```

[Federal Register Volume 76, Number 247 (Friday, December 23, 2011)]
[Proposed Rules]
[Pages 80532-80552]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-31644]

[[Page 80531]]

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

[[Page 80532]]

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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 (919) 541-7966 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: a-and-r-Docket@epa.gov, Attention Docket ID No. 
EPA-HQ-OAR-2006-0790.
     Fax: (202) 566-9744, 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 (202) 566-1744, and the telephone number for the 
Docket Center is (202) 566-1742.

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: (919) 541-5450; email address: 
eddinger.jim@epa.gov.

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

[[Page 80533]]

    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:

------------------------------------------------------------------------
                                                   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.
------------------------------------------------------------------------
\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,

[[Page 80534]]

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

[[Page 80535]]

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

[[Page 80536]]

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 (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

[[Page 80537]]

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

[[Page 80538]]

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.

[[Page 80539]]

 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),

[[Page 80540]]

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

[[Page 80541]]

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

[[Page 80542]]

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

[[Page 80543]]

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.

[[Page 80544]]

    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

[[Page 80545]]

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

[[Page 80546]]

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

[[Page 80547]]

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

[[Page 80548]]

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).

[[Page 80549]]

 
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
              Reduction Measures, and Management Practices
------------------------------------------------------------------------
   If your boiler is in this
       subcategory * * *            You must meet the following * * *
------------------------------------------------------------------------
1. Existing or new coal, new     Minimize the boiler's startup and
 biomass, and new oil (units      shutdown periods following the
 with heat input capacity of 10   manufacturer's recommended procedures.
 million Btu per hour or          If manufacturer's recommended
 greater).                        procedures are not available, you must
                                  follow recommended procedures for a
                                  unit of similar design for which
                                  manufacturer's recommended procedures
                                  are available.
2. Existing coal (units with     Conduct an initial tune-up as specified
 heat input capacity of less      in Sec.   63.11214, and conduct a tune-
 than 10 million Btu per hour).   up of the boiler biennially as
                                  specified in Sec.   63.11223.
3. New coal (units with heat     Conduct a tune-up of the boiler
 input capacity of less than 10   biennially as specified in Sec.
 million Btu per hour).           63.11223.
4. Existing oil-fired boilers    Conduct an initial tune-up as specified
 with heat input capacity         in Sec.   63.11214, and conduct a tune-
 greater than 5 million Btu per   up of the boiler biennially as
 hour, and all existing biomass-  specified in Sec.   63.11223.
 fired boilers.
5. New oil-fired boilers with    Conduct a tune-up of the boiler
 heat input capacity greater      biennially as specified in Sec.
 than 5 million Btu per hour,     63.11223.
 and all new biomass-fired
 boilers.
6. Existing seasonal boilers...  Conduct an initial tune-up as specified
                                  in Sec.   63.11214, and conduct a tune-
                                  up of the boiler every five years as
                                  specified in Sec.   63.11223.
7. New seasonal boilers........  Conduct a tune-up of the boiler every
                                  five years as specified in Sec.
                                  63.11223.
8. Existing oil-fired boiler     Conduct an initial tune-up as specified
 with heat input capacity of      in Sec.   63.11214, and conduct a tune-
 equal to or less than 5          up of the boiler every five years as
 million Btu per hour.            specified in Sec.   63.11223.
9. New oil-fired boiler with     Conduct a tune-up of the boiler every
 heat input capacity of equal     five years as specified in Sec.
 to or less than 5 million Btu    63.11223.
 per hour.
10. Existing coal, biomass, or   Must have a one-time energy assessment
 oil (units with heat input       performed by a qualified energy
 capacity of 10 million Btu per   assessor. An energy assessment
 hour and greater).               completed on or after January 1, 2008,
                                  that meets or is amended to meet the
                                  energy assessment requirements in this
                                  table satisfies the energy assessment
                                  requirement.
                                 The energy assessment must include:
                                 (1) A visual inspection of the boiler
                                  system.
                                 (2) An evaluation of operating
                                  characteristics of the facility,
                                  specifications of energy using
                                  systems, operating and maintenance
                                  procedures, and unusual operating
                                  constraints.
                                 (3) Inventory of major systems
                                  consuming energy from affected
                                  boiler(s).
                                 (4) A review of available architectural
                                  and engineering plans, facility
                                  operation and maintenance procedures
                                  and logs, and fuel usage.
                                 (5) A list of major energy conservation
                                  measures that are within the
                                  facility's control.
                                 (6) A list of the energy savings
                                  potential of the energy conservation
                                  measures identified.
                                 (7) A comprehensive report detailing
                                  the ways to improve efficiency, the
                                  cost of specific improvements,
                                  benefits, and the time frame for
                                  recouping those investments.
------------------------------------------------------------------------

    As stated in Sec.  63.11201, you must comply with the applicable 
operating limits:

[[Page 80550]]

 Table 3 to Subpart JJJJJJ of Part 63--Operating Limits for Boilers With
                             Emission Limits
------------------------------------------------------------------------
If you demonstrate compliance
   with applicable emission    You must meet these operating limit * * *
      limits using * * *
------------------------------------------------------------------------
1. Fabric filter control.....  a. Maintain opacity to less than or equal
                                to 10 percent opacity (daily block
                                average); OR
                               b. Install and operate a bag leak
                                detection system according to Sec.
                                63.11224 and operate the fabric filter
                                such that the bag leak detection system
                                alarm does not sound more than 5 percent
                                of the operating time during each 6-
                                month period.
2. Electrostatic precipitator  a. Maintain opacity to less than or equal
 control.                       to 10 percent opacity (daily block
                                average); OR
                               b. Maintain the 30-day rolling average
                                secondary electric power input of the
                                electrostatic precipitator at or above
                                the lowest 1-hour average secondary
                                electric power measured during the most
                                recent performance test demonstrating
                                compliance with the particulate matter
                                emission limitations.
3. Wet PM scrubber control...  Maintain the 30-day rolling average
                                pressure drop at or above the lowest 1-
                                hour average pressure drop across the
                                wet scrubber and the 30-day rolling
                                average liquid flow-rate at or above the
                                lowest 1-hour average liquid flow rate
                                measured during the most recent
                                performance test demonstrating
                                compliance with the PM emission
                                limitation.
4. Dry sorbent or carbon       Maintain the 30-day rolling average
 injection control.             sorbent or carbon injection rate at or
                                above the lowest 2-hour average sorbent
                                flow rate measured during the most
                                recent performance test demonstrating
                                compliance with the mercury emissions
                                limitation. When your boiler operates at
                                lower loads, multiply your sorbent or
                                carbon injection rate by the load
                                fraction (e.g., actual heat input
                                divided by the heat input during
                                performance stack test, for 50 percent
                                load, multiply the injection rate
                                operating limit by 0.5).
5. Any other add-on air        This option is for boilers that operate
 pollution control type.        dry control systems. Boilers must
                                maintain opacity to less than or equal
                                to 10 percent opacity (daily block
                                average).
6. Fuel analysis.............  Maintain the fuel type or fuel mixture
                                (annual average) such that the mercury
                                emission rates calculated according to
                                Sec.   63.11211(b) is less than the
                                applicable emission limits for mercury.
7. Performance stack testing.  For boilers that demonstrate compliance
                                with a performance stack test, maintain
                                the operating load of each unit such
                                that is does not exceed 110 percent of
                                the average operating load recorded
                                during the most recent performance stack
                                test.
8. Continuous Oxygen Monitor.  Maintain the 30-day rolling average
                                oxygen level at or above the lowest 1-
                                hour average oxygen level measured
                                during the most recent CO performance
                                stack test.
------------------------------------------------------------------------

* * * * *
    As stated in Sec.  63.11211, you must comply with the following 
requirements for establishing operating limits:

                       Table 6 to Subpart JJJJJJ of Part 63--Establishing Operating Limits
----------------------------------------------------------------------------------------------------------------
                                 And your operating                                            According to the
   If you have an applicable      limits are based     You must * * *        Using * * *          following
    emission limit for * * *          on * * *                                                   requirements
----------------------------------------------------------------------------------------------------------------
1. Particulate matter or         a. Wet scrubber     i. Establish a      (1) Data from the   (a) You must
 mercury.                         operating           site-specific       pressure drop and   collect pressure
                                  parameters.         minimum pressure    liquid flow rate    drop and liquid
                                                      drop and minimum    monitors and the    flow-rate data
                                                      flow rate           particulate         every 15 minutes
                                                      operating limit     matter or mercury   during the entire
                                                      according to Sec.   performance stack   period of the
                                                        63.11211(b).      test.               performance stack
                                                                                              tests;
                                 ..................  ..................  ..................  (b) Determine the
                                                                                              average pressure
                                                                                              drop and liquid
                                                                                              flow-rate for each
                                                                                              individual test
                                                                                              run in the three-
                                                                                              run performance
                                                                                              stack test by
                                                                                              computing the
                                                                                              average of all the
                                                                                              15-minute readings
                                                                                              taken during each
                                                                                              test run.
                                 b. Electrostatic    i. Establish a      (1) Data from the   (a) You must
                                  precipitator        site-specific       secondary           collect secondary
                                  operating           minimum secondary   electric power      electric power
                                  parameters.         electric power      monitors during     input data every
                                                      according to Sec.   the particulate     15 minutes during
                                                        63.11211(b).      matter or mercury   the entire period
                                                                          performance stack   of the performance
                                                                          test.               stack tests;
                                 ..................  ..................  ..................  (b) Determine the
                                                                                              secondary electric
                                                                                              power input for
                                                                                              each individual
                                                                                              test run in the
                                                                                              three-run
                                                                                              performance stack
                                                                                              test by computing
                                                                                              the average of all
                                                                                              the 15-minute
                                                                                              readings taken
                                                                                              during each test
                                                                                              run.
2. Mercury.....................  a. Activated        i. Establish a      (1) Data from the   (a) You must
                                  carbon injection.   site-specific       activated carbon    collect activated
                                                      minimum activated   rate monitors and   carbon injection
                                                      carbon injection    mercury             rate data every 15
                                                      rate operating      performance stack   minutes during the
                                                      limit according     tests.              entire period of
                                                      to Sec.                                 the performance
                                                      63.11211(b).                            stack tests;

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                                 ..................  ..................  ..................  (b) Determine the
                                                                                              average activated
                                                                                              carbon injection
                                                                                              rate for each
                                                                                              individual test
                                                                                              run in the three-
                                                                                              run performance
                                                                                              stack test by
                                                                                              computing the
                                                                                              average of all the
                                                                                              15-minute readings
                                                                                              taken during each
                                                                                              test run.
                                 ..................  ..................  ..................  (c) When your unit
                                                                                              operates at lower
                                                                                              loads, multiply
                                                                                              your activated
                                                                                              carbon injection
                                                                                              rate by the load
                                                                                              fraction (e.g.,
                                                                                              actual heat input
                                                                                              divided by heat
                                                                                              input during
                                                                                              performance stack
                                                                                              test, for 50
                                                                                              percent load,
                                                                                              multiply the
                                                                                              injection rate
                                                                                              operating limit by
                                                                                              0.5) to determine
                                                                                              the required
                                                                                              injection rate.
3. Carbon monoxide.............  a. Oxygen.........  i. Establish a      (1) Data from the   (a) You must
                                                      unit-specific       oxygen analyzer     collect oxygen
                                                      limit for minimum   system specified    data every 15
                                                      oxygen level.       in Sec.             minutes during the
                                                                          63.11224(a).        entire period of
                                                                                              the performance
                                                                                              stack tests;
                                 ..................  ..................  ..................  (b) Determine the
                                                                                              average hourly
                                                                                              oxygen
                                                                                              concentration for
                                                                                              each individual
                                                                                              test run in the
                                                                                              three-run
                                                                                              performance stack
                                                                                              test by computing
                                                                                              the average of all
                                                                                              the 15-minute
                                                                                              readings taken
                                                                                              during each test
                                                                                              run.
4. Any pollutant for which       a. Boiler           i. Establish a      (1) Data from the   (a) You must
 compliance is demonstrated by    operating load.     unit specific       operating load      collect operating
 a performance test.                                  limit for maximum   monitors (fuel      load data (fuel
                                                      operating load      feed monitors or    feed rate or steam
                                                      according to Sec.   from steam          generation data)
                                                        63.11212(c).      generation          every 15 minutes
                                                                          monitors).          during the entire
                                                                                              period of the
                                                                                              performance test.
                                 ..................  ..................  ..................  (b) Determine the
                                                                                              average operating
                                                                                              load by computing
                                                                                              the hourly
                                                                                              averages using all
                                                                                              of the 15-minute
                                                                                              readings taken
                                                                                              during each
                                                                                              performance test.
                                 ..................  ..................  ..................  (c) Determine the
                                                                                              average of the
                                                                                              three test run
                                                                                              averages during
                                                                                              the performance
                                                                                              test, and multiply
                                                                                              this by 1.1 (110
                                                                                              percent) as your
                                                                                              operating limit.
----------------------------------------------------------------------------------------------------------------

    As stated in Sec.  63.11222, you must show continuous compliance 
with the emission limitations for affected sources according to the 
following:

     Table 7 to Subpart JJJJJJ of Part 63--Demonstrating Continuous
                               Compliance
------------------------------------------------------------------------
 If you must meet the following      You must demonstrate continuous
     operating limits * * *                compliance by * * *
------------------------------------------------------------------------
1. Opacity.....................  a. Collecting the opacity monitoring
                                  system data according to Sec.
                                  63.11224(e) and Sec.   63.11221; and
                                 b. Reducing the opacity monitoring data
                                  to 6-minute averages; and
                                 c. Maintaining opacity to less than or
                                  equal to 10 percent (daily block
                                  average).
2. Fabric Filter Bag Leak        Installing and operating a bag leak
 Detection Operation.             detection system according to Sec.
                                  63.11224 and operating the fabric
                                  filter such that the requirements in
                                  Sec.   63.11222(a)(4) are met.
3. Wet Scrubber Pressure Drop    a. Collecting the pressure drop and
 and Liquid Flow-rate.            liquid flow rate monitoring system
                                  data according to Sec.  Sec.
                                  63.11224 and 63.11221; and
                                 b. Reducing the data to 30-day rolling
                                  averages; and
                                 c. Maintaining the 30-day rolling
                                  average pressure drop and liquid flow-
                                  rate at or above the operating limits
                                  established during the performance
                                  test according to Sec.   63.1140.
4. Dry Scrubber Sorbent or       a. Collecting the sorbent or carbon
 Carbon Injection Rate.           injection rate monitoring system data
                                  for the dry scrubber according to Sec.
                                   Sec.   63.11224 and 63.11220; and
                                 b. Reducing the data to 30-day rolling
                                  averages; and
                                 c. Maintaining the 30-day rolling
                                  average sorbent or carbon injection
                                  rate at or above the minimum sorbent
                                  or carbon injection rate as defined in
                                  Sec.   63.11237.
5. Electrostatic Precipitator    a. Collecting the total secondary
 Total Secondary Electric Power   electric power input monitoring system
 Input.                           data for the electrostatic
                                  precipitator according to Sec.  Sec.
                                  63.11224 and 63.11220; and
                                 b. Reducing the data to 30-day rolling
                                  averages; and
                                 c. Maintaining the 30-day rolling
                                  average total secondary electric power
                                  input at or above the operating limits
                                  established during the performance
                                  test according to Sec.   63.11214.
6. Fuel Pollutant Content......  a. Only burning the fuel types and fuel
                                  mixtures used to demonstrate
                                  compliance with the applicable
                                  emission limit according to Sec.
                                  63.11214 as applicable; and
                                 b. Keeping monthly records of fuel use
                                  according to Sec.   63.11222.

[[Page 80552]]

 
7. Oxygen content..............  a. Continuously monitor the oxygen
                                  content in the combustion exhaust
                                  according to Sec.   63.11224.
                                 b. Reducing the data to 30-day rolling
                                  averages; and
                                 c. Maintain the 30-day rolling average
                                  oxygen content at or above the
                                  operating limit established during the
                                  most recent carbon monoxide
                                  performance test.
8. Carbon monoxide emissions...  a. Continuously monitor the carbon
                                  monoxide concentration in the
                                  combustion exhaust according to Sec.
                                  63.11224(a).
                                 b. Correcting the data to 3 percent
                                  oxygen, and reducing the data to one-
                                  hour and daily block averages;
                                 c. Reducing the data from the daily
                                  averages to 10-day rolling averages;
                                 d. Maintain the 10-day rolling average
                                  carbon monoxide concentration at or
                                  below the applicable emission limit in
                                  Tables 1 of this subpart.
9. Boiler operating load.......  a. Collecting operating load data (fuel
                                  feed rate or steam generation data)
                                  every 15 minutes.
                                 b. Reducing the data to 30-day rolling
                                  averages; and
                                 c. Maintaining the 30-day rolling
                                  average at or below the operating
                                  limit established during the
                                  performance test according to Sec.
                                  63.11212(c).
------------------------------------------------------------------------

[FR Doc. 2011-31644 Filed 12-19-11; 8:45 am]
BILLING CODE 6560-50-P
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