is reasonable to expect that in most, if not all, 
cases, advanced FGD control technology (such as a wet-FGD scrubber or a 
high efficiency SDA) would be required as a result of other federal 
requirements--specifically a prevention of significant deterioration 
(PSD) best available control technology (BACT) analysis. More detailed 
discussion may be found in the memo ``MATS Reconsideration: Control 
Technology Needed to Meet New Source Limits'' contained in rulemaking 
docket EPA-HQ-OAR-2009-0234.
    A high efficiency SDA is less costly than a wet-FGD, and we think 
it likely that some new sources will be able to comply with PSD/BACT 
requirements using that less expensive option.\4\ For this reason, we 
believe that it is reasonable to assume the minimum level of 
performance for HCl control from a new EGU will be equivalent to that 
of a well-performing SDA for purposes of the beyond-the-floor analysis. 
We examined the level of HCl control achieved by those EGUs from the 
2010 utility information collection request (ICR) database that were 
equipped with SDA and we determined that those EGUs achieved HCl 
control in a range of 90 to 98 percent (coal-to-stack, depending on the 
coal Cl content).\5\
---------------------------------------------------------------------------

    \4\ New Source Review (NSR) permit requirements include, among 
other things, the application of BACT (best available control 
technology) under PSD. BACT control technology determinations and 
associated emission limit establishment involve case-by-case 
analyses and, such analyses take into account site-specific factors 
such as energy, environmental and economic impacts. For that reason, 
it is impossible to strictly predict the outcome of such analyses. 
However, based on recent BACT determinations for SO2 
emissions from coal-fired EGUs, it is reasonable to expect that in 
most, if not all, cases, flue gas desulfurization control 
technologies (such as wet-FGD scrubbers or high efficiency spray 
drier absorbers) would be required (see http://cfpub.epa.gov/RBLC/).
    \5\ Note that the HCl emission levels achieved are very similar 
for all EGUs. The difference observed in level of control 
(percentage) is due to the difference in chlorine levels seen in 
various coals.
---------------------------------------------------------------------------

    We, therefore, are proposing to set a beyond-the-floor HCl emission 
limit for new coal-fired EGUs at 1.0E-2 lb/MWh. We believe that a new 
EGU firing lower Cl-content coal would need to achieve a minimum of 90 
percent control to meet this proposed limit and that a new EGU firing a 
higher Cl-content coal would need to achieve a minimum of 98 percent 
control to meet the limit. We believe that this beyond-the-floor 
emission limit is cost-effective because it does not involve additional 
cost, as we expect that any new unit will install at least a high 
efficiency SDA to comply with other CAA requirements.
    We also considered a beyond-the-floor emission limit by assuming 
installation of a wet-FGD scrubber, which generally achieves greater 
HCl reductions, but at a greater cost, than a high efficiency SDA. We 
understand that some new coal-fired EGUs will likely be required to 
install this type of advanced FGD technology for SO2 
control. However, if the EGU is not required to install a wet-FGD 
scrubber from the PSD BACT determination for SO2, then the 
additional costs beyond those for a high efficiency SDA would be 
attributable to the achievement of additional HCl emission reductions, 
and the cost-effectiveness would not be reasonable.
6. Proposed New Source Emission Limits
    For coal-fired EGUs, the final rule regulates HCl as a surrogate 
for acid gas HAP, with an alternative equivalent standard for 
SO2 as a surrogate for acid gas HAP for coal-fired EGUs with 
FGD systems installed and operational; filterable PM as a surrogate for 
non-mercury HAP metals, with total non-mercury HAP metals and 
individual non-mercury HAP metals as alternative equivalent standards; 
Hg; and organic HAP. For oil-fired EGUs, the final rule regulates HCl 
and HF; filterable PM as a surrogate for total HAP metals, with 
individual HAP metals as alternative equivalent standards; and organic 
HAP. The filterable PM, HCl, and Hg limits that we are proposing to 
revise are provided in table 1; the alternate limits that we are 
proposing to revise are provided in table 2. We are soliciting comment 
on the revised new source emission limits proposed in this action.\6\
---------------------------------------------------------------------------

    \6\ Tables 1 and 2 in this preamble set forth the new source 
limits the Agency is proposing to revise. However, to comply with 
Federal Register guidelines, ``Table 1 to Subpart UUUUU of Part 63--
Emission Limits for New or Reconstructed EGUs'' in the regulatory 
text includes all of the new source limits, including the limits 
that are not proposed to be revised and are not part of this 
reconsideration action. The EPA is only accepting comments on the 
new source limits that are set forth in tables 1 and 2 of this 
preamble, which are the limits that are the subject of this 
reconsideration action.

[[Page 71329]]

                               Table 1--Proposed Emission Limitations for New EGUs
----------------------------------------------------------------------------------------------------------------
                                Filterable particulate
         Subcategory                    matter                 Hydrogen chloride                Mercury
----------------------------------------------------------------------------------------------------------------
New--Unit not designed for    9.0E-2 lb/MWh.............  1.0E-2 lb/MWh \a\.........  3.0E-3 lb/GWh.
 low rank virgin coal.
New--Unit designed for low    9.0E-2 lb/MWh.............  1.0E-2 lb/MWh \a\.........  NR.
 rank virgin coal.
New--IGCC...................  7.0E-2 lb/MWh \b\.........  2.0E-3 lb/MWh \d\.........  3.0E-3 lb/GWh.\e\
                              9.0E-2 lb/MWh \c\.........
New--Solid oil-derived......  3.0E-2 lb/MWh.............  NR........................  NR.
New--Liquid oil--continental  4.0E-1 lb/MWh.............  NR........................  NR.
----------------------------------------------------------------------------------------------------------------
Note: lb/MWh = pounds pollutant per megawatt-hour electric output (gross).
lb/GWh = pounds pollutant per gigawatt-hour electric output (gross).
NR = limit not revised.
\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.
\d\ Based on best-performing similar source.
\e\ Based on permit levels in comments received.

                      Table 2--Proposed Revised Alternate Emission Limitations for New EGUs
----------------------------------------------------------------------------------------------------------------
        Subcategory/pollutant              Coal-fired EGUs              IGCC \a\            Solid oil-derived
----------------------------------------------------------------------------------------------------------------
SO2..................................  1.0 lb/MWh.............  4.0E-1 lb/MWh \b\......  1.0 lb/MWh.
Total non-mercury metals.............  NR.....................  4.0E-1 lb/GWh..........  NR.
Antimony, Sb.........................  NR.....................  2.0E-2 lb/GWh..........  NR.
Arsenic, As..........................  NR.....................  2.0E-2 lb/GWh..........  NR.
Beryllium, Be........................  NR.....................  1.0E-3 lb/GWh..........  NR.
Cadmium, Cd..........................  NR.....................  2.0E-3 lb/GWh..........  NR.
Chromium, Cr.........................  NR.....................  4.0E-2 lb/GWh..........  NR.
Cobalt, Co...........................  NR.....................  4.0E-3 lb/GWh..........  NR.
Lead, Pb.............................  3.0E-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 revised.
\a\ Based on best-performing similar source unless otherwise noted.
\b\ Based on DOE information.

7. Control Technologies To Meet Proposed New Source Emission Limits
    We have evaluated the levels of control that would generally be 
needed to meet the proposed emission limits for new sources and have 
compared those to the levels of control needed to meet the new source 
emission limits in the final MATS rule. We compared the level of 
control needed by analyzing requirements for a new hypothetical 500 MW 
facility. The comparison led us to conclude that new EGUs would need to 
be designed to use the same types of emission control technologies to 
meet the proposed new source limits as would have been needed to meet 
the final MATS new source limits. More detailed discussion of this 
evaluation may be found in the memo ``MATS Reconsideration: Control 
Technology Needed to Meet New Source Limits'' contained in rulemaking 
docket EPA-HQ-OAR-2009-0234.
    Nothing in the statute requires the EPA to demonstrate that an 
existing source is able to meet all of the new source limits. 
Nevertheless, we note that based on our review of the data EPA 
collected as part of the 2010 ICR process, at least eight existing non-
low rank virgin coal-fired EGUs and one low rank virgin coal-fired EGU 
have reported short-term stack test data that demonstrate that these 
EGUs have in practice achieved the new source limits proposed in this 
notice (considering all of their submitted data). Furthermore, for HCl 
(as well as the SO2 surrogate) and filterable PM, the new 
source limits proposed in this notice are consistent with those in 
several permits for EGUs that have not yet commenced construction. For 
Hg, the new source limits proposed in this notice are consistent with 
the levels that a number of control vendors have suggested in their 
petitions for reconsideration are achievable and capable of being 
measured with an appropriate level of accuracy.
8. Filterable PM Monitoring
    We provided several monitoring options for the filterable PM 
standard in the final rule, including quarterly stack testing, PM CEMS, 
and PM continuous parameter monitoring system (PM CPMS) with annual 
testing. For many reasons, including continued use of already-installed 
instruments on some EGUs, direct (as opposed to parametric) measurement 
of the pollutant of concern, and continuous feedback for process 
control, we believe that many EGU owners or operators will choose to 
use PM CEMS to monitor the proposed filterable PM limit.
    We solicit comment on whether to retain the quarterly stack testing 
compliance option, as this option may not be necessary because 
continuous, direct measurement of filterable PM or a correlated 
parameter is available and likely to be used by most sources to monitor 
compliance with the revised standard.
    With respect to the PM CPMS compliance option for new EGUs, we 
considered three approaches to establish an operating limit based on 
emissions testing. The first approach would allow an EGU owner or 
operator to use the highest parameter value obtained during an 
individual emissions test when the result of that individual test was 
below the limit as the operating limit. The

[[Page 71330]]

second approach would allow an EGU owner or operator to use the average 
parameter value obtained from all runs pertaining to an individual 
emissions test as the operating limit. The third approach would allow 
an EGU owner or operator whose PM emissions as demonstrated during 
performance testing do not exceed 75 percent of the PM emissions limit 
to set his PM CPMS operating limit by linearly scaling the average 
operating value obtained during all the runs to be equivalent to the 
value at 75 percent of the limit; an EGU owner or operator whose PM 
emissions as demonstrated during performance testing exceed 75 percent 
of the PM emissions limit would establish his operating limit as a 30-
day rolling average equal to the average PM CPMS values recorded during 
performance testing. Such an approach would prevent unnecessary retests 
for EGUs with low PM emissions. See ``75 Percent CPMS Operating Limit 
Approach--MATS Reconsideration'' in rulemaking docket EPA-HQ-OAR-2009-
0234.
    Even though this rule proposes the first approach, we solicit 
comments on the appropriateness of any of the three approaches to 
establish a PM CPMS operating limit for new EGUs.
    In addition, this rule proposes to require emissions testing after 
each exceedance of the operating limit for new sources. This rule 
proposes a number of consequences if the PM monitoring parameter is 
exceeded. First, the EGU owner or operator will have 48 hours to 
conduct an inspection of the control device(s) and to take action to 
restore the controls to proper operation, if necessary, and 45 days to 
conduct a Method 5 compliance test under the same operating conditions 
to verify ongoing compliance with the filterable PM limit. Within 60 
days, the EGU owner or operator will have to complete the emissions 
sampling, sample analyses, and verification that the EGU is in 
compliance with its emissions limit, as well as having to determine an 
operating limit based on the PM CPMS data collected during the 
performance test. The EGU owner or operator would then compare the 
recalculated operating limit with the existing operating limit and, as 
appropriate, adjust the numerical operating limit to reflect compliance 
performance. Adjustments could include applying the most recently 
established value or combining the data collected over multiple 
performance tests to establish a more representative value. The EGU 
owner or operator would then apply the reverified or adjusted operating 
limit value from that time forward.
    Second, this rule proposes to limit the number of exceedances of 
the site-specific CPMS limit leading to follow-up performance tests in 
any 12 month process operating period and that an excess of this number 
be considered a violation of the standard. This presumption of 
violation could be rebutted by the EGU owner or operator, but would 
require more than a Method 5 test as a basis for the rebuttal (e.g., 
results of physical inspections would also need to be included). This 
additional information is necessary since a Method 5 test could not be 
conducted during or immediately following the discovery of exceedances 
and would not necessarily represent conditions identical to those when 
the exceedances occurred. The basis for this part of the proposal is 
that the site-specific CPMS operating limit reflects a 30-day average 
that should represent an actual emissions level lower than the three 
test run numerical emissions limit since variability is mitigated over 
time. Consequently, we believe that there should be few, if any, 
exceedances from the 30-day parametric limit and there is a reasonable 
basis for presuming that exceedances that lead to multiple performance 
tests to represent poor control device performance and to be a 
violation of the standard. Therefore, this rule proposes that PM CPMS 
exceedances leading to more than four required performance tests in a 
12-month process operating period is presumed to be a violation of this 
standard, subject to an EGU owner or operator's ability to rebut that 
presumption about process and control device operations in addition to 
the Method 5 performance test results. We solicit comment on this 
proposed revised approach.

B. Eligibility To Be a New Source

    The CAA section 112(a)(4) defines a new source as a stationary 
source ``the construction or reconstruction of which is commenced after 
the Administrator first proposes regulations under this section 
establishing an emissions standard applicable to such source.'' The EPA 
views the new source trigger date (the date EPA ``first proposes 
regulations'') to be the date EPA first proposes standards under a 
particular rulemaking record. (74 FR 21158). In this case, EPA first 
proposed standards for EGUs on May 3, 2011, and although we are 
proposing revisions to certain new source standards, the rulemaking 
record remains the same. As such, we are not proposing to revise the 
trigger date for determining whether a source is a new source. Any 
source which commenced construction or reconstruction after May 3, 2011 
is subject to the new source standards.\7\
---------------------------------------------------------------------------

    \7\ We are unaware of any new source that has commenced 
construction or reconstruction since May 3, 2011.
---------------------------------------------------------------------------

    Furthermore, it is the EPA's technical judgment that new sources 
would need to adopt the same or similar emissions control strategies 
under the amended standards as they would have under the promulgated 
standards. The revised standards remain stringent and can be met, in 
our view, using the same or similar control strategies as would have 
been required to meet the standards in the final rule.

C. Startup and Shutdown Provisions

    The EPA received petitions asserting that the public lacked an 
opportunity to comment on the startup and shutdown provisions in the 
final MATS. Petitioners also assert that the definitions of ``startup'' 
and ``shutdown'' in the final MATS and the provisions for work practice 
standards did not adequately address applicability to certain types of 
units, fuels considered ``clean,'' and operational limitations for 
certain EGU types and/or pollution control devices.
    We proposed numerical standards for startup and shutdown periods, 
and in response to comments on the proposed rule we changed those 
standards in the final MATS to work practice standards. Among other 
things, the work practice standards required sources to combust clean 
fuels during startup and shutdown periods and required sources to 
engage APCDs when coal or oil was fired in the EGU. (See 77 FR 9380-
83). We also revised the definitions of ``startup'' and ``shutdown'' 
after considering comments we received. Although we revised these 
provisions in response to comments, we are granting reconsideration on 
this issue to provide an opportunity for comment on the final startup 
and shutdown standards and those we have revised and propose today. For 
further discussion of petitioners' concerns and these proposed 
revisions, please refer to the memo ``Startup and shutdown provisions'' 
in rulemaking docket EPA-HQ-OAR-2009-0234. Below we summarize the 
startup and shutdown revisions proposed today.
1. Definitions
    We are proposing to revise the definitions of startup and shutdown 
in this reconsideration notice as set forth in 40 CFR 63.10042. 
Petitioners asserted that the final rule's definitions of startup and 
shutdown were not sufficiently clear, should accommodate operation of

[[Page 71331]]

cogeneration units, and did not accurately reflect startup conditions 
for all affected units, particularly supercritical units. We have 
clarified the definitions and added provisions including useful thermal 
energy.\8\ We believe that these changes address petitioners' concerns. 
For more discussion, please refer to the memo ``Startup and shutdown 
provisions'' in rulemaking docket EPA-HQ-OAR-2009-0234.
---------------------------------------------------------------------------

    \8\ 16 U.S.C. 796(18)(A) and 18 CFR 292.202(c).
---------------------------------------------------------------------------

2. Work Practice Standards
    We are proposing several revisions to the finalized work practice 
standards. Petitioners asserted that the final rule's work practice 
standards should include certain additional fuels as ``clean fuels'' 
and recognize operating limitations of certain EGU types and APCDs. 
Specifically, petitioners contend that the list of clean fuels required 
for use during startup in order to minimize emissions should include 
synthetic natural gas, syngas, and ultra-low sulfur diesel (ULSD). The 
EPA has also been informed since the final rule that propane is used to 
startup some EGUs and has been requested to consider it as a clean 
fuel. Petitioners additionally contend that the standards need to 
recognize operating conditions for FBC EGUs that inject limestone for 
acid gas control, selective non-catalytic reduction systems (SNCRs), 
selective catalytic reduction systems (SCRs), and other systems.
    In this reconsideration notice, we are proposing to add certain 
synthetic natural gas, syngas, propane, and ULSD to the list of clean 
fuels. We solicit comment on our understanding of clean fuels for 
startup and shutdown.
    We are also proposing to require EGU source owners and operators, 
when firing coal, solid oil-derived fuel, or residual oil in the EGU 
during startup or shutdown, to vent emissions to the main stack(s) and 
operate all control devices necessary to meet the operating standards 
that apply at all other times under the final rule (with the exception 
of limestone injection in FBC EGUs, dry scrubbers, SNCRs, and SCRs). 
Owners and operators of EGUs are responsible for starting limestone 
injection in FBC EGUs, dry scrubbers, SNCRs, and SCRs as expeditiously 
as possible, but, in any case, when necessary to comply with other 
standards applicable to the source that require operation of those 
control devices.
    Additionally, we are proposing to revise the final rule's work 
practice requirements to recognize constraints of certain EGUs and 
APCDs. The proposed revised standards allow limestone injection to 
start after appropriate temperatures have been attained in FBC EGUs 
that inject limestone for acid gas control and allow SNCR, SCR, and dry 
scrubber systems to start as soon as technically feasible after the 
appropriate temperature has been reached.
    For more discussion of each of these issues, please refer to the 
memo ``Startup and shutdown provisions'' in rulemaking docket EPA-HQ-
OAR-2009-0234.
3. Treatment of IGCC EGU Syngas
    The EPA understands that at an IGCC EGU, syngas is generated in the 
gasifier and combusted in the turbine. During the startup and shutdown 
periods, some or all of the syngas produced may not be combusted in the 
turbine. We are proposing two options for IGCC EGUs for handling syngas 
not fired in the combustion turbine: (1) syngas must be flared, not 
vented or (2) syngas must be routed to duct burners, which may need to 
be installed, and the flue gas from the duct burners must be routed to 
the heat recovery steam generator. We are soliciting comments on the 
need to flare the unfired syngas, if it is more appropriate to require 
routing of the unfired syngas back into the system for all IGCC EGUs, 
and on the costs of adding duct burners, should they be required.
    We solicit comments on the proposed revisions to the startup and 
shutdown requirements set forth in this notice.

V. Discussion of Provisions Subject To Reconsideration--Utility NSPS

    Petitioners state that because the final Utility NSPS rule contains 
a definition of ``natural gas'' that was not included in the proposed 
rule, they were not able to comment on the definition. Further, 
petitioners maintain that the definition established in the final rule 
is not a ``logical outgrowth'' of the proposed rule. Although the 
definition was changed between proposal and final based on public 
comment, we are re-proposing the definition of natural gas that was in 
the final Utility NSPS to allow additional opportunity to comment.
    We are also proposing several additional amendments so that 
synthetic natural gas will receive similar treatment as natural gas. We 
seek comment on all aspects of these additional amendments. First, 
consistent with the NESHAP definition, we are proposing to clarify the 
definition of coal to include synthetic natural gas derived from coal. 
As such, we are also proposing to add synthetic natural gas to the 
opacity exemption in paragraph 40 CFR 60.42Da(b)(2) since facilities 
burning synthetic natural gas would otherwise be subject to an opacity 
standard. In addition, we are also proposing to replace ``natural gas'' 
with ``gaseous fuels'' in 40 CFR 60.49Da(b) so facilities burning 
desulfurized coal-derived synthetic natural gas are not required to 
install an SO2 CEMS. The proposed amendments to the startup 
and shutdown requirements in the NESHAP portion of this proposal would 
also allow the use of synthetic natural gas for the work practice 
standards required for PM emissions control during periods of startup 
and shutdown.
    Additional proposed amendments include amending the definition of 
an IGCC to be similar to the corresponding NESHAP MATS definition. 
Potential language is as follows:

    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 burns a 
synthetic gas derived from coal and/or solid oil-derived fuel for 
more than 10.0 percent of the average annual heat input during any 3 
consecutive calendar years or for more than 15.0 percent of the 
annual heat input during any one calendar year in a combined-cycle 
gas turbine. No solid coal or solid oil-derived fuel is directly 
burned in the unit during operation.

    We believe that this would address the issue of IGCC facilities 
switching applicability between the stationary combustion turbine NSPS 
(40 CFR part 60, subpart KKKK) and the Utility NSPS. However, we are 
specifically requesting comment if it would be more appropriate to 
maintain the existing NSPS IGCC definition and add ``startup and 
commissioning, shutdown'' as suggested by one petitioner. Potential 
language for the alternate definition is as follows:

    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.

    In addition, the rationale for the filterable PM standard startup 
and shutdown work practice provision discussed in the NESHAP portion of 
this notice also applies to the filterable PM startup and shutdown 
standards in the Utility NSPS. Therefore, we are proposing to amend 
both the emissions

[[Page 71332]]

rate calculation procedure and monitoring requirements for PM to be 
similar to the requirements specified in the NESHAP for new facilities. 
Owners/operators of EGUs subject to the Utility NSPS would calculate 
the filterable PM emissions rate as the average of the measured hourly 
rates during the applicable averaging period (instead of as the sum of 
the emissions divided by the sum of the output over the applicable 
averaging period) and would use either a PM CEMS, PM CPMS, or quarterly 
performance testing to demonstrate compliance with the applicable 
standard.\9\
---------------------------------------------------------------------------

    \9\ As discussed in the final Utility NSPS Response to Comments 
document, because the amended NOX and SO2 
standards used CEMS data and included all periods of operation when 
establishing the numerical values for those standards, we are not 
proposing to amend how periods of startup and shutdown are handled 
or how the emission rates are calculated for the Utility NSPS 
NOX and SO2 standards. See docket entry EPA-
HQ-OAR-2011-0044-5759, p. 7.
---------------------------------------------------------------------------

    Finally, we are proposing to clarify that owners/operators electing 
to use PM CPMS to monitor PM emissions are exempt from the requirement 
to install a continuous opacity monitoring system (COMS) and would be 
allowed to elect to use alternate opacity monitoring procedures 
currently allowed in the Utility NSPS.

VI. Technical Corrections and Clarifications

    On April 19, 2012 (77 FR 23399), we issued a technical corrections 
notice addressing certain corrections to the February 16, 2012 (77 FR 
9304) MATS.
    In this notice, we are proposing several additional technical 
corrections. These amendments are being proposed to correct 
inaccuracies and other inadvertent errors in the final rule and to make 
the rule language consistent with provisions addressed through this 
reconsideration. We are soliciting comment only on whether the proposed 
changes provide the intended accuracy, clarity and consistency. These 
proposed technical changes are described in tables 3 and 4 of this 
preamble. We request comment on all of these proposed changes.

Table 3--Miscellaneous Proposed Technical Corrections to 40 CFR Part 60,
                               Subpart Da
------------------------------------------------------------------------
    Section of subpart Da          Description of proposed 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 Proposed Technical Corrections to 40 CFR Part 63,
                              Subpart UUUUU
------------------------------------------------------------------------
   Section of subpart UUUUU        Description of proposed 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 and
 (i)(5) and add                 measurement of fuel moisture content.
 63.10005(i)(6).
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 63.10011(g)...........  Clarify the language to use the word
                                ``and'' instead of ``or'' between the
                                words ``startup'' and ``shutdown.''
                               Clarify the language to use the word
                                ``or'' instead of ``and'' between the
                                words ``oil-fired'' and ``solid.''
40 CFR 63.10030(b), (c), and   Clarify the affected-source language.
 (d).
                               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......  Revise the definition of ``boiler
                                operating day'' to clarify that periods
                                of startup or shutdown are not included.
                               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    Correct the typographical error in
 Part 63.                       footnote 4 by replacing the erroneous
                                ``>='' with the correct ``<=.''
Table 7 to Subpart UUUUU of    Clarify the applicability of the
 Part 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.
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  Correct the typographical error by
 to 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  Correct the typographical error by
 B to Subpart UUUUU of Part     replacing the erroneous ``>='' with the
 63.                            correct ``<=.''
Section 5.3.4 to Appendix B    Correct the section number from the
 to Subpart UUUUU of Part 63.   incorrect ``5.3.4'' to the correct
                                ``5.3.3.''
------------------------------------------------------------------------

[[Page 71333]]

VII. Impacts of This Proposed Rule

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 rule will 
result in no significant change in costs, emission reductions, or 
benefits.\10\ Even if there were changes in costs for these units, 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, which is dominated by actions taken by existing units. Further, 
as noted elsewhere in this preamble, we believe that EGUs would put on 
the same controls for this proposed rule that they would have for the 
original final, so there should not be any incremental costs related to 
this proposed 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 the memo ``Economic Impact Analysis for the 
Proposed 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.
---------------------------------------------------------------------------

A. What are the air impacts?

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

B. What are the energy impacts?

    This proposed rule 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 standards.

C. What are the compliance costs?

    We believe there will be no significant change in compliance costs 
as a result of this proposed rule because electric power companies 
would install the same or similar control technologies as they would 
have installed to comply with the previously finalized standards. 
Moreover, we find no additional monitoring costs are necessary to 
comply with the proposed rule; however, as in any other rule, EGU 
owners or operators may choose to conduct additional monitoring (and 
incur its expense) for their own purposes.

D. 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 proposed in 
this action as they would have chosen to comply with the previously 
finalized standards, we do not anticipate that this proposed rule will 
result in significant changes in emissions, energy impacts, costs, 
benefits, or economic impacts. Likewise, we believe this rule will not 
have any impacts on the price of electricity, employment or labor 
markets, or the U.S. economy.

E. What are the benefits of the proposed standards?

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

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 (E.O.) 12866 (58 FR 51735, October 4, 1993), 
this action is a ``significant regulatory action'' because it ``raises 
novel legal or policy issues arising out of legal mandates.'' 
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 Proposed 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 standard, we project that this rule 
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 notice of reconsideration 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 77FR 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 notice of 
reconsideration 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.

[[Page 71334]]

    After considering the economic impacts of today's notice of 
reconsideration 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 notice of reconsideration 
imposes no additional regulatory requirements on owners or operators of 
affected sources. We have therefore concluded that today's notice of 
reconsideration will not result in a significant economic impact on a 
substantial number of small entities. We continue to be interested in 
the potential impacts of the rule on small entities and welcome 
comments on issues related to such impacts.

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.
    In the spirit of EO 13132, and consistent with EPA policy to 
promote communications between EPA and state and local governments, EPA 
specifically solicits comment on this notice of reconsideration from 
state and local officials.

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

    This action does not have tribal implications. It will not have 
substantial direct effects on tribal governments, on the relationship 
between the Federal government and Indian tribes, or on the 
distribution of power and responsibilities between the Federal 
government and Indian tribes, as specified in EO 13175. No affected 
facilities are owned or operated by Indian tribal governments. Thus, EO 
13175 does not apply to today's notice of reconsideration. The EPA 
specifically solicits comment on this notice of reconsideration from 
tribal officials.

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 Mercury and Air Toxics Standards 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.
    The public is invited to submit comments or identify peer-reviewed 
studies and data that assess effects of early life exposure to 
hazardous air pollutants.

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 notice of reconsideration 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 rule, 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 rule (77 FR 9441; February 16, 2012). Today's 
notice of reconsideration does not propose the use of any additional 
technical standards beyond those cited in the final rule. Therefore, 
EPA is not considering the use of any additional voluntary consensus 
standards for this notice.
    The EPA welcomes comments on this aspect of this notice of 
reconsideration and, specifically, invites the public to identify 
potentially-applicable voluntary consensus standards and to explain why 
such standards should be used in this regulation.

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

    Executive Order 12898 (59 FR 7629 (Feb. 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 notice of reconsideration 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 rule 
will result in no significant change in emission reductions.

[[Page 71335]]

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: November 16, 2012.
Lisa P. Jackson,
Administrator.

    For the reasons discussed in the preamble, the EPA proposes to 
amend 40 CFR parts 60 and 63 to read as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

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

0
2. 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 burns a synthetic 
natural gas derived from coal and/or solid oil-derived fuel for more 
than 10.0 percent of the average annual heat input during any 3 
consecutive calendar years or for more than 15.0 percent of the annual 
heat input during any one calendar year in a combined-cycle gas 
turbine. No solid coal or solid oil-derived fuel is directly burned in 
the unit during operation.
* * * * *
    Natural gas means a fluid mixture of hydrocarbons (e.g., methane, 
ethane, or propane), composed of at least 70 percent methane by volume 
or that has a gross calorific value between 35 and 41 megajoules (MJ) 
per dry standard cubic meter (950 and 1,100 Btu per dry standard cubic 
foot), that maintains a gaseous state under ISO conditions. In 
addition, natural gas contains 20.0 grains or less of total sulfur per 
100 standard cubic feet. Finally, natural gas does not include the 
following gaseous fuels: landfill gas, digester gas, refinery gas, sour 
gas, blast furnace gas, coal-derived gas, producer gas, coke oven gas, 
or any gaseous fuel produced in a process which might result in highly 
variable sulfur content or heating value.
* * * * *

0
3. Amend Sec.  60.42Da by revising paragraphs (a), (b)(2), (e)(1) 
introductory text, and (e)(1)(ii) 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 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.
* * * * *
    (ii) For an affected facility which commenced modification, any 
gases that contain PM in excess of the emission limits specified in 
paragraphs (c) or (d) of this section.
* * * * *

0
4. Amend Sec.  60.48Da by revising paragraphs (a), (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.

    (a) For affected facilities for which construction, modification, 
or reconstruction commenced before May 4, 2011, the applicable PM 
emissions limit and opacity standard under Sec.  60.42Da, 
SO2 emissions limit under Sec.  60.43Da, and NOX 
emissions limit under Sec.  60.44Da apply at all times except during 
periods of startup, shutdown, or malfunction. For affected facilities 
for which construction, modification, or reconstruction commenced after 
May 3, 2011, the applicable SO2 emissions limit under Sec.  
60.43Da, NOX emissions limit under Sec.  60.44Da, and 
NOX plus CO emissions limit under Sec.  60.45Da apply at all 
times. The applicable PM emissions limit and opacity standard under 
Sec.  60.42Da apply at all times except during periods of startup and 
shutdown; however, you are required to meet the work practice 
requirements as specified in 60.42Da(e)(2) of this subpart during 
periods of startup and shutdown.
* * * * *
    (f) For affected facilities for which construction, modification, 
or reconstruction commenced before May 4, 2011, compliance with the 
applicable daily average PM emissions limit is determined by 
calculating the arithmetic average of all hourly emission rates each 
boiler operating day, except for data obtained during startup, 
shutdown, or malfunction periods. Daily averages are only calculated 
for boiler operating days that have non-out-of-control data for at 
least 18 hours of unit operation during which the standard applies. 
Instead, all of the non-out-of-control hourly emission rates of the 
operating day(s) not meeting the minimum 18 hours non-out-of-control 
data daily average requirement are averaged with all of the non-out-of-
control hourly emission rates of the next boiler operating day with 18 
hours or more of non-out-of-control PM CEMS data to determine 
compliance. For affected facilities for which construction, 
modification, or reconstruction commenced after May 3, 2011, compliance 
with the applicable 30-boiler operating day rolling average PM 
emissions limit is determined 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 shall demonstrate

[[Page 71336]]

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 and (a)(2);
0
b. Adding paragraphs (a)(2)(v) and (a)(3)(iv); and
0
c. Revising paragraphs (a)(4) introductory text, (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 shall 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.
* * * * *
    (2) As an alternative to the monitoring requirements in paragraph 
(a)(1) of this section, an owner or operator of an affected facility 
that meets the conditions in either paragraph (a)(2)(i), (ii), (iii), 
(iv), or (v) of this section may elect to monitor opacity as specified 
in paragraph (a)(3) of this section.
* * * * *
    (v) 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.
* * * * *
    (3) * * *
    (iv) If the maximum 6-minute opacity is less than 10 percent during 
the most recent Method 9 of appendix A-4 of this part performance test, 
the owner or operator may, as an alternative to performing subsequent 
Method 9 of appendix A-4 performance tests, elect to perform subsequent 
monitoring using a digital opacity compliance system according to a 
site-specific monitoring plan approved by the Administrator. The 
observations shall 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 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 exceedances with the excess emissions report 
required under Sec.  60.51Da(d).
* * * * *
    (b) The owner or operator of an affected facility shall 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 
shall either install, certify, operate, and maintain a CEMS for 
measuring PM emissions according to the requirements of paragraph (v) 
of this section, 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, or conduct quarterly testing 
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

[[Page 71337]]

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 paragraph (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 
turbines that does not meet the definition of an IGCC shall 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, or if you commence reconstruction after May 
3, 2011.
* * * * *

0
9. In Sec.  63.10005, revise paragraphs (d)(2)(ii), (i)(4)(ii), and 
(i)(5) and add paragraph (i)(6) to read as follows:

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

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

0
10. 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-, and coal-fired EGUs and IGCC EGUs, you must conduct 
all applicable periodic emissions tests for filterable PM, or 
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
11. 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 to comply with the filterable PM emission limit 
and demonstrate continuous performance using a PM CPMS for an 
applicable emission limit 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
12. 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] TR30NO12.001

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,

[[Page 71338]]

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] TR30NO12.002

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] TR30NO12.003

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] TR30NO12.004

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
13. 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
14. In Sec.  63.10011, revise paragraphs (f) and (g) to read as 
follows:

Sec.  63.10011  How do I demonstrate initial compliance with the 
emissions limits and work practice standards?

* * * * *
    (f) You must use during periods of startup or shutdown any one or 
combination of the following clean fuels: natural gas, synthetic 
natural gas, propane, distillate oil, synthesis gas (syngas), and 
ultra-low sulfur diesel (ULSD).
    (g) You must follow the startup and shutdown requirements in Table 
3 for each coal-fired, liquid oil-fired, or solid oil-derived fuel-
fired EGU.

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);

[[Page 71339]]

    (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 from 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 based on the 
highest 1-hour average PM CPMS output value recorded during the 
performance test.
* * * * *

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 
60 days before the performance test is scheduled to begin.
* * * * *

0
18. Amend Sec.  63.10042 by:
0
a. Revising the definitions of ``Boiler operating day,'' ``Shutdown'', 
``Startup'', and ``Unit designed for coal > 8,300 Btu/lb subcategory''; 
and
0
b. Adding, in alphabetical order, a new definition of ``Clean fuel''.
    The revised and added text reads as follows:

Sec.  63.10042  What definitions apply to this subpart?

* * * * *
    Boiler operating day means a 24-hour period that begins at midnight 
and ends the following midnight during which any fuel is combusted at 
any time in the EGU, excluding periods of startup or shutdown. It is 
not necessary for the fuel to be combusted the entire 24-hour period.
* * * * *
    Clean fuel means natural gas, synthetic natural gas that meets the 
specification necessary for that gas to be transported on a Federal 
Energy Regulatory Commission (FERC) regulated pipeline, propane, 
distillate oil, synthesis gas (syngas), or ultra-low-sulfur diesel 
(ULSD).
* * * * *
    Shutdown means the period in which cessation of operation of an EGU 
is initiated for any purpose. Shutdown begins when the EGU no longer 
generates electricity or makes useful thermal energy (such as heat or 
steam) for industrial, commercial, heating, or cooling purposes or when 
no coal, liquid oil, syngas, or solid oil-derived fuel is being fired 
in the EGU, whichever is earlier. Shutdown ends when the EGU no longer 
generates electricity or makes useful thermal energy (such as steam or 
heat) for industrial, commercial, heating, or cooling purposes, and no 
fuel is being fired in the EGU.
    Startup means the period in which operation of an EGU is initiated 
for any purpose. Startup begins with either the first-ever firing of 
fuel in an EGU for the purpose of producing electricity or useful 
thermal energy (such as heat or steam) for industrial, commercial, 
heating, or cooling purposes or the firing of fuel in an EGU for any 
purpose after a shutdown event. Startup ends when the EGU generates 
electricity that is sold or used for any other purpose (including on 
site use), or the EGU makes useful thermal energy (such as heat or 
steam) for industrial, commercial, heating, or cooling purposes (16 
U.S.C. 796(18)(A) and 18 CFR 292.202(c)), whichever is earlier.
* * * * *
    Unit designed for coal = 8,300 Btu/lb subcategory means 
any coal-fired EGU that is not a coal-fired EGU in the ``unit designed 
for low rank virgin coal'' subcategory.
* * * * *

0
19. Revise Table 1 to Subpart UUUUU of Part 63 to read as follows:

Table 1 to Subpart UUUUU of Part 63--Emission Limits for New or 
Reconstructed EGUs

    As stated in Sec.  63.9991, you must comply with the following 
applicable emission limits:

----------------------------------------------------------------------------------------------------------------
                                                                                      Using these requirements,
                                                                You must meet the       as appropriate (e.g.,
 If your EGU is in this subcategory     For the following      following emission     specified sampling volume
               . . .                    pollutants . . .         limits and work      or test run duration) and
                                                             practice standards . .   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 dscm
 virgin coal.                         particulate matter                              per run.
                                      (PM).
                                     OR                      OR
                                     Total non-Hg HAP        6.0E-2 lb/GWh.........  Collect a minimum of 4 dscm
                                      metals.                                         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.

[[Page 71340]]

 
                                        Chromium (Cr)......  7.0E-3 lb/GWh.
                                        Cobalt (Co)........  2.0E-3 lb/GWh.
                                        Lead (Pb)..........  3.0E-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 a
                                      (HCl).                                          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 dscm
 coal.                                particulate matter                              per run.
                                      (PM).
                                     OR                      OR
                                     Total non-Hg HAP        6.0E-2 lb/GWh.........  Collect a minimum of 4 dscm
                                      metals.                                         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)..........  3.0E-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 a
                                      (HCl).                                          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 dscm
                                      particulate matter     9.0E-2 lb/MWh \5\.....   per run.
                                      (PM).
                                     OR                      OR
                                     Total non-Hg HAP        4.0E-1 lb/GWh.........  Collect a minimum of 1 dscm
                                      metals.                                         per run.
                                     OR                      OR
                                     Individual HAP metals:  ......................  Collect a minimum of 2 dscm
                                                                                      per run.
                                        Antimony (Sb)......  2.0E-2 lb/GWh.
                                        Arsenic (As).......  2.0E-2 lb/GWh.
                                        Beryllium (Be).....  1.0E-3 lb/GWh.
                                        Cadmium (Cd).......  2.0E-3 lb/GWh.
                                        Chromium (Cr)......  4.0E-2 lb/GWh.
                                        Cobalt (Co)........  4.0E-3 lb/GWh.
                                        Lead (Pb)..........  9.0E-3 lb/GWh.
                                        Manganese (Mn).....  2.0E-2 lb/GWh.
                                        Nickel (Ni)........  7.0E-2 lb/GWh.
                                        Selenium (Se)......  3.0E-1 lb/GWh.
                                     b. Hydrogen chloride    2.0E-3 lb/MWh.........  For Method 26A, collect a
                                      (HCl).                                          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--           a. Filterable           4.0E-1 lb/MWh \1\.....  Collect a minimum of 1 dscm
 continental (excluding limited-use   particulate matter     OR....................   per run.
 liquid oil-fired subcategory         (PM).                  2.0E-4 lb/MWh.........  Collect a minimum of 2 dscm
 units).                             OR....................  OR....................   per run.
                                     Total HAP metals......
                                     OR....................
                                     Individual HAP metals:  ......................  Collect a minimum of 2 dscm
                                                                                      per run.
                                        Antimony (Sb)......  1.0E-2 lb/GWh.

[[Page 71341]]

 
                                        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 a
                                      (HCl).                                          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 a
                                      (HF).                                           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 dscm
 continental (excluding limited-use   particulate matter     OR....................   per run.
 liquid oil-fired subcategory         (PM).                  7.0E-3 lb/MWh.........  Collect a minimum of 1 dscm
 units).                             OR....................  OR....................   per run.
                                     Total HAP metals......
                                     OR....................
                                     Individual HAP metals:  ......................  Collect a minimum of 3 dscm
                                                                                      per run.
                                        Antimony (Sb)......  8.0E-3 lb/GWh.
                                        Arsenic (As).......  6.0E-2 lb/GWh.
                                        Beryllium (Be).....  2.0E-3 lb/GWh.
                                        Cadmium (Cd).......  2.0E-3 lb/GWh.
                                        Chromium (Cr)......  2.0E-2 lb/GWh.
                                        Cobalt (Co)........  3.0E-1 lb/GWh.
                                        Lead (Pb)..........  3.0E-2 lb/GWh.
                                        Manganese (Mn).....  1.0E-1 lb/GWh.
                                        Nickel (Ni)........  4.1E0 lb/GWh.
                                        Selenium (Se)......  2.0E-2 lb/GWh.
                                     Mercury (Hg)..........  4.0E-4 lb/GWh.........  For Method 30B sample
                                                                                      volume determination
                                                                                      (Section 8.2.4), the
                                                                                      estimated Hg concentration
                                                                                      should nominally be <\1/2\
                                                                                      the standard.
                                     b. Hydrogen chloride    2.0E-3 lb/MWh.........  For Method 26A, collect a
                                      (HCl).                                          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 a
                                      (HF).                                           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      a. Filterable           3.0E-2 lb/MWh \1\.....  Collect a minimum of 1 dscm
 unit..                               particulate matter                              per run.
                                      (PM).
                                     OR                      OR
                                     Total non-Hg HAP        6.0E-1 lb/GWh.........  Collect a minimum of 1 dscm
                                      metals.                                         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 a
                                      (HCl).                                          minimum of 3 dscm per run.
                                                                                     For ASTM D6348-03 \2\ or
                                                                                      Method 320, sample for a
                                                                                      minimum of 1 hour.

[[Page 71342]]

 
                                     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 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 3 to Subpart UUUUU of Part 63 to read as follows:

Table 3 to Subpart UUUUU of Part 63 -- Work Practice Standards

    As stated in Sec. Sec.  63.9991, you must comply with the following 
applicable work practice standards:

----------------------------------------------------------------------------------------------------------------
          If your EGU is . . .                              You must meet the following . . .
----------------------------------------------------------------------------------------------------------------
1. An existing EGU.....................  Conduct a tune-up of the EGU burner and combustion controls at least
                                          each 36 calendar months, or each 48 calendar months if neural network
                                          combustion optimization software is employed, as specified in Sec.
                                          63.10021(e).
2. A new or reconstructed EGU..........  Conduct a tune-up of the EGU burner and combustion controls at least
                                          each 36 calendar months, or each 48 calendar months if neural network
                                          combustion optimization software is employed, as specified in Sec.
                                          63.10021(e).
3. A coal-fired, liquid oil-fired, or    You must operate all CMS during startup.
 solid oil-derived fuel-fired EGU        For startup of an EGU, you must use one or a combination of the
 during startup.                          following clean fuels: natural gas, synthetic natural gas, propane,
                                          distillate oil, syngas, and ultra-low sulfur diesel.
                                         Once you start firing coal, residual oil, or solid oil-derived fuel,
                                          you must vent emissions to the main stack(s) and engage all of the
                                          applicable control devices except limestone injection in FBC EGUs, dry
                                          scrubber, SNCR, and SCR. You must start your limestone injection in
                                          FBC EGUs, dry scrubber, SNCR, and SCR systems as expeditiously as
                                          possible, but, in any case, when necessary to comply with other
                                          standards applicable to the source that require operation of the
                                          control devices.
                                         Relative to the syngas not fired in the combustion turbine of an IGCC
                                          EGU during startup, you must either: (1) Flare the syngas or (2) route
                                          the syngas to duct burners, which may need to be installed, and route
                                          the flue gas from the duct burners to the heat recovery steam
                                          generator.
                                         You must comply with all applicable emission limits at all times except
                                          for startup or shutdown periods conforming with this work practice.
                                          You must collect monitoring data during periods of startup, as
                                          specified in Sec.   63.10020(a). You must keep records during periods
                                          of startup. You must provide reports concerning activities and periods
                                          of startup, as specified in Sec.   63.10011(g) and Sec.   63.10021(h)
                                          and (i).
4. A coal-fired, liquid oil-fired, or    You must operate all CMS during shutdown.
 solid oil-derived fuel-fired EGU        While firing coal, residual oil, or solid oil-derived fuel during
 during shutdown.                         shutdown, you must vent emissions to the main stack(s) and operate all
                                          applicable control devices, except limestone injection in FBC EGUs,
                                          dry scrubber, SNCR, and SCR. You must operate your limestone injection
                                          in FBC EGUs, dry scrubber, SNCR, and SCR systems as expeditiously as
                                          possible, but, in any case, when necessary to comply with other
                                          standards that apply to the source and that require operation of the
                                          control devices.
                                         If, in addition to the fuel used prior to initiation of shutdown,
                                          another fuel must be used to support the shutdown process, that
                                          additional fuel must be one or a combination of the following clean
                                          fuels: Natural gas, synthetic natural gas, propane, distillate oil,
                                          syngas, and ultra-low sulfur diesel.
                                         Relative to the syngas not fired in the combustion turbine of an IGCC
                                          EGU during shutdown, you must either: (1) Flare the syngas or (2)
                                          route the syngas to duct burners, which may need to be installed, and
                                          route the flue gas from the duct burners to the heat recovery steam
                                          generator.
                                         You must comply with all applicable emission limits at all times except
                                          during startup and shutdown periods at which time you must meet this
                                          work practice. You must collect monitoring data during periods of
                                          startup, as specified in Sec.   63.10020(a). You must keep records
                                          during periods of startup. You must provide reports concerning
                                          activities and periods of startup, as specified in Sec.   63.10011(g)
                                          and Sec.   63.10021(h) and (i).
----------------------------------------------------------------------------------------------------------------

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

Table 4 to Subpart UUUUU of Part 63--Operating Limits for EGUs

    As stated in Sec. Sec.  63.9991, you must comply with the 
applicable operating limits:

[[Page 71343]]

----------------------------------------------------------------------------------------------------------------
  If you demonstrate compliance using . . .               You must meet these operating limits . . .
----------------------------------------------------------------------------------------------------------------
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 at or below the highest 1-hour average PM CPMS output
                                               value recorded 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
22. 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
23. 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.
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 three run
                                                                                               performance test.
                                                                                              3. Determine the
                                                                                               highest 1-hour
                                                                                               average PM CPMS
                                                                                               measured during
                                                                                               the performance
                                                                                               run demonstrating
                                                                                               compliance with
                                                                                               the filterable PM
                                                                                               or HAP metals
                                                                                               emissions
                                                                                               limitations.
----------------------------------------------------------------------------------------------------------------

0
24. 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:

[[Page 71344]]

------------------------------------------------------------------------
If you use one of the following to meet
 applicable emissions limits, operating     You demonstrate continuous
 limits, or work practice standards . .        compliance by . . .
                   .
------------------------------------------------------------------------
1. CEMS to measure filterable PM, SO2,   Calculating the 30- (or 90-)
 HCl, HF, or Hg emissions, or using a     boiler operating day rolling
 sorbent trap monitoring system to        arithmetic average emissions
 measure Hg.                              rate in units of 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 with a  Calculating the arithmetic 30-
 parametric operating limit.              (or 90-) boiler operating day
                                          rolling 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 boiler operating
                                          days, excluding data recorded
                                          during periods of startup or
                                          shutdown.
3. Site-specific monitoring using CMS    If applicable, by conducting
 for liquid oil-fired EGUs for HCl and    the monitoring in accordance
 HF emission limit monitoring.            with an approved site-specific
                                          monitoring plan.
4. Quarterly performance testing for     Calculating the results of the
 coal-fired, solid oil derived fired,     testing in units of the
 or liquid oil-fired EGUs to measure      applicable emissions standard.
 compliance with one or more applicable
 emissions limit in Table 1 or 2.
5. Conducting periodic performance tune- Conducting periodic performance
 ups of your EGU(s).                      tune-ups of your EGU(s), as
                                          specified in Sec.
                                          63.10021(e).
6. Work practice standards for coal-     Operating in accordance with
 fired, liquid oil-fired, or solid oil-   Table 3.
 derived fuel-fired EGUs during startup.
7. Work practice standards for coal-     Operating in accordance with
 fired, liquid oil-fired, or solid oil-   Table 3.
 derived fuel-fired EGUs during
 shutdown.
------------------------------------------------------------------------

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 shall 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. 2012-28729 Filed 11-29-12; 8:45 am]
BILLING CODE 6560-50-P