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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.

**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 OilFired 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


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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:

Industry category NAICS code 1 Examples of regulated entities

Any area source facility using a boiler as defined in the final rule .. 321 Wood product manufacturing. 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,


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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. Wepromulgated final standards for coalfired 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, theywould be required to complete a tuneup every five years, instead of on abiennial basis as is required for nonseasonal boilers.

Agriculture industry representatives, specifically those from the sugar industry, noted that many boilers


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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 monoxideand oxygen as a component of the tuneup, 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 monoxideand oxygen as a component of the tuneup, 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


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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 tomeet the requirements of the rule, tuneups must, therefore, be completed by the compliance date for existing sources. For new units, we are proposing to remove the requirement for the initial tune-up. The EPA anticipates that new units will typically be tuned during the startup process. Thus, new units would be required to complete the applicable biennial (> 5MMBtu/h) or five-year ( ≤ 5MMBtu/h) tune-up no later than 25 months or 61 months, respectively, after the initial startup of
the new or reconstructed affected boiler.

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

Emission Limits

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


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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 oilfired 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 section112(c)(6). As such, we proposed MACTbased 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 forother HAP. Existing biomass and oilfired 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


### 80538 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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.)

2 [Citation to docket for the Earthjustice et al. petition.] 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 anychanges to the PM limits for new oilfired 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.

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.

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.


### 80539 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

TABLE 

### 1—M ISCELLANEOUS 

### T ECHNICAL 

### C ORRECTIONS TO 

### 40 CFR P ART 

### 63, S UBPART 

### 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 su ch 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 whichnew 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 timespent in startup and shutdown periods. 40 CFR 63.11224(c)(1) and (c)(2) ... Correcting a cross reference error. 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,’’ ‘‘Electricboiler,’’ ‘‘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 partic ulate 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),


### 80540 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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 redesignated 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 § 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 tuneup 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 unitsthat are only subject to a biennial tuneup. 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 onsite 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


### 80541 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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, themercury limit for new and existing coalfired boilers was 0.0000048 (4.8 × 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 ×

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


### 80542 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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. 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


### 80543 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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 § 605(c), the EPA is not required to complete an initial regulatory flexibility analysis for
this rule.

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 § 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.


### 80544 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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:

**§ 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:

**§ 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:

**§ 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 § 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 § 63.11196 and according to the applicable provisions in § 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 § 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 § 63.11225(g).

5. Section 63.11211 is amended by revising paragraph (b)(2) to read as
follows:

**§ 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 § 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:

**§ 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:

**§ 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:

**§ 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 § 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 § 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 § 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:

**§ 63.11221 Is there a minimum amount of monitoring data I must obtain?** 

(a) You must monitor and collect dataaccording to this section and the sitespecific monitoring plan required by § 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 § 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


### 80545 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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 tomonitoring system malfunctions or outof-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:

**§ 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 § 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 adjustmentsare made). You must conduct the tuneup 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 than5 million Btu per hour, the first fiveyear 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 existingor new coal-fired boiler, a new biomassfired 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: **§ 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 § 63.11237 according to paragraphs (a)(7) and (d) of this section by the compliance date specified in § 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 § 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 § 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


### 80546 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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:

**§ 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 § 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 § 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 § 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 § 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 § 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 § 241.3(b)(4), you must keep records as to how the operations that produced the fuel satisfies the definition of processing in § 241.2. If the fuel received a non-waste determination pursuant to the petition process submitted under § 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:

**§ 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


### 80547 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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 § 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 theappropriate fuel handling facilities onsite 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


### 80548 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

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 gascurtailment or supply interruption. Onsite 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 § 63.11201, you must comply with the following applicable
emission limits:



### TABLE 

### 1 TO 

### S UBPART 

### JJJJJJ OF 

### P ART 

### 63—E MISSION 

### L IMITS

If your boiler is in this subcategory * * * For the following pollutants * * * You must achieve less than or equal to the following emission limits, except during periods of startup and shutdown * * *

1. New coal-fired boiler with heat input

capacity of 30 million Btu per hour or greater. a. Particulate Matter (Filterable). 0.03 lb per MMBtu of heat input.

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 input

capacity of between 10 and 30 million Btu per hour. a. Particulate Matter (Filterable). 0.42 lb per MMBtu of heat input.

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).


### 80549 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

TABLE 

### 1 TO 

### S UBPART 

### JJJJJJ OF 

### P ART 

### 63—E MISSION 

### L IMITS

### —Continued

If your boiler is in this subcategory * * * For the following pollutants * * * You must achieve less than or equal to the following emission limits, except during periods of startup and shutdown * * *

3. New biomass-fired boiler with heat

input capacity of 30 million Btu per hour or greater. a. Particulate Matter (Filterable). 0.03 lb per MMBtu of heat input.

4. New biomass fired boiler with heat

input capacity of between 10 and 30 million Btu per hour. a. Particulate Matter (Filterable). 0.07 lb per MMBtu of heat input.

5. New oil-fired boiler with heat input capacity of 10 million Btu per hour or greater. a. Particulate Matter (Filterable). 0.03 lb per MMBtu of heat input.

6. Existing coal (units with heat input capacity of 10 million Btu per hour or greater). a. Mercury ............. 0.000022 lb per MMBtu of heat input.

b. Carbon Monoxide. 420 ppm by volume on a dry basis corrected to 3 percent oxygen.

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



### TABLE 

### 2 TO 

### S UBPART 

### JJJJJJ OF 

### P ART 

### 63—WORK 

### P RACTICE 

### S TANDARDS 

### , E MISSION 

### R EDUCTION 

### M EASURES



### , AND 

### M ANAGEMENT 

### P RACTICES

If your boiler is in this subcategory * * * You must meet the following * * *

1. Existing or new coal, new biomass, and

new oil (units with heat input capacity of 10 million Btu per hour or greater). Minimize the boiler’s startup and shutdown periods following the manufacturer’s recommendedprocedures. If manufacturer’s recommended 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 heat input capacity of less than 10 million Btu per hour). Conduct an initial tune-up as specified in § 63.11214, and conduct a tune-up of the boiler biennially as specified in § 63.11223. 3. New coal (units with heat input capacity

of less than 10 million Btu per hour). Conduct a tune-up of the boiler biennially as specified in § 63.11223.

4. Existing oil-fired boilers with heat input

capacity greater than 5 million Btu per hour, and all existing biomass-fired boilers. Conduct an initial tune-up as specified in § 63.11214, and conduct a tune-up of the boiler biennially as specified in § 63.11223.

5. New oil-fired boilers with heat input capacity greater than 5 million Btu per hour,
and all new biomass-fired boilers. Conduct a tune-up of the boiler biennially as specified in § 63.11223.

6. Existing seasonal boilers .......................... Conduct an initial tune-up as specified in § 63.11214, and conduct a tune- up of the boiler every five years as specified in § 63.11223. 7. New seasonal boilers ............................... Conduct a tune-up of the boiler every five years as specified in § 63.1122 3.8. Existing oil-fired boiler with heat input capacity of equal to or less than 5 million Btu per hour. Conduct an initial tune-up as specified in § 63.11214, and conduct a tune-up of the boiler every five years as specified in § 63.11223.

9. New oil-fired boiler with heat input capacity of equal to or less than 5 million Btu per hour. Conduct a tune-up of the boiler every five years as specified in § 63.11223.

10. Existing coal, biomass, or oil (units with

heat input capacity of 10 million Btu per hour and greater). Must have a one-time energy assessment performed by a qualified energy assessor. An energyassessment 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 § 63.11201, you must comply with the applicable operating
limits:


### 80550 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

TABLE 

### 3 TO 

### S UBPART 

### JJJJJJ OF 

### P ART 

### 63—O PERATING 

### L IMITS FOR 

### B OILERS 

### W ITH 

### E MISSION 

### L IMITS

If you demonstrate compliance with applicable emission limits using * * * You must meet these operating limit * * *

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 § 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 control. a. Maintain opacity to less than or equal 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 press ure dropacross 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 injection

control. Maintain the 30-day rolling average 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 themercury 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 pollution

control type. This option is for boilers that operate 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 emissi on rates calculated according to § 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 operatingload of eachunit 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 § 63.11211, you must comply with the following requirements for establishing operating limits:



### TABLE 

### 6 TO 

### S UBPART 

### JJJJJJ OF 

### P ART 

### 63—E STABLISHING 

### O PERATING 

### L IMITS

If you have an

applicable emission limit

for * * * And your operating limits are based on * * * You must * * * Using * * * According to the following requirements

1. Particulate

matter or

mercury. a. Wet scrubber operating parameters. i. Establish a site-specific minimum pressure dropand minimum flow rate operating limit according to § 63.11211(b). (1) Data from the pressure drop and liquid flow ratemonitors and the particulate matter or mercury performance stack test. (a) You must collect pressure drop and liquid flow-rate data every 15 minutes during the entire period of the performance stack tests;

....................... ............................................... ............................................... (b) Determ ine 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

precipitator operating parameters. i. Establish a site-specificminimum secondary electric power according to § 63.11211(b). (1) Data from the secondary electric power monitorsduring the particulate matter or mercury performance stack test. (a) You must collect secondary electric powerinput data every 15 minutes during the entire period of the performance stack tests;

....................... ............................................... ............................................... (b) Determ ine the secondary electric power input for each individual test run in thethree-run performance stack test by computing the average of all the 15-minute readings taken during each test run. 2. Mercury ...... a. Activated

carbon injection. i. Establish a site-specific

minimum activated carbon injection rate operating limit according to § 63.11211(b). (1) Data from the activated

carbon rate monitors and mercury performance

stack tests. (a) You must collect activated carbon injection rate data every 15 minutes during the entire period of the performance stack tests;


### 80551 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

TABLE 

### 6 TO 

### S UBPART 

### JJJJJJ OF 

### P ART 

### 63—E STABLISHING 

### O PERATING 

### L IMITS

### —Continued

If you have an

applicable emission limit

for * * * And your operating limits are based on * * * You must * * * Using * * * According to the following requirements

....................... ............................................... ............................................... (b) Determ ine the average activated carbon injection rate for each individual test run in thethree-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 theinjection rate operating limit by 0.5) to determine the required injection rate.
3. Carbon

monoxide. a. Oxygen ...... i. Establish a unit-specific limit for minimum oxygen

level. (1) Data from the oxygen analyzer system specified in § 63.11224(a). (a) You must collect oxygen data every 15minutes during the entire period of the performance stack tests; ....................... ............................................... ............................................... (b) Determ ine the average hourly oxygen concentration for each individual test run in thethree-run performance stack test by computing the average of all the 15-minute readings taken during each test run. 4. Any pollutant

for which compliance

is demonstrated bya performance test. a. Boiler operating load. i. Establish a unit specificlimit for maximum operating load according to § 63.11212(c). (1) Data from the operating load monitors (fuel feed
monitors or from steam generation monitors). (a) You must collect operating load data (fuel feed rate or steam generation data) every 15 minutes during the entire period of the performance test.

....................... ............................................... ............................................... (b) Determ ine the average operating load by computing the hourly averages using all of the 15-minute readings taken during each performance test. ....................... ............................................... ............................................... (c) Determ ine 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 § 63.11222, you must show continuous compliance with the emission limitations for affected sources according to the following:



### TABLE 

### 7 TO 

### S UBPART 

### JJJJJJ OF 

### P ART 

### 63—D EMONSTRATING 

### C ONTINUOUS 

### C OMPLIANCE

If you must meet the following operating limits * * * You must demonstrate continuous compliance by * * *

1. Opacity ......................................... a. Collecting the opacity monitoring system data according to § 63.11224(e) a nd § 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 Detection

Operation. Installing and operating a bag leak detection system according to § 63.11224 and operating the fabric filter such that the requirements in § 63.11222(a)(4) are met. 3. Wet Scrubber Pressure Drop and

Liquid Flow-rate. a. Collecting the pressure drop and liquid flow rate monitoring system data according to §§ 63.11224 and 63.11221; and b. Reducing the data to 30-day rolling averages; andc. 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 § 63.1140. 4. Dry Scrubber Sorbent or Carbon

Injection Rate. a. Collecting the sorbent or carbon injection rate monitoring system data for the dry scrubber according to §§ 63.11224 and 63.11220; and b. Reducing the data to 30-day rolling averages; andc. Maintaining the 30-day rolling average sorbent or carbon injection rate at or above the minimum sorbent or carbon injection rate as defined in § 63.11237. 5. Electrostatic Precipitator Total

Secondary Electric Power Input. a. Collecting the total secondary electric power input monitoring system data for the electrostatic precipitator according to §§ 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 § 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 § 63.11214 as applicable; and b. Keeping monthly records of fuel use according to § 63.11222.


### 80552 Federal Register / Vol. 76, No. 247 / Friday, December 23, 2011 / Proposed Rules

TABLE 

### 7 TO 

### S UBPART 

### JJJJJJ OF 

### P ART 

### 63—D EMONSTRATING 

### C ONTINUOUS 

### C OMPLIANCE

### —Continued

If you must meet the following operating limits * * * You must demonstrate continuous compliance by * * *

7. Oxygen content ............................ a. Continuously monitor the oxygen content in the combustion exhaust according to § 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 accordin g to § 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 1 5 minutes. b. Reducing the data to 30-day rolling averages; andc. Maintaining the 30-day rolling average at or below the operating limit established during the performance test according to § 63.11212(c).

[FR Doc. 2011–31644 Filed 12–19–11; 8:45 am]

**BILLING CODE 6560–50–P**