[Federal Register Volume 76, Number 247 (Friday, December 23, 2011)]
[Proposed Rules]
[Pages 80532-80552]
[FR Doc No: 2011-31644]

Vol. 76

Friday,

No. 247

December 23, 2011

Part III

Environmental Protection Agency

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40 CFR Part 63

National Emission Standards for Hazardous Air Pollutants for Area
Sources: Industrial, Commercial, and Institutional Boilers; Proposed
Rule

Federal Register / Vol. 76 , No. 247 / Friday, December 23, 2011 /
Proposed Rules

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2006-0790; FRL-9503-3]
RIN 2060-AR14

National Emission Standards for Hazardous Air Pollutants for Area
Sources: Industrial, Commercial, and Institutional Boilers

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule; Reconsideration of final rule.

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SUMMARY: On March 21, 2011, the EPA promulgated national emission
standards for the control of hazardous air pollutants from two area
source categories: industrial boilers, and commercial and institutional
boilers. On that same date, the EPA announced that it was convening a
proceeding for reconsideration of certain portions of those final
emission standards. After promulgation, the Administrator received
petitions for reconsideration of certain provisions in the final rule.
In this action, the EPA is proposing for reconsideration specific
elements and accepting public comment on those elements. We are not
requesting comment on any other provisions of the final rule.
    In this action, the EPA is proposing a limited number of amendments
to the final rule. In addition, the EPA is proposing amendments and
technical corrections to the final rule to clarify some applicability
and implementation issues raised by stakeholders subject to the final
rule.

DATES: Comments. Comments must be received on or before February 21,
2012.
    Public Hearing. If anyone contacts the EPA requesting to speak at a
public hearing by January 3, 2012, a public hearing will be held on
January 9, 2012. For further information on the public hearing and
requests to speak, contact Ms. Pamela Garrett at<PHONE_NUMBER> to
verify that a hearing will be held. If a public hearing is held, it
will be held at 10 a.m. at the EPA's Environmental Research Center
Auditorium, Research Triangle Park, North Carolina, or an alternate
site nearby.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2006-0790, by one of the following methods:
     www.regulations.gov: Follow the on-line instructions for
submitting comments.
     Email<EMAIL_ADDRESS>Attention Docket ID No.
EPA-HQ-OAR-2006-0790.
     Fax:<PHONE_NUMBER>, Attention Docket ID No. EPA-HQ-OAR-
2006-0790.
     Mail: U.S. Postal Service, send comments to: Air and
Radiation Docket and Information Center, Environmental Protection
Agency, Mailcode: 2822T, 1200 Pennsylvania Ave. NW., Washington, DC
20460, Attention Docket ID No. EPA-HQ-OAR-2006-0790.
     Hand Delivery: In person or by Courier, deliver comments
to: EPA Docket Center (2822T), Room 3334, 1301 Constitution Ave. NW.,
Washington, DC 20004. Such deliveries are only accepted during the
Docket's normal hours of operation, and special arrangements should be
made for deliveries of boxed information.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2006-0790. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at 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 www.regulations.gov
or email. The 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
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. For additional information about the EPA's public
docket, visit the EPA Docket Center homepage at http://www.epa.gov/epahome/dockets.htm.
    Docket: All documents in the docket are listed in the
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.
Publicly available docket materials are available either electronically
in www.regulations.gov or in hard copy at the EPA Docket Center, EPA
West Building, Room 3334, 1301 Constitution Ave. NW., Washington, DC.
The Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holidays. The telephone number for the
Public Reading Room is<PHONE_NUMBER>, and the telephone number for the
Docket Center is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Mr. James Eddinger, Energy Strategies
Group (D243-01), Sector Policies and Programs Division, Office of Air
Quality Planning and Standards, Environmental Protection Agency,
Research Triangle Park, North Carolina 27711; telephone number: (919)
541-5426; fax number:<PHONE_NUMBER>; email address:
<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Organization of this Document. The following
outline is provided to aid in locating information in this preamble.

I. General Information
    A. Does this notice of reconsideration 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 Information
III. Actions We Are Taking
IV. Discussion of Issues for Reconsideration
    A. Subcategory for Seasonally Operated Boilers
    B. Exemption for Temporary Boilers
    C. Initial Compliance Schedule for Existing Boilers
    D. Definition of Natural Gas Curtailment
    E. Monitoring Carbon Monoxide Emissions
    F. Averaging Times
    G. Affirmative Defense Language
    H. Tune-up Work Practices
    I. Using the Upper Prediction Limit (UPL) for Setting Carbon
Monoxide Emission Limits
    J. Establishing GACT Emission Limits for Biomass and Oil-Fired
Boilers
    K. Energy Assessment
    L. Setting PM Standards Under Generally Available Control
Technology for Oil-Fired Area Source Boilers.
    M. Title V Permitting Requirements
V. Technical Corrections and Clarifications
    A. Electric and Residential Boilers
    B. Establishing Operating Limits for Wet Scrubbers.
    C. Timing of Subsequent Performance Tests
    D. Demonstrating Initial Compliance

    E. Demonstrating Compliance with the Work Practice and
Management Practice Standards
    F. Monitoring Requirements
    G. Notification, Recordkeeping, and Reporting Requirements
    H. Definitions
    I. Change to the Mercury Emission Limit for New Coal-Fired
Boilers.
    J. Changes to the Work Practice Standards, Emission Reduction
Measures, and Management Practices
    K. Requirements for Establishing Operating Limits
    L. Demonstrating Continuous Compliance
VI. What are the impacts associated with the amendments?
VII. 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 Concerning Regulations 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 notice of reconsideration apply to me?

    The regulated categories and entities potentially affected by this
action include:

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                                                   Examples of regulated
        Industry category           NAICS code\1\         entities
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Any area source facility using a              321  Wood product
 boiler as defined in the final                     manufacturing.
 rule.
                                               11  Agriculture,
                                                    greenhouses.
                                              311  Food manufacturing.
                                              327  Nonmetallic mineral
                                                    product
                                                    manufacturing.
                                              424  Wholesale trade,
                                                    nondurable goods.
                                              531  Real estate.
                                              611  Educational services.
                                              813  Religious, civic,
                                                    professional, and
                                                    similar
                                                    organizations.
                                               92  Public
                                                    administration.
                                              722  Food services and
                                                    drinking places.
                                               62  Health care and
                                                    social assistance.
                                            22111  Electric power
                                                    generation.
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\1\ North American Industry Classification System.

    This table is not intended to be exhaustive, but rather provides a
guide for readers regarding entities likely to be regulated by this
reconsideration action. To determine whether your facility may be
affected by this reconsideration action, you should examine the
applicability criteria in 40 CFR 63.11193 of subpart JJJJJJ (National
Emission Standards for Hazardous Air Pollutants for Industrial,
Commercial, and Institutional Boilers Area Sources). If you have any
questions regarding the applicability of the final rule to a particular
entity, consult either the air permit authority for the entity or your
EPA regional representative, as listed in 40 CFR 63.13.

B. What should I consider as I prepare my comments to the EPA?

    Submitting CBI. Do not submit information that you consider to be
CBI electronically through http://www.regulations.gov or Email. Send or
deliver information identified as CBI to only the following address:
Mr. James Eddinger, c/o OAQPS Document Control Officer (Room C404-02),
U.S. Environmental Protection Agency, Research Triangle Park, North
Carolina 27711, Attn: Docket ID No. EPA-HQ-OAR-2006-0790.
    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 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. If you submit a disk or CD-ROM that
does not contain CBI, mark the outside of the disk or CD-ROM clearly
that it does not contain CBI. Information marked as CBI will not be
disclosed except in accordance with procedures set forth in 40 CFR part
2.
    If you have any questions about CBI or the procedures for claiming
CBI, please consult the person identified in the FOR FURTHER
INFORMATION CONTACT section.

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

    Docket. The docket number for this action and the final rule (40
CFR part 63, subpart JJJJJJ) is Docket ID No. EPA-HQ-OAR-2006-0790.
    World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of this action is available on the WWW through the
Technology Transfer Network (TTN) Web site. Following signature, a copy
of this notice will be posted on the TTN's policy and guidance page for
newly proposed or promulgated rules at http://www.epa.gov/ttn/oarpg.
The TTN provides information and technology exchange in various areas
of air pollution control.

II. Background Information

    Section 112(d) of the Clean Air Act (CAA) requires the EPA to
establish national emission standards for hazardous air pollutants
(NESHAP) for both major and area sources of hazardous air pollutants
(HAP) that are listed for regulation under CAA section 112(c). A major
source is any stationary source that emits or has the potential to emit
10 tons per year (tpy) or more of any single HAP or 25 tpy or more of
any combination of HAP. An area source is a stationary source that is
not a major source.
    On March 21, 2011 (76 FR 15554), we issued the NESHAP for
industrial, commercial, and institutional area source boilers pursuant
to CAA sections 112(c)(3), 112(c)(6), and 112(k)(3)(B).
    CAA section 112(k)(3)(B) directs the EPA to identify at least 30
HAP that, as a result of emissions from area sources, pose the greatest
threat to public health in the largest number of urban areas. The EPA
implemented this provision in 1999 in the Integrated Urban Air Toxics
Strategy, (64 FR 38715, July 19, 1999) (Strategy). Specifically, in the
Strategy,

the EPA identified 30 HAP that pose the greatest potential health
threat in urban areas, and these HAP are referred to as the ``30 urban
HAP.'' Section 112(c)(3) of the CAA requires the EPA to list sufficient
categories or subcategories of area sources to ensure that area sources
representing 90 percent of the emissions of the 30 urban HAP are
subject to regulation. Under CAA section 112(d)(5), the EPA may elect
to promulgate standards or requirements for area sources ``which
provide for the use of generally available control technologies
(``GACT'') or management practices by such sources to reduce emissions
of hazardous air pollutants.''
    While GACT may be a basis for standards for most types of HAP
emitted from area sources, CAA section 112(c)(6) requires that the EPA
list categories and subcategories of sources assuring that sources
accounting for not less than 90 percent of the aggregate emissions of
each of seven specified HAP are subject to standards under CAA sections
112(d)(2) or (d)(4), which require the application of the more
stringent MACT. The seven HAP specified in CAA section 112(c)(6) are as
follows: Alkylated lead compounds, polycyclic organic matter (POM) as
7-polynuclear aromatic hydrocarbons (PAH), hexachlorobenzene, mercury,
polychlorinated biphenyls (PCBs), 2,3,7,8-tetrachlorodibenzofurans, and
2,3,7,8-tetrachlorodibenzo-p-dioxin.
    As noted in the preamble to the final rule, (76 FR 15556, March 21,
2011), we listed area source industrial boilers and commercial/
institutional boilers combusting coal under CAA section 112(c)(6) based
on the source categories' contribution of mercury and POM, and under
CAA section 112(c)(3) for their contribution of arsenic, beryllium,
cadmium, lead, chromium, manganese, nickel, ethylene dioxide, and PCBs,
as well as mercury and POM. We promulgated final standards for coal-
fired area source boilers to reflect the application of MACT for
mercury and POM, and to reflect GACT for the urban HAP other than
mercury and POM.
    We listed industrial and commercial/institutional boilers
combusting oil or biomass under CAA section 112(c)(3) for their
contribution of mercury, arsenic, beryllium, cadmium, lead, chromium,
manganese, nickel, POM, ethylene dioxide, and PCBs. For boilers firing
oil or biomass, the final standards reflect GACT for all of the urban
HAP.
    On March 21, 2011, we also published a notice to initiate the
reconsideration of certain aspects of the final rule for area source
industrial, commercial, and institutional boilers (76 FR 15266). In
that notice, we announced that we would identify specific elements of
this rule for which we believe further public comment is appropriate.
We also announced that we would develop proposals to modify certain
provisions after more fully evaluating the data and comments received
in response to the original proposed area source rule published on June
4, 2010 (75 FR 31896). Finally, we recognized that certain issues of
central relevance to these rules arose after the period for public
comment or may have been impracticable to comment upon. Therefore, we
concluded that reconsideration was appropriate under section
307(d)(7)(B) of the CAA. Although we took final action and promulgated
the area source boiler rule, and believe that the final rule reflects
reasonable approaches consistent with the requirements of the CAA, some
of the issues identified in the comments raised difficult technical
issues that we believe may benefit from additional public involvement.
    In the March 21, 2011, notice, we identified the following issues
affecting area source boilers as being appropriate and consistent with
the requirements of the Act, but for which we believe reconsideration
and additional opportunity for public review and comment should be
obtained:
     Establishment of standards for biomass and oil-fired area
source boilers based on generally available control technology.
     Providing an affirmative defense for malfunction events
for area source boilers.
    The following additional issues concern actions taken in the final
rule for which we believe reconsideration under section 307(d) and,
potentially, further revisions may be warranted because they involve
issues of central relevance that arose after the period for public
comment or may have been impracticable to comment upon:
     Setting PM standards under generally available control
technology for oil-fired area source boilers.
     Certain findings regarding the applicability of Title V
permitting requirements for area source boilers.
    Additional information concerning issues and concerns presented by
commenters can be found in Docket No. EPA-HQ-OAR-2006-0790 for the
final area source boiler rule under reconsideration in today's notice.

III. Actions We Are Taking

    In this notice, we are requesting comment on the four issues listed
in section II of this preamble, which were identified in the March 21,
2011 notice, and we are also convening reconsideration of, and
requesting comment on, certain issues raised by Petitioners in their
petitions for reconsideration. Section IV of this preamble summarizes
these issues and discusses our proposed responses to each issue.
    We are also proposing technical corrections to correct inaccuracies
and inadvertent oversights promulgated in the final rule. We are also
proposing several amendments to clarify some applicability and
implementation issues raised by stakeholders subject to the final rule.
Section V of this preamble describes these corrections and amendments
and provides the rationale for these corrections and amendments. These
proposed changes, if finalized, would for example:
     Clarify certain regulatory requirements, such as whether
compliance is based on a value calculated as a block average from
recorded data.
     Provide greater flexibility to certain facilities for
which the current compliance requirements are impractical, such as
increasing the time between tune-ups for seasonally operated boilers.
     Correct certain rule drafting or printing errors, such as
correcting cross references among rule sections, removing paragraphs
that are no longer relevant, or correcting the placement of text in a
table.
    We are seeking public comment only on the issues specifically
identified in this notice. We will not respond to any comments
addressing other aspects of the final rule or any other related
rulemakings.

IV. Discussion of Issues for Reconsideration

    This section of the preamble contains the EPA's basis for our
proposed responses to the issues identified in the petitions for
reconsideration. We solicit comment on all proposed responses and
revisions discussed in the following sections.

A. Subcategory for Seasonally Operated Boilers

    We are proposing to create a new subcategory for seasonally
operated boilers. For these seasonally operated boilers, we are
proposing to amend 40 CFR 63.11223 to specify, after an initial tune up
by the compliance date, they would be required to complete a tune-up
every five years, instead of on a biennial basis as is required for
non-seasonal boilers.
    Agriculture industry representatives, specifically those from the
sugar industry, noted that many boilers

operate only seasonally, and these boilers are generally not equipped
to measure carbon monoxide and oxygen. As a result, stack testing must
be performed to measure carbon monoxide and oxygen as a component of
the tune-up, as required by 40 CFR 63.11223(b)(5). The petitioners
requested that the EPA reconsider the frequency of tune-ups for
seasonal boilers. Specifically, the petitioners requested a reduction
in the required frequency of subsequent tune-ups to the lesser of every
24 months of operation or every six to eight years. The petitioners
commented that the final rule is more burdensome on industries with
short seasonal operations than non-seasonal industries. The seasonal
nature means that each boiler must undergo tune-ups every six or eight
months of operation. This, the petitioners commented, is far more
frequent than envisioned by the final rule.
    We agree with the industry representatives on this issue and are
proposing to address the issue by creating a subcategory for seasonal
boilers and amending 40 CFR 63.11223 to specify that seasonal boilers
would be required to complete the initial tune-up by March 21, 2014,
and a subsequent tune-up every five years after the initial tune-up.
    Seasonally operated boilers would be defined as follows:

    Seasonal boiler means a boiler that undergoes a shutdown for a
period of at least 7 consecutive months (or 210 consecutive days)
due to seasonal market conditions. This definition only applies to
boilers that would otherwise be included in the biomass subcategory
or the oil subcategory.

B. Exemption for Temporary Boilers

    We are proposing to amend 40 CFR 63.11195 (Are any boilers not
subject to this subpart?) by adding temporary boilers to the list of
boilers not subject to subpart JJJJJJ. In the final major source rule
for boilers, the EPA excluded temporary boilers from the source
category (see 40 CFR 63.7491(j), and 76 FR 15665 (March 21, 2011)), and
is now proposing to do the same in the area source rule. Owners and
operators of regulated sources have pointed out that temporary boilers
are small (less than 10 MMBtu/hr heat input) and are generally owned
and operated by contractors, rather than the facility. As a result,
they are not included in the facility's operating permits because state
and federal CAA operating permit programs have historically classified
such units as insignificant sources. The owners and operators also
noted that compliance with the work practice requirements applicable to
these small boilers would be complicated because they are typically
located on site for less than a year, but would be subject to biennial
management practice requirements.
    We agree that the source category identified in subpart JJJJJJ
should specifically exclude these temporary boilers because they have
been considered insignificant sources, and were not included in the
EPA's analysis of the source category. Therefore, we are proposing to
amend 40 CFR 63.11195 by adding temporary boilers to the list of
boilers not subject to subpart JJJJJJ.
    Temporary boilers would be defined in 40 CFR 63.11237 as:

``* * * any gaseous or liquid fuel boiler that is designed to, and
is capable of, being carried or moved from one location to another
by means of, for example, wheels, skids, carrying handles, dollies,
trailers, or platforms. A boiler is not a temporary boiler if any
one of the following conditions exists:
    (1) The equipment is attached to a foundation.
    (2) The boiler or a replacement remains at a location for more
than 12 consecutive months. Any temporary boiler that replaces a
temporary boiler at a location and performs the same or similar
function will be included in calculating the consecutive time
period.
    (3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
    (4) The equipment is moved from one location to another within
the facility in an attempt to circumvent the residence time
requirements of this definition.

C. Initial Compliance Schedule for Existing Boilers

    We are proposing to amend 40 CFR 63.11196 to specify that all
existing boilers subject to the tune-up requirement would have two
years (by March 21, 2013) in which to demonstrate initial compliance,
instead of one year to demonstrate initial compliance.
    Industry representatives, specifically those with large numbers of
affected boilers or seasonal boilers, note that many boilers are not
equipped to measure carbon monoxide and oxygen. As a result, stack
testing must be performed to measure carbon monoxide and oxygen as a
component of the tune-up, as required by 40 CFR 63.11223(b)(5). The
industry members have noted that they cannot schedule and complete the
testing needed to comply with the tune-up requirements during the one
year initial compliance period, as specified in the final rule. The
industry members also noted that the three-year initial compliance date
originally provided in the proposed rule would have allowed for the
staggering of the tune-ups over three years, while the final rule
requires initial tune-ups be completed in one year. Finally, industry
members and other stakeholders did not have an adequate opportunity to
comment on the one-year compliance period for the tune-up requirement.
    We agree with the industry representatives on this issue and are
proposing to address the issue by allowing two years to complete the
initial compliance demonstration of the tune-up requirements applicable
to existing boilers. Even though existing boilers that are subject to
emission limits have three years to demonstrate initial compliance, we
believe the proposed change to the tune-up initial compliance period is
appropriate because compliance with the tune-up requirement does not
involve the installation of control equipment. Providing the amended
compliance schedule would eliminate the potential need to approve
alternative compliance schedules for facilities with multiple boilers
or seasonal boilers that could not comply with the one-year compliance
requirement.
    We are specifically requesting comment on whether the initial
compliance period for the tune-up requirement should be extended to
three years.
    If the Agency has not taken final action on the initial compliance
date for tune-ups prior to the date (March 21, 2012) for initial
compliance, we could stay the effectiveness of the rule for 90 days, as
allowed under CAA section 307(d)(7)(B), so that the Agency could
complete reconsideration.

D. Definition of Natural Gas Curtailment

    We are proposing to amend the definition of ``period of natural gas
curtailment or supply interruption'' to clarify that a curtailment does
not include normal market fluctuations in the price of gas that are not
associated with periods of supplier delivery restrictions. We are also
proposing to amend the definition to indicate that periods of supply
interruption that are beyond control of the facility can also include
on-site natural gas system emergencies and equipment failures, and that
legitimate periods of supply interruption are not limited to off-site
circumstances. Finally, we are proposing to revise the term and the
definition so that it includes the curtailment of any gaseous fuel, and
is not limited to just natural gas.
    The definition would be amended to read as follows:

    Period of gas curtailment or supply interruption means a period
of time during

which the supply of gaseous fuel to an affected facility is halted
for reasons beyond the control of the facility. The act of entering
into a contractual agreement with a supplier of natural gas
established for curtailment purposes does not constitute a reason
that is under the control of a facility for the purposes of this
definition. An increase in the cost or unit price of natural gas due
to normal market fluctuations not during periods of supplier
delivery restriction does not constitute a period of natural gas
curtailment or supply interruption. On-site gaseous fuel system
emergencies or equipment failures may qualify as periods of supply
interruption when the emergency or failure is beyond the control of
the facility.

E. Monitoring Carbon Monoxide Emissions

    We are proposing to amend the monitoring requirements in 40 CFR
63.11224(a) to allow sources subject to a carbon monoxide emission
limit the option to install, operate and maintain a carbon monoxide and
oxygen continuous emission monitoring system (CEMS). The CEMS would be
installed, operated, and maintained according to Performance
Specifications 3 and 4A at 40 CFR part 60, appendix B, and according to
the site-specific monitoring plan that each facility is already
required to develop according to the final rule published on March 21,
2011. The CEMS would also be required to complete a performance
evaluation, also according to Performance Specifications 3 and 4A.
    The rule currently requires sources subject to a carbon monoxide
emission limit to demonstrate compliance by measuring carbon monoxide
emissions while also monitoring the oxygen content of the exhaust, and
then demonstrating continuous compliance by monitoring and complying
with an oxygen content operating limit that is established during the
performance test.
    Under the proposed amendments, sources would have the option to
demonstrate continuous compliance by either monitoring both carbon
monoxide and oxygen to demonstrate compliance with the carbon monoxide
emission limit, corrected to 3 percent oxygen, or by complying with an
operating limit for oxygen content established during the performance
test.
    Several facilities have indicated that they already have carbon
monoxide CEMS, and should be able to rely on the data from those CEMS
to demonstrate compliance, rather than from a performance test and from
compliance with the operating limit. They noted that these proposed
amendments would also resolve any compliance questions that may arise
if their oxygen monitor showed a deviation from the operating limit,
but the CEMS still showed compliance with the carbon monoxide emission
limit.
    We are proposing to amend the oxygen monitoring requirements to
allow for the use of continuous oxygen trim analyzer systems. These
systems would be defined as a system of monitors that is used to
maintain excess air at the desired level in a combustion device. A
typical system consists of a flue gas oxygen and/or carbon monoxide
monitor that automatically provide a feedback signal to the combustion
air controller. Owners and operators would be required to operate the
oxygen trim system with the oxygen level set at the minimum percent
oxygen by volume that is established as the operating limit for oxygen
during the carbon monoxide performance test. We are also removing the
requirement that the oxygen monitor be located at the outlet of the
boiler, so that it can be located either within the combustion zone or
at the outlet as a flue gas oxygen monitor.

F. Averaging Times

    The EPA has determined the 30 day rolling average for parameter
monitoring and compliance with operating limits is appropriate for this
rule. The operating limits established through performance testing in
this rule represent short term process and control operating conditions
representative of compliance. Concerns of variability outside the
operators control such as fuel content, seasonal factors, load cycling,
and infrequent hours of needed operation prompted us to look at longer
averaging periods on which to base operating compliance determination.
We are aware from studies of emissions over long averaging periods that
long term (e.g., 30 day) average emissions for operating in compliance
will have a variability of about half of that represented by the
results of short term testing. Given that short term tests are
representative of distinct points along a continuum of that inherent
operational variability, we believe it appropriate to provide a means
for the source operator to account for that variability by applying a
long term average for establishing compliance. We expect more
problematic control system variability (e.g. ESP transformer failure or
scrubber venturi fan failure) to result in deviations from a 30-day
average relative to compliance almost as much as for a shorter term
average.

G. Affirmative Defense Language

    The EPA finalized affirmative defense provisions for malfunctions
and, as part of this reconsideration proposal, we are soliciting
comments on the affirmative defense provisions that were included in
the final rule.

H. Tune-up Work Practices

    1. Requirements for Small Units. Petitioners requested that the EPA
reconsider the tune-up work practices for a subset of very small units.
Specifically, petitioners requested that small oil-fired boilers
(petitioners defined ``small'' at various levels between 2 MMBtu/hr and
10 MMBtu/hr) be exempted from the rule. While the EPA disagrees that
small units should be exempt from the rule, the EPA agrees that for the
smallest units, a decreased tune-up frequency is appropriate. The large
number of small oil-fired units that can be located at an individual
facility, particularly an institution, provides logistical issues with
completion of tune-ups on a biennial basis. We are proposing to require
an initial tune-up by March 21, 2014, the compliance date for this
rule, and to change the requirement for subsequent tune-ups only for
oil-fired boilers equal to or less than 5 MMBtu/hr to a tune-up once
every 5 years.
    2. Conducting Initial Tune-ups at New Sources. Petitioners
requested that the EPA clarify the timing of tune-ups with respect to
the compliance dates for existing and new sources. All emission
standards must be met by the compliance date, even if compliance
demonstrations are sometimes allowed after the compliance date. In
order to meet the requirements of the rule, tune-ups must, therefore,
be completed by the compliance date for existing sources. For new
units, we are proposing to remove the requirement for the initial tune-
up. The EPA anticipates that new units will typically be tuned during
the startup process. Thus, new units would be required to complete the
applicable biennial (> 5MMBtu/h) or five-year (<= 5MMBtu/h) tune-up no
later than 25 months or 61 months, respectively, after the initial
startup of the new or reconstructed affected boiler.

I. Using the Upper Prediction Limit (UPL) for Setting Carbon Monoxide
Emission Limits

    We are proposing to amend the final carbon monoxide emission limit
for coal-fired boilers to reflect a revised analysis that uses the
original 99 percent confidence level in determining the UPL. In the
final rule, the EPA selected the use of a 99.9 percent confidence
interval for calculating the MACT floor for CO emissions. A petitioner
requested reconsideration of this selection given the fact that the EPA
used a 99 percent confidence interval for all of the other emission
limits in the

final rule. The petitioner pointed out that if the data are highly
variable, the 99 percent confidence interval should adequately reflect
the variability of emissions as well as for the data sets for other
pollutants. In the development of the final rule, the 99.9 percent
confidence interval was selected in part because the standards covered
periods of startup and shutdown, while the data did not reflect CO
emissions during those periods. While the EPA finalized work practice
standards for startup and shutdown periods, the selection of the
confidence interval was not revisited due to time constraints. The EPA
is now proposing to use a 99 percent confidence interval in order to
maintain a consistent methodology with the development of the MACT
floors for other pollutants, and because optional CO CEMS-based limits
are being proposed that would allow sources additional flexibility in
meeting the requirements of the rule.
    In the revised analysis, we have also removed the data from a
boiler for which only two test runs were completed in measuring carbon
monoxide emissions. The required number of test runs for accurately
measuring emissions and demonstrating compliance is three test runs.
Therefore, we determined that the datum from this unit was not
representative and we excluded it from the data set upon which we
performed the revised analysis.
    Based on the results of the revised analysis, we are proposing to
amend the carbon monoxide emission limit for new and existing coal-
fired boilers from 400 parts per million (ppm) by volume on a dry
basis, corrected to 3 percent oxygen, to 420 ppm by volume on a dry
basis, corrected to 3 percent oxygen.

J. Establishing GACT Emission Limits for Biomass and Oil-Fired Boilers

    We are taking comment on basing the final standards for biomass-
and oil-fired area source boilers on generally available control
technology (GACT) instead of based on maximum achievable control
technology (MACT) as were the proposed standards.
    We stated in the preamble (75 FR 31904) to the proposed rule, that
both industrial boilers and institutional/commercial boilers were on
the list of CAA section 112(c)(6) source categories for mercury and
POM. Section 112(c)(6) requires MACT standards for each of the
pollutants needed to achieve regulation of 90 percent of the emissions
of the relevant pollutant. In contrast, CAA section 112(c)(3) allows
the EPA to establish standards under GACT instead of MACT for urban
HAP. At proposal, we believed that we had to regulate POM from coal-
fired, biomass-fired, and oil-fired area source boilers and mercury
from coal-fired area source boilers in order to meet the requirement in
section 112(c)(6). As such, we proposed MACT-based limits for POM for
all subcategories and mercury for the coal subcategory. However, based
on the information we received after proposal in developing standards
for various other source categories, such as major source boilers, gold
mines, commercial and industrial solid waste incinerators, and other
categories, we determined only coal-fired area source boilers were
necessary to meet the 90 percent requirement set forth in section
112(c)(6) for POM and mercury in the final rule.
    In the proposed rule published on June 4, 2010 (75 FR 31896) for
the biomass and oil subcategories, all new biomass and oil-fired
boilers would have been subject to numerical emission limits for both
PM (GACT-based) and CO (MACT-based) as surrogates for other HAP.
Existing biomass and oil-fired boilers equal to or greater than 10
million British thermal units (Btu) per hour heat input capacity would
have been subject to a MACT-based numerical emission limits for CO, and
would have needed a one-time energy assessment. Existing boilers with
heat input capacity less than 10 million Btu per hour would have been
required to have a MACT-based work practice standard, as allowed under
CAA section 112(h), of a biennial tune-up in lieu of being subject to a
numerical CO limit.
    The final standards for area source biomass- and oil-fired boilers
published on March 21, 2011, required these boilers to meet the
following emission limitations:
     New boilers with heat input capacity greater than 10
million Btu per hour that are biomass-fired or oil-fired must meet a
GACT-based numerical emission limits for PM.
     New boilers with heat input capacity greater than 10
million Btu per hour that are biomass-fired or oil-fired must comply
with work practice standards to minimize the boiler's startup and
shutdown periods following the manufacturer's recommendations, or the
manufacturer's recommendations for a unit of similar design.
     Existing boilers with heat input capacity greater than 10
million Btu per hour that are biomass-fired or oil-fired must have a
one-time energy assessment performed by a qualified energy assessor.
     All new and existing units, regardless of size, that are
biomass-fired or oil-fired must have a GACT-based tune-up biennially
(every two years).
    The EPA's rationale for the changes between proposal and
promulgation for the biomass- and oil-fired boilers can be found in the
preamble to the promulgated area source standards (76 FR 15565-15567
and 15574-15575, March 21, 2011). As explained in the preamble to the
final rule, rather than require a numeric MACT-based limit for CO as a
surrogate for the individual organic urban HAP (including POM), new and
existing biomass- and oil-fired boilers must meet GACT requirements
consisting of management practice requirements. For the purposes of
regulating PM from new boilers, we concluded that the GACT standards
should consist of numeric emission limits for units with heat input
capacities greater than 10 million Btu per hour or greater because
these new units will be subject to the new source performance standard
(NSPS) emission limits for PM, and the NSPS will require PM emissions
testing. For units with capacity less than 10 million Btu per hour,
GACT does not include a numerical emission limit because of technical
limitations of testing PM emissions from boilers with small diameter
stacks.
    We are accepting comment on basing the final standards for these
two subcategories of area source boilers on GACT, but we are not
proposing any amendments to these standards at this time.

K. Energy Assessment

    1. Scope. Petitioners requested that the EPA clarify the scope of
the energy assessment. Specifically, petitioners requested that the
scope be clearly limited to only those energy use systems, located on-
site, associated with the affected boilers and process heaters. The
final definition for ``Energy use system'' was intended only to list
examples of potential systems that may use the energy generated by
affected boilers and process heaters. We did not intend that the energy
assessment would include energy use systems using electricity purchased
from an off-site source. We also did not intend that the energy
assessment include energy use systems located off-site. We have revised
the definition of ``Energy assessment'' to better clarify our intent.
    2. Compliance Date. Petitioners requested that the EPA clarify the
due date of the energy assessment. All emission standards must be met
by the compliance date (March 21, 2014), even if compliance
demonstrations are sometimes allowed after the compliance date. In
order to meet the requirements

of the rule, energy assessments must, therefore, be completed by the
compliance date (March 21, 2014) for existing sources.
    3. Maximum Duration Requirements. Petitioners requested that the
EPA reconsider the stated ``maximum time'' to conduct the energy
assessment because the maximum times were not included in the proposal
and stakeholders had no opportunity to comment. The concern raised by
petitioners is that, as the final definition of ``Energy assessment''
is worded, a deviation and a potential violation could occur if the
energy assessment effort exceeds these time limits. Our intent for
including the ``maximum time'' in the final rule definition was to
minimize the burden on the smaller fuel-use facilities, many of which
are likely small entities, by limiting the extent of the energy
assessment. Our concern was that if there was no time limit these small
facilities would have no means to limit the time/effort of an outside
energy assessor that is contracted to perform the energy assessment. We
have revised the definition of ``Energy assessment'' to change the
maximum time from one-day to 8 technical hours and from three-day to 24
technical hours and to allow sources to perform longer assessments at
their discretion.

L. Setting PM Standards Under Generally Available Control Technology
for Oil-Fired Area Source Boilers

    The EPA's rationale for finalizing PM emissions limits, based on
GACT, for new oil-fired area source boilers can be found in the
preamble to the promulgated area source standards (76 FR 15574). We are
not proposing any changes to the PM limits for new oil-fired area
source boilers. We are only soliciting comments on the final PM limits
for new oil-fired area source boilers.

M. Title V Permitting Requirements

    In the proposed rule published on June 4, 2010 (75 FR 31925), we
proposed to exempt area sources from the requirement to obtain a title
V permit, if they were not an area source as a result of installing a
control device on a boiler after November 15, 1990. In other words,
this exemption would have only applied to ``natural'' area sources and
would not have applied to ``synthetic'' area sources that would
otherwise have been major sources but for the control device. In the
final rule, in response to comments and after a full review of the
record, we extended the exemption to all area sources, including major
sources that became synthetic area sources by installing air pollution
controls. We explained that we lacked sufficient information at that
time to distinguish from other synthetic and natural area sources those
sources which have applied controls to boilers in order to become area
sources.\1\ As a result, the rationale for exempting most area sources
subject to this rule as explained in the proposal preamble (see 75 FR
31910 to 31913, June 4, 2010) was also relevant for those sources which
we proposed to permit. Thus, no area sources subject to subpart JJJJJJ
are required to obtain a title V permit as a result of being subject to
subpart JJJJJJ.
---------------------------------------------------------------------------

    \1\ In the preamble to the proposed area source NESHAP, we
estimated that at least 48 synthetic area sources reduced their
emissions to below the major source threshold by installing air
pollution control devices. (75 FR 31911, June 4, 2010.)
---------------------------------------------------------------------------

    After promulgation of the final boiler area source rule, we
received a petition to reconsider the decision to not require title V
permits for area source boilers in the final rule, and to reconsider
the decision to extend the exemption to include synthetic area sources.
The petition from Sierra Club is in the docket for today's rule.\2\ The
petition disputes our conclusion that title V permitting is
unnecessarily burdensome; discusses the benefits of permitting,
including compliance benefits; contests our estimation of the costs of
permitting; and challenges our determination to extend the proposed
exemption from title V permitting to include synthetic area sources.
---------------------------------------------------------------------------

    \2\ [Citation to docket for the Earthjustice et al. petition.]
---------------------------------------------------------------------------

    We are not proposing any changes to the title V exemption at this
time. We invite comment on the rationale we expressed in the March 21,
2011 final rule as well as on the arguments outlined in the petition
for reconsideration. Additionally, with respect to the issue of
exempting synthetic area sources, we invite comment on our additional
analysis of the petitioner's issue, presented below.
    At proposal, we estimated that about 137,000 area source facilities
are in the category, including schools, hospitals, and churches. See 75
FR 31912. We also estimated that at least 48 synthetic area sources
reduced their HAP emissions to below the major source threshold by
installing air pollution controls. See 75 FR 31911. The total number of
facilities that are likely to be synthetic area sources for HAP
emissions is likely to be a small proportion (e.g., less than 1
percent) of the total population of area source facilities in the
category.
    Those facilities that are synthetic minor sources for HAP may
already have a title V permit for other reasons. For example they could
still be major sources for criteria pollutants, or may be subject to
NSPS. The title V exemption in subpart JJJJJJ does not affect the
applicability of title V under those other programs and facilities
required to obtain a title V permit under those other programs would
still be required to have a permit.
    The presence of an exemption from title V permitting for synthetic
area sources under subpart JJJJJJ would still mean that synthetic area
sources would likely be subject to more stringent permitting and
monitoring requirements than natural area sources. In order for a
facility to be treated as a synthetic area source due to the
installation of controls, the facility still has a legal duty to use
the control equipment because the control equipment requirement must be
Federally enforceable. The use of the control is not optional and must
be continued.
    Facilities that are synthetic minors because of add-on controls are
similar in size and sophistication to those that are natural area
sources and the added burden of obtaining and complying with a title V
permit would be disproportionate to any added environmental benefit,
after accounting for the relatively small size differences between
synthetic minor and natural area source facilities. The uncontrolled
emissions are generally on the same order of magnitude as the emissions
of natural area sources, and the facilities and owners are comparable
in size.

V. Technical Corrections and Clarifications

    We are proposing several technical corrections. These amendments
are being proposed to correct inaccuracies and oversights that were
promulgated in the final rule. These proposed changes are summarized in
Table 1 of this preamble and described in more detail in the paragraphs
that follow.

 Table 1--Miscellaneous Technical Corrections to 40 CFR Part 63, Subpart
                                 JJJJJJ
------------------------------------------------------------------------
   Section of subpart JJJJJJ        Description of proposed correction
------------------------------------------------------------------------
40 CFR 63.11195................  Adding residential boilers and electric
                                  boilers to the list of boilers not
                                  subject to subpart JJJJJJ.
40 CFR 63.11195(c).............  Clarifying the language in this
                                  paragraph to provide an exemption
                                  stating ``unless such units do not
                                  combust hazardous waste and combust
                                  comparable fuels.''
40 CFR 63.11210................  Revising paragraph (d) and adding a new
                                  paragraph (e) to clarify the dates by
                                  which new and reconstructed affected
                                  boilers need to demonstrate initial
                                  compliance.
40 CFR 63.11210(g).............  Adding a new paragraph (g) to clarify
                                  the dates by which affected boilers
                                  that switch subcategories need to
                                  demonstrate compliance.
40 CFR 63.11211(b)(2)..........  Removing the second sentence of that
                                  paragraph.
40 CFR 63.11220................  Removing paragraphs (b) through (d)
                                  because they are not relevant, and
                                  renumber paragraph (e) as (b).
40 CFR 63.11221................  Clarifying the monitoring data
                                  collection requirements and the
                                  meaning of a ``deviation'' with
                                  respect to collecting monitoring data.
40 CFR 63.11223(b).............  Clarifying the requirements for units
                                  that burn more than one type of fuel.
40 CFR 63.11223(c).............  Adding a new paragraph to allow for a
                                  triennial tune-up for seasonal
                                  boilers.
40 CFR 63.11223(d).............  Including oil-fired and biomass-fired
                                  boilers in the requirement to minimize
                                  the time spent in startup and shutdown
                                  periods.
40 CFR 63.11224(c)(1) and        Correcting a cross reference error.
 (c)(2).
40 CFR 63.11224(b).............  Clarifying the requirements for the
                                  annual and biennial compliance
                                  reports.
40 CFR 63.11224(c).............  Clarifying the record keeping
                                  requirements.
40 CFR 63.11225(b).............  Clarifying the requirements for
                                  compliance reports.
40 CFR 63.11225(d).............  Revising to allow for computer access
                                  of records.
40 CFR 63.11225(g).............  Revising to include physical changes to
                                  the boiler that may also result in the
                                  applicability of a different
                                  subcategory.
40 CFR 63.11237................  Revising the definitions for ``Annual
                                  heat input basis,'' ``Biomass
                                  subcategory,'' ``Boiler,'' ``Energy
                                  assessment,'' ``Gas-fired boiler,''
                                  ``Hot water heater,'' ``Institutional
                                  boiler,'' ``Liquid fuel,'' ``Oil
                                  subcategory,'' ``Period of natural gas
                                  curtailment or supply interruption,''
                                  ``Qualified Energy Assessor'' and
                                  ``Waste heat boiler.'' Adding
                                  definitions for ``30-day rolling
                                  average,'' ``Calendar year,'' ``Daily
                                  block average,'' ``Electric boiler,''
                                  ``Electric utility steam generating
                                  unit (EGU),'' ``Minimum total
                                  secondary electric power,'' ``Oxygen
                                  analyzer system,'' ``Oxygen trim
                                  system,'' ``Process heater,''
                                  ``Residential boiler,'' ``Seasonal
                                  boiler,'' ``Shutdown,'' ``Startup,''
                                  and ``Temporary boiler.'' Deleting the
                                  definition for ``Minimum voltage or
                                  amperage.''
Table 1 to subpart JJJJJJ......  Amending the mercury emission limit for
                                  coal fired boilers. Clarifying that
                                  the particulate matter emission limits
                                  do not include condensable particulate
                                  matter.
Table 2 to subpart JJJJJJ......  Allowing seasonal boilers to conduct a
                                  tune-up every five years.
Table 6 to subpart JJJJJJ......   Correcting a printing error in
                                  Item 1.a related to wet scrubbers.
                                  Clarifying the applicability
                                  of the operating limits for ESPs.
                                  Adding operating load limit
                                  requirements for units subject to
                                  emission limits and performance stack
                                  tests.
Table 7 to subpart JJJJJJ......   Revising the 12-hour averages
                                  to 30-day rolling averages.
                                  Adding operating load limit
                                  requirements for units subject to
                                  emission limits and performance stack
                                  tests.
------------------------------------------------------------------------

A. Electric and Residential Boilers

    We are proposing to amend 40 CFR 63.11195 (Are any boilers not
subject to this subpart?) by adding electric boilers and residential
boilers to the list of boilers not subject to subpart JJJJJJ. Electric
boilers would be added because they do not have any combustion
emissions, except when gaseous or liquid fuels are combusted as an
emergency back-up during electric power outages. An electric boiler
would be defined in 40 CFR 63.11237 as:

``* * * a boiler in which electric heating serves as the source of
heat. Electric boilers that burn gaseous or liquid fuel during
periods of electrical power curtailment or failure are included in
this definition.''

    Residential boilers are the boilers used in single and multi-family
residences (e.g., duplexes, townhouses) where each dwelling typically
has its own heating and hot water system, rather than a shared central
system as in an apartment building or dormitory. Owners and operators
of regulated sources have pointed out that residential boilers are
small and are not included in the facility's operating permits because
such units have historically been classified as insignificant sources
under state and federal Clean Air Act operating permit programs. We
agree that these residential boilers should be specifically excluded
from the source category identified in subpart JJJJJJ because they are
not part of either the industrial boiler source category or the
commercial/institutional source category. The EPA did not intend to
include these in the final rule for industrial, commercial, and
institutional boilers.
    A residential boiler would be defined in 40 CFR 63.11237 as:

``* * * a boiler used to provide heat and/or hot water used by the
owner or occupant of a dwelling designed for and used for not more
than four family units. This definition includes boilers used
primarily to provide heat and/or hot water for a dwelling containing
four or fewer families located at an institutional facility (e.g.,
university campus, military base, church grounds) or commercial/
industrial facility (e.g., farm).''

B. Establishing Operating Limits for Wet Scrubbers

    We are proposing to amend the operating limit provisions to clarify
the operating limits for electrostatic precipitators. We are amending
40 CFR 63.11211(b)(2) to remove the second sentence stating that the
operating limits for electrostatic precipitators (ESP) do not apply to
dry ESP systems operated without a wet scrubber.

C. Timing of Subsequent Performance Tests

    We are proposing to amend 40 CFR 63.11220 to correct a technical
error. Paragraphs (b) through (d) of that section should have been
removed from the final rule, and paragraph (a) should have been revised
to remove the references to paragraphs (b) through (d),

when the testing frequency in paragraph (a) was changed between
proposal and promulgation from annual testing to triennial testing for
all sources. Paragraph (e) will be re-numbered to become paragraph (b).

D. Demonstrating Initial Compliance

    We are proposing to amend 40 CFR 63.11210 to clarify the dates by
which new and reconstructed boilers need to demonstrate initial
compliance. We are proposing to amend 40 CFR 63.11210(d) to clarify
that only boilers that are subject to emission limits for PM, mercury,
or carbon monoxide in Table 1 to subpart JJJJJJ have a 180-day period
after the applicable compliance date to demonstrate initial compliance.
We are adding a new paragraph (e) to clarify that units that are only
subject to work practice standards, emission reduction measures, and
management practices in Table 2 to subpart JJJJJJ, and not subject to
emission limits in Table 1, must demonstrate initial compliance no
later than the applicable compliance date. The existing paragraph (e)
would be re-designated paragraph (f).
    We are adding a new paragraph (g) to clarify that units that switch
fuels that result in the applicability of a different subcategory must
demonstrate initial compliance with the applicable standards of the new
subcategory no later than 180 days after the date upon which the fuel
switch is commenced as identified in the notification submitted
according to Sec.  63.11225(g).

E. Demonstrating Compliance with the Work Practice and Management
Practice Standards

    We are proposing to amend 40 CFR 63.11223(b) to specify that you
must conduct boiler tune-ups while burning the type of fuel that
provided the majority of the heat input to the boiler over the 12
months prior to the tune-up. We are also proposing to amend 40 CFR
63.11223(b)(6)(iii) to specify that the type and amount of fuel needs
to be included in the biennial report only if the unit was physically
and legally capable of using more than one type of fuel during that
period. We are also proposing to specify that for units sharing a fuel
meter, you may estimate the fuel use by each unit. These changes are
being proposed to accommodate units that burn more than one type of
fuel.
    We are also proposing to amend 40 CFR 63.11223 to include a new
paragraph (c) to specify that, after an initial tune-up by the
compliance date, seasonal boilers must complete a tune-up every 5
years, rather than a biennial tune-up.
    We are renumbering paragraph (c) of 40 CFR 63.11223 to become
paragraph (d) and amending that paragraph to include oil-fired and
biomass-fired boilers in the requirement to minimize the time spent in
startup and shutdown periods so that this requirement matches the
requirement specified in Table 2 to subpart JJJJJJ.

F. Monitoring Requirements

    We are proposing to amend 40 CFR 63.11224(c)(1) and (c)(2) to
correct a cross reference error. The references to (b)(1)(i) should be
to (c)(1)(i) in those two paragraphs.

G. Notification, Recordkeeping, and Reporting Requirements

    We are proposing to amend 40 CFR 63.11225(b) to clarify the
requirements for submitting a biennial report for units that are only
subject to a biennial tune-up. We are also proposing to amend 40 CFR
63.11225(b)(2) to specify the information that must be included in the
annual or biennial compliance report.
    We are proposing to amend 40 CFR 63.11225(c)(2) to add additional
record requirements. These would include a copy of the energy
assessment and the days of operation for each boiler that meets the
definition of a seasonal boiler. We are also proposing to amend 40 CFR
63.11225(c)(2) to specify that records of fuel use and type are
required only for boilers that are subject to numerical emission limits
in Table 1 to subpart JJJJJJ, instead of for all boilers.
    We are also proposing to revise 40 CFR 63.11225(d) to remove the
reference to 40 CFR 63.10(b)(1) and the requirement that the most
recent 2 years of records be maintained ``on site.'' We are proposing
to add language that would allow for computer access or other means of
immediate access of records stored in a centralized location.
    We are proposing to revise 40 CFR 63.11225(g) to add any physical
change that may result in the applicability of a different subcategory
to the notification requirement. We are proposing this revision to
address the situation when a physical modification is made to limit/
reduce the heat input capacity such that there is a change in
applicability.
    We are also proposing to amend 40 CFR 63.11214(c) to remove the
requirement for submitting, upon request, the energy assessment.
Petitioners commented that this approach, submit upon request, is
contrary to the approach taken in the final Boiler MACT [40 CFR
63.7530(e)]. We agree that we had previously stated our intent to
recognize in the final Boiler Area Source rule the sensitivity of
confidential business information (CBI) contained in energy
assessments. Considering this, the petitioners requested that the EPA
reconsider the text of 63.11214(c) and clarify that energy assessment
reports are not required to be submitted. We note that, even with this
change, the Agency has the authority to obtain the energy assessment as
authorized by CAA section 114, including the provisions for protecting
CBI.

H. Definitions

    We are proposing the following changes to the definitions in 40 CFR
63.11237:
    Biomass subcategory: Proposing to revise the definition for
``Biomass subcategory'' to clarify that boilers burning any biomass are
included in the definition unless they are included in the ``Coal
subcategory'' definition. This change is being proposed to account for
boilers burning less than 15 percent, on an annual heat input basis, in
combination with gaseous fuels which would otherwise meet neither the
definition of a biomass-fired boiler nor the definition of a gas-fired
boiler.
    Boiler: Proposing to revise the definition for ``Boiler'' to
clarify that boilers may heat steam, hot water, or both, and to clarify
that process heaters (for which a definition would be added) are
excluded from the definition of boilers.
    Electric utility steam generating unit (EGU): Proposing to amend
the rule to define ``Electric utility steam generating unit (EGU)'' so
that fossil fuel-fired EGUs are not inadvertently included in the
boiler source category.
    Energy assessment: Proposing to amend the definition of ``Energy
assessment'' to correct a reference to Table 2 of subpart JJJJJJ, to
remove the inclusion of process heaters, and to clarify that the energy
assessment only needs to include an assessment of on-site energy usage.
This latter change is made to account for the fact that some boilers
provide steam and/or hot-water to off-site customers over whom they
have no control.
    We are also revising the definition of the energy assessment to
change the time limit for the assessment from one or three days to
eight or 24 technical labor hours, and to allow facilities to spend
additional time on the assessment at their discretion. Facilities have
indicated that it may be difficult to complete the energy assessments
in the amount of time allowed in the final rule, and they should have
the option to spend more time to complete the assessment. By switching
from days to technical labor hours, we are also

recognizing that the assessment may require intermittent activity
spread over several days, instead of uninterrupted activity for a one-
day or three-day period.
    Gas-fired boiler: Proposing to amend the definition of ``Gas-fired
boiler'' to include startups as one of the conditions during which
liquid fuel can be burned in units meeting this definition. We are also
proposing to change from ``gas supply emergencies'' to ``gas supply
interruptions'' because the term ``interruption'' more accurately and
objectively describes the situations under which liquid fuels may be
burned than ``emergency.''
    Hot water heater: Proposing to amend the definition of ``Hot water
heater'' to clarify that hot water boilers are included in the
definition. Hot water boilers having a heat input capacity of less than
1.6 million Btu per hour meet the criteria listed for hot water
heaters. We are also proposing to amend the definition to clarify/
simplify applicability determinations.
    Institutional boiler: Proposing to revise this definition to better
encompass and describe the range of facilities that would be considered
``institutions'' by adding nursing homes, elementary and secondary
schools, libraries, religious establishments, and governmental
buildings to the examples in the definition. We are also adding
language to clarify that ``institutions'' are not limited to just these
examples.
    Minimum voltage or amperage: Proposing to replace the term
``Minimum voltage or amperage'' with the term ``Minimum total secondary
electric power,'' to better reflect the concept being described and the
operating limit to which it applies. We are also proposing revising the
definition of that term to clarify the meaning.
    Oil subcategory: Proposing to change the terms in the definition
from ``gas supply emergencies'' to ``gas supply interruptions,'' and
adding ``startups'' as conditions under which liquid fuels can be
burned in gas-fired units that are specifically excluded from meeting
the definition of oil subcategory. We are also proposing to amend this
definition to clarify that the 48-hour limit per calendar year applies
only to periodic testing.
    Period of natural gas curtailment or supply interruption: The
rationale and description of the proposed amendments to this definition
are described in Section IV.D of this preamble.
    Process heater: Proposing to amend the rule to define ``Process
heater'' so that process heaters are not inadvertently included in the
boiler source category. This definition would also clarify that units
that heat a water mixture as a heat transfer fluid, without generating
steam, are not considered boilers. Although they are not specifically
mentioned in the definition, the proposed definition would also be
broad enough to include process heaters that utilize waste heat, as
well as process heaters that rely directly on fuel combustion. A
process heater would be defined as follows:

    Process heater means an enclosed device using controlled flame,
and the unit's primary purpose is to transfer heat indirectly to a
process material (liquid, gas, or solid; raw, intermediate or
finished) or to a heat transfer material (e.g., glycol or a mixture
of glycol and water) for use in a process unit, instead of
generating steam. Process heaters are devices in which the
combustion gases do not come into direct contact with process
materials. Process heaters include units that heat water/water
mixtures for pool heating, sidewalk heating, cooling tower water
heating, power washing, oil heating, or autoclaves.

    Qualified energy assessor: Proposing to amend the definition to
correct a paragraph numbering error in the definition.
    Residential boiler and temporary boiler: Proposing to add
definitions for ``Residential boiler'' and ``Temporary boiler'' because
we are proposing to add these two types of boilers to the list of
boilers that are exempt from subpart JJJJJJ. The rationale for adding
temporary boilers and the definition are described in Section IV.B of
this preamble, and the rationale for adding residential boilers and the
definition are described in Section V.A of this preamble.
    Seasonal boiler: Proposing to add a definition for ``Seasonal
boiler'' because we are proposing to add a subcategory for those types
of boilers. The rationale for adding this subcategory and the proposed
definition is described in Section IV.A of this preamble.
    Startup and Shutdown: While we are maintaining a work practice/
management practice approach for startup and shutdown, we are proposing
definitions of startup and shutdown. We are proposing to define
``startup'' as the period between the state of no combustion in the
boiler to the period where the boiler first achieves 25 percent load
(i.e., a cold start). We are proposing to define ``shutdown'' as the
period that begins when a boiler last operates at 25 percent load and
ending with a state of no fuel combustion in the boiler.

I. Change to the Mercury Emission Limit for New Coal-Fired Boilers

    We are proposing to amend the mercury emission limit for new and
existing coal-fired boilers in Table 1 to subpart JJJJJJ. At
promulgation, the mercury limit for new and existing coal-fired boilers
was 0.0000048 (4.8 x 10-6) pounds (lb) mercury per MMBtu.
This limit was based on the best performer of seven units for which
data were available. All of the mercury data emissions from this boiler
were below the method detection limit. After promulgation, however, the
EPA determined that the boiler on which the EPA based this limit is a
utility boiler and thus is not part of the source category and should
not have been considered in setting the mercury emission limit for
existing and new sources.
    Examining the emissions data for the remaining six units, the top
performing unit is now a unit from Massachusetts that achieved an
emission level of 2.0 x 10-6 lb mercury per MMBtu. These
emissions are above the method detection limit. Because this unit is
from Massachusetts, the fuel variability factor (FVF) for eastern
bituminous coal of 10.9 is still applicable. Using these data and the
FVF of 10.9, the proposed mercury emission limit for new and existing
coal-fired boilers is 0.000022 lb mercury per MMBtu.

J. Changes to the Work Practice Standards, Emission Reduction Measures,
and Management Practices

    We are proposing to amend Table 2 to subpart JJJJJJ to add a
provision that allows seasonal boilers, after an initial tune up by the
compliance date, to conduct a tune-up every 5 years instead of a
biennial tune-up. As explained in section IV.A of this preamble, we are
proposing to create a new subcategory for seasonally operated boilers.
Because these boilers are operated seasonally, it can be difficult to
schedule and complete the testing needed to complete the tune-up
requirements every other year (biennially) for periods when the boilers
are operating, especially at facilities that have multiple boilers.
Therefore, we are proposing to allow seasonally operated boilers to
conduct tune-ups every five years after the initial tune up by the
compliance date, and include this requirement in Table 2 to subpart
JJJJJJ.

K. Requirements for Establishing Operating Limits

    We are proposing several changes to Table 6 to subpart JJJJJJ:
    We are proposing to revise the requirements for establishing the

operating limits for wet scrubbers in Item 1.a of Table 6 to correct a
printing error related to how the recorded data are reduced to
determine the operating limits. Operators are currently instructed to
collect pressure drop and liquid flow-rate data every 15 minutes during
the entire period of the performance stack tests. The instruction to
determine the average pressure drop and liquid flow-rate for each
individual test run in the three-run performance stack test was placed
in the incorrect column of Table 6. It will be moved from the second
column (``And your operating limits are based on * * *'') to the fifth
column (``According to the following requirements'').
    We are proposing to revise the requirements for establishing the
operating limits for ESPs in Item 1.b of Table 6 to clarify that they
apply to all ESPs, and do not apply to only those that are operated on
units with wet scrubbers.
    We are proposing to revise Table 6 to include as Item 4 provisions
for establishing a unit-specific limit for maximum operating load.
These provisions would apply to any unit subject to a pollutant
emissions limit for which compliance is demonstrated by a performance
(stack) test. Operating load data would include fuel feed rate data or
steam generation rate data and would be collected at 15 minute
intervals during each run of the performance test. The average rate
would be determined for each run of the performance test and the
average of the three test runs would be determined. The maximum
operating limit would be 110 percent of the average of the three test
runs.

L. Demonstrating Continuous Compliance

    We are proposing several amendments to Table 7 to subpart JJJJJJ:
    We are proposing to amend the continuous compliance requirements
for the following operating limits to clarify that compliance is based
on a 30-day rolling average:
     Wet scrubber pressure drop and liquid flow rate in Item
3.c.
     Dry scrubber sorbent or carbon injection rate in Item 4.c.
     ESP secondary amperage and voltage, or total power input
in Item 5.c.
     Oxygen content in the combustion exhaust in Item 7.b.
    We are proposing to amend the provisions for oxygen monitoring to
reflect the amendments to add oxygen trim analyzer systems that were
discussed in more detail in section IV.E of this preamble.
    We are also proposing to add new requirements as Item 8 for
establishing a unit-specific operating limit for unit operating load
based on fuel feed rate or steam generation rate. This change coincides
with the proposed amendment to Table 6 to subpart JJJJJJ to establish a
unit-specific operating limit for maximum operating load for any
pollutant for which compliance is demonstrated by a performance (stack)
test.

VI. What are the impacts associated with the amendments?

    The proposed amendments contained in this action are corrections
that are intended to clarify, but not change, the coverage of the final
rule. The clarifications and corrections should make it easier for
owners and operators and for local and State authorities to understand
and implement the requirements. The amendments will not increase the
costs for the final rule but will result in a decrease in the burden on
small facilities as a result of the reduction in the frequency of
conducting tune-ups for seasonal boilers and small (equal to or less
than 5 MMBtu/hr) oil-fired boilers.
    As discussed in section V, the mercury emission limits for new and
existing large (10 MMBtu/hr or greater) coal-fired area source boilers
was revised because of an error discovered in the analysis conducted
for the final rule. This technical correction resulted in an increase
in the emission limits for mercury. Concurrently, we revised our
impacts analysis to be consistent with changes made to the major source
boiler rule. The baseline emissions for area sources are calculated
using the emission factors developed for the major source rule because
of insufficient data for area sources. Since promulgation, the EPA has
received and incorporated a significant amount of additional data and
has corrected previous calculation errors that impacted the emission
factors used to calculate baseline emissions resulting in a higher
baseline emission for mercury from coal-fired area source boilers.
Consequently, the result of the increase in both baseline mercury
emissions and mercury emission limits in this proposed rule is that the
overall reduction in mercury emissions does not change significantly
from the estimated reduction for the promulgated rule.
    In summary, as compared to the control costs estimated in the March
2011 final rule, the proposed amendments will result in a decrease in
the capital and annual cost due to the increase in emission limits and
the decrease in burden on small facilities.

VII. 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 12866 (58 FR 51735, October 4, 1993), this
action is a ``significant regulatory action'' because it may raise
novel legal or policy issues. Accordingly, the EPA submitted this
action to the Office of Management and Budget (OMB) for review under
Executive Order 12866 and Executive Order 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.

B. Paperwork Reduction Act

    This proposed rule does not impose any new information collection
burden. However, OMB has previously approved the information collection
requirements contained in the existing regulation (40 CFR part 63,
subpart JJJJJJ) under the provisions of the Paperwork Reduction Act, 44
U.S.C. 3501, et seq., and has assigned OMB control number 2060-0688,
EPA information collection request (ICR) number 2253.02, to the ICR.
    This action results in no changes to the information collection
requirements of the final rule and will have no impact on the
information collection estimate of project cost and hour burden made
and approved by OMB. Therefore, the ICR has not been revised. The OMB
control numbers for the EPA's regulations in 40 CFR are listed in 40
CFR part 9.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) 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.\3\ The RFA also

allows an agency to ``consider a series of closely related rules as one
rule for the purposes of sections'' 603 (initial regulatory flexibility
analysis) and 604 (final regulatory flexibility analysis) in order to
avoid ``duplicative action.'' 5 U.S.C. 605(c). This proposed rule is
closely related to the boiler area source rule, which EPA signed on
February 21, 2011 and that took effect on May 20, 2011. The EPA
prepared an initial regulatory flexibility analysis in connection with
the boiler area source rule. Therefore, pursuant to Sec.  605(c), the
EPA is not required to complete an initial regulatory flexibility
analysis for this rule.
---------------------------------------------------------------------------

    \3\ Small entities include small businesses, small
organizations, and small governmental jurisdictions. For purposes of
assessing the impacts of this proposed rule on small entities, small
entity is defined as: (1) A small business as defined by the Small
Business Administration size standards for small businesses at 13
CFR 121.201 (less than 500, 750, or 1,000 employees, depending on
the specific NAICS Code under subcategory 325); (2) a small
governmental jurisdiction that is a government of a city, county,
town, school district or special district with a population of less
than 50,000; and (3) a small organization that is any not-for-profit
enterprise that is independently owned and operated and is not
dominant in its field.
---------------------------------------------------------------------------

    The EPA has been concerned with potential small entity impacts
since it began developing the boiler area source rule. The EPA
conducted outreach to small entities and, pursuant to Sec.  609 of RFA,
convened a Small Business Advocacy Review Panel (the Panel) on January
22, 2009, to obtain advice and recommendations from small entity
representatives. Pursuant to the RFA, the EPA used the Panel's report
and prepared both an initial regulatory flexibility analysis and a
final regulatory flexibility analysis in connection with the closely
related boiler area source rule. Convening an additional Panel and
preparing an additional initial regulatory flexibility analysis would
be procedurally duplicative and is unnecessary given that the issues
here are within the scope of those considered by the Panel. Finally, we
note that this rule, which proposes to amend the boiler area source
rule, will not impose any additional regulatory requirements beyond
those imposed by the previously promulgated boiler area source rule.

D. Unfunded Mandates Reform Act

    This action contains no new 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. This proposed rule imposes no new enforceable duty on any
State, local, or tribal governments or the private sector. Therefore,
this proposed rule is not subject to the requirements of sections 202
and 205 of the UMRA.
    This action is also not subject to the requirements of section 203
of UMRA because it contains no new regulatory requirements that might
significantly or uniquely affect small governments. This rule proposes
amendments to aid with compliance, but does not change the level of the
standards in the rule.

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 Executive Order 13132. This proposed rule will not impose
new direct compliance costs on State or local governments, and will not
preempt State law. Thus, Executive Order 13132 does not apply to this
action.
    In the spirit of Executive Order 13132 and consistent with the EPA
policy to promote communications between the EPA and State and local
governments, the EPA specifically solicits comment on this proposed
action from State and local officials.

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

    This proposed rule does not have tribal implications, as specified
in Executive Order 13175 (65 FR 67249, November 9, 2000). It will not
have substantial new 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 Executive Order 13175.
Thus, Executive Order 13175 does not apply to this proposed rule.
    The EPA specifically solicits additional comment on this proposed
action from tribal officials.

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

    The EPA interprets Executive Order 13045 (62 FR 19885, April 23,
1997) as applying to those regulatory actions that concern health or
safety risks, such that the analysis required under section 5-501 of
the Executive Order has the potential to influence the regulation. This
proposed rule is not subject to Executive Order 13045 because it is
based solely on technology performance.

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

    This action is not a ``significant energy action'' as defined in
Executive Order 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, this action does not change
the level of standards already in place.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act (NTTAA) of 1995, Public Law No. 104-113, 12(d) (15 U.S.C. 272 note)
directs the EPA to use voluntary consensus standards (VCS) in its
regulatory activities, unless to do so would be inconsistent with
applicable law or otherwise impractical. VCS are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by VCS bodies. NTTAA
directs the EPA to provide Congress, through OMB, explanations when the
Agency decides not use available and applicable VCS.
    This proposed rulemaking does not involve any new technical
standards. Therefore, the EPA did not consider the use of any VCS.

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

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
Federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
    The EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it would not
change the level of environmental protection for any affected
populations. Therefore, it does not have any disproportionately high or
adverse human health or environmental effects on any population,
including any minority or low-income population. The amendments would
not relax the control measures on sources regulated by the rules, and,
therefore, will not cause emissions increases from these sources.

List of Subjects in 40 CFR Part 63

    Environmental protection, Administrative practice and procedure,
Air pollution control, Hazardous substances.

    Dated: December 2, 2011.
Lisa P. Jackson,
Administrator.

    For the reasons stated in the preamble, title 40, chapter I, part
63 of the Code of Federal Regulations is proposed to be amended as
follows:

PART 63--[AMENDED]

    1. The authority citation for part 63 continues to read as follows:

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

Subpart JJJJJJ--[AMENDED]

    2. Section 63.11195 is amended by revising the introductory text
and paragraph (c) and by adding paragraphs (h), (i), (j), and (k) to
read as follows:

Sec.  63.11195  Are any boilers not subject to this subpart?

    The types of boilers listed in paragraphs (a) through (k) of this
section are not subject to this subpart and to any requirements in this
subpart.
* * * * *
    (c) A boiler required to have a permit under section 3005 of the
Solid Waste Disposal Act or covered by subpart EEE of this part (e.g.,
hazardous waste boilers), unless such units do not combust hazardous
waste and combust comparable fuels.
* * * * *
    (h) Temporary boilers as defined in this subpart.
    (i) Residential boilers as defined in this subpart.
    (j) Electric boilers as defined in this subpart.
    (k) An electric utility steam generating unit as defined in this
subpart.
    3. Section 63.11196 is amended by revising paragraph (a)(1) to read
as follows:

Sec.  63.11196  What are my compliance dates?

    (a) * * *
    (1) If the existing affected boiler is subject to a work practice
or management practice standard of a tuneup, you must achieve
compliance with the work practice or management standard no later than
March 21, 2013.
* * * * *
    4. Section 63.11210 is amended by revising paragraph (d), by
redesignating paragraph (e) as paragraph (f) and adding a new
paragraphs (e) and (g) to read as follows:

Sec.  63.11210  What are my initial compliance requirements and by what
date must I conduct them?

* * * * *
    (d) For new or reconstructed affected boilers that have applicable
emission limits, you must demonstrate initial compliance no later than
180 calendar days after March 21, 2011 or within 180 calendar days
after startup of the source, whichever is later, according to Sec.
63.7(a)(2)(ix).
    (e) For new or reconstructed affected boilers that have only
applicable work practice standards or management practices, you must
demonstrate initial compliance no later than the compliance date that
is specified in Sec.  63.11196 and according to the applicable
provisions in Sec.  63.7(a)(2). You are not required to complete an
initial performance tune-up for a new or reconstructed affected source,
but you are required to complete the applicable biennial or five-year
tune-up as specified in Sec.  63.11223(b), (c), and (d) no later than
25 months or 61 months, respectively, after the initial startup of the
new or reconstructed affected source.
* * * * *
    (g) For affected boilers that switch fuels or make a physical
modification to the boiler that result in the applicability of a
different subcategory, you must demonstrate compliance within 180 days
of the effective date of the fuel switch or physical modification
consistent with Sec.  63.11225(g).
    5. Section 63.11211 is amended by revising paragraph (b)(2) to read
as follows:

Sec.  63.11211  How do I demonstrate initial compliance with the
emission limits?

* * * * *
    (b) * * *
    (2) For an electrostatic precipitator operated with a wet scrubber,
you must establish the minimum secondary voltage and secondary amperage
(or total secondary electric power input), as defined in Sec.
63.11237, as your operating limits during the three-run performance
stack test.
* * * * *
    6. Section 63.11212 is amended by revising paragraph (b) to read as
follows:

Sec.  63.11212  What stack tests and procedures must I use for the
performance tests?

* * * * *
    (b) You must conduct each stack test according to the requirements
in Table 4 to this subpart. Boilers that use a continuous emission
monitoring system for carbon monoxide are exempt from the initial
carbon monoxide performance testing in Table 4 to this subpart and the
oxygen concentration operating limit requirement specified in Table 3
to this subpart.
* * * * *
    7. Section 63.11214 is amended by revising paragraph (c) to read as
follows:

Sec.  63.11214  How do I demonstrate initial compliance with the work
practice standard, emission reduction measures, and management
practice?

* * * * *
    (c) If you own or operate an existing affected boiler with a heat
input capacity of 10 million Btu per hour or greater, you must submit a
signed certification in the Notification of Compliance Status report
that an energy assessment of the boiler and its energy use systems was
completed according to Table 2 to this subpart and is an accurate
depiction of your facility.
* * * * *
    8. Section 63.11220 is amended by revising paragraphs (a) and (b)
and removing paragraphs (c), (d), and (f).
    The revisions read as follows:

Sec.  63.11220  When must I conduct subsequent performance tests?

    (a) If your boiler has a heat input capacity of 10 million Btu per
hour or greater, you must conduct all applicable performance (stack)
tests according to Sec.  63.11212 on a triennial basis. Triennial
performance tests must be completed no more than 37 months after the
previous performance test.
    (b) If you demonstrate compliance with the mercury emission limit
based on fuel analysis, you must conduct a fuel analysis according to
Sec.  63.11213 for each type of fuel burned monthly. If you plan to
burn a new type of fuel or fuel mixture, you must conduct a fuel
analysis before burning the new type of fuel or mixture in your boiler.
You must recalculate the mercury emission rate using Equation 1 of
Sec.  63.11211. The recalculated mercury emission rate must be less
than the applicable emission limit.
    9. Section 63.11221 is amended by revising the section heading, and
paragraphs (a), (b), and (d) to read as follows:

Sec.  63.11221  Is there a minimum amount of monitoring data I must
obtain?

    (a) You must monitor and collect data according to this section and
the site-specific monitoring plan required by Sec.  63.11205(c).
    (b) You must operate the monitoring system and collect data at all
required intervals at all times the affected source is operating and
compliance is required, except for periods of monitoring system
malfunctions or out-of-control periods (see Sec.  63.8(c)(7) of this
part), repairs associated with monitoring system malfunctions or out-
of-control periods, and required monitoring system quality assurance or
quality control activities

including, as applicable, calibration checks and required zero and span
adjustments. A monitoring system malfunction is any sudden, infrequent,
not reasonably preventable failure of the monitoring system to provide
valid data. Monitoring system failures that are caused in part by poor
maintenance or careless operation are not malfunctions. You are
required to effect monitoring system repairs in response to monitoring
system malfunctions or out-of-control periods and to return the
monitoring system to operation as expeditiously as practicable.
* * * * *
    (d) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required monitoring
system quality assurance or quality control activities including, as
applicable, calibration checks and required zero and span adjustments,
failure to collect required data is a deviation of the monitoring
requirements.
    10. Section 63.11223 is amended by revising paragraphs (a), (b)
introductory text, (b)(5), (b)(6) introductory text, (b)(6)(iii), and
(c), and adding paragraphs (d) and (e) to read as follows:

Sec.  63.11223  How do I demonstrate continuous compliance with the
work practice and management practice standards?

    (a) For affected sources subject to the work practice standard or
the management practices of a tune-up, you must conduct a performance
tune-up according to paragraph (b) of this section and keep records as
required in Sec.  63.11225(c) to demonstrate continuous compliance.
    (b) Except as specified in paragraphs (c) and (d) of this section,
you must conduct a tune-up of the boiler biennially to demonstrate
continuous compliance as specified in paragraphs (b)(1) through (7) of
this section. Each biennial tune-up must be conducted no more than 25
months after the previous tune-up. For a new or reconstructed boiler,
the first biennial tune-up must be no later than 25 months after the
initial startup of the new or reconstructed boiler.
* * * * *
    (5) Measure the concentrations in the effluent stream of carbon
monoxide in parts per million, by volume, and oxygen in volume percent,
before and after the adjustments are made (measurements may be either
on a dry or wet basis, as long as it is the same basis before and after
the adjustments are made). You must conduct the tune-up while burning
the type of fuel that provided the majority of the heat input to the
boiler over the 12 months prior to the tune-up.
    (6) Maintain onsite and submit, if requested by the Administrator,
a report containing the information in paragraphs (b)(6)(i) through
(iii) of this section.
* * * * *
    (iii) The type and amount of fuel used over the 12 months prior to
the tune-up of the boiler, but only if the unit was physically and
legally capable of using more than one type of fuel during that period.
Units sharing a fuel meter may estimate the fuel use by each unit.
* * * * *
    (c) Seasonal boilers must complete a tune-up every five years as
specified in paragraphs (b)(1) through (7) of this section. Each five-
year tune-up must be conducted no more than 61 months after the
previous tune-up. For a new or reconstructed seasonal boiler, the first
five-year tune-up must be no later than 61 months after the initial
startup.
    (d) Oil-fired boilers with a heat input capacity of equal to or
less than 5 million Btu per hour must complete a tune-up every five
years as specified in paragraphs (b)(1) through (7) of this section.
Each five-year tune-up must be conducted no more than 61 months after
the previous tune-up. For a new or reconstructed oil-fired boiler with
a heat input capacity of equal to or less than 5 million Btu per hour,
the first five-year tune-up must be no later than 61 months after the
initial startup. You may delay the burner inspection specified in
paragraph (b)(1) of this section until the next scheduled unit
shutdown, but you must inspect each burner at least once every 72
months.
    (e) If you own or operate an existing or new coal-fired boiler, a
new biomass-fired boiler, or a new oil-fired boiler with a heat input
capacity of 10 million Btu per hour or greater, you must minimize the
boiler's time spent during startup and shutdown following the
manufacturer's recommended procedures and you must submit a signed
statement in the Notification of Compliance Status report that
indicates that you conducted startups and shutdowns according to the
manufacturer's recommended procedures.
    11. Section 63.11224 is amended by revising paragraphs (a)
introductory text, (a)(1), (a)(2), (a)(5), (a)(6), (c)(1) introductory
text, and (c)(2) introductory text, and adding paragraph (a)(7) to read
as follows:

Sec.  63.11224  What are my monitoring, installation, operation, and
maintenance requirements?

    (a) If your boiler is subject to a carbon monoxide emission limit
in Table 1 to this subpart, you must either install, operate, and
maintain a CEMS for CO and oxygen according to the procedures in
paragraphs (a)(1) through (6) of this section, or install, operate, and
maintain a continuous oxygen analyzer system as defined in Sec.
63.11237 according to paragraphs (a)(7) and (d) of this section by the
compliance date specified in Sec.  63.11196. The CEMS for CO and oxygen
shall be monitored at the same location at the outlet of the boiler.
Boilers that use a CEMS for CO are exempt from the initial CO
performance testing and oxygen concentration operating limit
requirements specified in Sec.  63.11211(a) of this subpart.
    (1) Each CO CEMS must be installed, operated, and maintained
according to the applicable procedures under Performance Specification
4, 4A, or 4B at 40 CFR part 60, appendix B, and each oxygen CEMS must
be installed, operated, and maintained according to Performance
Specification 3 at 40 CFR part 60, appendix B. Both the CO and oxygen
CEMS must also be installed, operated, and maintained according to the
site-specific monitoring plan developed according to paragraph (c) of
this section.
    (2) You must conduct a performance evaluation of each CEMS
according to the requirements in Sec.  63.8(e) and according to
Performance Specifications 3 and 4, 4A, or 4B at 40 CFR part 60,
appendix B.
* * * * *
    (5) You must calculate one-hour arithmetic averages, corrected to 3
percent oxygen from each hour of CO CEMS data in parts per million CO
concentrations. The one-hour arithmetic averages required shall be used
to calculate the boiler operating day daily arithmetic average
emissions. Calculate a 10-day rolling average from the daily averages.
Use Equation 19-19 in section 12.4.1 of Method 19 of 40 CFR part 60,
appendix A-7 for calculating the average carbon monoxide concentration
from the hourly values.
    (6) For purposes of calculating data averages, you must use all the
data collected during all periods in assessing compliance, excluding
data collected during periods when the monitoring system malfunctions
or is out of control, during associated repairs, and during required
quality assurance or control activities (including, as applicable,
calibration checks and required zero and span adjustments). Monitoring
failures that are caused in part by poor

maintenance or careless operation are not malfunctions. Any period for
which the monitoring system is out of control and data are not
available for a required calculation constitutes a deviation from the
monitoring requirements. Periods when data are unavailable because of
required quality assurance or control activities (including, as
applicable, calibration checks and required zero and span adjustments)
do not constitute monitoring deviations.
    (7) You must operate the oxygen analyzer system with the oxygen
level set at the minimum percent oxygen by volume that is established
as the operating limit for oxygen according to Table 4 to this subpart.
    (c) * * *
    (1) For each continuous monitoring system (CMS) required in this
section, you must develop, and submit to the EPA Administrator for
approval upon request, a site-specific monitoring plan that addresses
paragraphs (c)(1)(i) through (iii) of this section. You must submit
this site-specific monitoring plan (if requested) at least 60 days
before your initial performance evaluation of your CMS.
* * * * *
    (2) In your site-specific monitoring plan, you must also address
paragraphs (c)(2)(i) through (iii) of this section.
* * * * *
    12. Section 63.11225 is amended by revising paragraphs (b)
introductory text, (b)(2), (c)(2) introductory text, (c)(2)(ii), (d),
and (g) and by adding (c)(2)(iii) through (v) to read as follows:

Sec.  63.11225   What are my notification, reporting, and
recordkeeping, requirements

* * * * *
    (b) You must prepare, by March 1 of each year, and submit to the
delegated authority upon request, an annual compliance certification
report for the previous calendar year containing the information
specified in paragraphs (b)(1) through (4) of this section. You must
submit the report by March 15 if you had any instance described by
paragraph (b)(3) of this section. For boilers that are subject only to
a requirement to conduct a biennial or five-year tune-up according to
Sec.  63.11223(a) and not subject to emission limits or operating
limits, you may prepare only a biennial or five-year compliance report
as specified in paragraphs (b)(1) and (2) of this section.
* * * * *
    (2) Statement by a responsible official, with the official's name,
title, phone number, email address, and signature, certifying the
truth, accuracy and completeness of the notification and a statement of
whether the source has complied with all the relevant standards and
other requirements of this subpart. Your notification must include the
following certification(s) of compliance, as applicable, and signed by
a responsible official:
    (i) ``This facility complies with the requirements in Sec.
63.11223 to conduct a biennial or five-year tune-up, as applicable, of
each boiler.''
    (ii) For units that do not qualify for a statutory exemption as
provided in section 129(g)(1) of the Clean Air Act: ``No secondary
materials that are solid waste were combusted in any affected unit.''
    (iii) ``This facility complies with the requirement in Sec.
63.11223(c) to minimize the boiler's time spent during startup and
shutdown following the manufacturer's recommended procedures.''
* * * * *
    (c) * * *
    (2) You must keep records to document conformance with the work
practices, emission reduction measures, and management practices
required by Sec.  63.11214 as specified in paragraphs (c)(2)(i) through
(v) of this section.
* * * * *
    (ii) Records documenting the fuel type(s) used monthly by each
boiler, including whether the fuel has received a non-waste
determination by you or the EPA. If you combust non-hazardous secondary
materials that have been determined not to be solid waste pursuant to
Sec.  241.3(b)(1), you must keep a record which documents how the
secondary material meets each of the legitimacy criteria. If you
combust a fuel that has been processed from a discarded non-hazardous
secondary material pursuant to Sec.  241.3(b)(4), you must keep records
as to how the operations that produced the fuel satisfies the
definition of processing in Sec.  241.2. If the fuel received a non-
waste determination pursuant to the petition process submitted under
Sec.  241.3(c), you must keep a record that documents how the fuel
satisfies the requirements of the petition process.
    (iii) For each boiler required to conduct an energy assessment, you
must keep a copy of the energy assessment report.
    (iv) For each boiler subject to an emission limit in Table 1 to
this subpart, you must also keep records of monthly fuel use by each
boiler, including the type(s) of fuel and amount(s) used.
    (v) You must keep records of days of operation by each boiler that
meets the definition of seasonal boiler.
* * * * *
    (d) Your records must be in a form suitable and readily available
for expeditious review. You must keep each record for 5 years following
the date of each recorded action. You must keep each record onsite or
be accessible from a central location by computer or other means that
instantly provide access at the site for at least 2 years after the
date of each recorded action. You may keep the records off site for the
remaining 3 years.
* * * * *
    (g) If you intend to switch fuels or make a physical change to the
boiler, and this fuel switch or change may result in the applicability
of a different subcategory or a switch out of subpart JJJJJJ due to a
switch to 100 percent natural gas, you must provide 30 days prior
notice of the date upon which you will switch fuels. The notification
must identify:
    (1) The name of the owner or operator of the affected source, the
location of the source, the boiler(s) that will switch fuels or be
physically modified, and the date of the notice.
    (2) The currently applicable subcategory under this subpart.
    (3) The date on which you became subject to the currently
applicable standards.
    (4) The date upon which you will commence the fuel switch or
modification.
    13. Section 63.11237 is amended as follows:
    a. By adding new definitions in alphabetical order for ``30-day
rolling average,'' ``Calendar year,'' ``Daily block average,''
``Electric boiler,'' ``Electric utility steam generating unit (EGU),''
``Minimum total secondary electric power,'' ``Oxygen analyzer system,''
``Oxygen trim system,'' ``Process heater,'' ``Residential boiler,''
``Seasonal boiler,'' ``Shutdown,'' ``Startup,'' and ``Temporary
boiler.''
    b. By revising the definitions for ``Annual heat input basis,''
``Biomass subcategory,'' ``Boiler,'' ``Energy assessment,'' ``Gas-fired
boiler,'' ``Hot water heater,'' ``Institutional boiler,'' ``Oil
subcategory,'' ``Period of natural gas curtailment or supply
interruption,'' ``Qualified Energy Assessor,'' and ``Waste heat
boiler.''
    c. By removing the definition for ``Minimum voltage or amperage.''
    The additions and revisions read as follows:

Sec.  63.11237  What definitions apply to this subpart?

* * * * *
    30-day rolling average means the arithmetic mean of all valid data
from 30 successive operating days that is

calculated for each operating day using the data from that operating
day and the previous 29 operating days.
* * * * *
    Annual heat input basis means the heat input for the calendar year
preceding the compliance demonstration.
* * * * *
    Biomass subcategory includes any boiler that burns any biomass and
is not in the coal subcategory.
    Boiler means an enclosed device using controlled flame combustion
in which water is heated to recover thermal energy in the form of steam
and/or hot water. Controlled flame combustion refers to a steady-state,
or near steady-state, process wherein fuel and/or oxidizer feed rates
are controlled. A device combusting solid waste, as defined in Sec.
241.3, is not a boiler unless the device is exempt from the definition
of a solid waste incineration unit as provided in section 129(g)(1) of
the Clean Air Act. Waste heat boilers and process heaters are excluded
from this definition.
* * * * *
    Calendar year means the period between January 1 and December 31,
inclusive, for a given year.
* * * * *
    Daily block average means the arithmetic mean of all valid emission
concentrations or parameter levels recorded when a unit is operating
measured over the 24-hour period from 12 a.m. (midnight) to 12 a.m.
(midnight).
* * * * *
    Electric boiler means a boiler in which electric heating serves as
the source of heat. Electric boilers that burn gaseous or liquid fuel
during periods of electrical power curtailment or failure are included
in this definition.
    Electric utility steam generating unit (EGU) means a fossil fuel-
fired combustion unit of more than 25 megawatts that serves a generator
that produces electricity for sale. A fossil fuel-fired unit that
cogenerates steam and electricity and supplies more than one-third of
its potential electric output capacity and more than 25 megawatts
electrical output to any utility power distribution system for sale is
considered an electric utility steam generating unit. To be ``capable
of combusting'' fossil fuels, an EGU would need to have these fuels
allowed in their operating permits and have the appropriate fuel
handling facilities on-site or otherwise available (e.g., coal handling
equipment, including coal storage area, belts and conveyers,
pulverizers, etc.; oil storage facilities). In addition, fossil fuel-
fired EGU means any EGU that fired fossil fuel for more than 10.0
percent of the average annual heat input in any 3 consecutive calendar
years or for more than 15.0 percent of the annual heat input during any
one calendar year after (COMPLIANCE DATE OF THE FINAL EGU RULE].
* * * * *
    Energy assessment means the following only as this term is used in
Table 2 to this subpart:
    (1) Energy assessment for facilities with affected boilers using
less than 0.3 trillion Btu (TBtu) per year heat input will be 8
technical labor hours in length maximum, but may be longer at the
discretion of the owner or operator of the affected source. The boiler
system and on-site energy use system accounting for at least 50 percent
of the affected boiler(s) energy output will be evaluated to identify
energy savings opportunities, within the limit of performing an 8-hour
energy assessment.
    (2) Energy assessment for facilities with affected boilers using
0.3 to 1 TBtu/year will be 24 technical labor hours in length maximum,
but may be longer at the discretion of the owner or operator of the
affected source. The boiler system(s) and any on-site energy use
system(s) accounting for at least 33 percent of the affected boiler(s)
energy output will be evaluated to identify energy savings
opportunities, within the limit of performing a 24-hour energy
assessment.
    (3) Energy assessment for facilities with affected boilers using
greater than 1.0 TBtu/year, the boiler system(s) and any on-site energy
use system(s) accounting for at least 20 percent of the affected
boiler(s) energy output will be evaluated to identify energy savings
opportunities.
* * * * *
    Gas-fired boiler includes any boiler that burns gaseous fuels not
combined with any solid fuels, burns liquid fuel only during periods of
gas curtailment, gas supply interruption, startups, or periodic testing
on liquid fuel. Periodic testing of liquid fuel shall not exceed a
combined total of 48 hours during any calendar year.
* * * * *
    Hot water heater means a closed vessel with a capacity of no more
than 120 U.S. gallons in which water is heated by combustion of gaseous
or liquid fuel and hot water is withdrawn for use external to the
vessel. Hot water boilers (i.e., not generating steam) combusting
gaseous or liquid fuel with a heat input capacity of less than 1.6
million Btu per hour are included in this definition.
* * * * *
    Institutional boiler means a boiler used in institutional
establishments such as, but not limited to, medical centers, nursing
homes, research centers, institutions of higher education, elementary
and secondary schools, libraries, religious establishments, and
governmental buildings to provide electricity, steam, and/or hot water.
* * * * *
    Liquid fuel includes, but is not limited to, distillate oil,
residual oil, any form of liquid fuel derived from petroleum, on-spec
used oil, liquid biofuels, biodiesel, and vegetable oil.
* * * * *
    Minimum total secondary electric power means the lowest hourly
average total secondary electric power determined from the values of
secondary voltage and secondary current to the electrostatic
precipitator measured according to Table 6 to this subpart during the
most recent performance test demonstrating compliance with the
applicable emission limits.
* * * * *
    Oil subcategory includes any boiler that burns any liquid fuel and
is not in either the biomass or coal subcategories. Gas-fired boilers
that burn liquid fuel only during periods of gas curtailment, gas
supply interruptions, startups, or for periodic testing are not
included in this definition. Periodic testing on liquid fuel shall not
exceed a combined total of 48 hours during any calendar year..
* * * * *
    Oxygen analyzer system means all equipment required to determine
the oxygen content of a gas stream and used to monitor oxygen in the
boiler flue gas or firebox. This definition includes oxygen trim
systems. The source owner or operator is responsible to install,
calibrate, maintain, and operate the oxygen analyzer system in
accordance with the manufacturer's recommendations.
    Oxygen trim system means a system of monitors that is used to
maintain excess air at the desired level in a combustion device. A
typical system consists of a flue gas oxygen and/or carbon monoxide
monitor that automatically provide a feedback signal to the combustion
air controller.
    Period of gas curtailment or supply interruption means a period of
time during which the supply of gaseous fuel to an affected facility is
halted for reasons beyond the control of the facility. The act of
entering into a contractual agreement with a supplier of

natural gas established for curtailment purposes does not constitute a
reason that is under the control of a facility for the purposes of this
definition. An increase in the cost or unit price of natural gas due to
normal market fluctuations not during periods of supplier delivery
restriction does not constitute a period of natural gas curtailment or
supply interruption. On-site gaseous fuel system emergencies or
equipment failures may qualify as periods of supply interruption when
the emergency or failure is beyond the control of the facility.
    Process heater means an enclosed device using controlled flame, and
the unit's primary purpose is to transfer heat indirectly to a process
material (liquid, gas, or solid; raw, intermediate or finished) or to a
heat transfer material (e.g., glycol or a mixture of glycol and water)
for use in a process unit, instead of generating steam. Process heaters
are devices in which the combustion gases do not come into direct
contact with process materials. Process heaters include units that heat
water/water mixtures for pool heating, sidewalk heating, cooling tower
water heating, power washing, or oil heating.
    Qualified Energy Assessor means:
    (1) Someone who has demonstrated capabilities to evaluate energy
savings opportunities for steam generation and major energy using
systems, including, but not limited to:
    (i) Boiler combustion management.
    (ii) Boiler thermal energy recovery, including
    (A) Conventional feed water economizer.
    (B)Conventional combustion air preheater, and
    (C)Condensing economizer.

    (iii) Boiler blowdown thermal energy recovery.
    (iv) Primary energy resource selection, including
    (A) Fuel (primary energy source) switching, and
    (B) Applied steam energy versus direct-fired energy versus
electricity.

    (v) Insulation issues.
    (vi) Steam trap and steam leak management.
    (vii) Condensate recovery.
    (viii) Steam end-use management.
    (2) Capabilities and knowledge includes, but is not limited to:
    (i) Background, experience, and recognized abilities to perform the
assessment activities, data analysis, and report preparation.
    (ii) Familiarity with operating and maintenance practices for steam
or process heating systems.
    (iii) Additional potential steam system improvement opportunities
including improving steam turbine operations and reducing steam demand.
    (iv) Additional process heating system opportunities including
effective utilization of waste heat and use of proper process heating
methods.
    (v) Boiler-steam turbine cogeneration systems.
    (vi) Industry specific steam end-use systems.

    Residential boiler means a boiler used in a dwelling containing
four or fewer family units to provide heat and/or hot water. This
definition includes boilers used primarily to provide heat and/or hot
water for a dwelling containing four or fewer families located at an
institutional facility (e.g., university campus, military base, church
grounds) or commercial/industrial facility (e.g., farm).
* * * * *
    Seasonal boiler means a boiler that undergoes a shutdown for a
period of at least 7 consecutive months (or 210 consecutive days) due
to seasonal market conditions.
    Shutdown means the period that begins when the boiler last operates
at 25 percent load and ending with a state of no fuel combustion in the
boiler.
* * * * *
    Startup means the period between the state of no combustion in the
boiler to the period where the boiler first achieves 25 percent load
(i.e., a cold start).
    Temporary boiler means any gaseous or liquid fuel boiler that is
designed to, and is capable of, being carried or moved from one
location to another by means of, for example, wheels, skids, carrying
handles, dollies, trailers, or platforms. A boiler is not a temporary
boiler if any one of the following conditions exists:
    (1) The equipment is attached to a foundation.
    (2) The boiler or a replacement remains at a location for more than
12 consecutive months. Any temporary boiler that replaces a temporary
boiler at a location and performs the same or similar function will be
included in calculating the consecutive time period.
    (3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least 2 years, and operates at that
facility for at least 3 months each year.
    (4) The equipment is moved from one location to another in an
attempt to circumvent the residence time requirements of this
definition.
* * * * *
    Waste heat boiler means a device that recovers normally unused
energy and converts it to usable heat. Waste heat boilers are also
referred to as heat recovery steam generators. This definition includes
both fired and unfired waste heat boilers.
* * * * *
    14. Tables 1, 2, 3, 6, and 7 to subpart JJJJJJ are revised to read
as follows:
    As stated in Sec.  63.11201, you must comply with the following
applicable emission limits:

                              Table 1 to Subpart JJJJJJ of Part 63--Emission Limits
----------------------------------------------------------------------------------------------------------------
                                                                      You must achieve less than or equal to the
If your boiler is in this subcategory *       For the following        following emission limits, except during
                  * *                         pollutants * * *          periods of startup and shutdown * * *
----------------------------------------------------------------------------------------------------------------
1. New coal-fired boiler with heat       a. Particulate Matter       0.03 lb per MMBtu of heat input.
 input capacity of 30 million Btu per     (Filterable).
 hour or greater.
                                         b. Mercury................  0.000022 lb per MMBtu of heat input.
                                         c. Carbon Monoxide........  420 ppm by volume on a dry basis corrected
                                                                      to 3 percent oxygen (3-run average or 10-
                                                                      day rolling average).
2. New coal-fired boiler with heat       a. Particulate Matter       0.42 lb per MMBtu of heat input.
 input capacity of between 10 and 30      (Filterable).
 million Btu per hour.
                                         b. Mercury................  0.000022 lb per MMBtu of heat input.
                                         c. Carbon Monoxide........  420 ppm by volume on a dry basis corrected
                                                                      to 3 percent oxygen (3-run average or 10-
                                                                      day rolling average).

3. New biomass-fired boiler with heat    a. Particulate Matter       0.03 lb per MMBtu of heat input.
 input capacity of 30 million Btu per     (Filterable).
 hour or greater.
4. New biomass fired boiler with heat    a. Particulate Matter       0.07 lb per MMBtu of heat input.
 input capacity of between 10 and 30      (Filterable).
 million Btu per hour.
5. New oil-fired boiler with heat input  a. Particulate Matter       0.03 lb per MMBtu of heat input.
 capacity of 10 million Btu per hour or   (Filterable).
 greater.
6. Existing coal (units with heat input  a. Mercury................  0.000022 lb per MMBtu of heat input.
 capacity of 10 million Btu per hour or
 greater).
                                         b. Carbon Monoxide........  420 ppm by volume on a dry basis corrected
                                                                      to 3 percent oxygen.
----------------------------------------------------------------------------------------------------------------

    As stated in Sec.  63.11201, you must comply with the following
applicable work practice standards, emission reduction measures, and
management practices:

 Table 2 to Subpart JJJJJJ of Part 63--Work Practice Standards, Emission