
[Federal Register Volume 78, Number 22 (Friday, February 1, 2013)]
[Rules and Regulations]
[Pages 7487-7522]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2012-31645]



[[Page 7487]]

Vol. 78

Friday,

No. 22

February 1, 2013

Part II





Environmental Protection Agency





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40 CFR Part 63





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

  Federal Register / Vol. 78 , No. 22 / Friday, February 1, 2013 / 
Rules and Regulations  

[[Page 7488]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2006-0790; FRL-9698-5]
RIN 2060-AR14


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule; notice of final action on reconsideration.

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SUMMARY: In this action, the EPA is taking final action on 
reconsideration of certain issues related to the emission standards to 
control hazardous air pollutants from new and existing industrial, 
commercial and institutional boilers at area sources which were issued 
under section 112 of the Clean Air Act. As part of this action, the EPA 
is amending certain compliance dates for the standard and making 
technical corrections to the final rule to clarify definitions, 
references, applicability and compliance issues raised by petitioners 
and other stakeholders affected by the rule. The EPA today is taking 
final action on the proposed reconsideration.

DATES: This final rule is effective on February 1, 2013. The 
incorporation by reference of certain publications listed in this final 
rule were approved by the Director of the Federal Register as of 
February 1, 2013.

ADDRESSES: The EPA established a single docket under Docket ID No. EPA-
HQ-OAR-2006-0790 for this action. All documents in the docket are 
listed on the http://www.regulations.gov Web site. Although listed in 
the index, some information is not publicly available, e.g., 
confidential business information or other information whose disclosure 
is restricted by statute. Certain other material, such as copyrighted 
material, is not placed on the Internet and will be publicly available 
only in hard copy form. Publicly available docket materials are 
available either electronically through http://www.regulations.gov or 
in hard copy at the EPA's Docket Center, Public Reading Room, EPA West 
Building, Room 3334, 1301 Constitution Avenue NW., Washington, DC 
20004. This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holidays. The telephone number for the 
Public Reading Room is (202) 566-1744, and the telephone number for the 
Air Docket is (202) 566-1741.

FOR FURTHER INFORMATION CONTACT: Ms. Mary Johnson, 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) 
541-5025; fax number: (919) 541-5450; email address: 
johnson.mary@epa.gov.

Executive Summary

Purpose of This Regulatory Action

    The EPA is taking final action on its proposed reconsideration of 
certain provisions of its March 21, 2011, final rule that established 
emission standards for the source category of new and existing 
industrial, commercial, and institutional boilers located at area 
source facilities listed pursuant to CAA sections 112(c)(3), 112(c)(6), 
and 112(k)(3)(B).
    Section 112(d) of the CAA requires the EPA to regulate HAP from 
both major and area stationary sources. Section 112(d)(5) of the CAA 
allows the EPA to establish standards for area sources of HAP ``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 serves as the basis for 
standards of most emissions from area source boilers, two pollutants 
emitted by coal-fired boilers, POM as 7-PAH and Hg, must be regulated 
based on the performance of MACT. These two pollutants are regulated 
based on MACT because area source industrial, commercial and 
institutional boilers combusting coal were listed under section 
112(c)(6) of the CAA due to the source categories' emissions of POM and 
Hg. Section 112(c)(6) requires the EPA to regulate sources listed 
pursuant to that provision by issuing standards under section 112(d)(2) 
or (d)(4). The final rule meets this requirement by setting MACT 
standards for Hg and CO (as a surrogate for POM) for units in the coal-
fired subcategory. Further, the final rule sets standards based on GACT 
for the urban HAP, other than Hg and POM, emitted from coal-fired 
boilers that pose the greatest public health risk, pursuant to section 
112(c)(3) of the CAA, including arsenic, beryllium, cadmium, lead, 
chromium, manganese, nickel, ethylene dioxide, and PCBs. In addition, 
the final rule sets standards based on GACT for boilers combusting oil 
or biomass for urban HAP, including Hg, arsenic, beryllium, cadmium, 
lead, chromium, manganese, nickel, POM, ethylene dioxide, and PCBs.
    In developing the MACT standards for coal-fired boilers, the EPA 
considered section 112(h) of the CAA, which allows the EPA to establish 
work practice standards in lieu of numerical emission limits under 
section 112(d)(2) only in cases where the agency determines that it is 
not feasible to prescribe or enforce an emission standard. The EPA has 
set work practice standards for emissions of Hg and POM from small 
coal-fired boilers, pursuant to section 112(h), in the form of periodic 
tune-ups.
    This final rule amends certain provisions of the final rule issued 
by EPA on March 11, 2011, and responds to petitions for reconsideration 
filed by a number of different entities.

Summary of Major Reconsideration Provisions

    In general, the final rule requires facilities classified as area 
sources of HAP with affected boilers to reduce emissions of harmful 
toxic air emissions from these combustion sources, improving air 
quality, and protecting public health in communities where these 
facilities are located.
    Recognizing the diversity of this source category and the multiple 
sectors of the economy this rule affects, the EPA is establishing seven 
subcategories for boilers based on the design of the combustion 
equipment and operating schedules of the unit. In addition to the coal, 
biomass, and oil subcategories in the March 2011 final rule, we are 
establishing subcategories for seasonal boilers, limited-use boilers, 
oil-fired boilers with heat input capacity of equal to or less than 5 
MMBtu/hr, and certain boilers that use a continuous oxygen trim system.
    Numerical emission limits, based on MACT, are established for Hg 
and CO at new and existing large coal-fired boilers (i.e., with a 
design heat input capacity of 10 MMBtu/hr or more). A review of the 
data has resulted in changes to the Hg and CO emission limits contained 
in the March 2011 final rule. The EPA is also establishing a CEMS 
alternative compliance option for the numeric CO emission limit. Coal-
fired boilers subject to a CO emission limit can comply with the limit 
using a periodic stack test and CPMS, or by using CEMS. The CO CEMS 
alternative compliance option is based on a 10-day rolling average and 
provides additional compliance flexibility to sources with existing CO 
CEMS equipment. New and existing small coal-fired units (i.e., with a 
design heat input capacity of less than 10 MMBtu/hr) are subject to 
periodic tune-up work practices for CO and Hg in lieu of numeric 
emission limits because the EPA found that it was technologically

[[Page 7489]]

and economically impracticable to apply measurement methodology to 
these small sources, pursuant to CAA section 112(h).
    Numerical emission limits, based on GACT, are established for PM as 
a surrogate for urban metal HAP other than Hg for new large coal-fired 
boilers. New and existing small coal-fired boilers are subject to 
periodic tune-up management practices for PM as a surrogate for urban 
metal HAP other than Hg, and for CO as a surrogate for urban organic 
HAP other than POM, based on GACT.
    New large biomass- and oil-fired boilers are subject to numerical 
emission limits for PM as a surrogate for urban metal HAP, based on 
GACT. Existing biomass and oil-fired boilers and new small biomass- and 
oil-fired boilers are subject to periodic tune-up management practices 
for PM as a surrogate for urban metal HAP, based on GACT. New and 
existing biomass- and oil-fired boilers are subject to periodic tune-up 
management practices for CO as a surrogate for urban organic HAP, based 
on GACT. Certain other subcategories (seasonal boilers, limited-use 
boilers, oil-fired boilers with heat input capacity of equal to or less 
than 5 MMBtu/hr, and boilers with an oxygen trim system) are subject to 
periodic tune-up work practice or management practice requirements 
tailored to their schedule of operation and types of fuel.
    The compliance date for existing sources is March 21, 2014. The 
compliance date for new sources that began operations on or before May 
20, 2011 is May 20, 2011. For new sources that start up after May 20, 
2011, the compliance date is the date of startup. New sources are 
defined as sources that began operation after June 4, 2010.

Costs and Benefits

    This final action is intended to clarify definitions, references, 
applicability and compliance issues, but not change the coverage of the 
final rule. The final rule will affect an estimated 180,000 existing 
area source boilers and the EPA projects that approximately an 
additional 6,800 new boilers will be subject to the rule over the 
initial 3-year period. The clarifications should make it easier for 
owners and operators and for local and state authorities to understand 
and implement the rule's requirements. As compared to the March 2011 
final rule, this final rule will not affect the estimated emission 
reductions, control costs or the benefits of the rule in substance. 
This final rule does not impose any additional regulatory requirements 
beyond those imposed by the previously promulgated boiler area source 
rule and, in fact, will result in a decrease in regulatory requirements 
for certain subcategories of boilers. A more detailed discussion of the 
costs and benefits of the March 2011 final rule is provided at 76 FR 
15579, March 21, 2011, and 76 FR 80542, December 23, 2011. Section VI 
of this preamble provides a discussion of the impacts of this final 
rule.

SUPPLEMENTARY INFORMATION:

    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

7-PAH 7-polynuclear aromatic hydrocarbons
ACI activated carbon injection
ASTM American Society for Testing and Materials
Btu British thermal unit
CO carbon monoxide
CEMS continuous emission monitoring system
CDX Central Data Exchange
CAA Clean Air Act
CFR Code of Federal Regulations
COMS continuous opacity monitoring system
CPMS continuous parameter monitoring system
DOE Department of Energy
ERT Electronic Reporting Tool
ESP electrostatic precipitator
FR Federal Register
GACT generally available control technologies
HAP hazardous air pollutants
Hg mercury
HQ Headquarters
ISO International Standards Organization
lb pounds
MACT maximum achievable control technology
MMBtu million British thermal units
NAA No Action Assurance
NAICS North American Industry Classification System
NESHAP national emission standards for hazardous air pollutants
NSPS new source performance standard
NTTAA National Technology Transfer and Advancement Act
OMB Office of Management and Budget
PCBs polychlorinated biphenyls
PM particulate matter
POM polycyclic organic matter
ppm parts per million
PSD prevention of significant deterioration
RFA Regulatory Flexibility Act
RIN Regulatory Information Number
TBtu trillion British thermal units
TTN Technology Transfer Network
tpy tons per year
UMRA Unfunded Mandates Reform Act of 1995
UPL upper prediction limit
VCS Voluntary Consensus Standards
WWW Worldwide Web

    Organization of This Document. The information presented in this 
preamble is organized as follows:

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document?
    C. Judicial Review
II. Background Information
III. Summary of Final Action on Reconsideration
    A. Affected Sources
    B. Source Category Exclusions
    C. Emission Limits
    D. Tune-Up Work Practice and Management Practice Standards
    E. Energy Assessment Work Practice and Management Practice 
Standards
    F. GACT-Based Standards
    G. Initial Compliance
    H. Operating Limits
    I. Continuous Compliance
    J. Periods of Startup and Shutdown
    K. Affirmative Defense Language
    L. Notification, Recordkeeping and Reporting Requirements
    M. Title V Permitting Requirements
    N. Definition of Period of Gas Curtailment or Supply 
Interruption
    O. Miscellaneous Technical Corrections
    P. Other Issues
IV. Summary of Significant Changes Since Proposed Action on 
Reconsideration
    A. Applicability
    B. Tune-Up Requirements
    C. Energy Assessment
    D. Clarification of Oxygen Concentration Operating Limits
    E. Definitions Regarding Averaging Times
    F. Fuel Sampling Frequency
    G. Performance Testing Frequency
    H. Startup and Shutdown Definitions
    I. Notifications
    J. Miscellaneous Definitions
V. Other Actions the EPA Is Taking
VI. Impacts Associated With This Final Rule
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
    K. Congressional Review Act

I. General Information

A. Does this action apply to me?

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

[[Page 7490]]



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          Industry category           NAICS Code \a\                Examples of regulated entities
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Any area source facility using a                 321  Wood product manufacturing.
 boiler as defined in the final                   11  Agriculture, greenhouses.
 rule..                                          311  Food manufacturing.
                                                 327  Nonmetallic mineral product manufacturing.
                                                 424  Wholesale trade, nondurable goods.
                                                 531  Real estate.
                                                 611  Educational services.
                                                 813  Religious, civic, professional, and similar organizations.
                                                  92  Public administration.
                                                 722  Food services and drinking places.
                                                  62  Health care and social assistance.
                                               22111  Electric power generation.
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\a\ 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 
final action. To determine whether your facility may be affected by 
this 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 
this 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 of subpart A (General Provisions).

B. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of 
this action will also be available on the WWW through the TTN. 
Following signature, a copy of the action will be posted on the TTN's 
policy and guidance page for newly proposed or promulgated rules at the 
following address: http://www.epa.gov/ttn/oarpg/. The TTN provides 
information and technology exchange in various areas of air pollution 
control.

C. Judicial Review

    Under the CAA section 307(b)(1), judicial review of this final rule 
is available only by filing a petition for review in the U.S. Court of 
Appeals for the District of Columbia Circuit by April 2, 2013. Under 
CAA section 307(d)(7)(B), only an objection to this final rule that was 
raised with reasonable specificity during the period for public comment 
can be raised during judicial review.
    Under CAA section 307(b)(2), the requirements established by this 
final rule may not be challenged separately in any civil or criminal 
proceedings brought by EPA to enforce these requirements.

II. Background Information

    Section 112(d) of the CAA requires the EPA to establish NESHAP for 
both major and area sources of 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 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), the EPA issued the NESHAP for 
industrial, commercial and institutional area source boilers pursuant 
to CAA sections 112(c)(3), 112(c)(6), and 112(k)(3)(B).
    CAA section 112(k)(3)(B) directs the EPA to identify at least 30 
HAP that, as a result of emissions from area sources, pose the greatest 
threat to public health in the largest number of urban areas. The EPA 
implemented this provision in 1999 in the Integrated Urban Air Toxics 
Strategy, (64 FR 38715, July 19, 1999) (Strategy). Specifically, in the 
Strategy, the EPA identified 30 HAP that pose the greatest potential 
health threat in urban areas, and these HAP are referred to as the ``30 
urban HAP.'' Section 112(c)(3) of the CAA requires the EPA to list 
sufficient categories or subcategories of area sources to ensure that 
area sources representing 90 percent of the emissions of the 30 urban 
HAP are subject to regulation. Under CAA section 112(d)(5), the EPA may 
elect to promulgate standards or requirements for area sources ``which 
provide for the use of generally available control technologies 
(``GACT'') or management practices by such sources to reduce emissions 
of hazardous air pollutants.''
    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, POM, hexachlorobenzene, Hg, PCBs, 2,3,7,8-
tetrachlorodibenzofuran, 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 Hg 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 Hg and POM. We promulgated final standards for coal-fired 
area source boilers to reflect the application of MACT for Hg and POM, 
and to reflect GACT for the urban HAP other than Hg and POM.
    We listed industrial and commercial/institutional boilers 
combusting oil or biomass under CAA section 112(c)(3) for their 
contribution of Hg, 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). The 
reconsideration notice identified several provisions of the final rule 
where additional public comment was appropriate. The notice also 
identified several issues of central relevance to the rulemaking where 
reconsideration was appropriate under CAA section 307(d).
    Following promulgation of the final rule, the EPA also received 
petitions for reconsideration from the following organizations 
(Petitioners): American

[[Page 7491]]

Sugar Cane League of the U.S.A., Alaska Oil and Gas Association, 
American Coke and Coal Chemicals Institute, American Iron and Steel 
Institute, American Petroleum Institute, Council of Industrial Boiler 
Owners, Industry Coalition (American Forest and Paper Association 
(AF&PA) et. al.), National Petrochemical and Refiners Association, 
Sierra Club, and the State of Washington Department of Ecology. 
Petitioners, pursuant to CAA section 307(d)(7)(B), requested that the 
EPA reconsider numerous provisions in the rules. On December 23, 2011, 
the EPA granted the petitions for reconsideration on certain issues, 
and proposed certain revisions to the final rule in response to the 
reconsideration petitions and to address the issues that the EPA 
previously identified as warranting reconsideration. That proposal 
solicited comment on several specific aspects of the rule, including:
     Establishing separate requirements for seasonally operated 
boilers.
     Addressing temporary boilers.
     Clarifying the initial compliance schedule for existing 
boilers subject to tune-ups.
     Defining periods of gas curtailment.
     Providing an optional CO compliance mechanism using CEMS.
     Averaging times for parameter monitoring.
     Providing an affirmative defense for malfunction events.
     Adjusting frequency of tune-up work practices for very 
small units.
     Selecting a 99 percent confidence interval for setting the 
CO emission limit.
     Establishing GACT-based limits for biomass and oil-fired 
boilers.
     Scope and duration of the energy assessment and deadline 
for completing the assessment.
     Revising GACT-based limits for PM at new oil-fired 
boilers.
     Exempting area sources from title V permitting 
requirements.
    In this action, the EPA is finalizing multiple changes to this 
NESHAP after considering public comments on the items under 
reconsideration.

III. Summary of Final Action on Reconsideration

    As stated above, the December 23, 2011, proposed rule addressed 
specific issues and provisions the EPA identified for reconsideration. 
This summary reflects the agency's final action in regards to those 
provisions identified for reconsideration and on other discrete matters 
identified in response to comments or data received during the comment 
period.

A. Affected Sources

    This final rule amends 40 CFR 63.11194 to specify that an existing 
dual-fuel fired boiler (i.e., commenced construction or reconstruction 
on or before June 4, 2010) meeting the definition of gas-fired boiler, 
as defined in 40 CFR 63.11237, that meets the applicability 
requirements of subpart JJJJJJ after June 4, 2010 due to a fuel switch 
from gaseous fuel to solid fossil fuel, biomass, or liquid fuel is 
considered to be an existing source under this subpart as long as the 
boiler was designed to accommodate the alternate fuel. A new or 
reconstructed dual-fuel fired boiler (i.e., commenced construction or 
reconstruction after June 4, 2010) meeting the definition of gas-fired 
boiler, as defined in 40 CFR 63.11237, that meets the applicability 
criteria of subpart JJJJJJ after June 4, 2010 due to a fuel switch from 
gaseous fuel to solid fossil fuel, biomass, or liquid fuel is 
considered to be a new source under this subpart.

B. Source Category Exclusions

    This final rule amends the list of boilers that are not part of the 
source categories subject to subpart JJJJJJ. We are revising this list 
(as set forth in 40 CFR 63.11195) to clarify certain boiler types and 
to include certain additional boilers that may be located at an 
industrial, commercial or institutional area source facility. These 
revisions of the source categories are described below.
1. Electric Boilers
    The EPA is amending 40 CFR 63.11195 by adding electric boilers to 
the list of boilers not subject to subpart JJJJJJ. Electric boilers are 
defined in 40 CFR 63.11237 as follows:

    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.
2. Residential Boilers
    The EPA is amending 40 CFR 63.11195 by adding residential boilers 
to the list of boilers not subject to subpart JJJJJJ. We are clarifying 
that a residential boiler may be part of a residential combined heat 
and power system and that a boiler serving a single unit residence 
dwelling that has since been converted or subdivided into condominiums 
or apartments may also be considered a residential boiler. Residential 
boilers are defined in 40 CFR 63.11237 as follows:

    Residential boiler means a boiler used to provide heat and/or 
hot water and/or as part of a residential combined heat and power 
system. This definition includes boilers located at an institutional 
facility (e.g., university campus, military base, church grounds) or 
commercial/industrial facility (e.g., farm) used primarily to 
provide heat and/or hot water for:
    (1) A dwelling containing four or fewer families, or
    (2) A single unit residence dwelling that has since been 
converted or subdivided into condominiums or apartments.
3. Temporary Boilers
    The EPA is amending 40 CFR 63.11195 by adding temporary boilers to 
the list of boilers not subject to subpart JJJJJJ. Similar to 
residential boilers, we did not intend to regulate temporary boilers 
under the area source standards because they are not part of either the 
industrial boiler source category or the commercial/institutional 
boiler source category. We note that neither the CAA section 112(c)(6) 
inventory nor the CAA section 112(c)(3) inventory included temporary 
boilers. In this final action, the EPA is simply clarifying the scope 
of categories regulated by subpart JJJJJJ. By their nature of being 
temporary, these boilers are operating in place of another non-
temporary boiler while that boiler is being constructed, replaced or 
repaired, in which case we would have counted the non-temporary boiler 
as one being regulated. Additionally, the final major source rule for 
boilers excludes temporary boilers.
    The definition of ``temporary boiler'' specifies that a boiler is 
not a temporary boiler if it remains at a location within the facility 
and performs the same or similar function for more than 12 consecutive 
months unless the regulatory agency approves an extension. The 
definition of ``temporary boiler'' also specifies that any temporary 
boiler that replaces a temporary boiler at a location within the 
facility and performs the same or similar function will be included in 
calculating the consecutive time period unless there is a gap in 
operation of 12 months or more. Temporary boilers are defined in 40 CFR 
63.11237 as follows:

    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 within the 
facility and performs the same or similar function for more than 12 
consecutive months, unless the regulatory agency approves an 
extension. An extension may be granted by the regulatory agency

[[Page 7492]]

upon petition by the owner or operator of a unit specifying the 
basis for such a request. Any temporary boiler that replaces a 
temporary boiler at a location within the facility and performs the 
same or similar function will be included in calculating the 
consecutive time period unless there is a gap in operation of 12 
months or more.
    (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 but continues to perform the same or similar function 
and serve the same electricity, steam, and/or hot water system in an 
attempt to circumvent the residence time requirements of this 
definition.
4. Boilers With Section 3005 Permits
    The EPA is clarifying the language in 40 CFR 63.11195(c) to provide 
an exclusion stating ``unless such units do not combust hazardous waste 
and combust comparable fuels'' such that it reads: ``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.''
5. Boilers Used as Control Devices
    The EPA is amending the language in 40 CFR 63.11195(g) to clarify 
that any boiler that is used as a control device to comply with a 
subpart under part 60, 61, or 65 of chapter 40 is not subject to 
subpart JJJJJJ provided that at least 50 percent of the heat input to 
the boiler is provided by the gas stream that is regulated under 
another subpart.

C. Emission Limits

1. Hg Emission Limit for Coal-Fired Boilers
    The EPA is amending the Hg emission limit for large coal-fired 
boilers to 0.000022 lb per MMBtu based on a revised analysis. The 
revised analysis excludes data for a utility boiler that were 
erroneously used as the basis for the Hg emission limit included in the 
March 2011 final rule. Further discussion of this revision to the Hg 
emission limit is located in the December 23, 2011, proposal (76 FR 
80541).
    A memorandum ``Beyond-the-Floor Analysis for Mercury and Carbon 
Monoxide'' located in the docket for the rulemaking describes our 
beyond-the-floor analysis for Hg and CO emissions from new and existing 
area source coal-fired boilers with heat input capacity of 10 MMBtu/hr 
or greater. In the beyond-the-floor option for Hg emissions, new and 
existing coal-fired boilers would be required to comply with a Hg 
emission limit more stringent than the MACT floor-based emission limit 
of 2.2 X 10-\5\ lb of Hg per MMBtu. To comply with a limit 
more stringent than the fabric filter-based MACT floor limit, it is 
expected that an affected boiler would need to employ fabric filter 
control along with ACI. In summary, we determined that the beyond-the-
floor option of installing ACI for Hg control from area source coal-
fired boilers is not economically feasible.
    As discussed in the preamble to the June 2010 proposed rule (75 FR 
31896) and the preamble to the March 2011 final rule (76 FR 15554), we 
also considered whether fuel switching was an appropriate control 
technology for purposes of determining either the MACT floor level or 
beyond-the-floor level of control. We determined that fuel switching 
was not an appropriate floor or beyond-the-floor control. As also 
discussed in the June 2010 and March 2011 preambles, we determined that 
an energy assessment requirement was an appropriate beyond-the-floor 
option for existing large boilers. These previous analyses continue to 
be applicable for mercury.
2. Using the UPL for Setting the CO Emission Limit
    The EPA is amending the CO emission limit for coal-fired boilers to 
reflect a revised analysis that uses the 99 percent confidence level in 
determining the UPL. Based on the results of the revised analysis, we 
are amending the CO emission limit for new and existing coal-fired 
boilers from 400 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.
    As discussed in the ``Beyond-the-Floor Analysis for Mercury and 
Carbon Monoxide'' memorandum, to comply with a limit more stringent 
than the MACT floor based CO limit, it is expected that new and 
existing area source coal-fired boilers with heat input capacity of 10 
MMBtu/hr or greater may need to install an oxidation catalyst. As fully 
explained in the memorandum, we determined that the beyond-the-floor 
option of installing an oxidation catalyst for CO control was 
technically infeasible. Other methods of reducing CO emissions, such as 
upgrading new burners and overfire air systems, were also considered 
and determined to be technically infeasible options. As explained 
earlier in this preamble, we determined that fuel switching was not an 
appropriate floor or beyond-the-floor control and that an energy 
assessment requirement was an appropriate beyond-the-floor option for 
existing large boilers. These previous analyses continue to be 
applicable for CO.
3. Compliance Alternative for PM for Certain Oil-Fired Boilers
    The EPA is amending the applicability of PM emission limit 
requirements for certain new or reconstructed oil-fired boilers. We are 
amending 40 CFR 63.11210 to specify that new or reconstructed oil-fired 
boilers satisfy GACT for PM when they combust only oil that contains no 
more than 0.50 weight percent sulfur or a mixture of 0.50 weight 
percent sulfur oil with other fuels not subject to a PM emission limit 
under this subpart and do not use a post-combustion technology (except 
a wet scrubber) to reduce PM or sulfur dioxide emissions.

D. Tune-Up Work Practice and Management Practice Standards

1. Requirements for Seasonally Operated Boilers
    The EPA is establishing separate requirements for a subcategory of 
boilers that are seasonally operated. For seasonally operated boilers, 
we are amending 40 CFR 63.11223 to specify that these boilers are 
required to complete a tune-up every 5 years, instead of on a biennial 
basis as is required for most non-seasonal boilers. Specifically, 
existing seasonal boilers are required to complete the initial tune-up 
by March 21, 2014, and a subsequent tune-up every 5 years after the 
initial tune-up. New and reconstructed seasonal boilers are not 
required to complete an initial tune-up, but are required to complete a 
tune-up every 5 years after the initial startup of the new or 
reconstructed boiler.\1\ A combined total of 15 days of periodic 
testing of the seasonal boiler during the 7-month shutdown is allowed. 
The definition of ``seasonal boiler'' clarifies that it only applies to 
biomass- or oil-fired boilers. Seasonally operated boilers are defined 
in 40 CFR 63.11237 as follows:
---------------------------------------------------------------------------

    \1\ Generally, boilers are initially installed optimized for 
efficiency, i.e., ``in tune.'' Periodic tune-ups restore a boiler to 
its efficient state, given its age and other parameters. We do not 
require a tune-up upon startup because boilers normally would 
already be efficient at that time. Emission reductions are projected 
to occur by maintaining efficient combustion through periodic tune-
ups.

    Seasonal boiler means a boiler that undergoes a shutdown for a 
period of at least 7 consecutive months (or 210 consecutive days) 
each 12-month period due to seasonal conditions, except for periodic 
testing. Periodic testing shall not exceed a combined total of 15 
days during the 7-month shutdown. This definition only applies to

[[Page 7493]]

boilers that would otherwise be included in the biomass subcategory 
or the oil subcategory.
2. Requirements for Small Oil-Fired Units
    The EPA is establishing separate requirements for a subcategory of 
oil-fired boilers with a heat input capacity of equal to or less than 5 
MMBtu/hr. We are amending 40 CFR 63.11223 to specify that this 
subcategory of small oil-fired boilers are required to complete a tune-
up every 5 years, instead of on a biennial basis as is required for 
most larger oil-fired boilers. Specifically, existing oil-fired boilers 
with a heat input capacity of equal to or less than 5 MMBtu/hr are 
required to complete the initial tune-up by March 21, 2014, and a 
subsequent tune-up every 5 years after the initial tune-up. New and 
reconstructed oil-fired boilers with a heat input capacity of equal to 
or less than 5 MMBtu/hr are not required to complete an initial tune-
up, but are required to complete a tune-up every 5 years after the 
initial startup of the new or reconstructed boiler.
3. Requirements for Boilers With Oxygen Trim Systems
    The EPA is establishing separate requirements for boilers with 
oxygen trim systems that maintain an optimum air-to-fuel ratio that 
would otherwise be subject to a biennial tune-up. We are amending 40 
CFR 63.11223 to specify that this subcategory of boilers is required to 
complete a tune-up every 5 years. Specifically, existing boilers with 
oxygen trim systems are required to complete the initial tune-up by 
March 21, 2014, and a subsequent tune-up every 5 years after the 
initial tune-up. New and reconstructed boilers with oxygen trim systems 
are not required to complete an initial tune-up, but are required to 
complete a tune-up every 5 years after the initial startup of the new 
or reconstructed boiler.
4. Requirements for Limited-Use Boilers
    The EPA is establishing separate requirements for a subcategory of 
boilers that operate on a limited basis. The limited-use subcategory 
includes any boiler that burns any amount of solid or liquid fuels and 
has a federally enforceable average annual capacity factor of no more 
than 10 percent. For limited-use boilers, we are amending 40 CFR 
63.11223 of the final rule to specify that these boilers are required 
to complete a tune-up every 5 years. Specifically, existing limited-use 
boilers are required to complete the initial tune-up by March 21, 2014, 
and a subsequent tune-up every 5 years after the initial tune-up. New 
and reconstructed limited-use boilers are not required to complete an 
initial tune-up, but are required to complete a tune-up every 5 years 
after the initial startup of the new or reconstructed boiler. Limited-
use boilers are not subject to the emission limits in Table 1 to the 
subpart, the energy assessment requirements in Table 2 to the subpart, 
or the operating limits in Table 4 to the subpart.

E. Energy Assessment Work Practice and Management Practice Standards

1. Scope
    The EPA is amending the definition of ``energy assessment'' to 
clarify that the scope of the energy assessment does not encompass 
energy use systems located off-site or energy use systems using 
electricity purchased from an off-site source. The energy assessment is 
limited to only those energy use systems, located on-site, associated 
with the affected boilers. We are also clarifying that the scope of the 
assessment is based on energy use by discrete segments of a facility 
(e.g., production area or building) and not by a total aggregation of 
all individual energy using segments of a facility.
    The definition of ``boiler system'' is being revised in this final 
rule to clarify that it means the boiler and associated components 
directly connected to and serving the energy use systems. We are 
amending the definition of ``energy use system'' to clarify that energy 
use systems are only those systems using energy clearly produced by 
affected boilers.
    We are clarifying that energy assessor approval and qualification 
requirements are waived in instances where an energy assessment 
completed on or after January 1, 2008 meets or is amended to meet the 
energy assessment requirements in this final rule by March 21, 2014. 
Finally, we are specifying that a source that is operating under an 
energy management program established through energy management systems 
compatible with ISO 50001, that includes the affected boilers, by March 
21, 2014, satisfies the energy assessment requirement. We consider 
these energy management programs to be equivalent to the one-time 
energy assessment because facilities having these programs operate 
under a set of practices and procedures designed to manage energy use 
on an ongoing basis. These programs contain energy performance 
measurements and tracking plans with periodic reviews.
2. Compliance Date
    As specified in 40 CFR 63.11196(a)(3), existing boilers that are 
subject to the energy assessment requirement must achieve compliance 
with the energy assessment requirement no later than March 21, 2014. 
Thus, in order to meet the requirements of the rule, energy assessments 
must, therefore, be completed by the compliance date (March 21, 2014) 
for existing sources.
3. Maximum Duration Requirements
    The EPA is amending the definition of ``energy assessment'' for 
facilities with affected boilers with less than 0.3 TBtu/yr heat input 
capacity and for facilities with affected boilers with 0.3 to 1 TBtu/yr 
heat input capacity to change the maximum time to conduct the energy 
assessment from one day to 8 on-site technical hours and from three 
days to 24 on-site technical hours, respectively, and to allow sources 
to perform longer assessments at their discretion. We are also amending 
the definition of ``energy assessment'' for facilities with affected 
boilers with greater than 1 TBtu/yr heat input capacity to specify that 
the maximum time to conduct the assessment is up to 24 on-site 
technical hours for the first TBtu/yr plus 8 on-site technical hours 
for every additional 1.0 TBtu/yr not to exceed 160 on-site technical 
hours, but may be longer at the discretion of the owner or operator.

F. GACT-Based Standards

1. Establishing GACT-Based Emission Limits for Biomass- and Oil-Fired 
Boilers
    The EPA is not amending the GACT-based standards, as specified in 
the March 21, 2011, final rule, for biomass- and oil-fired boilers. 
Specifically, the final standards for biomass- and oil-fired area 
source boilers are based on GACT instead of MACT as were the proposed 
standards for all pollutants except POM. Our rationale for the changes 
between proposal and promulgation for the biomass- and oil-fired 
boilers, including not requiring MACT for POM, can be found in the 
preamble to the promulgated area source standards (76 FR 15565-15567 
and 15574-15575, March 21, 2011). The final standards for area source 
biomass- and oil-fired boilers require these boilers to meet the 
following standards:
    New boilers with heat input capacity greater than 10 MMBtu/hr that 
are biomass-fired or oil-fired must meet GACT-based numerical emission 
limits for PM.
    New boilers with heat input capacity greater than 10 MMBtu/hr that 
are biomass-fired or oil-fired must comply

[[Page 7494]]

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 MMBtu/hr 
that are biomass-fired or oil-fired must have a one-time energy 
assessment performed by a qualified energy assessor, an energy 
assessment completed on or after January 1, 2008 that meets or is 
amended to meet the energy assessment requirements in this final rule 
by March 21, 2014, or an energy management program established through 
energy management systems compatible with ISO 50001, that includes the 
affected boilers, by March 21, 2014, under which the owner or operator 
currently operates.
    All new and existing units, regardless of size, that are biomass-
fired or oil-fired must have a GACT-based periodic tune-up.
2. Setting GACT-Based PM Standards for New Oil-Fired Boilers
    The EPA is not making any changes to the PM limit for new oil-fired 
boilers. New oil-fired boilers with heat input capacity greater than 10 
MMBtu/hr must meet a GACT-based numerical emission limit for PM (0.03 
lb per MMBtu of heat input). New oil-fired units, regardless of size, 
must have a GACT-based periodic tune-up. Our rationale for finalizing 
GACT-based PM emissions limits can be found in the preamble to the 
promulgated area source standards (76 FR 15574, March 21, 2011).

G. Initial Compliance

1. Dates
    Some commenters have argued that the 3-year compliance deadline of 
March 21, 2014, for existing sources to meet the standards does not 
provide sufficient time for sources to meet the standards in view of 
the large number of sources subject to the rule and that these sources 
will be competing for the needed resources and materials from 
engineering consultants, permitting authorities, equipment vendors, 
construction contractors, financial institutions, and other critical 
suppliers.
    As an initial matter, we note that many sources subject to the 
standards should be able to meet the standards within 3 years (i.e., by 
March 21, 2014), even those that need to install pollution control 
technologies to do so. In addition, many sources subject to the 
standards are existing biomass- or oil-fired boilers or small coal-
fired boilers (less than 10 MMBtu/hr) and will not need to install 
controls in order to demonstrate compliance, as these sources are 
subject only to work practices or management practices.
    At the same time, the CAA allows title V permitting authorities to 
grant sources, on a case-by-case basis, extensions to the compliance 
time of up to 1 year if such time is needed for the installation of 
controls. See CAA section 112(i)(3)(B)). Permitting authorities are 
already familiar with, and in many cases have experience with, applying 
the 1-year extension authority under section 112(i)(3)(B) since the 
provision applies to all NESHAP. See 40 CFR 63.6(i)(4)(A). We believe 
that should the range of circumstances that commenters have cited as 
impeding sources' ability to install controls within 3 years 
materialize, then permitting authorities can take those circumstances 
into consideration when evaluating an existing source's request for a 
1-year extension, and where such applications prove to be well-founded, 
permitting authorities can make the 1-year extension available to 
applicants.
    In making a determination as to whether an extension is 
appropriate, we believe it is reasonable for permitting authorities to 
consider the large number of pollution control retrofit projects being 
undertaken for purposes of complying either with the standards in this 
rule or with those of other rules such as the Major Source Boilers 
Standards and the Mercury and Air Toxics Standards for the power sector 
that may be competing for similar resources.
    Further, commenters have pointed out that in some cases operators 
of existing sources that are subject to these standards and that 
generate energy may opt to meet the standards by terminating operations 
at these sources and building new sources to replace the energy 
generation at the shut-down sources. While the ultimate discretion to 
provide a 1-year extension lies with the permitting authority, the EPA 
believes that it may be reasonable for permitting authorities to allow 
the fourth year extension for the installation of replacement sources 
of energy generation at the site of a facility applying for an 
extension for that purpose. Specifically, the EPA believes where an 
applicant demonstrates that it is building replacement sources of 
energy generation for purposes of meeting the requirements of these 
standards, such a replacement project could be deemed to constitute the 
``installation of controls'' under section 112(i)(3)(B).
    In sum, the EPA believes that although most, if not all, units will 
be able to fully comply with the standards within 3 years, the fourth 
year that permitting authorities are allowed to grant for installation 
of controls is an important flexibility that will address situations 
where an extra year is necessary.
2. Demonstrating Initial Compliance
    The EPA is amending 40 CFR 63.11210 to clarify the dates by which 
new and reconstructed boilers need to demonstrate initial compliance. 
We are amending 40 CFR 63.11210(d) to clarify that only boilers that 
are subject to emission limits for PM, Hg or CO 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 (i) to 40 CFR 63.11210 to clarify the 
initial compliance requirements for boilers located at existing major 
sources of HAP that become area sources on a timely basis. Any such 
existing boiler at the existing source must demonstrate compliance with 
subpart JJJJJJ within 180 days of the later of March 21, 2014 or upon 
the existing major source commencing operation as an area source. Any 
new or reconstructed boiler at the existing source must demonstrate 
compliance with subpart JJJJJJ within 180 days of the later of March 
21, 2011 or startup. Notification of such changes must be submitted 
according to 40 CFR 63.11225(g).
    We are adding a new paragraph (j) to 40 CFR 63.11210 that specifies 
initial compliance demonstration requirements for existing affected 
boilers that have not operated between the effective date of the rule 
and the source's compliance date. Owners and operators of boilers 
subject to emission limits must complete the initial compliance 
demonstration no later than 180 days after the re-start of the affected 
boiler, sources subject to tune-up requirements must complete the 
initial performance tune-up no later than 30 days after the re-start of 
the affected boiler, and sources subject to the one-time energy 
assessment must complete the assessment no later than the compliance 
date specified in 40 CFR 63.11196.
3. Schedule for Existing Boilers Subject to Tune-Up Requirements
    The EPA is amending 40 CFR 63.11196 to specify that all existing 
boilers subject to the tune-up requirement have 3 years (by March 21, 
2014) in which to demonstrate initial compliance, instead of 1 year as 
specified in the 2011 final rule (76 FR 15554, March 21, 2011) or 2 
years as specified in the proposed reconsideration of final rule action 
(76

[[Page 7495]]

FR 80532, December 23, 2011). In the December 23, 2011, proposal, we 
specifically requested comment on whether the initial compliance period 
for the tune-up requirement should be extended to March 21, 2014.
4. Conducting Initial Tune-Ups at New and Reconstructed Sources
    The EPA is removing the requirement for an initial tune-up for new 
and reconstructed boilers. Thus, new and reconstructed units are 
required to complete the applicable biennial or 5-year tune-up no later 
than 25 months or 61 months, respectively, after the initial startup of 
the new or reconstructed boiler.
5. Fuel Requirements
    The EPA is amending 40 CFR 63.11223(a) to specify that boiler tune-
ups must be conducted 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.

H. Operating Limits

1. Operating Limits for Oxygen Concentration
    The EPA is clarifying that the oxygen concentration must be at or 
above the minimum established during a performance stack test. These 
limits have also been clarified to be applicable when the unit is 
firing the fuel or fuel mixture utilized during the CO performance 
test.
2. Maximum Operating Load
    The EPA is including provisions for establishing a unit-specific 
limit for maximum operating load that applies to any boiler subject to 
an emission limit for which compliance is demonstrated by a performance 
stack test. Operating load data includes fuel feed rate data or steam 
generation rate data.
3. Establishing Operating Limits for Wet Scrubbers
    The EPA is amending the operating limit provisions in 40 CFR 
63.11211(b)(2) for an ESP operated with a wet scrubber to remove the 
statement that the operating limits for ESP do not apply to dry ESP 
systems operated without a wet scrubber.

I. Continuous Compliance

1. CO Emission Limit
    The March 2011 final rule requires sources subject to a CO emission 
limit to demonstrate compliance by measuring CO emissions while also 
monitoring the oxygen content of the exhaust. We are amending the 
monitoring requirements in 40 CFR 63.11224(a) to allow sources subject 
to a CO emission limit the option to install, operate, and maintain CO 
and oxygen CEMS. The CEMS must be installed, operated and maintained 
according to Performance Specifications 3 and 4, 4A, or 4B at 40 CFR 
part 60, appendix B, and according to the site-specific monitoring plan 
that each facility is required to develop. The CEMS will also be 
required to complete a performance evaluation, also according to 
Performance Specifications 3 and 4, 4A, or 4B.
    Sources have the option to demonstrate continuous compliance by 
monitoring both CO and oxygen using CEMS to demonstrate compliance with 
the CO emission limit, corrected to 3 percent oxygen, or monitoring and 
complying with an oxygen content operating limit that is established 
during the performance stack test. Sources that use CO and oxygen CEMS 
are not required to perform initial CO performance testing nor are they 
subject to oxygen content operating limit requirements. Sources that 
choose to demonstrate continuous compliance by monitoring and complying 
with an oxygen content operating limit must install, operate, and 
maintain an oxygen analyzer system at or above the minimum percent 
oxygen by volume that is established as the operating limit for oxygen 
when firing the fuel or fuel mixture utilized during the most recent CO 
performance stack test. We have removed 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.
    We are amending the oxygen monitoring requirements to allow for the 
use of oxygen trim systems and have included oxygen trim systems in the 
definition of ``oxygen analyzer system.'' We have clarified that 
operation of oxygen trim systems to meet the oxygen monitoring 
requirements shall not be done in a manner that compromises furnace 
safety. The definitions of ``oxygen analyzer system'' and ``oxygen trim 
system'' in 40 CFR 63.11237 read as follows:
     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, boiler firebox, or other appropriate 
intermediate location. This definition includes oxygen trim systems.
     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 provides a feedback signal to the combustion 
air controller.
2. Tune-Up Standards
    The EPA is amending the requirements for demonstrating continuous 
compliance with the work practice and management practice tune-up 
standards in 40 CFR 63.11223 to clarify that CO measurements that are 
required before and after tune-up adjustments may be taken using a 
portable CO analyzer. We are clarifying that the requirements to 
inspect the burner and the system controlling the air-to-fuel ratio may 
be delayed until the next scheduled shutdown. We are also clarifying 
that units that produce electricity for sale may delay these 
inspections until the first outage, not to exceed 36 months from the 
previous inspection. In addition, we are clarifying that optimization 
of CO emissions should be consistent with any NOX 
requirements to which the unit is subject. Finally, we are specifying 
for units that are not operating on the required date for a tune-up, 
the tune-up must be conducted within 30 days of startup.
3. Performance Testing Frequency
    The EPA is amending 40 CFR 63.11220 to specify in paragraph (b) 
that the owner or operator of an affected boiler does not need to 
conduct further PM emissions testing if, when demonstrating initial 
compliance with the PM emission limit, the performance test results 
show that the PM emissions are equal to or less than half of the PM 
emission limit. The owner or operator must continue to comply with all 
applicable operating limits and monitoring requirements. If the initial 
performance test results show that the PM emissions are greater than 
half of the PM emission limit, the owner or operator must conduct 
subsequent performance tests as specified in 40 CFR 63.11220(a).
    We are clarifying in 40 CFR 63.11220(d) that existing affected 
boilers that have not operated since the previous compliance 
demonstration must complete their subsequent compliance demonstration 
no later than 180 days after the re-start of the affected boiler.
4. Fuel Analysis
    The EPA is amending 40 CFR 63.11220 to specify in paragraph (c) 
that the owner or operator of an affected coal-fired boiler does not 
need to conduct further fuel analysis sampling if, when demonstrating 
initial compliance with the Hg emission limit, the Hg constituents in 
the fuel or fuel

[[Page 7496]]

mixture are measured to be equal to or less than half of the Hg 
emission limit. The owner or operator must continue to comply with all 
applicable operating limits and monitoring requirements.
    When demonstrating initial compliance with the Hg emission limit, 
if the Hg constituents in the fuel or fuel mixture are greater than 
half of the Hg emission limit, the owner or operator must conduct 
quarterly sampling.
5. Averaging Times
    The EPA is amending the averaging time for parameter monitoring and 
compliance with operating limits to a 30-day rolling average.
    The EPA is revising the definitions of ``30-day rolling average'' 
and ``daily block average'' to exclude periods of startup and shutdown 
and periods when the unit is not operating in the calculation of the 
arithmetic mean.
6. Monitoring Data
    The EPA is clarifying in 40 CFR 63.11221 the monitoring data 
collection requirements.

J. Periods of Startup and Shutdown

1. Definitions
    The EPA is revising the definitions of ``startup'' and ``shutdown'' 
such that they are tailored for industrial boilers and are consistent 
with the definitions of ``startup'' and ``shutdown'' in the 40 CFR part 
63, subpart A General Provisions. The revised definitions reflect the 
fact that industrial boilers function to provide steam or, in the case 
of cogeneration units, electricity. We are defining startup as the 
period between either the first-ever firing of fuel in the boiler or 
the firing of fuel in the boiler after a shutdown and when the boiler 
first supplies steam or heat. We are defining shutdown as the period 
between either when no more steam or heat is supplied by the boiler or 
no fuel is being fired in the boiler and when there is no steam and no 
heat being supplied and no fuel being fired in the boiler.
2. Compliance With Operating Limits
    The EPA has clarified that operating limits must be met at all 
times except during periods of startup and shutdown.
3. Minimization of Startup and Shutdown Periods
    The EPA is amending 40 CFR 63.11223(g) to include biomass- and oil-
fired boilers in the requirement to minimize the time spent in startup 
and shutdown periods. Specifically, the requirement is to minimize the 
boiler's startup and shutdown periods and conduct startups and 
shutdowns according to the manufacturer's recommended procedures. If 
manufacturer's recommended procedures are not available, recommended 
procedures for a unit of similar design for which manufacturer's 
recommended procedures are available must be followed.

K. Affirmative Defense Language

    In this final rule, the EPA is updating the affirmative defense 
provisions for malfunctions that were included in the March 21, 2011, 
final rule. We have made certain changes to 40 CFR 63.11226 to clarify 
the circumstances under which a source may assert an affirmative 
defense. The changes clarify that a source may assert an affirmative 
defense to a claim for civil penalties for violations of standards that 
are caused by malfunctions. A source can avail itself of the 
affirmative defense when there has been a violation of the emission 
standards due to an event that meets the definition of malfunction 
under 40 CFR 63.2 and qualifies for assertion of an affirmative defense 
under 40 CFR 63.11226. In the March 2011 final rule, we used terms such 
as ``exceedance'' or ``excess emissions'' in 40 CFR 63.11226, which 
created unnecessary confusion as to when the affirmative defense could 
be used. In this final rule, we have eliminated those terms and used 
the word ``violation'' to make clear that the affirmative defense to 
civil penalties is available only where an event that causes a 
violation of the emissions standard meets the criteria for the 
assertion of an affirmative defense under 40 CFR 63.11226.
    This final rule requires that to establish the affirmative defense 
the owner must prove by a preponderance of evidence that repairs were 
made as expeditiously as possible when a violation occurs. We have re-
evaluated the language concerning the use of off-shift and overtime 
labor, to the extent practicable, to make the repairs and believe that 
the language is not necessary. Thus, the language has been eliminated 
from this final rule.
    We have also eliminated the 2-day notification requirement that was 
included in 40 CFR 63.11226(b) of the March 2011 final rule because we 
expect to receive sufficient notification of malfunction events that 
result in violations in other required compliance reports as specified 
under 40 CFR 63.11225. In addition, we have revised the 45-day 
affirmative defense reporting requirement that was included in 40 CFR 
63.11226(b) of the March 2011 final rule. This final rule requires 
sources to include the report in the first compliance, deviation or 
excess emission report due after the initial occurrence of the 
violation, unless the compliance, deviation or excess emission report 
is due less than 45 days after the violation. In that case, the 
affirmative defense report may be included in the second compliance, 
deviation or excess emission report due after the initial occurrence of 
the violation. Because the affirmative defense report is now included 
in a subsequent compliance, deviation or excess emission report, there 
is no longer a need for the 30-day extension for submitting a stand-
alone affirmative defense report. Consequently, we are not including 
that provision in this final rule.

L. Notification, Recordkeeping and Reporting Requirements

    The EPA is amending 40 CFR 63.11225(a)(2) to specify that existing 
affected boilers have until January 20, 2014 to submit their Initial 
Notification.
    The EPA is amending 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. We are also amending 40 CFR 63.11223(b) to 
clarify that the type and amount of fuel needs to be included in 
reports only if the boiler was physically and legally capable of using 
more than one type of fuel during that time period and that the report 
should include concentrations of CO and oxygen, measured at high fire 
or typical operating load, before and after the tune-up of the boiler. 
Finally, we are specifying that for units sharing a fuel meter, the 
fuel use by each boiler may be estimated.
    The EPA is amending 40 CFR 63.11225(b) to clarify the requirements 
for submitting a biennial or 5-year report for units that are only 
subject to tune-up requirements and to specify the information that 
must be included in the annual, biennial, or 5-year compliance report.
    We are amending 40 CFR 63.11225(c)(2) to specify, as applicable, 
that a copy of the energy assessment, records documenting the days of 
operation for each boiler that meets the definition of a seasonal 
boiler, and a copy of the federally enforceable permit for each boiler 
that meets the definition of a limited-use boiler must be maintained.
    We are revising 40 CFR 63.11225(d) to remove the requirement that 
the most recent 2 years of records be maintained on site and are adding 
language that allows for computer access or other means of immediate 
access of records stored in a centralized location.

[[Page 7497]]

    We are adding a new paragraph 40 CFR 63.11225(g) to require that 
boilers that switch fuels, make a physical change, or take a permit 
limit that results in the applicability of a different subcategory 
within subpart JJJJJJ, a switch out of subpart JJJJJJ, or the 
applicability of subpart JJJJJJ must provide notification within 30 
days of the fuel switch, physical change, or permit limit. 40 CFR 
63.11225(g) also specifies what information the notification must 
include.

M. Title V Permitting Requirements

    For the reasons stated in our March 21, 2011, final rule (76 FR 
15554) as well as our reconsideration proposal (76 FR 80532, December 
23, 2011), the EPA is not making any changes to the title V exemption 
for area sources. 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.
    Facilities that are synthetic area sources for HAP under subpart 
JJJJJJ may already be covered by a title V permit or may be required to 
obtain a title V permit in the future for a reason other than subpart 
JJJJJJ. For example, area source boilers could be major sources of non-
HAP pollutants or could be located at sources that are subject to title 
V. Thus, the title V exemption in subpart JJJJJJ does not affect 
whether or not these area sources under subpart JJJJJJ are otherwise 
required to obtain a permit under part 70 or part 71. See 40 CFR 
70.3(a) and (b) or 71.3(a) and (b).

N. Definition of Period of Gas Curtailment or Supply Interruption

    We are amending the definition of ``period of natural gas 
curtailment or supply interruption'' in 40 CFR 63.11237 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 amending 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. We are revising the term and the 
definition so that it includes the curtailment of any gaseous fuel, and 
is not limited to just natural gas. Finally, we are clarifying that the 
supply of gaseous fuel is to an ``affected boiler'' rather than 
``affected facility'' and that the supply of gaseous fuel is 
``restricted or halted'' for reasons beyond the control of the 
facility. The definition is amended to read as follows:

    Period of gas curtailment or supply interruption means a period 
of time during which the supply of gaseous fuel to an affected 
boiler is restricted or 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 qualify as 
periods of supply interruption when the emergency or failure is 
beyond the control of the facility.

O. Miscellaneous Technical Corrections

    In addition to the above summary of the EPA's final action 
regarding provisions identified for reconsideration and on other 
discrete matters identified in response to comments or data received 
during the comment period, other definitional and regulatory text 
revisions are being made. These clarifications will help affected 
sources determine their applicability and better understand the rule 
requirements. In some instances, definitions and regulatory text have 
been revised or added to correspond with other related rules, 
especially the emission standards for industrial, commercial, and 
institutional boilers at major sources of HAP (40 CFR part 63, subpart 
DDDDD). Section IV of this preamble includes additional details 
regarding these miscellaneous technical corrections.

P. Other Issues

    40 CFR 63.11196(a)(1) of the March 21, 2011, final rule (76 FR 
15554) requires that owners and operators of existing affected boilers 
subject to the tune-up requirement complete the initial boiler tune-up 
by March 21, 2012. In addition, 40 CFR 63.11225(a)(4) requires that 
owners and operators of existing affected boilers subject to the tune-
up requirement submit their Notification of Compliance Status no later 
than 120 days after the applicable compliance date specified in 40 CFR 
63.11196. That means that those owners and operators were required to 
submit their Notification of Compliance Status by July 19, 2012. The 
Notification must include, among other information, a certification 
that states ``This facility complies with the requirements in Sec.  
63.11214 to conduct an initial tune-up of the boiler.''
    On March 13, 2012, the EPA issued a No Action Assurance (NAA) to 
all owners and/or operators of existing industrial boilers and 
commercial and institutional boilers at area sources of HAP emissions 
stating that we would not enforce the requirement to conduct an initial 
tune-up by March 21, 2012. The NAA was primarily based upon the EPA's 
concern that sources were reporting a shortage of qualified individuals 
to prepare boilers for tune-ups and then conduct those tune-ups by the 
regulatory deadline, as well as upon the uncertainty in the regulated 
community resulting from the pending reconsideration of the Area Source 
Boiler Rule. The March 13, 2012, NAA states that it remains in effect 
until either (1) 11:59 p.m. EDT, October 1, 2012, or (2) the effective 
date of a final rule addressing the proposed reconsideration of the 
Area Source Boiler Rule, whichever occurs earlier.
    As the July 19, 2012, Notification of Compliance Status deadline 
approached, a final rule addressing the proposed reconsideration of the 
Area Source Boiler Rule had not been issued, and thus the NAA continued 
to remain in effect. Nothing that the EPA learned since the issuance of 
the original NAA letter led us to question our original concerns about 
the feasibility of all sources timely completing an initial tune-up. 
Further, sources that did not complete a tune-up could not certify that 
they conducted one. Thus, on July 18, 2012, the EPA extended the NAA 
for sources required to complete an initial tune-up by March 21, 2012, 
to also include the deadline for submitting the Notification of 
Compliance Status regarding the initial tune-up. In addition, given 
that no final rule addressing the proposed reconsideration of the Area 
Source Boiler Rule had been issued as of July 18, 2012, the pending 
reconsideration continued to create uncertainty in the regulated 
community. Thus, the NAA letter also amended the expiration date of the 
March 13, 2012, NAA, such that the NAA would remain in effect until 
either (1) 11:59 p.m. EST, December 31, 2012, or (2) the effective date 
of a final rule addressing the proposed reconsideration of the Area 
Source Boiler Rule, whichever occurs earlier.
    This final rule revises the compliance date for existing affected 
boilers subject to a tune-up from March 21, 2012, to March 21, 2014. 
The July 19, 2012, deadline for submitting the Notification of 
Compliance Status regarding the initial tune-up is reset to July 19, 
2014, as a result of revising the compliance date for existing affected 
boilers subject to a tune-up to March 21, 2014. Owners or operators 
that had not yet conducted their boiler tune-up, but submitted a 
Notification of Compliance Status by July 19, 2012, simply to notify 
the EPA

[[Page 7498]]

that the tune-up had not been completed, will need to submit a revised 
Notification of Compliance Status after their boiler tune-up is 
conducted.

IV. Summary of Significant Changes Since Proposed Action on 
Reconsideration

    Numerous changes are being made to the March 2011 final rule based 
on the public comments received. Most of the changes are editorial to 
clarify applicability and implementation issues raised by the 
commenters. The public comments received on the proposed changes and 
the responses to them can be viewed in the memorandum ``Summary of 
Public Comments and Responses for: National Emission Standards for 
Hazardous Air Pollutants for Area Sources: Industrial, Commercial, and 
Institutional Boilers'' located in the docket.

A. Applicability

    Since proposal, changes to the applicability of this final rule 
have been made.
1. Dual-Fuel Fired Boilers
    The March 2011 final rule includes as a new affected source a 
boiler that commences fuel switching from natural gas to solid fossil 
fuel, biomass, or liquid fuel after June 4, 2010. For example, under 
the March 2011 final rule, if an unaffected gas-fired boiler currently 
burns oil as allowed under the definition of gas-fired boiler, but 
after June 4, 2010 burns oil for reasons not allowed under the 
definition of gas-fired, these boilers would become new affected oil-
fired units. The December 2011 reconsideration action did not propose 
any revisions to the provisions regarding boilers that fuel switch 
after June 4, 2010. However, the EPA has been made aware through public 
comments that many dual-fuel fired units presently burn primarily 
natural gas with limited or no amounts of oil, and that these units may 
want to burn oil in the future for reasons not allowed under subpart 
JJJJJJ's definition of gas-fired (e.g. cost). Under the March 2011 
final rule, such an existing dual-fuel gas-fired boiler that wanted to 
avoid being subject to the new source requirements would notify as an 
existing oil-fired unit and be subject to the requirements for existing 
oil-fired boilers.
    We received public comments regarding rule applicability and 
compliance requirements for these existing dual-fuel fired boilers. One 
commenter asserted that regardless of the fuel capability identified in 
an initial notification, the distinction between a new source and an 
existing source should only be made based upon a source's capability to 
burn a particular fuel as of the effective date of the rule. The 
commenter explained that many facilities have boilers that can burn 
either gas or liquid and, because the price of gas is currently lower 
than the price of most liquid fuels, they likely are currently firing 
gas during normal operation, with liquid being fired only during 
periods of curtailment. The commenter pointed out that, in the future, 
the price of liquid fuel may be lower than the price of gaseous fuel, 
and facilities may want to preferentially burn liquid fuel over gas 
fuel. The commenter asserted that a change in the fuel from the initial 
notification should not, in and of itself, reclassify a source as a new 
source for purposes of subpart JJJJJJ. Further, the commenter asserted 
that their interpretation is comparable to the fuel switching 
provisions in the EPA's NSPS and PSD regulations. The same commenter 
asserted that if a source already has oil or alternate fuel capability, 
then that source would not be commencing construction or making a 
change to the source. The commenter explained that many of these 
facilities with boilers capable of burning fuel oil as a back-up for 
natural gas may not have submitted an initial notification since 
gaseous fuel-fired boilers that only burn liquid during periods of 
curtailment are not covered by the Area Source Boiler Rule. The 
commenter maintained the EPA's guidance, that a dual-fuel fired boiler 
that fails to file an initial notification and then plans to burn oil 
in the future would be considered to be a new source, appears to be 
contrary to regulatory text stating that an affected source is a new 
source if construction or reconstruction of the affected source is 
commenced after June 4, 2010 and the applicability criteria are met at 
the time construction is commenced. The commenter suggested that the 
EPA clarify that to become a new source, the source must be altered to 
be capable of accommodating a new fuel, so that new sources are not 
created simply by failing to submit an initial notification or a notice 
of fuel switching for a unit that is already capable of accommodating 
that fuel. Another commenter explained that owners and operators of 
dual-fuel fired boilers anticipate firing natural gas for many years to 
come, or until gas supply is temporarily curtailed outside of their 
control or until such a time when fuel oil becomes more cost effective 
to burn than gas. The commenter asserted that, based on common sense 
and increased flexibility, these dual-fuel fired boilers normally 
burning gas could not be considered subject to any oil-fired 
requirements as long as they continue to fire only gas, except under 
the regulation's stated exemptions for burning oil.
    In addition to carefully considering the public comments received 
regarding dual-fuel fired boilers, the EPA reconsidered its overall 
intent with regard to existing dual-fuel fired boilers that fuel switch 
after June 4, 2010. Consequently, in this final rule, we are revising 
the provisions regarding existing boilers that fuel switch after June 
4, 2010. This final rule amends 40 CFR 63.11194 to specify that an 
existing dual-fuel fired boiler (i.e., commenced construction or 
reconstruction on or before June 4, 2010) meeting the definition of 
gas-fired boiler, as defined in 40 CFR 63.11237, that meets the 
applicability requirements of subpart JJJJJJ after June 4, 2010 due to 
a fuel switch from gaseous fuel to solid fossil fuel, biomass, or 
liquid fuel is considered to be an existing source under this subpart 
as long as the boiler was designed to accommodate the alternate fuel. A 
new or reconstructed dual-fuel fired boiler (i.e., commenced 
construction or reconstruction after June 4, 2010) meeting the 
definition of gas-fired boiler, as defined in 40 CFR 63.11237, that 
meets the applicability criteria of subpart JJJJJJ after June 4, 2010 
due to a fuel switch from gaseous fuel to solid fossil fuel, biomass, 
or liquid fuel is considered to be a new source under this subpart. 
This revision maintains consistency with the rule's applicability 
criteria for determining new versus existing sources, eliminates the 
requirement that existing dual-fuel fired boilers notify as affected 
sources although, at the time, they are not subject to subpart JJJJJJ, 
and promotes flexibility in that these existing dual-fuel fired sources 
that were designed to accommodate an alternate fuel may fire the 
alternate fuel and move into subpart JJJJJJ without being subject to 
the more stringent requirements for new boilers.
2. Residential Boilers
    One commenter suggested that the definition of ``residential 
boiler,'' as proposed, be revised to acknowledge the use of combined 
heat and power systems which function with heat and/or hot water 
systems. The EPA agrees and is amending the proposed definition to 
clarify that a boiler that operates as part of a residential combined 
heat and power system (and that meets other definitional requirements) 
is a residential boiler. Another commenter explained that

[[Page 7499]]

historical buildings may be subdivided into more than four units but 
boilers serving those units should still be considered residential 
boilers. We agree and, in this final rule, are amending the proposed 
definition to clarify that a boiler serving a single unit residence 
dwelling that has since been converted or subdivided into condominiums 
or apartments may also be considered a residential boiler.
3. Temporary Boilers
    One commenter supported the EPA's 12-month threshold above which 
the boiler would no longer be considered temporary but pointed out that 
a boiler used on a temporary basis during construction of a commercial 
building may be needed for more than 12 months due to the length of the 
construction period. The commenter suggested that the definition of 
temporary boiler, as proposed, be revised to allow owners or operators 
to petition for an extension beyond 12 months. We agree with the 
commenter and, in this final rule, are amending the proposed definition 
to allow an owner or operator to submit to their regulatory agency a 
petition for an extension beyond 12 months. Another commenter suggested 
that the EPA expand on the intent of ``location'' in the definition of 
``temporary boiler.'' We are amending the proposed definition to 
clarify that ``location'' means ``location within the facility.'' This 
clarification will allow a boiler to be moved from one location to 
another within a facility and be considered a different temporary 
boiler (i.e., a new time period begins) as long as the boiler does not 
continue to perform the same or similar function and to serve the same 
electricity, steam, and/or hot water system. Another commenter pointed 
out that our definition, as proposed, does not specify a time period 
associated with the statement ``Any temporary boiler that replaces a 
temporary boiler at a location within the facility and performs the 
same or similar function will be included in calculating the 
consecutive time period.'' The commenter explained that it is not 
unusual for a temporary boiler to be used for short periods during 
turnarounds or other maintenance activities that recur several years 
apart. Under the proposal, these boilers would not be considered 
temporary because each boiler replaces the previous one and performs 
the same function, even though there is a multi-year gap between the 
occurrences. The commenter suggested that replacements that occur after 
a gap of at least one year should not be considered consecutive for the 
purposes of the definition. We agree with the commenter and are 
amending numbered paragraph (2) in the proposed definition of 
``temporary boiler'' such that it specifies that ``Any temporary boiler 
that replaces a temporary boiler at a location within the facility and 
performs the same or similar function will be included in calculating 
the consecutive time period unless there is a gap in operation of 12 
months or more.''.
4. Seasonal Boilers
    Several commenters explained that boilers subject to semi-annual 
testing requirements would not meet the proposed 7 consecutive month 
shutdown criteria, but otherwise would be considered seasonal boilers. 
Commenters suggested that seasonal boiler be defined to allow periodic 
testing during the 7-month shutdown period. We agree with the 
commenters and, in this final rule, are revising the proposed 
definition of seasonal boiler to allow for a combined total of 15 days 
of use during the shutdown period for periodic testing.
    Another commenter pointed out that the EPA's seasonal boiler 
definition, as proposed, would potentially allow more regular use. The 
commenter specifically suggested that the proposed definition be 
revised to clarify that there must be a 7 consecutive month shutdown 
every 12 months. It was the EPA's intent that the shutdown period of at 
least 7 consecutive months be on a 12-month basis. In response to this 
comment, we are clarifying in the definition of seasonal boiler that 
the shutdown must be for a period of at least 7 consecutive months (or 
210 consecutive days) each 12-month period.
5. Limited-Use Boilers
    Several commenters asserted that the EPA should also include a 
limited-use subcategory in the area source rule for the same reasons we 
determined a seasonal boiler subcategory was appropriate. Commenters 
suggested that we should apply the same 5-year tune-up cycle for 
limited-use units such as auxiliary boilers that we proposed for 
seasonally-operated units and small oil-fired units. Commenters 
explained that in the electric utility industry, auxiliary boilers are 
typically used to generate the steam necessary to bring a main EGU on 
line during startup and, since auxiliary boilers are primarily operated 
during unit startup, operation for many of these boilers is typically 
very limited and sporadic. Commenters also pointed out that the Major 
Source Boiler Rule includes a limited-use subcategory.
    The EPA has determined that a limited-use subcategory is 
appropriate and is including a limited-use subcategory in this final 
Area Source Boiler Rule. Specifically, a limited-use boiler is defined 
in this final rule to mean any boiler that burns any amount of solid or 
liquid fuels and has a federally enforceable average annual capacity 
factor of no more than 10 percent. We are using a capacity-factor 
approach for the same reasons that the approach is being used in the 
Major Source Boiler Rule. A capacity-factor approach allows operational 
flexibility for units that operate on standby mode or low loads for 
periods longer than would be allowed under an approach that limited 
hours of operation (e.g., the 876 hours per year included in the 
proposed limited-use definition for major source boilers). The 
operational flexibility associated with a capacity-factor approach can 
be achieved without increasing emissions or harm to human health and 
the environment. Units operating at 10 percent load for 8,760 hours per 
year would emit the same amount of emissions as units operating at full 
load for 876 hours per year. Further, it is technically infeasible to 
test these limited-use boilers since these units serve as back-up 
energy sources and their operating schedules can be intermittent and 
unpredictable.
    This final rule specifies that limited-use boilers are required to 
complete a tune-up every 5 years. Boilers that operate no more than 10 
percent of the year (i.e., a limited-use boiler) would operate for no 
more than 6 months in between tune-ups on a 5-year tune-up cycle. The 
brief period of operations is even less than the number of operating 
months that seasonal boilers and full-time boilers will operate between 
tune-ups. The irregular schedule of operations also makes it difficult 
to schedule more frequent tune-ups. We believe that establishing a 
limited-use subcategory is reasonable.
6. Alternative PM Emission Control for Certain Oil-Fired Boilers
    The EPA received a number of comments urging that we provide an 
exemption from the PM limit for units burning low-sulfur liquid fuel as 
is provided in subpart Dc of 40 CFR part 60 (standards of performance 
for new small industrial-commercial-institutional steam generating 
units). Commenters asserted that such an exemption is justified since 
the low sulfur content indicates low PM emissions and that boilers 
firing low-sulfur liquid fuel should only be subject to a requirement 
to maintain records documenting the liquid fuel fired. We agree burning 
low-sulfur liquid fuel can be an alternative method of meeting GACT for 
PM. We are amending 40 CFR

[[Page 7500]]

63.11210 to specify that new or reconstructed oil-fired boilers that 
combust only oil that contains no more than 0.50 weight percent sulfur 
or a mixture of 0.50 weight percent sulfur oil with other fuels not 
subject to a PM emission limit under this subpart and that do not use a 
post-combustion technology (except a wet scrubber) to reduce PM or 
sulfur dioxide emissions meet GACT for PM providing the type of fuel 
combusted is monitored and recorded on a monthly basis. Further, we are 
specifying that if you intend to burn a new type of fuel or fuel 
mixture that does not meet the requirements of this paragraph, you must 
conduct a performance test within 60 days of burning the new fuel.

B. Tune-Up Requirements

1. Boilers With Oxygen Trim Systems
    In this final rule, the EPA is adding to the types of boilers that 
must conduct a tune-up every 5 years boilers that have an oxygen trim 
system that maintain an optimum air-to-fuel ratio that would otherwise 
be subject to biennial tune-ups. These units do not need to be tuned as 
frequently as other types of boilers because the trim system is 
designed to maintain an optimum air-to-fuel ratio which is the purpose 
of a tune-up.
2. Initial Compliance for Existing Boilers
    The EPA is revising the initial compliance date for existing 
boilers subject to the work practice or management practice standard of 
a tune-up. Under the proposed rule, owners and operators of existing 
affected boilers would have had to comply with the final rule by March 
21, 2013. We solicited comments on whether to extend the compliance 
date to March 21, 2014. We received no comments objecting to either of 
these dates. Support for an extension until 2014 came from a variety of 
stakeholders affected by the rule. Therefore, this final rule requires 
that if you own or operate an existing boiler subject to a work 
practice or management practice standard of a tune-up, you must comply 
with the final rule no later than March 21, 2014.
3. Compliance Demonstration
    We solicited comment on the requirements for demonstrating 
compliance with the work practice and management practice tune-up 
standards, with one focus on clarifying how to measure CO. Commenters 
requested that we clarify that CO measurements may be taken with a 
portable CO analyzer. We agree that this clarification is appropriate 
and are including this clarification in this final rule.

C. Energy Assessment

    The EPA received a number of comments regarding the energy 
assessment requirements and in this final rule is making a series of 
changes to the energy assessment provisions and related definitions 
that clarify terms used and better set the scope of the assessment.
    In this final rule, we are revising the definition of energy 
assessment by providing a duration for performing the energy assessment 
for numbered paragraph (3) in the definition of ``energy assessment'' 
in 40 CFR 63.11237 for facilities with units with greater than 1 TBtu/
yr heat input capacity to specify time duration/size ratio and are 
including a cap to the maximum number of on-site technical hours that 
should be used in the energy assessment. The energy assessment for 
facilities with affected boilers and process heaters with greater than 
1.0 TBtu/yr heat input capacity will be up to 24 on-site technical 
labor hours in length for the first TBtu/yr plus 8 technical labor 
hours for every additional 1.0 TBtu/yr not to exceed 160 technical 
hours, but may be longer at the discretion of the owner or operator.
    The revised definition of energy assessment also clarifies our 
intentions that the scope of assessment is based on energy use by 
discrete segments of a facility, which could vary significantly 
depending on the site and its complexity, and not by a total 
aggregation of all individual energy using elements of a facility. We 
are adding the following language, as paragraph (4), to the ``energy 
assessment'' definition to help resolve current problems and allow for 
more streamlined assessments:
    ``(4) The on-site energy use systems serving as the basis for the 
percent of affected boiler(s) energy output in paragraphs (1), (2), and 
(3) of this definition may be segmented by production area or energy 
use area as most logical and applicable to the specific facility being 
assessed (e.g., product X manufacturing area; product Y drying area; 
Building Z).''
    In this final rule, we are revising 40 CFR 63.11201 and Table 2 to 
subpart JJJJJJ to allow a source that is operating under an energy 
management program established through energy management systems 
compatible with ISO 50001, that includes the affected boilers, by March 
21, 2014, to satisfy the energy assessment requirement. In addition, we 
are clarifying that energy assessor approval and qualification 
requirements are waived in instances where an energy assessment 
completed on or after January 1, 2008 meets or is amended to meet the 
energy assessment requirements in this final rule by March 21.
    The definition of ``boiler system'' is being revised in this final 
rule to clarify that it means the boiler and associated components 
directly connected to and serving the energy use systems.
    The definition of ``energy use system'' is also being revised in 
this final rule to clarify that energy use systems are only those on-
site systems using energy clearly produced by affected boilers.

D. Clarification of Oxygen Concentration Operating Limits

    We are clarifying in this final rule that operating limits for 
oxygen concentration must be at or above the minimum established during 
a performance stack test. We are also clarifying that these limits are 
applicable when the unit is firing the fuel or fuel mixture utilized 
during the CO performance test.

E. Definitions Regarding Averaging Times

    The EPA received comments requesting that we clarify that periods 
of startup and shutdown are excluded from calculation of the arithmetic 
mean in the definitions of ``30-day rolling average'' and ``daily block 
average.'' We agree with the commenters and, in this final rule, are 
revising the definitions accordingly.

F. Fuel Sampling Frequency

    The EPA is amending the fuel sampling requirements in 40 CFR 
63.11220(c) because we realized that when performance stack testing 
requirements were revised in the March 2011 final rule we neglected to 
revise the fuel analysis requirements. In this final rule, we are 
specifying that the owner or operator does not need to conduct further 
fuel analysis sampling if, when demonstrating initial compliance with 
the Hg emission limit, the Hg constituents in the fuel or fuel mixture 
are measured to be equal to or less than half of the Hg emission limit. 
If, when demonstrating initial compliance, the Hg constituents in the 
fuel or fuel mixture are greater than half of the Hg emission limit, 
the owner or operator must conduct quarterly sampling.

G. Performance Testing Frequency

    The EPA is amending the PM performance testing requirements in 40 
CFR 63.11220(b) to specify that the

[[Page 7501]]

owner or operator of an affected boiler does not need to conduct 
further PM emission testing if, when demonstrating initial compliance 
with the PM emission limit, the performance test results show that the 
PM emissions are equal to or less than half of the PM emission limit. 
The owner or operator must continue to comply with all applicable 
operating limits and monitoring requirements. If the initial 
performance test results show that the PM emissions are greater than 
half of the PM emission limit, the owner or operator must conduct 
subsequent performance tests as specified in 40 CFR 63.11220(a).
    With respect to the reconsideration issue regarding the GACT-based 
PM standards for new oil-fired boilers, we received comments asserting 
that the most effective control strategy for small oil-fired boilers is 
the tune-up required by the standards and that establishing a PM limit 
for those boilers between 10 MMBtu/hr and 30 MMBtu/hr just ensures that 
those boilers will do stack testing demonstrating that the boilers are 
in compliance without the need for controls; a fact already known. 
Commenters also asserted that establishing a PM limit imposes a stack 
test obligation on small facilities with the least resources to deal 
with the testing.
    We have reviewed the comments and are not eliminating or revising 
the PM limit for new oil-fired boilers with heat input capacity between 
10 MMBtu/hr and 30 MMBtu/hr. We do however, believe that adjustments to 
the PM performance test frequency as described above are appropriate 
for boilers that demonstrate during their initial performance test that 
their PM emissions are equal to or less than half of the PM limit. We 
believe that the performance test adjustment should not be potentially 
applicable to only new oil-fired boilers with heat input capacity 
between 10 MMBtu/hr and 30 MMBtu/hr, but to all new boilers. Owners or 
operators of boilers whose initial performance test results show that 
their PM emissions are equal to or less than half of the PM emission 
limit and, thus, do not need to conduct further PM emissions testing, 
must continue to comply with all applicable operating limits and 
monitoring requirements to ensure that there are no changes in 
operation of the boiler or air pollution control equipment that could 
increase emissions. This adjustment in PM performance test frequency 
will potentially reduce the burden on small entities operating boilers 
that meet the adjustment criteria.

H. Startup and Shutdown Definitions

    A number of commenters indicated that the proposed load 
specifications (i.e., 25 percent load) within the definitions of 
``startup'' and ``shutdown'' were inconsistent with either safe or 
normal (proper) operation of the various types of boilers encountered 
within the source category. As the basis for defining periods of 
startup and shutdown, a number of commenters suggested alternative load 
specifications based on the specific considerations of their boilers; 
other commenters suggested the achievement of various steady-state 
conditions.
    We have reviewed these comments and believe adjustments are 
appropriate in the definitions of ``startup'' and ``shutdown.'' These 
adjustments are tailored for industrial boilers and are consistent with 
the definitions of ``startup'' and ``shutdown'' contained in the 40 CFR 
part 63, subpart A General Provisions. We believe these revised 
definitions address the comments and are rational based on the fact 
that industrial boilers function to provide steam or, in the case of 
cogeneration units, electricity. Therefore, industrial boilers should 
be considered subject to applicable standards at all times steam of the 
proper pressure, temperature and flow rate is being provided to a 
common header system or energy user(s) for use as either process steam 
or for the cogeneration of electricity. The definitions of ``startup'' 
and ``shutdown'' have been revised in this final rule as follows:

    Startup means either the first-ever firing of fuel in a boiler 
for the purpose of supplying steam or heat for heating and/or 
producing electricity, or for any other purpose, or the firing of 
fuel in a boiler after a shutdown event for any purpose. Startup 
ends when any of the steam or heat from the boiler is supplied for 
heating and/or producing electricity, or for any other purpose.
    Shutdown means the cessation of operation of a boiler for any 
purpose. Shutdown begins either when none of the steam or heat from 
the boiler is supplied for heating and/or producing electricity, or 
for any other purpose, or at the point of no fuel being fired in the 
boiler, whichever is earlier. Shutdown ends when there is no steam 
and no heat being supplied and no fuel being fired in the boiler.

I. Notifications

1. Initial Notification
    The EPA has been made aware that there are many affected boilers at 
area sources that are just becoming aware, or are not yet aware, that 
they are subject to emission standards. Thus, we are amending 40 CFR 
63.11225(a)(2) to allow these sources until January 20, 2014 to submit 
their Initial Notification.
2. Notification of Fuel Change, Physical Change, or Permit Limit
    The notification requirement in 40 CFR 63.11225(g) of the final 
rule for instances when a change in fuel or a physical change to a 
boiler results in the applicability of a different subcategory or a 
change out of subpart JJJJJJ is being revised. Under the proposed 
reconsideration action, a facility would have been required to provide 
30 days prior notice of the date upon which the change was scheduled to 
occur. Commenters explained that an advanced notification requirement 
would delay such a change if the owner or operator decided to 
immediately make a change (e.g., switch to 100 percent natural gas) and 
could potentially restrict flexibility in manufacturing operations, and 
suggested that the owner or operator be allowed to make notification 
within 30 days after the change has occurred. We agree that 
notification within 30 days after a change that results in 
applicability of a different subcategory or a change out of subpart 
JJJJJJ will provide the EPA or state/local agency with the required 
information within a reasonable timeframe. Thus, in this final rule, we 
are requiring facilities making these types of changes to provide 
notification within 30 days following the change. The notification 
requirement in 40 CFR 63.11225(g) is also being amended to clarify that 
it includes affected boilers that switch fuels or make a physical 
change to the boiler and the fuel switch or change results in the 
applicability of a different subcategory within subpart JJJJJJ, in the 
boiler becoming subject to subpart JJJJJJ, or in the boiler switching 
out of subpart JJJJJJ due to a change to 100 percent natural gas, as 
well as affected boilers that take a permit limit that results in the 
applicability of subpart JJJJJJ. Commenters requested that we make this 
clarification and we agree that it is appropriate.

J. Miscellaneous Definitions

    In this final rule, we are revising some definitions and adding 
others to help affected sources determine their applicability. 
Specifically, definitions have been added for the terms ``10-day 
rolling average,'' ``30-day rolling average,'' ``Annual heat input,'' 
``Biodiesel,'' ``Calendar year,'' ``Common stack,'' ``Daily block 
average,'' ``Distillate oil,'' ``Electric boiler,'' ``Electric utility 
steam generating unit (EGU),'' ``Energy management program,'' 
``Fluidized bed boiler,'' ``Fluidized bed combustion,'' ``Hourly 
average,'' ``Limited-use boiler,'' ``Load fraction,''

[[Page 7502]]

``Minimum scrubber pressure drop,'' ``Minimum sorbent injection rate,'' 
``Minimum total secondary electric power,'' ``Operating day,'' ``Oxygen 
analyzer system,'' ``Oxygen trim system,'' ``Process heater,'' 
``Regulated gas stream,'' ``Residential boiler,'' ``Residual oil,'' 
``Seasonal boiler,'' ``Shutdown,'' ``Solid fuel,'' ``Startup,'' 
``Temporary boiler,'' ``Tune-up,'' ``Vegetable oil,'' ``Voluntary 
Consensus Standards (VCS),'' and ``Wet scrubber.''
    Definitions revised to clarify the term include ``Bag leak 
detection system,'' ``Biomass subcategory,'' ``Boiler,'' ``Boiler 
system,'' ``Deviation,'' ``Dry scrubber,'' ``Electrostatic precipitator 
(ESP),'' ``Energy assessment,'' ``Energy use system,'' ``Federally 
enforceable,'' ``Gas-fired boiler,'' ``Heat input,'' ``Hot water 
heater,'' ``Institutional boiler,'' ``Liquid fuel,'' ``Minimum 
activated carbon injection rate,'' ``Minimum oxygen level,'' ``Minimum 
scrubber liquid flow rate,'' ``Natural gas,'' ``Oil subcategory,'' 
``Particulate matter,'' ``Period of gas curtailment or supply 
interruption,'' ``Qualified Energy Assessor,'' and ``Waste heat 
boiler.''

V. Other Actions the EPA Is Taking

    Section 307(d)(7)(B) of the CAA states that ``[o]nly an objection 
to a rule or procedure which was raised with reasonable specificity 
during the period for public comment (including any public hearing) may 
be raised during judicial review. If the person raising an objection 
can demonstrate to the Administrator that it was impracticable to raise 
such objection within such time or if the grounds for such objection 
arose after the period for public comment (but within the time 
specified for judicial review) and if such objection is of central 
relevance to the outcome of the rule, the Administrator shall convene a 
proceeding for reconsideration of the rule and provide the same 
procedural rights as would have been afforded had the information been 
available at the time the rule was proposed. If the Administrator 
refuses to convene such a proceeding, such person may seek review of 
such refusal in the United States court of appeals for the appropriate 
circuit (as provided in subsection (b)).''
    As to the first procedural criterion for reconsideration, a 
petitioner must show why the issue could not have been presented during 
the comment period, either because it was impracticable to raise the 
issue during that time or because the grounds for the issue arose after 
the period for public comment (but within 60 days of publication of the 
final action). The EPA is denying the petitions for reconsideration of 
five issues because this criterion has not been met. In many cases, the 
petitions reiterate comments made on the proposed June 2010 rule during 
the public comment period for that rule. On those issues, the EPA 
responded to those comments in the March 2011 final rule, and made 
appropriate revisions to the proposed rule after consideration of 
public comments received. It is well established that an agency may 
refine its proposed approach without providing an additional 
opportunity for public comment. See Community Nutrition Institute v. 
Block, 749 F.2d 50, 58 (DC Cir. 1984) and International Fabricare 
Institute v. EPA, 972 F.2d 384, 399 (DC Cir. 1992) (notice and comment 
is not intended to result in ``interminable back-and-forth[,]'' nor is 
agency required to provide additional opportunity to comment on its 
response to comments) and Small Refiner Lead Phase-Down Task Force v. 
EPA, 705 F.2d 506, 547 (DC Cir. 1983) (``notice requirement should not 
force an agency endlessly to repropose a rule because of minor 
changes'')
    In the EPA's view, an objection is of central relevance to the 
outcome of the rule only if it provides substantial support for the 
argument that the promulgated regulation should be revised. See Union 
Oil v. EPA, 821 F.2d 768, 683 (DC Cir. 1987) (court declined to remand 
rule because petitioners failed to show substantial likelihood that 
final rule would have been changed based on information in petition). 
See also the EPA's Denial of the Petitions to Reconsider the 
Endangerment and Cause or Contribute Findings for Greenhouse Gases 
under Section 202 of the Clean Air Act, 75 FR at 49556, 49561 (August 
13, 2010). See also, 75 FR at 49556, 49560-49563 (August 13, 2010) and 
76 FR at 4780, 4786--4788 (January 26, 2011) for additional discussion 
of the standard for reconsideration under CAA section 307(d)(7)(B).
    We are denying reconsideration on the following five issues 
contained in the petitions for reconsideration because they failed to 
meet the standard described above for reconsideration under CAA section 
307(d)(7)(B). Specifically, on these issues, the petitioner has failed 
to show the following: That it was impracticable to raise their 
objections during the comment period or that the grounds for their 
objections arose after the close of the comment period; and/or that 
their concern is of central relevance to the outcome of the rule. 
Therefore, the EPA is denying the petitions for reconsideration on the 
issues for the reasons described below.

Issue: Use of RDL Is Unlawful

    The petitioner (Sierra Club) objected to the EPA establishing a 
MACT floor emission limit at a level equal to three times the RDL as 
being unlawful and arbitrary. This issue is not of central relevance to 
the outcome of this final rule. The final emission limits in this rule 
are based on the UPL at a confidence interval of 99 percent. The RDL 
analysis was not used in this final rule.

Issue: MACT Floor for Existing Sources Must Reflect Average Performance 
of the Top 12 Percent of Units

    The petitioner (Sierra Club) stated that the MACT floor for 
existing sources must reflect the average performance of the top 12 
percent of units. The petitioner has not demonstrated that it lacked 
the opportunity to comment on the EPA's MACT floor analysis. The 
methods used to compute the MACT floors were subject to notice and 
comment. Rationale and responses to comments on the MACT floor 
methodology were provided at 75 FR 31904, June 4, 2010; 76 FR 15571, 
March 21, 2011. Therefore, the EPA is denying the request for 
reconsideration.

Issue: Consider a De Minimis Size Threshold

    The petitioners (American Petroleum Institute, National 
Petrochemical and Refiners Association, Alaska Oil and Gas Association) 
requested that the EPA consider a de minimis size threshold using 
guidelines from insignificance thresholds authorized under CAA part 71. 
The EPA is denying the request for reconsideration on this issue. In 
the June 2010 proposed rule, it was readily apparent that we were not 
establishing de minimis size thresholds in the area source rulemaking. 
We received multiple comments on this issue and responded to them in 
the response to comments document for the March 2011 final rule. The 
issue on which petitioners seek reconsideration was one that could have 
been raised during the comment period and thus does not meet the 
requirements for reconsideration. Therefore, the EPA is denying this 
request for reconsideration.

Issue: MACT Standards Must Be Set for All HAP

    The petitioner (Sierra Club) asserted that MACT standards must be 
set for all HAP including HAP not listed in CAA section 112(c)(6). The 
EPA is denying the request for reconsideration on this issue. We 
disagree with the petitioner that the EPA must issue emission standards 
for all HAP. MACT standards have been set for Hg and CO, as a

[[Page 7503]]

surrogate for POM emissions, but the EPA does not interpret CAA section 
112(c)(6) to compel regulation of all HAP emitted by area sources. The 
EPA's position on this issue was clear in the proposed rule (75 FR 
31900, 31904, 31918). This commenter raised this issue in its comments 
(76 FR 15567, March 21, 2011). Not only did the petitioner have an 
opportunity to present its theory in its comments, but also it did so.

Issue: CO Is Not a Valid Surrogate for POM

    The petitioner (Sierra Club) requested that the EPA remove the CO 
standard as a surrogate for POM and instead adopt a numeric limit for 
POM because CO is not an appropriate surrogate. The EPA is denying the 
request for reconsideration on this issue. While the EPA disagrees with 
the petitioner's argument regarding the suitability of CO as a 
surrogate for POM, the petitioner has not demonstrated that it lacked 
the opportunity to comment on this issue. The EPA revised the final CO 
emission limit to ensure a more accurate correlation between POM and CO 
levels. The EPA made its position on this issue clear and explained the 
agency's basis for concluding that CO was an appropriate surrogate in 
the proposed rule (75 FR 31900, 31904, June 4, 2010). The petitioner 
raised this issue in its comments (Document ID: EPA-HQ-OAR-2006-0790-
1982, Comments of Earthjustice, Sierra Club, Clean Air Task Force, and 
Natural Resources Defense Council, p. 4). Therefore, the EPA is denying 
the request for reconsideration.

VI. Impacts Associated With This Final Rule

    The amendments contained in this final 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 final amendments will not affect 
the estimated emission reductions, control costs or the benefits of the 
rule in substance. The amendments do not impose any additional 
regulatory requirements beyond those imposed by the previously 
promulgated boiler area source rule and, in fact, 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, limited-
use boilers, small (equal to or less than 5 MMBtu/hr) oil-fired boilers 
and boilers using an oxygen trim system that maintain an optimum air-
to-fuel ratio. Additionally, the burden will be reduced on facilities 
with existing large boilers that currently operate under an energy 
management program established through energy management systems 
compatible with ISO 50001, that includes the affected boilers, because 
a one-time energy assessment will not be required. Burden will also be 
reduced on facilities with affected boilers that burn low-sulfur oil 
because, in lieu of needing to meet an emission limit, we consider low-
sulfur oil combustion to be GACT for PM for those boilers. This change 
should allow sources currently complying with 40 CFR 60 subpart Dc to 
use the same compliance approach rather than needing to monitor limits. 
Further reduction in burden will occur in instances where initial 
compliance demonstrations with the Hg emission limit via fuel sampling 
or with the PM emission limit via performance stack testing show that 
the emissions are equal to or less than half the respective emission 
limit because no further sampling or testing of those boilers will be 
required.
    As discussed in section III, the Hg emission limits for new and 
existing large (10 MMBtu/hr or greater) coal-fired area source boilers 
were revised because of an error discovered in the analysis conducted 
for the final rule. This technical correction resulted in an increase 
in the emission limit for Hg. As explained in the December 2011 
proposal, we also revised our impacts analysis to be consistent with 
emission factor 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 Boiler Rule because of 
insufficient data for area sources. Emission factor changes resulted in 
a higher baseline emission for Hg from coal-fired area source boilers. 
Consequently, the result of the increase in both baseline Hg emissions 
and Hg emission limits is that the overall reduction in Hg emissions 
does not change significantly from the estimated reduction for the 
promulgated rule.
    In summary, as compared to the control costs estimated for the 
March 2011 final rule, this final rule will not result in any 
meaningful change 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 section 3(f)(1) of Executive Order 12866 (58 FR 51735, 
October 4, 1993), this action is a ``significant regulatory action'' 
because it is likely to raise novel legal or policy issues. 
Accordingly, the EPA submitted this action to the 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 action does not impose an information collection burden. This 
action results in no significant changes to the information collection 
requirements of the promulgated rule and will have no increased impact 
on the information collection estimate of projected cost and hour 
burden made and approved by OMB. In fact, the reduction in tune-up 
frequency for some boilers will result in less information collection 
burden. Therefore, the information collection request has not been 
revised. However, the 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 2060-0668. The OMB control numbers for the EPA's regulations in 
40 CFR are listed in 40 CFR part 9.

C. Regulatory Flexibility Act

    The 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.\2\

[[Page 7504]]

The RFA also allows an agency to ``consider a series of closely related 
rules as one rule for the purposes of sections'' 603 (initial 
regulatory flexibility analysis) and 604 (final regulatory flexibility 
analysis) in order to avoid ``duplicative action.'' 5 U.S.C. section 
605(c). These amendments and notice of final action on reconsideration 
are closely related to the final Area Source Boiler Rule, which the EPA 
signed on February 21, 2011, and that took effect on May 20, 2011. The 
EPA prepared a final regulatory flexibility analysis in connection with 
the final Area Source Boiler Rule. Therefore, pursuant to section 
605(c), the EPA is not required to complete a final regulatory 
flexibility analysis for this rule (i.e., the amendments and final 
action).
---------------------------------------------------------------------------

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

    The EPA has been concerned with potential small entity impacts 
since it began developing the Area Source Boiler Rule. The EPA 
conducted outreach to small entities and, pursuant to section 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 final Area Source Boiler Rule. Convening an additional Panel 
and preparing an additional final 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 action, which amends the Area Source Boiler Rule, will 
not impose any additional regulatory requirements beyond those imposed 
by the previously promulgated Area Source Boiler Rule and, in fact, the 
amendments will afford relief to some boilers.

D. Unfunded Mandates Reform Act

    This action contains no new federal mandates under the provisions 
of Title II of the UMRA of 1995, 2 U.S.C. 1531-1538 for state, local, 
or tribal governments or the private sector. This action imposes no new 
enforceable duty on any state, local, or tribal governments or the 
private sector. Therefore, this action 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 regulatory requirements that might 
significantly or uniquely affect small governments. This rule finalizes 
amendments to aid with compliance.

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 final 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.

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

    This action 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 action.

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 Order has the potential to influence the regulation. This action 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. We estimate no significant changes for 
the energy sector for price, production, or imports.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the NTTAA of 1995, Public Law No. 104-113, 12(d) 
(15 U.S.C. 272 note) directs the EPA to use 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 action 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 final rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because the level of 
protection provided to human health or the environment through the 
rule's requirements does not vary. 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.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of the Congress and to the Comptroller General of the 
United States. The EPA will submit a report containing this rule and 
other required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to

[[Page 7505]]

publication of the rule in the Federal Register. A Major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is a reconsideration of a previous action that 
was a major rule under the CRA. However, today's action makes only 
certain limited revisions to the March 2011 rule and those revisions do 
not qualify as a major rule under the CRA. Therefore, this action is 
not a ``major rule'' as defined by 5 U.S.C. 804(2). This rule will be 
effective February 1, 2013.

List of Subjects in 40 CFR Part 63

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

    Dated: December 20, 2012.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part 
63 of the Code of Federal Regulations is amended as follows:

PART 63--[AMENDED]

0
1. The authority citation for part 63 continues to read as follows:

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

Subpart A--[Amended]

0
2. Section 63.14 is amended by:
0
a. Revising paragraphs (b)(19), (b)(23), (b)(35), (b)(40), (b)(69), and 
(b)(70).
0
b. Removing and reserving paragraph (b)(53).
0
c. Adding paragraphs (b)(46), (b)(55), and (b)(76) through (83).
0
d. Adding paragraphs (p)(12) through (20).
0
e. Adding paragraph (r).
    The revisions and additions read as follows:


Sec.  63.14  Incorporations by reference.

* * * * *
    (b) * * *
    (19) ASTM D95-05 (Reapproved 2010), Standard Test Method for Water 
in Petroleum Products and Bituminous Materials by Distillation, 
approved May 1, 2010, IBR approved for Sec.  63.10005(i) and table 6 to 
subpart DDDDD.
* * * * *
    (23) ASTM D4006-11, Standard Test Method for Water in Crude Oil by 
Distillation, including Annex A1 and Appendix X1, approved June 1, 
2011, IBR approved for Sec.  63.10005(i) and table 6 to subpart DDDDD.
* * * * *
    (35) ASTM D6784-02 (Reapproved 2008) Standard Test Method for 
Elemental, Oxidized, Particle-Bound and Total Mercury in Flue Gas 
Generated from Coal-Fired Stationary Sources (Ontario Hydro Method), 
approved April 1, 2008, IBR approved for table 1 to subpart DDDDD of 
this part, table 2 to subpart DDDDD of this part, table 5 to subpart 
DDDDD, table 11 to subpart DDDDD of this part, table 12 to subpart 
DDDDD of this part, table 13 to subpart DDDDD of this part, and table 4 
to subpart JJJJJJ of this part.
* * * * *
    (40) ASTM D396-10 Standard Specification for Fuel Oils, approved 
October 1, 2010, IBR approved for Sec.  63.7575 and Sec.  6311237.
* * * * *
    (46) ASTM D4606-03(2007), Standard Test Method for Determination of 
Arsenic and Selenium in Coal by the Hydride Generation/Atomic 
Absorption Method, approved October 1, 2007, IBR approved for table 6 
to subpart DDDDD.
* * * * *
    (55) ASTM D6357-11, Test Methods for Determination of Trace 
Elements in Coal, Coke, and Combustion Residues from Coal Utilization 
Processes by Inductively Coupled Plasma Atomic Emission Spectrometry, 
approved April 1, 2011, IBR approved for table 6 to subpart DDDDD.
* * * * *
    (69) ASTM D4057-06 (Reapproved 2011), Standard Practice for Manual 
Sampling of Petroleum and Petroleum Products, including Annex A1, 
approved June 1, 2011, IBR approved for Sec.  63.10005(i) and table 6 
to subpart DDDDD.
    (70) ASTM D4177-95 (Reapproved 2010), Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products, including 
Annexes A1 through A6 and Appendices X1 and X2, approved May 1, 2010, 
IBR approved for Sec.  63.10005(i) and table 6 to subpart DDDDD.
* * * * *
    (76) ASTM D6751-11b, Standard Specification for Biodiesel Fuel 
Blend Stock (B100) for Middle Distillate Fuels, approved July 15, 2011, 
IBR approved for Sec.  63.7575 and Sec.  63.11237.
    (77) ASTM D975-11b, Standard Specification for Diesel Fuel Oils, 
approved December 1, 2011, IBR approved for Sec.  63.7575.
    (78) ASTM D5864-11 Standard Test Method for Determining Aerobic 
Aquatic Biodegradation of Lubricants or Their Components, approved 
March 1, 2011, IBR approved for table 6 to subpart DDDDD.
    (79) ASTM D240-09 Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter, approved July 1, 2009, 
IBR approved for table 6 to subpart DDDDD.
    (80) ASTM D4208-02(2007) Standard Test Method for Total Chlorine in 
Coal by the Oxygen Bomb Combustion/Ion Selective Electrode Method, 
approved May 1, 2007, IBR approved for table 6 to subpart DDDDD.
    (81) ASTM D5192-09 Standard Practice for Collection of Coal Samples 
from Core, approved June 1, 2009, IBR approved for table 6 to subpart 
DDDDD.
    (82) ASTM D7430-11ae1, Standard Practice for Mechanical Sampling of 
Coal, approved October 1, 2011, IBR approved for table 6 to subpart 
DDDDD.
    (83) ASTM D6883-04, Standard Practice for Manual Sampling of 
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, 
approved June 1, 2004, IBR approved for table 6 to subpart DDDDD.
* * * * *
    (p) * * *
    (12) Method 5050 (SW-846-5050), Bomb Preparation Method for Solid 
Waste, Revision 0, September 1994, in EPA Publication No. SW-846, Test 
Methods for Evaluating Solid Waste, Physical/Chemical Methods, Third 
Edition IBR approved for table 6 to subpart DDDDD.
    (13) Method 9056 (SW-846-9056), Determination of Inorganic Anions 
by Ion Chromatography, Revision 1, February 2007, in EPA Publication 
No. SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
    (14) Method 9076 (SW-846-9076), Test Method for Total Chlorine in 
New and Used Petroleum Products by Oxidative Combustion and 
Microcoulometry, Revision 0, September 1994, in EPA Publication No. SW-
846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
    (15) Method 1631 Revision E, Mercury in Water by Oxidation, Purge 
and Trap, and Cold Vapor Atomic Absorption Fluorescence Spectrometry, 
Revision E, EPA-821-R-02-019, August 2002, IBR approved for table 6 to 
subpart DDDDD.
    (16) Method 200.8, Determination of Trace Elements in Waters and 
Wastes by Inductively Coupled Plasma--Mass Spectrometry, Revision 5.4, 
1994, IBR approved for table 6 to subpart DDDDD.
    (17) Method 6020A (SW-846-6020A), Inductively Coupled Plasma-Mass 
Spectrometry, Revision 1, February 2007, in EPA Publication No. SW-846, 
Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,

[[Page 7506]]

Third Edition, IBR approved for table 6 to subpart DDDDD.
    (18) Method 6010C (SW-846-6010C), Inductively Coupled Plasma-Atomic 
Emission Spectrometry, Revision 3, February 2007, in EPA Publication 
No. SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
    (19) Method 7060A (SW-846-7060A), Arsenic (Atomic Absorption, 
Furnace Technique), Revision 1, September 1994, in EPA Publication No. 
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
    (20) Method 7740 (SW-846-7740), Selenium (Atomic Absorption, 
Furnace Technique), Revision 0, September 1986, in EPA Publication No. 
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods, Third Edition, IBR approved for table 6 to subpart DDDDD.
* * * * *
    (r) The following material is available for purchase from the 
Technical Association of the Pulp and Paper Industry (TAPPI), 15 
Technology Parkway South, Norcross, GA 30092, (800) 332-8686, http://www.tappi.org.
    (1) TAPPI T 266, Determination of Sodium, Calcium, Copper, Iron, 
and Manganese in Pulp and Paper by Atomic Absorption Spectroscopy 
(Reaffirmation of T 266 om-02), Draft No. 2, July 2006, IBR approved 
for table 6 to subpart DDDDD.
    (2) [Reserved]

Subpart JJJJJJ--[AMENDED]

0
3. Section 63.11194 is amended by revising paragraphs (a)(1), (c) and 
(d), by redesignating paragraph (e) as paragraph (f) and by adding new 
paragraph (e) to read as follows:


Sec.  63.11194  What is the affected source of this subpart?

    (a) * * *
    (1) The affected source of this subpart is the collection of all 
existing industrial, commercial, and institutional boilers within a 
subcategory, as listed in Sec.  63.11200 and defined in Sec.  63.11237, 
located at an area source.
* * * * *
    (c) An affected source is a new source if you commenced 
construction of the affected source after June 4, 2010, and the boiler 
meets the applicability criteria at the time you commence construction.
    (d) An affected source is a reconstructed source if the boiler 
meets the reconstruction criteria as defined in Sec.  63.2, you 
commenced reconstruction after June 4, 2010, and the boiler meets the 
applicability criteria at the time you commence reconstruction.
    (e) An existing dual-fuel fired boiler meeting the definition of 
gas-fired boiler, as defined in Sec.  63.11237, that meets the 
applicability requirements of this subpart after June 4, 2010 due to a 
fuel switch from gaseous fuel to solid fossil fuel, biomass, or liquid 
fuel is considered to be an existing source under this subpart as long 
as the boiler was designed to accommodate the alternate fuel.
* * * * *

0
4. Section 63.11195 is amended by revising the introductory text and 
paragraphs (c) and (g) and by adding paragraphs (h) through (k) to read 
as follows:


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

    The types of boilers listed in paragraphs (a) through (k) of this 
section are not subject to this subpart and to any requirements in this 
subpart.
* * * * *
    (c) A boiler required to have a permit under section 3005 of the 
Solid Waste Disposal Act or covered by subpart EEE of this part (e.g., 
hazardous waste boilers), unless such units do not combust hazardous 
waste and combust comparable fuels.
* * * * *
    (g) Any boiler that is used as a control device to comply with 
another subpart of this part, or part 60, part 61, or part 65 of this 
chapter provided that at least 50 percent of the average annual heat 
input during any 3 consecutive calendar years to the boiler is provided 
by regulated gas streams that are subject to another standard.
    (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 (EGU) covered by 
subpart UUUUU of this part.

0
5. Section 63.11196 is amended by revising paragraphs (a)(1) and (d) to 
read as follows:


Sec.  63.11196  What are my compliance dates?

    (a) * * *
    (1) If the existing affected boiler is subject to a work practice 
or management practice standard of a tune-up, you must achieve 
compliance with the work practice or management practice standard no 
later than March 21, 2014.
* * * * *
    (d) If you own or operate an industrial, commercial, or 
institutional boiler and would be subject to this subpart except for 
the exemption in Sec.  63.11195(b) for commercial and industrial solid 
waste incineration units covered by 40 CFR part 60, subpart CCCC or 
subpart DDDD, and you cease combusting solid waste, you must be in 
compliance with this subpart on the effective date of the waste to fuel 
switch as specified in Sec.  60.2145(a)(2) and (3) of subpart CCCC or 
Sec.  60.2710(a)(2) and (3) of subpart DDDD.

0
6. Section 63.11200 is revised to read as follows:


Sec.  63.11200  What are the subcategories of boilers?

    The subcategories of boilers, as defined in Sec.  63.11237 are:
    (a) Coal.
    (b) Biomass.
    (c) Oil.
    (d) Seasonal boilers.
    (e) Oil-fired boilers with heat input capacity of equal to or less 
than 5 million British thermal units (Btu) per hour.
    (f) Boilers with an oxygen trim system that maintains an optimum 
air-to-fuel ratio that would otherwise be subject to a biennial tune-
up.
    (g) Limited-use boilers.

0
7. Section 63.11201 is amended by revising paragraphs (b) and (d) to 
read as follows:


Sec.  63.11201  What standards must I meet?

* * * * *
    (b) You must comply with each work practice standard, emission 
reduction measure, and management practice specified in Table 2 to this 
subpart that applies to your boiler. An energy assessment completed on 
or after January 1, 2008 that meets or is amended to meet the energy 
assessment requirements in Table 2 to this subpart satisfies the energy 
assessment requirement. A facility that operates under an energy 
management program established through energy management systems 
compatible with ISO 50001, that includes the affected units, also 
satisfies the energy assessment requirement.
* * * * *
    (d) These standards apply at all times the affected boiler is 
operating, except during periods of startup and shutdown as defined in 
Sec.  63.11237, during which time you must comply only with Table 2 to 
this subpart.

0
8. Section 63.11205 is amended by revising paragraphs (b), (c) 
introductory

[[Page 7507]]

text, (c)(1) introductory text, and (c)(1)(i) to read as follows:


Sec.  63.11205  What are my general requirements for complying with 
this subpart?

* * * * *
    (b) You must demonstrate compliance with all applicable emission 
limits using performance stack testing, fuel analysis, or a continuous 
monitoring system (CMS), including a continuous emission monitoring 
system (CEMS), a continuous opacity monitoring system (COMS), or a 
continuous parameter monitoring system (CPMS), where applicable. You 
may demonstrate compliance with the applicable mercury emission limit 
using fuel analysis if the emission rate calculated according to Sec.  
63.11211(c) is less than the applicable emission limit. Otherwise, you 
must demonstrate compliance using stack testing.
    (c) If you demonstrate compliance with any applicable emission 
limit through performance stack testing and subsequent compliance with 
operating limits (including the use of CPMS), with a CEMS, or with a 
COMS, you must develop a site-specific monitoring plan according to the 
requirements in paragraphs (c)(1) through (3) of this section for the 
use of any CEMS, COMS, or CPMS. This requirement also applies to you if 
you petition the EPA Administrator for alternative monitoring 
parameters under Sec.  63.8(f).
    (1) For each CMS required in this section (including CEMS, COMS, or 
CPMS), you must develop, and submit to the Administrator for approval 
upon request, a site-specific monitoring plan that addresses paragraphs 
(c)(1)(i) through (vi) 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. This requirement to develop 
and submit a site-specific monitoring plan does not apply to affected 
sources with existing CEMS or COMS operated according to the 
performance specifications under appendix B to part 60 of this chapter 
and that meet the requirements of Sec.  63.11224.
    (i) Installation of the CMS sampling probe or other interface at a 
measurement location relative to each affected process unit such that 
the measurement is representative of control of the exhaust emissions 
(e.g., on or downstream of the last control device);
* * * * *

0
9. Section 63.11210 is amended by revising paragraphs (b) through (e) 
and adding paragraphs (f) through (j) to read as follows:


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

* * * * *
    (b) For existing affected boilers that have applicable emission 
limits, you must demonstrate initial compliance with the applicable 
emission limits no later than 180 days after the compliance date that 
is specified in Sec.  63.11196 and according to the applicable 
provisions in Sec.  63.7(a)(2), except as provided in paragraph (j) of 
this section.
    (c) For existing affected boilers that have applicable work 
practice standards, management practices, or emission reduction 
measures, you must demonstrate initial compliance no later than the 
compliance date that is specified in Sec.  63.11196 and according to 
the applicable provisions in Sec.  63.7(a)(2), except as provided in 
paragraph (j) of this section.
    (d) For new or reconstructed affected boilers that have applicable 
emission limits, you must demonstrate initial compliance with the 
applicable emission limits no later than 180 days after March 21, 2011 
or within 180 days after startup of the source, whichever is later, 
according to Sec.  63.7(a)(2)(ix).
    (e) For new or reconstructed oil-fired boilers that combust only 
oil that contains no more than 0.50 weight percent sulfur or a mixture 
of 0.50 weight percent sulfur oil with other fuels not subject to a PM 
emission limit under this subpart and that do not use a post-combustion 
technology (except a wet scrubber) to reduce particulate matter (PM) or 
sulfur dioxide emissions, you are not subject to the PM emission limit 
in Table 1 of this subpart providing you monitor and record on a 
monthly basis the type of fuel combusted. If you intend to burn a new 
type of fuel or fuel mixture that does not meet the requirements of 
this paragraph, you must conduct a performance test within 60 days of 
burning the new fuel.
    (f) For new or reconstructed affected boilers that have applicable 
work practice standards or management practices, you are not required 
to complete an initial performance tune-up, but you are required to 
complete the applicable biennial or 5-year tune-up as specified in 
Sec.  63.11223 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 ceased burning solid waste consistent 
with Sec.  63.11196(d) and for which your initial compliance date has 
passed, you must demonstrate compliance within 60 days of the effective 
date of the waste-to-fuel switch as specified in Sec.  60.2145(a)(2) 
and (3) of subpart CCCC or Sec.  60.2710(a)(2) and (3) of subpart DDDD. 
If you have not conducted your compliance demonstration for this 
subpart within the previous 12 months, you must complete all compliance 
demonstrations for this subpart before you commence or recommence 
combustion of solid waste.
    (h) For affected boilers that switch fuels or make a physical 
change to the boiler that results in the applicability of a different 
subcategory within subpart JJJJJJ or the boiler becoming subject to 
subpart JJJJJJ, you must demonstrate compliance within 180 days of the 
effective date of the fuel switch or the physical change. Notification 
of such changes must be submitted according to Sec.  63.11225(g).
    (i) For boilers located at existing major sources of HAP that limit 
their potential to emit (e.g., make a physical change or take a permit 
limit) such that the existing major source becomes an area source, you 
must comply with the applicable provisions as specified in paragraphs 
(i)(1) through (3) of this section.
    (1) Any such existing boiler at the existing source must 
demonstrate compliance with subpart JJJJJJ within 180 days of the later 
of March 21, 2014 or upon the existing major source commencing 
operation as an area source.
    (2) Any new or reconstructed boiler at the existing source must 
demonstrate compliance with subpart JJJJJJ within 180 days of the later 
of March 21, 2011 or startup.
    (3) Notification of such changes must be submitted according to 
Sec.  63.11225(g).
    (j) For existing affected boilers that have not operated between 
the effective date of the rule and the compliance date that is 
specified for your source in Sec.  63.11196, you must comply with the 
applicable provisions as specified in paragraphs (j)(1) through (3) of 
this section.
    (1) You must complete the initial compliance demonstration, if 
subject to the emission limits in Table 1 to this subpart, as specified 
in paragraphs (a) and (b) of this section, no later than 180 days after 
the re-start of the affected boiler and according to the applicable 
provisions in Sec.  63.7(a)(2).
    (2) You must complete the initial performance tune-up, if subject 
to the tune-up requirements in Sec.  63.11223, by following the 
procedures described in Sec.  63.11223(b) no later than 30 days after 
the re-start of the affected boiler.
    (3) You must complete the one-time energy assessment, if subject to 
the energy assessment requirements specified in Table 2 to this 
subpart, no

[[Page 7508]]

later than the compliance date specified in Sec.  63.11196.

0
10. Section 63.11211 is amended by revising paragraphs (a), (b)(1), and 
(b)(2) to read as follows:


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

    (a) For affected boilers that demonstrate compliance with any of 
the emission limits of this subpart through performance (stack) 
testing, your initial compliance requirements include conducting 
performance tests according to Sec.  63.11212 and Table 4 to this 
subpart, conducting a fuel analysis for each type of fuel burned in 
your boiler according to Sec.  63.11213 and Table 5 to this subpart, 
establishing operating limits according to Sec.  63.11222, Table 6 to 
this subpart and paragraph (b) of this section, as applicable, and 
conducting CMS performance evaluations according to Sec.  63.11224. For 
affected boilers that burn a single type of fuel, you are exempted from 
the compliance requirements of conducting a fuel analysis for each type 
of fuel burned in your boiler. For purposes of this subpart, boilers 
that use a supplemental fuel only for startup, unit shutdown, and 
transient flame stability purposes still qualify as affected boilers 
that burn a single type of fuel, and the supplemental fuel is not 
subject to the fuel analysis requirements under Sec.  63.11213 and 
Table 5 to this subpart.
    (b) * * *
    (1) For a wet scrubber, you must establish the minimum scrubber 
liquid flow rate and minimum scrubber pressure drop as defined in Sec.  
63.11237, as your operating limits during the three-run performance 
stack test. If you use a wet scrubber and you conduct separate 
performance stack tests for PM and mercury emissions, you must 
establish one set of minimum scrubber liquid flow rate and pressure 
drop operating limits. If you conduct multiple performance stack tests, 
you must set the minimum scrubber liquid flow rate and pressure drop 
operating limits at the highest minimum values established during the 
performance stack tests.
    (2) For an electrostatic precipitator operated with a wet scrubber, 
you must establish the minimum total secondary electric power 
(secondary voltage and secondary current), as defined in Sec.  
63.11237, as your operating limits during the three-run performance 
stack test.
* * * * *

0
11. Section 63.11212 is amended by revising paragraphs (b) and (e) to 
read as follows:


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

* * * * *
    (b) You must conduct each stack test according to the requirements 
in Table 4 to this subpart. Boilers that use a CEMS for carbon monoxide 
(CO) are exempt from the initial CO performance testing in Table 4 to 
this subpart and the oxygen concentration operating limit requirement 
specified in Table 3 to this subpart.
* * * * *
    (e) To determine compliance with the emission limits, you must use 
the F-Factor methodology and equations in sections 12.2 and 12.3 of EPA 
Method 19 of appendix A-7 to part 60 of this chapter to convert the 
measured PM concentrations and the measured mercury concentrations that 
result from the performance test to pounds per million Btu heat input 
emission rates.

0
12. Section 63.11214 is amended by revising paragraph (c) to read as 
follows:


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

* * * * *
    (c) If you own or operate an existing affected boiler with a heat 
input capacity of 10 million Btu per hour or greater, you must submit a 
signed certification in the Notification of Compliance Status report 
that an energy assessment of the boiler and its energy use systems was 
completed according to Table 2 to this subpart and is an accurate 
depiction of your facility.
* * * * *

0
13. Section 63.11220 is revised to read as follows:


Sec.  63.11220  When must I conduct subsequent performance tests or 
fuel analyses?

    (a) If your boiler has a heat input capacity of 10 million British 
thermal units per hour or greater, you must conduct all applicable 
performance (stack) tests according to Sec.  63.11212 on a triennial 
basis, except as specified in paragraphs (b) through (d) of this 
section. Triennial performance tests must be completed no more than 37 
months after the previous performance test.
    (b) When demonstrating initial compliance with the PM emission 
limit, if your boiler's performance test results show that your PM 
emissions are equal to or less than half of the PM emission limit, you 
do not need to conduct further performance tests for PM but must 
continue to comply with all applicable operating limits and monitoring 
requirements. If your initial performance test results show that your 
PM emissions are greater than half of the PM emission limit, you must 
conduct subsequent performance tests as specified in paragraph (a) of 
this section.
    (c) If you demonstrate compliance with the mercury emission limit 
based on fuel analysis, you must conduct a fuel analysis according to 
Sec.  63.11213 for each type of fuel burned as specified in paragraphs 
(c)(1) and (2) of this section. If you plan to burn a new type of fuel 
or fuel mixture, you must conduct a fuel analysis before burning the 
new type of fuel or mixture in your boiler. You must recalculate the 
mercury emission rate using Equation 1 of Sec.  63.11211. The 
recalculated mercury emission rate must be less than the applicable 
emission limit.
    (1) When demonstrating initial compliance with the mercury emission 
limit, if the mercury constituents in the fuel or fuel mixture are 
measured to be equal to or less than half of the mercury emission 
limit, you do not need to conduct further fuel analysis sampling but 
must continue to comply with all applicable operating limits and 
monitoring requirements.
    (2) When demonstrating initial compliance with the mercury emission 
limit, if the mercury constituents in the fuel or fuel mixture are 
greater than half of the mercury emission limit, you must conduct 
quarterly sampling.
    (d) For existing affected boilers that have not operated since the 
previous compliance demonstration and more than 3 years have passed 
since the previous compliance demonstration, you must complete your 
subsequent compliance demonstration no later than 180 days after the 
re-start of the affected boiler.

0
14. Section 63.11221 is revised to read as follows:


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

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

[[Page 7509]]

adjustments, and scheduled CMS maintenance as defined in your site-
specific monitoring plan. 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 complete monitoring system 
repairs in response to monitoring system malfunctions or out-of-control 
periods and to return the monitoring system to operation as 
expeditiously as practicable.
    (c) You may not use data collected during monitoring system 
malfunctions or out-of-control periods, repairs associated with 
monitoring system malfunctions or out-of-control periods, or required 
monitoring system quality assurance or quality control activities in 
calculations used to report emissions or operating levels. Any such 
periods must be reported according to the requirements in Sec.  
63.11225. You must use all the data collected during all other periods 
in assessing the operation of the control device and associated control 
system.
    (d) Except for periods of monitoring system malfunctions or 
monitoring system out-of-control periods, repairs associated with 
monitoring system malfunctions or monitoring system out-of-control 
periods, and required monitoring system quality assurance or quality 
control activities (including, as applicable, calibration checks, 
required zero and span adjustments, and scheduled CMS maintenance as 
defined in your site-specific monitoring plan), failure to collect 
required data is a deviation of the monitoring requirements.

0
15. Section 63.11223 is amended by revising paragraphs (a), (b) 
introductory text, (b)(1), (b)(3) through (5), (b)(6) introductory 
text, (b)(6)(i), (b)(6)(iii), (b)(7), and (c), and adding paragraphs 
(d) through (g) to read as follows:


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

    (a) For affected sources subject to the work practice standard or 
the management practices of a tune-up, you must conduct a performance 
tune-up according to paragraph (b) of this section and keep records as 
required in Sec.  63.11225(c) to demonstrate continuous compliance. You 
must conduct the tune-up while burning the type of fuel (or fuels in 
the case of boilers that routinely burn two types of fuels at the same 
time) that provided the majority of the heat input to the boiler over 
the 12 months prior to the tune-up.
    (b) Except as specified in paragraphs (c) through (f) 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.
    (1) As applicable, inspect the burner, and clean or replace any 
components of the burner as necessary (you may delay the burner 
inspection until the next scheduled unit shutdown, not to exceed 36 
months from the previous inspection). Units that produce electricity 
for sale may delay the burner inspection until the first outage, not to 
exceed 36 months from the previous inspection.
* * * * *
    (3) Inspect the system controlling the air-to-fuel ratio, as 
applicable, and ensure that it is correctly calibrated and functioning 
properly (you may delay the inspection until the next scheduled unit 
shutdown, not to exceed 36 months from the previous inspection). Units 
that produce electricity for sale may delay the inspection until the 
first outage, not to exceed 36 months from the previous inspection.
    (4) Optimize total emissions of CO. This optimization should be 
consistent with the manufacturer's specifications, if available, and 
with any nitrogen oxide requirement to which the unit is subject.
    (5) Measure the concentrations in the effluent stream of CO in 
parts per million, by volume, and oxygen in volume percent, before and 
after the adjustments are made (measurements may be either on a dry or 
wet basis, as long as it is the same basis before and after the 
adjustments are made). Measurements may be taken using a portable CO 
analyzer.
    (6) Maintain on-site and submit, if requested by the Administrator, 
a report containing the information in paragraphs (b)(6)(i) through 
(iii) of this section.
    (i) The concentrations of CO in the effluent stream in parts per 
million, by volume, and oxygen in volume percent, measured at high fire 
or typical operating load, before and after the tune-up of the boiler.
* * * * *
    (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.
    (7) If the unit is not operating on the required date for a tune-
up, the tune-up must be conducted within 30 days of startup.
    (c) Boilers with an oxygen trim system that maintains an optimum 
air-to-fuel ratio that would otherwise be subject to a biennial tune-up 
must conduct a tune-up of the boiler every 5 years as specified in 
paragraphs (b)(1) through (7) of this section. Each 5-year tune-up must 
be conducted no more than 61 months after the previous tune-up. For a 
new or reconstructed boiler with an oxygen trim system, the first 5-
year tune-up must be no later than 61 months after the initial startup. 
You may delay the burner inspection specified in paragraph (b)(1) of 
this section and inspection of the system controlling the air-to-fuel 
ratio specified in paragraph (b)(3) of this section until the next 
scheduled unit shutdown, but you must inspect each burner and system 
controlling the air-to-fuel ratio at least once every 72 months.
    (d) Seasonal boilers must conduct a tune-up every 5 years as 
specified in paragraphs (b)(1) through (7) of this section. Each 5-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 5-year 
tune-up must be no later than 61 months after the initial startup. You 
may delay the burner inspection specified in paragraph (b)(1) of this 
section and inspection of the system controlling the air-to-fuel ratio 
specified in paragraph (b)(3) of this section until the next scheduled 
unit shutdown, but you must inspect each burner and system controlling 
the air-to-fuel ratio at least once every 72 months. Seasonal boilers 
are not subject to the emission limits in Table 1 to this subpart or 
the operating limits in Table 3 to this subpart.
    (e) Oil-fired boilers with a heat input capacity of equal to or 
less than 5 million Btu per hour must conduct a tune-up every 5 years 
as specified in paragraphs (b)(1) through (7) of this section. Each 5-
year tune-up must be conducted no more than 61 months after the 
previous tune-up. For a new or reconstructed oil-fired boiler with a 
heat input capacity of equal to or less than 5 million Btu per hour, 
the first 5-year tune-up must be no later than 61 months after the 
initial startup. You may delay the burner inspection specified in 
paragraph (b)(1) of this section and inspection of the system 
controlling the air-to-fuel ratio specified

[[Page 7510]]

in paragraph (b)(3) of this section until the next scheduled unit 
shutdown, but you must inspect each burner and system controlling the 
air-to-fuel ratio at least once every 72 months.
    (f) Limited-use boilers must conduct a tune-up every 5 years as 
specified in paragraphs (b)(1) through (7) of this section. Each 5-year 
tune-up must be conducted no more than 61 months after the previous 
tune-up. For a new or reconstructed limited-use boiler, the first 5-
year tune-up must be no later than 61 months after the initial startup. 
You may delay the burner inspection specified in paragraph (b)(1) of 
this section and inspection of the system controlling the air-to-fuel 
ratio specified in paragraph (b)(3) of this section until the next 
scheduled unit shutdown, but you must inspect each burner and system 
controlling the air-to-fuel ratio at least once every 72 months. 
Limited-use boilers are not subject to the emission limits in Table 1 
to this subpart, the energy assessment requirements in Table 2 to this 
subpart, or the operating limits in Table 3 to this subpart.
    (g) If you own or operate a boiler subject to emission limits in 
Table 1 of this subpart, you must minimize the boiler's startup and 
shutdown periods following the manufacturer's recommended procedures, 
if available. 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. 
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 or procedures 
specified for a boiler of similar design if manufacturer's recommended 
procedures are not available.

0
16. Section 63.11224 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(1) through (3), 
(a)(5), (a)(6),
0
b. Adding paragraph (a)(7).
0
c. Revising paragraphs (c)(1) introductory text, (c)(2) introductory 
text, and (d).
0
d. Revising paragraphs (e) introductory text, (e)(6), and (e)(7).
0
e. Adding paragraph (e)(8).
0
f. Revising paragraph (f)(7).
    The revisions and additions read as follows:


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

    (a) If your boiler is subject to a CO 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, calibrate, operate, and maintain an 
oxygen analyzer system, as defined in Sec.  63.11237, according to the 
manufacturer's recommendations and paragraphs (a)(7) and (d) of this 
section, as applicable, by the compliance date specified in Sec.  
63.11196. Where a certified CO CEMS is used, the CO level shall be 
monitored at the outlet of the boiler, after any add-on controls or 
flue gas recirculation system and before release to the atmosphere. 
Boilers that use a CO CEMS are exempt from the initial CO performance 
testing and oxygen concentration operating limit requirements specified 
in Sec.  63.11211(a) of this subpart. Oxygen monitors and oxygen trim 
systems must be installed to monitor oxygen in the boiler flue gas, 
boiler firebox, or other appropriate intermediate location.
    (1) Each CO CEMS must be installed, operated, and maintained 
according to the applicable procedures under Performance Specification 
4, 4A, or 4B at 40 CFR part 60, appendix B, and each oxygen CEMS must 
be installed, operated, and maintained according to Performance 
Specification 3 at 40 CFR part 60, appendix B. Both the CO and oxygen 
CEMS must also be installed, operated, and maintained according to the 
site-specific monitoring plan developed according to paragraph (c) of 
this section.
    (2) You must conduct a performance evaluation of each CEMS 
according to the requirements in Sec.  63.8(e) and according to 
Performance Specifications 3 and 4, 4A, or 4B at 40 CFR part 60, 
appendix B.
    (3) Each CEMS must complete a minimum of one cycle of operation 
(sampling, analyzing, and data recording) every 15 minutes. You must 
have CEMS data values from a minimum of four successive cycles of 
operation representing each of the four 15-minute periods in an hour, 
or at least two 15-minute data values during an hour when CEMS 
calibration, quality assurance, or maintenance activities are being 
performed, to have a valid hour of data.
* * * * *
    (5) You must calculate hourly averages, corrected to 3 percent 
oxygen, from each hour of CO CEMS data in parts per million CO 
concentrations and determine the 10-day rolling average of all recorded 
readings, except as provided in Sec.  63.11221(c). Calculate a 10-day 
rolling average from all of the hourly averages collected for the 10-
day operating period using Equation 2 of this section.
[GRAPHIC] [TIFF OMITTED] TR01FE13.000

Where:

Hpvi = the hourly parameter value for hour i
n = the number of valid hourly parameter values collected over 10 
boiler operating days

    (6) For purposes of collecting CO data, you must operate the CO 
CEMS as specified in Sec.  63.11221(b). For purposes of calculating 
data averages, you must use all the data collected during all periods 
in assessing compliance, except that you must exclude certain data as 
specified in Sec.  63.11221(c). Periods when CO data are unavailable 
may constitute monitoring deviations as specified in Sec.  63.11221(d).
    (7) You must operate the oxygen analyzer system at or above the 
minimum oxygen level that is established as the operating limit 
according to Table 6 to this subpart when firing the fuel or fuel 
mixture utilized during the most recent CO performance stack test. 
Operation of oxygen trim systems to meet these requirements shall not 
be done in a manner which compromises furnace safety.
* * * * *
    (c) * * *
    (1) For each 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.
* * * * *

[[Page 7511]]

    (2) In your site-specific monitoring plan, you must also address 
paragraphs (c)(2)(i) through (iii) of this section.
* * * * *
    (d) If you have an operating limit that requires the use of a CMS, 
you must install, operate, and maintain each CPMS according to the 
procedures in paragraphs (d)(1) through (4) of this section.
    (1) The CPMS must complete a minimum of one cycle of operation 
every 15 minutes. You must have data values from a minimum of four 
successive cycles of operation representing each of the four 15-minute 
periods in an hour, or at least two 15-minute data values during an 
hour when CMS calibration, quality assurance, or maintenance activities 
are being performed, to have a valid hour of data.
    (2) You must calculate hourly arithmetic averages from each hour of 
CPMS data in units of the operating limit and determine the 30-day 
rolling average of all recorded readings, except as provided in Sec.  
63.11221(c). Calculate a 30-day rolling average from all of the hourly 
averages collected for the 30-day operating period using Equation 3 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR01FE13.001

Where:

Hpvi = the hourly parameter value for hour i
n = the number of valid hourly parameter values collected over 30 
boiler operating days

    (3) For purposes of collecting data, you must operate the CPMS as 
specified in Sec.  63.11221(b). For purposes of calculating data 
averages, you must use all the data collected during all periods in 
assessing compliance, except that you must exclude certain data as 
specified in Sec.  63.11221(c). Periods when CPMS data are unavailable 
may constitute monitoring deviations as specified in Sec.  63.11221(d).
    (4) Record the results of each inspection, calibration, and 
validation check.
    (e) If you have an applicable opacity operating limit under this 
rule, you must install, operate, certify and maintain each COMS 
according to the procedures in paragraphs (e)(1) through (8) of this 
section by the compliance date specified in Sec.  63.11196.
* * * * *
    (6) You must operate and maintain each COMS according to the 
requirements in the monitoring plan and the requirements of Sec.  
63.8(e). You must identify periods the COMS is out of control including 
any periods that the COMS fails to pass a daily calibration drift 
assessment, a quarterly performance audit, or an annual zero alignment 
audit.
    (7) You must calculate and record 6-minute averages from the 
opacity monitoring data and determine and record the daily block 
average of recorded readings, except as provided in Sec.  63.11221(c).
    (8) For purposes of collecting opacity data, you must operate the 
COMS as specified in Sec.  63.11221(b). For purposes of calculating 
data averages, you must use all the data collected during all periods 
in assessing compliance, except that you must exclude certain data as 
specified in Sec.  63.11221(c). Periods when COMS data are unavailable 
may constitute monitoring deviations as specified in Sec.  63.11221(d).
    (f) * * *
    (7) For positive pressure fabric filter systems that do not duct 
all compartments or cells to a common stack, a bag leak detection 
system must be installed in each baghouse compartment or cell.
* * * * *

0
17. Section 63.11225 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(1), (a)(2), (a)(4), 
(a)(5), (b) introductory text, (b)(2), (c) introductory text, (c)(2) 
introductory text, and (c)(2)(ii).

0
b. Adding paragraphs (c)(2)(iii) through (vi).
0
c. Revising paragraphs (d), (e), and (g).
    The revisions and additions read as follows:


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

    (a) You must submit the notifications specified in paragraphs 
(a)(1) through (5) of this section to the administrator.
    (1) You must submit all of the notifications in Sec. Sec.  63.7(b); 
63.8(e) and (f); and 63.9(b) through (e), (g), and (h) that apply to 
you by the dates specified in those sections except as specified in 
paragraphs (a)(2) and (4) of this section.
    (2) An Initial Notification must be submitted no later than January 
20, 2014 or within 120 days after the source becomes subject to the 
standard.
* * * * *
    (4) You must submit the Notification of Compliance Status no later 
than 120 days after the applicable compliance date specified in Sec.  
63.11196 unless you must conduct a performance stack test. If you must 
conduct a performance stack test, you must submit the Notification of 
Compliance Status within 60 days of completing the performance stack 
test. You must submit the Notification of Compliance Status in 
accordance with paragraphs (a)(4)(i) and (vi) of this section. The 
Notification of Compliance Status must include the information and 
certification(s) of compliance in paragraphs (a)(4)(i) through (v) of 
this section, as applicable, and signed by a responsible official.
    (i) You must submit the information required in Sec.  63.9(h)(2), 
except the information listed in Sec.  63.9(h)(2)(i)(B), (D), (E), and 
(F). If you conduct any performance tests or CMS performance 
evaluations, you must submit that data as specified in paragraph (e) of 
this section. If you conduct any opacity or visible emission 
observations, or other monitoring procedures or methods, you must 
submit that data to the Administrator at the appropriate address listed 
in Sec.  63.13.
    (ii) ``This facility complies with the requirements in Sec.  
63.11214 to conduct an initial tune-up of the boiler.''
    (iii) ``This facility has had an energy assessment performed 
according to Sec.  63.11214(c).''
    (iv) For units that install bag leak detection systems: ``This 
facility complies with the requirements in Sec.  63.11224(f).''
    (v) 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.''
    (vi) The notification must be submitted electronically using the 
Compliance and Emissions Data Reporting Interface (CEDRI) that is 
accessed through EPA's Central Data Exchange (CDX) (www.epa.gov/cdx). 
However, if the reporting form specific to this subpart is not 
available in CEDRI at the time that the report is due, the written 
Notification of Compliance Status must be submitted to the

[[Page 7512]]

Administrator at the appropriate address listed in Sec.  63.13.
    (5) If you are using data from a previously conducted emission test 
to serve as documentation of conformance with the emission standards 
and operating limits of this subpart, you must include in the 
Notification of Compliance Status the date of the test and a summary of 
the results, not a complete test report, relative to this subpart.
    (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 5-year tune-up according to 
Sec.  63.11223(a) and not subject to emission limits or operating 
limits, you may prepare only a biennial or 5-year compliance report as 
specified in paragraphs (b)(1) and (2) of this section.
* * * * *
    (2) Statement by a responsible official, with the official's name, 
title, phone number, email address, and signature, certifying the 
truth, accuracy and completeness of the notification and a statement of 
whether the source has complied with all the relevant standards and 
other requirements of this subpart. Your notification must include the 
following certification(s) of compliance, as applicable, and signed by 
a responsible official:
    (i) ``This facility complies with the requirements in Sec.  
63.11223 to conduct a biennial or 5-year tune-up, as applicable, of 
each boiler.''
    (ii) For units that do not qualify for a statutory exemption as 
provided in section 129(g)(1) of the Clean Air Act: ``No secondary 
materials that are solid waste were combusted in any affected unit.''
    (iii) ``This facility complies with the requirement in Sec. Sec.  
63.11214(d) and 63.11223(g) to minimize the boiler's time spent during 
startup and shutdown and to conduct startups and shutdowns according to 
the manufacturer's recommended procedures or procedures specified for a 
boiler of similar design if manufacturer's recommended procedures are 
not available.''
* * * * *
    (c) You must maintain the records specified in paragraphs (c)(1) 
through (7) of this section.
* * * * *
    (2) You must keep records to document conformance with the work 
practices, emission reduction measures, and management practices 
required by Sec.  63.11214 and Sec.  63.11223 as specified in 
paragraphs (c)(2)(i) through (vi) of this section.
* * * * *
    (ii) For operating units that combust non-hazardous secondary 
materials that have been determined not to be solid waste pursuant to 
Sec.  241.3(b)(1) of this chapter, you must keep a record which 
documents how the secondary material meets each of the legitimacy 
criteria under Sec.  241.3(d)(1). If you combust a fuel that has been 
processed from a discarded non-hazardous secondary material pursuant to 
Sec.  241.3(b)(4) of this chapter, you must keep records as to how the 
operations that produced the fuel satisfies the definition of 
processing in Sec.  241.2 and each of the legitimacy criteria in Sec.  
241.3(d)(1) of this chapter. If the fuel received a non-waste 
determination pursuant to the petition process submitted under Sec.  
241.3(c) of this chapter, you must keep a record that documents how the 
fuel satisfies the requirements of the petition process. For operating 
units that combust non-hazardous secondary materials as fuel per Sec.  
241.4, you must keep records documenting that the material is a listed 
non-waste under Sec.  241.4(a).
    (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) For each boiler that meets the definition of seasonal boiler, 
you must keep records of days of operation per year.
    (vi) For each boiler that meets the definition of limited-use 
boiler, you must keep a copy of the federally enforceable permit that 
limits the annual capacity factor to less than or equal to 10 percent 
and records of fuel use for the days the boiler is operating.
* * * * *
    (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 on-site 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.
    (e)(1) Within 60 days after the date of completing each performance 
test (defined in Sec.  63.2) as required by this subpart you must 
submit the results of the performance tests, including any associated 
fuel analyses, required by this subpart to EPA's WebFIRE database by 
using CEDRI that is accessed through EPA's CDX (www.epa.gov/cdx). 
Performance test data must be submitted in the file format generated 
through use of EPA's Electronic Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html). Only data collected using test 
methods on the ERT Web site are subject to this requirement for 
submitting reports electronically to WebFIRE. Owners or operators who 
claim that some of the information being submitted for performance 
tests is confidential business information (CBI) must submit a complete 
ERT file including information claimed to be CBI on a compact disk or 
other commonly used electronic storage media (including, but not 
limited to, flash drives) to EPA. The electronic media must be clearly 
marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: 
WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. 
The same ERT file with the CBI omitted must be submitted to EPA via CDX 
as described earlier in this paragraph. At the discretion of the 
delegated authority, you must also submit these reports, including CBI, 
to the delegated authority in the format specified by the delegated 
authority. For any performance test conducted using test methods that 
are not listed on the ERT Web site, the owner or operator shall submit 
the results of the performance test in paper submissions to the 
Administrator at the appropriate address listed in Sec.  63.13.
    (2) Within 60 days after the date of completing each CEMS 
performance evaluation test as defined in Sec.  63.2, you must submit 
relative accuracy test audit (RATA) data to EPA's CDX by using CEDRI in 
accordance with paragraph (e)(1) of this section. Only RATA pollutants 
that can be documented with the ERT (as listed on the ERT Web site) are 
subject to this requirement. For any performance evaluations with no 
corresponding RATA pollutants listed on the ERT Web site, the owner or 
operator shall submit the results of the performance evaluation in 
paper submissions to the Administrator at the appropriate address 
listed in Sec.  63.13.
* * * * *
    (g) If you have switched fuels or made a physical change to the 
boiler and the fuel switch or change resulted in the

[[Page 7513]]

applicability of a different subcategory within subpart JJJJJJ, in the 
boiler becoming subject to subpart JJJJJJ, or in the boiler switching 
out of subpart JJJJJJ due to a change to 100 percent natural gas, or 
you have taken a permit limit that resulted in you being subject to 
subpart JJJJJJ, you must provide notice of the date upon which you 
switched fuels, made the physical change, or took a permit limit within 
30 days of the change. 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 have switched fuels, were 
physically changed, or took a permit limit, and the date of the notice.
    (2) The date upon which the fuel switch, physical change, or permit 
limit occurred.
    18. Section 63.11226 is revised to read as follows:


Sec.  63.11226  Affirmative defense for violation of emission standards 
during malfunction.

    In response to an action to enforce the standards set forth in 
Sec.  63.11201 you may assert an affirmative defense to a claim for 
civil penalties for violations of such standards that are caused by 
malfunction, as defined at 40 CFR 63.2. Appropriate penalties may be 
assessed if you fail to meet your burden of proving all of the 
requirements in the affirmative defense. The affirmative defense shall 
not be available for claims for injunctive relief.
    (a) Assertion of affirmative defense. To establish the affirmative 
defense in any action to enforce such a standard, you must timely meet 
the reporting requirements in paragraph (b) of this section, and must 
prove by a preponderance of evidence that:
    (1) The violation:
    (i) Was caused by a sudden, infrequent, and unavoidable failure of 
air pollution control equipment, process equipment, or a process to 
operate in a normal or usual manner; and
    (ii) Could not have been prevented through careful planning, proper 
design or better operation and maintenance practices; and
    (iii) Did not stem from any activity or event that could have been 
foreseen and avoided, or planned for; and
    (iv) Was not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance; and
    (2) Repairs were made as expeditiously as possible when a violation 
occurred; and
    (3) The frequency, amount, and duration of the violation (including 
any bypass) were minimized to the maximum extent practicable; and
    (4) If the violation resulted from a bypass of control equipment or 
a process, then the bypass was unavoidable to prevent loss of life, 
personal injury, or severe property damage; and
    (5) All possible steps were taken to minimize the impact of the 
violation on ambient air quality, the environment, and human health; 
and
    (6) All emissions monitoring and control systems were kept in 
operation if at all possible, consistent with safety and good air 
pollution control practices; and
    (7) All of the actions in response to the violation were documented 
by properly signed, contemporaneous operating logs; and
    (8) At all times, the affected source was operated in a manner 
consistent with good practices for minimizing emissions; and
    (9) A written root cause analysis has been prepared, the purpose of 
which is to determine, correct, and eliminate the primary causes of the 
malfunction and the violation resulting from the malfunction event at 
issue. The analysis shall also specify, using best monitoring methods 
and engineering judgment, the amount of any emissions that were the 
result of the malfunction.
    (b) Report. The owner or operator seeking to assert an affirmative 
defense shall submit a written report to the Administrator with all 
necessary supporting documentation, that it has met the requirements 
set forth in paragraph (a) of this section. This affirmative defense 
report shall be included in the first periodic compliance, deviation 
report or excess emission report otherwise required after the initial 
occurrence of the violation of the relevant standard (which may be the 
end of any applicable averaging period). If such compliance, deviation 
report or excess emission report is due less than 45 days after the 
initial occurrence of the violation, the affirmative defense report may 
be included in the second compliance, deviation report or excess 
emission report due after the initial occurrence of the violation of 
the relevant standard.

0
19. Section 63.11236 is amended by revising paragraph (a) to read as 
follows:


Sec.  63.11236  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by EPA or an 
administrator such as your state, local, or tribal agency. If the EPA 
Administrator has delegated authority to your state, local, or tribal 
agency, then that agency has the authority to implement and enforce 
this subpart. You should contact your EPA Regional Office to find out 
if implementation and enforcement of this subpart is delegated to your 
state, local, or tribal agency.
* * * * *

0
20. Section 63.11237 is amended as follows:
0
a. By adding definitions in alphabetical order for ``10-day rolling 
average,'' ``30-day rolling average,'' ``Annual heat input,'' 
``Biodiesel,'' ``Calendar year,'' ``Common stack,'' ``Daily block 
average,'' ``Distillate oil,'' ``Electric boiler,'' ``Electric utility 
steam generating unit (EGU),'' ``Energy management program,'' 
``Fluidized bed boiler,'' ``Fluidized bed combustion,'' ``Hourly 
average,'' ``Limited-use boiler,'' ``Load fraction,'' ``Minimum 
scrubber pressure drop,'' ``Minimum sorbent injection rate,'' ``Minimum 
total secondary electric power,'' ``Operating day,'' ``Oxygen analyzer 
system,'' ``Oxygen trim system,'' ``Process heater,'' ``Regulated gas 
stream,'' ``Residential boiler,'' ``Residual oil,'' ``Seasonal 
boiler,'' ``Shutdown,'' ``Solid fuel,'' ``Startup,'' ``Temporary 
boiler,'' ``Tune-up,'' ``Vegetable oil,'' ``Voluntary Consensus 
Standards (VCS),'' and ``Wet scrubber.''
0
b. By revising the definitions for ``Bag leak detection system,'' 
``Biomass subcategory,'' ``Boiler,'' ``Boiler system,'' ``Deviation,'' 
``Dry scrubber,'' ``Electrostatic precipitator (ESP),'' ``Energy 
assessment,'' ``Energy use system,'' ``Federally enforceable,'' ``Gas-
fired boiler,'' ``Heat input,'' ``Hot water heater,'' ``Institutional 
boiler,'' ``Liquid fuel,'' ``Minimum activated carbon injection rate,'' 
``Minimum oxygen level,'' ``Minimum scrubber liquid flow rate,'' 
``Natural gas,'' ``Oil subcategory,'' ``Particulate matter,'' ``Period 
of gas curtailment or supply interruption,'' ``Qualified Energy 
Assessor,'' ``Solid fossil fuel,'' and ``Waste heat boiler.''
0
c. By removing the definitions for ``Annual heat input basis,'' 
``Minimum PM scrubber pressure drop,'' ``Minimum sorbent flow rate,'' 
and ``Minimum voltage or amperage''.


Sec.  63.11237  What definitions apply to this subpart?

    10-day rolling average means the arithmetic mean of all valid hours 
of data from 10 successive operating days, except for periods of 
startup and shutdown and periods when the unit is not operating.
    30-day rolling average means the arithmetic mean of all valid hours 
of data from 30 successive operating days, except for periods of 
startup and shutdown and periods when the unit is not operating.
* * * * *

[[Page 7514]]

    Annual heat input means the heat input for the 12 months preceding 
the compliance demonstration.
    Bag leak detection system means a group of instruments that are 
capable of monitoring particulate matter loadings in the exhaust of a 
fabric filter (i.e., baghouse) in order to detect bag failures. A bag 
leak detection system includes, but is not limited to, an instrument 
that operates on electrodynamic, triboelectric, light scattering, light 
transmittance, or other principle to monitor relative particulate 
matter loadings.
    Biodiesel means a mono-alkyl ester derived from biomass and 
conforming to ASTM D6751-11b, Standard Specification for Biodiesel Fuel 
Blend Stock (B100) for Middle Distillate Fuels (incorporated by 
reference, see Sec.  63.14).
* * * * *
    Biomass subcategory includes any boiler that burns any biomass and 
is not in the coal subcategory.
    Boiler means an enclosed device using controlled flame combustion 
in which water is heated to recover thermal energy in the form of steam 
and/or hot water. Controlled flame combustion refers to a steady-state, 
or near steady-state, process wherein fuel and/or oxidizer feed rates 
are controlled. A device combusting solid waste, as defined in Sec.  
241.3 of this chapter, 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, process 
heaters, and autoclaves are excluded from the definition of Boiler.
    Boiler system means the boiler and associated components, such as, 
feedwater systems, combustion air systems, fuel systems (including 
burners), blowdown systems, combustion control systems, steam systems, 
and condensate return systems, directly connected to and serving the 
energy use systems.
    Calendar year means the period between January 1 and December 31, 
inclusive, for a given year.
* * * * *
    Common stack means the exhaust of emissions from two or more 
affected units through a single flue. Affected units with a common 
stack may each have separate air pollution control systems located 
before the common stack, or may have a single air pollution control 
system located after the exhausts come together in a single flue.
    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), except for periods of startup and shutdown and periods when 
the unit is not operating.
    Deviation (1) Means any instance in which an affected source 
subject to this subpart, or an owner or operator of such a source:
    (i) Fails to meet any applicable requirement or obligation 
established by this subpart including, but not limited to, any emission 
limit, operating limit, or work practice standard; or
    (ii) Fails to meet any term or condition that is adopted to 
implement an applicable requirement in this subpart and that is 
included in the operating permit for any affected source required to 
obtain such a permit.
    (2) A deviation is not always a violation.
    Distillate oil means fuel oils that contain 0.05 weight percent 
nitrogen or less and comply with the specifications for fuel oil 
numbers 1 and 2, as defined by the American Society of Testing and 
Materials in ASTM D396 (incorporated by reference, see Sec.  63.14) or 
diesel fuel oil numbers 1 and 2, as defined by the American Society for 
Testing and Materials in ASTM D975 (incorporated by reference, see 
Sec.  63.14), kerosene, and biodiesel as defined by the American 
Society of Testing and Materials in ASTM D6751-11b (incorporated by 
reference, see Sec.  63.14).
    Dry scrubber means an add-on air pollution control system that 
injects dry alkaline sorbent (dry injection) or sprays an alkaline 
sorbent (spray dryer) to react with and neutralize acid gas in the 
exhaust stream forming a dry powder material. Sorbent injection systems 
used as control devices in fluidized bed boilers and process heaters 
are included in this definition. A dry scrubber is a dry control 
system.
    Electric boiler means a boiler in which electric heating serves as 
the source of heat. Electric boilers that burn gaseous or liquid fuel 
during periods of electrical power curtailment or failure are included 
in this definition.
    Electric utility steam generating unit (EGU) means a fossil fuel-
fired combustion unit of more than 25 megawatts that serves a generator 
that produces electricity for sale. A fossil fuel-fired unit that 
cogenerates steam and electricity and supplies more than one-third of 
its potential electric output capacity and more than 25 megawatts 
electrical output to any utility power distribution system for sale is 
considered an electric utility steam generating unit. To be ``capable 
of combusting'' fossil fuels, an EGU would need to have these fuels 
allowed in their operating permits and have the appropriate fuel 
handling facilities on-site or otherwise available (e.g., coal handling 
equipment, including coal storage area, belts and conveyers, 
pulverizers, etc.; oil storage facilities). In addition, fossil fuel-
fired EGU means any EGU that fired fossil fuel for more than 10.0 
percent of the average annual heat input in any 3 consecutive calendar 
years or for more than 15.0 percent of the annual heat input during any 
one calendar year after April 16, 2015.
    Electrostatic precipitator (ESP) means an add-on air pollution 
control device used to capture particulate matter by charging the 
particles using an electrostatic field, collecting the particles using 
a grounded collecting surface, and transporting the particles into a 
hopper. An electrostatic precipitator is usually a dry control system.
    Energy assessment means the following for the emission units 
covered by this subpart:
    (1) The energy assessment for facilities with affected boilers with 
less than 0.3 trillion Btu per year (TBtu/year) heat input capacity 
will be 8 on-site 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 50 percent of the affected boiler(s) energy 
(e.g., steam, hot water, or electricity) production, as applicable, 
will be evaluated to identify energy savings opportunities, within the 
limit of performing an 8-hour energy assessment.
    (2) The energy assessment for facilities with affected boilers with 
0.3 to 1.0 TBtu/year heat input capacity will be 24 on-site 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 (e.g., steam, hot water, or electricity) 
production, as applicable, will be evaluated to identify energy savings 
opportunities, within the limit of performing a 24-hour energy 
assessment.
    (3) The energy assessment for facilities with affected boilers with 
greater than 1.0 TBtu/year heat input capacity will be up to 24 on-site 
technical labor hours in length for the first TBtu/year plus 8 on-site 
technical labor hours for every additional 1.0 TBtu/year not to exceed 
160 on-site technical hours, but may be longer at the discretion of the 
owner or operator of the affected source. The boiler

[[Page 7515]]

system(s) and any on-site energy use system(s) accounting for at least 
20 percent of the affected boiler(s) energy (e.g., steam, hot water, or 
electricity) production, as applicable, will be evaluated to identify 
energy savings opportunities.
    (4) The on-site energy use system(s) serving as the basis for the 
percent of affected boiler(s) energy production, as applicable, in 
paragraphs (1), (2), and (3) of this definition may be segmented by 
production area or energy use area as most logical and applicable to 
the specific facility being assessed (e.g., product X manufacturing 
area; product Y drying area; Building Z).
    Energy management program means a program that includes a set of 
practices and procedures designed to manage energy use that are 
demonstrated by the facility's energy policies, a facility energy 
manager and other staffing responsibilities, energy performance 
measurement and tracking methods, an energy saving goal, action plans, 
operating procedures, internal reporting requirements, and periodic 
review intervals used at the facility. Facilities may establish their 
program through energy management systems compatible with ISO 50001.
    Energy use system (1) Includes the following systems located on the 
site of the affected boiler that use energy provided by the boiler:
    (i) Process heating; compressed air systems; machine drive (motors, 
pumps, fans); process cooling; facility heating, ventilation, and air 
conditioning systems; hot water systems; building envelop; and 
lighting; or
    (ii) Other systems that use steam, hot water, process heat, or 
electricity, provided by the affected boiler.
    (2) Energy use systems are only those systems using energy clearly 
produced by affected boilers.
* * * * *
    Federally enforceable means all limitations and conditions that are 
enforceable by the EPA Administrator, including, but not limited to, 
the requirements of 40 CFR parts 60, 61, 63, and 65, requirements 
within any applicable state implementation plan, and any permit 
requirements established under 40 CFR 52.21 or under 40 CFR 51.18 and 
40 CFR 51.24.
    Fluidized bed boiler means a boiler utilizing a fluidized bed 
combustion process that is not a pulverized coal boiler.
    Fluidized bed combustion means a process where a fuel is burned in 
a bed of granulated particles, which are maintained in a mobile 
suspension by the forward flow of air and combustion products.
* * * * *
    Gas-fired boiler includes any boiler that burns gaseous fuels not 
combined with any solid fuels and 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.
    Heat input means heat derived from combustion of fuel in a boiler 
and does not include the heat input from preheated combustion air, 
recirculated flue gases, returned condensate, or exhaust gases from 
other sources such as gas turbines, internal combustion engines, kilns.
    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, liquid, or biomass fuel and hot water is withdrawn for use 
external to the vessel. Hot water boilers (i.e., not generating steam) 
combusting gaseous, liquid, or biomass fuel with a heat input capacity 
of less than 1.6 million Btu per hour are included in this definition. 
The 120 U.S. gallon capacity threshold to be considered a hot water 
heater is independent of the 1.6 million Btu per hour heat input 
capacity threshold for hot water boilers. Hot water heater also means a 
tankless unit that provides on-demand hot water.
    Hourly average means the arithmetic average of at least four CMS 
data values representing the four 15-minute periods in an hour, or at 
least two 15-minute data values during an hour when CMS calibration, 
quality assurance, or maintenance activities are being performed.
* * * * *
    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.
    Limited-use boiler means any boiler that burns any amount of solid 
or liquid fuels and has a federally enforceable average annual capacity 
factor of no more than 10 percent.
    Liquid fuel includes, but is not limited to, distillate oil, 
residual oil, any form of liquid fuel derived from petroleum, used oil 
meeting the specification in 40 CFR 279.11, liquid biofuels, biodiesel, 
and vegetable oil, and comparable fuels as defined under 40 CFR 261.38.
    Load fraction means the actual heat input of a boiler divided by 
heat input during the performance test that established the minimum 
sorbent injection rate or minimum activated carbon injection rate, 
expressed as a fraction (e.g., for 50 percent load the load fraction is 
0.5).
    Minimum activated carbon injection rate means load fraction 
multiplied by the lowest hourly average activated carbon injection rate 
measured according to Table 6 to this subpart during the most recent 
performance stack test demonstrating compliance with the applicable 
emission limit.
    Minimum oxygen level means the lowest hourly average oxygen level 
measured according to Table 6 to this subpart during the most recent 
performance stack test demonstrating compliance with the applicable 
carbon monoxide emission limit.
    Minimum scrubber liquid flow rate means the lowest hourly average 
scrubber liquid flow rate (e.g., to the particulate matter scrubber) 
measured according to Table 6 to this subpart during the most recent 
performance stack test demonstrating compliance with the applicable 
emission limit.
    Minimum scrubber pressure drop means the lowest hourly average 
scrubber pressure drop measured according to Table 6 to this subpart 
during the most recent performance stack test demonstrating compliance 
with the applicable emission limit.
    Minimum sorbent injection rate means:
    (1) The load fraction multiplied by the lowest hourly average 
sorbent injection rate for each sorbent measured according to Table 6 
to this subpart during the most recent performance stack test 
demonstrating compliance with the applicable emission limits; or
    (2) For fluidized bed combustion, the lowest average ratio of 
sorbent to sulfur measured during the most recent performance test.
    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 stack test demonstrating compliance with the 
applicable emission limits.
    Natural gas means:
    (1) A naturally occurring mixture of hydrocarbon and nonhydrocarbon 
gases found in geologic formations beneath

[[Page 7516]]

the earth's surface, of which the principal constituent is methane; or
    (2) Liquefied petroleum gas, as defined by the American Society for 
Testing and Materials in ASTM D1835 (incorporated by reference, see 
Sec.  63.14); or
    (3) A mixture of hydrocarbons that maintains a gaseous state at ISO 
conditions (i.e., a temperature of 288 Kelvin, a relative humidity of 
60 percent, and a pressure of 101.3 kilopascals). Additionally, natural 
gas must either be composed of at least 70 percent methane by volume or 
have a gross calorific value between 35 and 41 megajoules (MJ) per dry 
standard cubic meter (950 and 1,100 Btu per dry standard cubic foot); 
or
    (4) Propane or propane-derived synthetic natural gas. Propane means 
a colorless gas derived from petroleum and natural gas, with the 
molecular structure C3H8.
    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.
* * * * *
    Operating day means a 24-hour period between 12 midnight and the 
following midnight during which any fuel is combusted at any time in 
the boiler unit. It is not necessary for fuel to be combusted for the 
entire 24-hour period.
    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, boiler firebox, or other appropriate intermediate 
location. This definition includes oxygen trim systems.
    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 provides a feedback signal to the combustion 
air controller.
    Particulate matter (PM) means any finely divided solid or liquid 
material, other than uncombined water, as measured by the test methods 
specified under this subpart, or an approved alternative method.
* * * * *
    Period of gas curtailment or supply interruption means a period of 
time during which the supply of gaseous fuel to an affected boiler is 
restricted or 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 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) 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.
    Regulated gas stream means an offgas stream that is routed to a 
boiler for the purpose of achieving compliance with a standard under 
another subpart of this part or part 60, part 61, or part 65 of this 
chapter.
    Residential boiler means a boiler used to provide heat and/or hot 
water and/or as part of a residential combined heat and power system. 
This definition includes boilers located at an institutional facility 
(e.g., university campus, military base, church grounds) or commercial/
industrial facility (e.g., farm) used primarily to provide heat and/or 
hot water for:
    (1) A dwelling containing four or fewer families, or
    (2) A single unit residence dwelling that has since been converted 
or subdivided into condominiums or apartments.
    Residual oil means crude oil, fuel oil that does not comply with 
the specifications under the definition of distillate oil, and all fuel 
oil numbers 4, 5, and 6, as defined by the American Society of Testing 
and Materials in ASTM D396-10 (incorporated by reference, see Sec.  
63.14(b)).
* * * * *
    Seasonal boiler means a boiler that undergoes a shutdown for a 
period of at least 7 consecutive months (or 210 consecutive days) each 
12-month period due to seasonal conditions, except for periodic 
testing. Periodic testing shall not exceed a combined total of 15 days 
during the 7-month shutdown. This definition only applies to boilers 
that would otherwise be included in the biomass subcategory or the oil 
subcategory.
    Shutdown means the cessation of operation of a boiler for any 
purpose. Shutdown begins either when none of the steam or heat from the 
boiler is supplied for heating and/or producing electricity, or for any 
other purpose, or at the point of no fuel being fired in the boiler, 
whichever is earlier. Shutdown ends when there is no steam and no heat 
being supplied and no fuel being fired in the boiler.
    Solid fossil fuel includes, but is not limited to, coal, coke, 
petroleum coke, and tire-derived fuel.

[[Page 7517]]

    Solid fuel means any solid fossil fuel or biomass or bio-based 
solid fuel.
    Startup means either the first-ever firing of fuel in a boiler for 
the purpose of supplying steam or heat for heating and/or producing 
electricity, or for any other purpose, or the firing of fuel in a 
boiler after a shutdown event for any purpose. Startup ends when any of 
the steam or heat from the boiler is supplied for heating and/or 
producing electricity, or for any other purpose.
    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 within the 
facility and performs the same or similar function for more than 12 
consecutive months, unless the regulatory agency approves an extension. 
An extension may be granted by the regulating agency upon petition by 
the owner or operator of a unit specifying the basis for such a 
request. Any temporary boiler that replaces a temporary boiler at a 
location within the facility and performs the same or similar function 
will be included in calculating the consecutive time period unless 
there is a gap in operation of 12 months or more.
    (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 but continues to perform the same or similar function and 
serve the same electricity, steam, and/or hot water system in an 
attempt to circumvent the residence time requirements of this 
definition.
    Tune-up means adjustments made to a boiler in accordance with the 
procedures outlined in Sec.  63.11223(b).
    Vegetable oil means oils extracted from vegetation.
    Voluntary Consensus Standards (VCS) mean technical standards (e.g., 
materials specifications, test methods, sampling procedures, business 
practices) developed or adopted by one or more voluntary consensus 
bodies. EPA/Office of Air Quality Planning and Standards, by precedent, 
has only used VCS that are written in English. Examples of VCS bodies 
are: American Society of Testing and Materials (ASTM 100 Barr Harbor 
Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, 
(800) 262-1373, http://www.astm.org), American Society of Mechanical 
Engineers (ASME ASME, Three Park Avenue, New York, NY 10016-5990, (800) 
843-2763, http://www.asme.org), International Standards Organization 
(ISO 1, ch. de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, 
Switzerland, +41 22 749 01 11, http://www.iso.org/iso/home.htm), 
Standards Australia (AS Level 10, The Exchange Centre, 20 Bridge 
Street, Sydney, GPO Box 476, Sydney NSW 2001, + 61 2 9237 6171 http://www.stadards.org.au), British Standards Institution (BSI, 389 Chiswick 
High Road, London, W4 4AL, United Kingdom, +44 (0)20 8996 9001, http://www.bsigroup.com), Canadian Standards Association (CSA 5060 Spectrum 
Way, Suite 100, Mississauga, Ontario L4W 5N6, Canada, 800-463-6727, 
http://www.csa.ca), European Committee for Standardization (CEN CENELEC 
Management Centre Avenue Marnix 17 B-1000 Brussels, Belgium +32 2 550 
08 11, http://www.cen.eu/cen), and German Engineering Standards (VDI 
VDI Guidelines Department, P.O. Box 10 11 39 40002, Duesseldorf, 
Germany, +49 211 6214-230, http://www.vdi.eu). The types of standards 
that are not considered VCS are standards developed by: the United 
States, e.g., California (CARB) and Texas (TCEQ); industry groups, such 
as American Petroleum Institute (API), Gas Processors Association 
(GPA), and Gas Research Institute (GRI); and other branches of the U.S. 
government, e.g., Department of Defense (DOD) and Department of 
Transportation (DOT). This does not preclude EPA from using standards 
developed by groups that are not VCS bodies within their rule. When 
this occurs, EPA has done searches and reviews for VCS equivalent to 
these non-EPA methods.
    Waste heat boiler means a device that recovers normally unused 
energy (i.e., hot exhaust gas) and converts it to usable heat. Waste 
heat boilers are also referred to as heat recovery steam generators. 
Waste heat boilers are heat exchangers generating steam from incoming 
hot exhaust gas from an industrial (e.g., thermal oxidizer, kiln, 
furnace) or power (e.g., combustion turbine, engine) equipment. Duct 
burners are sometimes used to increase the temperature of the incoming 
hot exhaust gas.
    Wet scrubber means any add-on air pollution control device that 
mixes an aqueous stream or slurry with the exhaust gases from a boiler 
to control emissions of particulate matter or to absorb and neutralize 
acid gases, such as hydrogen chloride. A wet scrubber creates an 
aqueous stream or slurry as a byproduct of the emissions control 
process.
* * * * *

0
21. Table 1 to subpart JJJJJJ is revised to read as follows:
    As stated in Sec.  63.11201, you must comply with the following 
applicable emission limits:

          Table 1 to Subpart JJJJJJ of Part 63--Emission Limits
------------------------------------------------------------------------
                                                   You must achieve less
                                                    than or equal to the
                                For the following    following emission
   If your boiler is in this     pollutants . . .  limits, except during
       subcategory . . .                             periods of startup
                                                     and shutdown . . .
 
------------------------------------------------------------------------
1. New coal-fired boilers with  a. PM              3.0E-02 pounds(lb)
 heat input capacity of 30       (Filterable).      per million British
 million British thermal units  b. Mercury.......   thermal units
 per hour (MMBtu/hr) or         c. CO............   (MMBtu) of heat
 greater that do not meet the                       input.
 definition of limited-use                         2.2E-05 lb per MMBtu
 boiler.                                            of heat input.
                                                   420 parts per million
                                                    (ppm) by volume on a
                                                    dry basis corrected
                                                    to 3 percent oxygen
                                                    (3-run average or 10-
                                                    day rolling
                                                    average).
2. New coal-fired boilers with  a. PM              4.2E-01 lb per MMBtu
 heat input capacity of          (Filterable).      of heat input.
 between 10 and 30 MMBtu/hr     b. Mercury.......  2.2E-05 lb per MMBtu
 that do not meet the           c. CO............   of heat input.
 definition of limited-use                         420 ppm by volume on
 boiler.                                            a dry basis
                                                    corrected to 3
                                                    percent oxygen (3-
                                                    run average or 10-
                                                    day rolling
                                                    average).

[[Page 7518]]

 
3. New biomass-fired boilers    PM (Filterable)..  3.0E-02 lb per MMBtu
 with heat input capacity of                        of heat input.
 30 MMBtu/hr or greater that
 do not meet the definition of
 seasonal boiler or limited-
 use boiler.
4. New biomass fired boilers    PM (Filterable)..  7.0E-02 lb per MMBtu
 with heat input capacity of                        of heat input.
 between 10 and 30 MMBtu/hr
 that do not meet the
 definition of seasonal boiler
 or limited-use boiler.
5. New oil-fired boilers with   PM (Filterable)..  3.0E-02 lb per MMBtu
 heat input capacity of 10                          of heat input.
 MMBtu/hr or greater that do
 not meet the definition of
 seasonal boiler or limited-
 use boiler.
6. Existing coal-fired boilers  a. Mercury.......  2.2E-05 lb per MMBtu
 with heat input capacity of    b. CO............   of heat input.
 10 MMBtu/hr or greater that                       420 ppm by volume on
 do not meet the definition of                      a dry basis
 limited-use boiler.                                corrected to 3
                                                    percent oxygen.
------------------------------------------------------------------------


0
22. Table 2 to subpart JJJJJJ is revised to read as follows:
    As stated in Sec.  63.11201, you must comply with the following 
applicable work practice standards, emission reduction measures, and 
management practices:

 Table 2 to Subpart JJJJJJ of Part 63--Work Practice Standards, Emission
              Reduction Measures, and Management Practices
------------------------------------------------------------------------
  If your boiler is in this
      subcategory . . .            You must meet the following . . .
------------------------------------------------------------------------
1. Existing or new coal-       Minimize the boiler's startup and
 fired, new biomass-fired, or   shutdown periods and conduct startups
 new oil-fired boilers (units   and shutdowns according to the
 with heat input capacity of    manufacturer's recommended procedures.
 10 MMBtu/hr or greater).       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-fired         Conduct an initial tune-up as specified
 boilers with heat input        in Sec.   63.11214, and conduct a tune-
 capacity of less than 10       up of the boiler biennially as specified
 MMBtu/hr that do not meet      in Sec.   63.11223.
 the definition of limited-
 use boiler, or use an oxygen
 trim system that maintains
 an optimum air-to-fuel ratio.
3. New coal-fired boilers      Conduct a tune-up of the boiler
 with heat input capacity of    biennially as specified in Sec.
 less than 10 MMBtu/hr that     63.11223.
 do not meet the definition
 of limited-use boiler, or
 use an oxygen trim system
 that maintains an optimum
 air-to-fuel ratio.
4. Existing oil-fired boilers  Conduct an initial tune-up as specified
 with heat input capacity       in Sec.   63.11214, and conduct a tune-
 greater than 5 MMBtu/hr that   up of the boiler biennially as specified
 do not meet the definition     in Sec.   63.11223.
 of seasonal boiler or
 limited-use boiler, or use
 an oxygen trim system that
 maintains an optimum air-to-
 fuel ratio.
5. New oil-fired boilers with  Conduct a tune-up of the boiler
 heat input capacity greater    biennially as specified in Sec.
 than 5 MMBtu/hr that do not    63.11223.
 meet the definition of
 seasonal boiler or limited-
 use boiler, or use an oxygen
 trim system that maintains
 an optimum air-to-fuel ratio.
6. Existing biomass-fired      Conduct an initial tune-up as specified
 boilers that do not meet the   in Sec.   63.11214, and conduct a tune-
 definition of seasonal         up of the boiler biennially as specified
 boiler or limited-use          in Sec.   63.11223.
 boiler, or use an oxygen
 trim system that maintains
 an optimum air-to-fuel ratio.
7. New biomass-fired boilers   Conduct a tune-up of the boiler
 that do not meet the           biennially as specified in Sec.
 definition of seasonal         63.11223.
 boiler or limited-use
 boiler, or use an oxygen
 trim system that maintains
 an optimum air-to-fuel ratio.
8. Existing seasonal boilers.  Conduct an initial tune-up as specified
                                in Sec.   63.11214, and conduct a tune-
                                up of the boiler every 5 years as
                                specified in Sec.   63.11223.
9. New seasonal boilers......  Conduct a tune-up of the boiler every 5
                                years as specified in Sec.   63.11223.
10. Existing limited-use       Conduct an initial tune-up as specified
 boilers.                       in Sec.   63.11214, and conduct a tune-
                                up of the boiler every 5 years as
                                specified in Sec.   63.11223.
11. New limited-use boilers..  Conduct a tune-up of the boiler every 5
                                years as specified in Sec.   63.11223.
12. Existing oil-fired         Conduct an initial tune-up as specified
 boilers with heat input        in Sec.   63.11214, and conduct a tune-
 capacity of equal to or less   up of the boiler every 5 years as
 than 5 MMBtu/hr.               specified in Sec.   63.11223.
13. New oil-fired boilers      Conduct a tune-up of the boiler every 5
 with heat input capacity of    years as specified in Sec.   63.11223.
 equal to or less than 5
 MMBtu/hr.

[[Page 7519]]

 
14. Existing coal-fired,       Conduct an initial tune-up as specified
 biomass-fired, or oil-fired    in Sec.   63.11214, and conduct a tune-
 boilers with an oxygen trim    up of the boiler every 5 years as
 system that maintains an       specified in Sec.   63.11223.
 optimum air-to-fuel ratio
 that would otherwise be
 subject to a biennial tune-
 up.
15. New coal-fired, biomass-   Conduct a tune-up of the boiler every 5
 fired, or oil-fired boilers    years as specified in Sec.   63.11223.
 with an oxygen trim system
 that maintains an optimum
 air-to-fuel ratio that would
 otherwise be subject to a
 biennial tune-up.
16. Existing coal-fired,       Must have a one-time energy assessment
 biomass-fired, or oil-fired    performed by a qualified energy
 boilers (units with heat       assessor. An energy assessment completed
 input capacity of 10 MMBtu/    on or after January 1, 2008, that meets
 hr and greater), not           or is amended to meet the energy
 including limited-use          assessment requirements in this table
 boilers.                       satisfies the energy assessment
                                requirement. Energy assessor approval
                                and qualification requirements are
                                waived in instances where past or
                                amended energy assessments are used to
                                meet the energy assessment requirements.
                                A facility that operates under an energy
                                management program compatible with ISO
                                50001 that includes the affected units
                                also satisfies the energy assessment
                                requirement. The energy assessment must
                                include the following with extent of the
                                evaluation for items (1) to (4)
                                appropriate for the on-site technical
                                hours listed in Sec.   63.11237:
                               (1) A visual inspection of the boiler
                                system,
                               (2) An evaluation of operating
                                characteristics of the affected boiler
                                systems, specifications of energy use
                                systems, operating and maintenance
                                procedures, and unusual operating
                                constraints,
                               (3) An inventory of major energy use
                                systems consuming energy from affected
                                boiler(s) and which are under control of
                                the boiler owner or operator,
                               (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, and
                               (7) A comprehensive report detailing the
                                ways to improve efficiency, the cost of
                                specific improvements, benefits, and the
                                time frame for recouping those
                                investments.
------------------------------------------------------------------------


0
23.Table 3 to subpart JJJJJJ is revised to read as follows:
    As stated in Sec.  63.11201, you must comply with the applicable 
operating limits:

 Table 3 to Subpart JJJJJJ of Part 63--Operating Limits for Boilers With
                             Emission Limits
------------------------------------------------------------------------
If you demonstrate compliance     You must meet these operating limits
   with applicable emission       except during periods of startup and
      limits using . . .                     shutdown . . .
------------------------------------------------------------------------
1. Fabric filter control.....  a. Maintain opacity to less than or equal
                                to 10 percent opacity (daily block
                                average); OR
                               b. Install and operate a bag leak
                                detection system according to Sec.
                                63.11224 and operate the fabric filter
                                such that the bag leak detection system
                                alarm does not sound more than 5 percent
                                of the operating time during each 6-
                                month period.
2. Electrostatic precipitator  a. Maintain opacity to less than or equal
 control.                       to 10 percent opacity (daily block
                                average); OR
                               b. Maintain the 30-day rolling average
                                total secondary electric power of the
                                electrostatic precipitator at or above
                                the minimum total secondary electric
                                power as defined in Sec.   63.11237.
3. Wet scrubber control......  Maintain the 30-day rolling average
                                pressure drop across the wet scrubber at
                                or above the minimum scrubber pressure
                                drop as defined in Sec.   63.11237 and
                                the 30-day rolling average liquid flow
                                rate at or above the minimum scrubber
                                liquid flow rate as defined in Sec.
                                63.11237.
4. Dry sorbent or activated    Maintain the 30-day rolling average
 carbon injection control.      sorbent or activated carbon injection
                                rate at or above the minimum sorbent
                                injection rate or minimum activated
                                carbon injection rate as defined in Sec.
                                  63.11237. When your boiler operates at
                                lower loads, multiply your sorbent or
                                activated carbon injection rate by the
                                load fraction (e.g., actual heat input
                                divided by the heat input during the
                                performance stack test; for 50 percent
                                load, multiply the injection rate
                                operating limit by 0.5).
5. Any other add-on air        This option is for boilers that operate
 pollution control type..       dry control systems. Boilers must
                                maintain opacity to less than or equal
                                to 10 percent opacity (daily block
                                average).
6. Fuel analysis.............  Maintain the fuel type or fuel mixture
                                (annual average) such that the mercury
                                emission rate calculated according to
                                Sec.   63.11211(c) are less than the
                                applicable emission limit for mercury.
7. Performance stack testing.  For boilers that demonstrate compliance
                                with a performance stack test, maintain
                                the operating load of each unit such
                                that it does not exceed 110 percent of
                                the average operating load recorded
                                during the most recent performance stack
                                test.
8. Oxygen analyzer system....  For boilers subject to a CO emission
                                limit that demonstrate compliance with
                                an oxygen analyzer system as specified
                                in Sec.   63.11224(a), maintain the 30-
                                day rolling average oxygen level at or
                                above the minimum oxygen level as
                                defined in Sec.   63.11237. This
                                requirement does not apply to units that
                                install an oxygen trim system since
                                these units will set the trim system to
                                the level specified in Sec.
                                63.11224(a)(7).
------------------------------------------------------------------------


[[Page 7520]]

* * * * *

0
24. Table 6 to subpart JJJJJJ is revised to read as follows:
    As stated in Sec.  63.11211, you must comply with the following 
requirements for establishing operating limits:

                                           Table 6 to Subpart JJJJJJ of Part 63--Establishing Operating Limits
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                  And your operating
  If you have an applicable    limits are based on . .         You must . . .                 Using . . .                According to the following
   emission limit for . . .               .                                                                                     requirements
--------------------------------------------------------------------------------------------------------------------------------------------------------
1. PM or mercury.............  a. Wet scrubber          Establish site-specific       Data from the pressure drop  (a) You must collect pressure drop
                                operating parameters.    minimum scrubber pressure     and liquid flow rate         and liquid flow rate data every 15
                                                         drop and minimum scrubber     monitors and the PM or       minutes during the entire period of
                                                         liquid flow rate operating    mercury performance stack    the performance stack tests;
                                                         limits according to Sec.      tests.
                                                         63.11211(b).
                                                                                                                   (b) Determine the average pressure
                                                                                                                    drop and liquid flow rate for each
                                                                                                                    individual test run in the three-run
                                                                                                                    performance stack test by computing
                                                                                                                    the average of all the 15-minute
                                                                                                                    readings taken during each test run.
                               b. Electrostatic         Establish a site-specific     Data from the secondary      (a) You must collect secondary
                                precipitator operating   minimum total secondary       electric power monitors      electric power data every 15 minutes
                                parameters.              electric power operating      and the PM or mercury        during the entire period of the
                                                         limit according to Sec.       performance stack tests.     performance stack tests;
                                                         63.11211(b).
                                                                                                                   (b) Determine the average total
                                                                                                                    secondary electric power for each
                                                                                                                    individual test run in the three-run
                                                                                                                    performance stack test by computing
                                                                                                                    the average of all the 15-minute
                                                                                                                    readings taken during each test run.
2. Mercury...................  Dry sorbent or           Establish a site-specific     Data from the sorbent or     (a) You must collect sorbent or
                                activated carbon         minimum sorbent or            activated carbon injection   activated carbon injection rate data
                                injection rate           activated carbon injection    rate monitors and the        every 15 minutes during the entire
                                operating parameters.    rate operating limit          mercury performance stack    period of the performance stack
                                                         according to Sec.             tests.                       tests;
                                                         63.11211(b).
                                                                                                                   (b) Determine the average sorbent or
                                                                                                                    activated carbon injection rate for
                                                                                                                    each individual test run in the
                                                                                                                    three-run performance stack test by
                                                                                                                    computing the average of all the 15-
                                                                                                                    minute readings taken during each
                                                                                                                    test run.
                                                                                                                   (c) When your unit operates at lower
                                                                                                                    loads, multiply your sorbent or
                                                                                                                    activated carbon injection rate by
                                                                                                                    the load fraction (e.g., actual heat
                                                                                                                    input divided by heat input during
                                                                                                                    performance stack test, for 50
                                                                                                                    percent load, multiply the injection
                                                                                                                    rate operating limit by 0.5) to
                                                                                                                    determine the required injection
                                                                                                                    rate.
3. CO........................  Oxygen.................  Establish a unit-specific     Data from the oxygen         (a) You must collect oxygen data
                                                         limit for minimum oxygen      analyzer system specified    every 15 minutes during the entire
                                                         level.                        in Sec.   63.11224(a).       period of the performance stack
                                                                                                                    tests;
                                                                                                                   (b) Determine the average hourly
                                                                                                                    oxygen concentration for each
                                                                                                                    individual test run in the three-run
                                                                                                                    performance stack test by computing
                                                                                                                    the average of all the 15-minute
                                                                                                                    readings taken during each test run.
4. Any pollutant for which     Boiler operating load..  Establish a unit-specific     Data from the operating      (a) You must collect operating load
 compliance is demonstrated                              limit for maximum operating   load monitors (fuel feed     data (fuel feed rate or steam
 by a performance stack test.                            load according to Sec.        monitors or steam            generation data) every 15 minutes
                                                         63.11212(c).                  generation monitors).        during the entire period of the
                                                                                                                    performance test.
                                                                                                                   (b) Determine the average operating
                                                                                                                    load by computing the hourly
                                                                                                                    averages using all of the 15-minute
                                                                                                                    readings taken during each
                                                                                                                    performance test.
                                                                                                                   (c) Determine the average of the
                                                                                                                    three test run averages during the
                                                                                                                    performance test, and multiply this
                                                                                                                    by 1.1 (110 percent) as your
                                                                                                                    operating limit.
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 7521]]


0
25. Table 7 to subpart JJJJJJ is revised to read as follows:
    As stated in Sec.  63.11222, you must show continuous compliance 
with the emission limitations for each boiler according to the 
following:

     Table 7 to Subpart JJJJJJ of Part 63--Demonstrating Continuous
                               Compliance
------------------------------------------------------------------------
     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 Sec.
                                63.11224(e) and Sec.   63.11221; and
                               b. Reducing the opacity monitoring data
                                to 6-minute averages; and
                               c. Maintaining opacity to less than or
                                equal to 10 percent (daily block
                                average).
2. Fabric Filter Bag Leak      Installing and operating a bag leak
 Detection Operation.           detection system according to Sec.
                                63.11224(f) and operating the fabric
                                filter such that the requirements in
                                Sec.   63.11222(a)(4) are met.
3. Wet Scrubber Pressure Drop  a. Collecting the pressure drop and
 and Liquid Flow Rate.          liquid flow rate monitoring system data
                                according to Sec.  Sec.   63.11224 and
                                63.11221; and
                               b. Reducing the data to 30-day rolling
                                averages; and
                               c. Maintaining the 30-day rolling average
                                pressure drop and liquid flow rate at or
                                above the minimum pressure drop and
                                minimum liquid flow rate according to
                                Sec.   63.11211.
4. Dry Scrubber Sorbent or     a. Collecting the sorbent or activated
 Activated Carbon Injection     carbon injection rate monitoring system
 Rate.                          data for the dry scrubber according to
                                Sec.  Sec.   63.11224 and 63.11221; and
                               b. Reducing the data to 30-day rolling
                                averages; and
                               c. Maintaining the 30-day rolling average
                                sorbent or activated carbon injection
                                rate at or above the minimum sorbent or
                                activated carbon injection rate
                                according to Sec.   63.11211.
5. Electrostatic Precipitator  a. Collecting the total secondary
 Total Secondary Electric       electric power monitoring system data
 Power.                         for the electrostatic precipitator
                                according to Sec.  Sec.   63.11224 and
                                63.11221; and
                               b. Reducing the data to 30-day rolling
                                averages; and
                               c. Maintaining the 30-day rolling average
                                total secondary electric power at or
                                above the minimum total secondary
                                electric power according to Sec.
                                63.11211.
6. Fuel Pollutant Content....  a. Only burning the fuel types and fuel
                                mixtures used to demonstrate compliance
                                with the applicable emission limit
                                according to Sec.   63.11213 as
                                applicable; and
                               b. Keeping monthly records of fuel use
                                according to Sec.  Sec.   63.11222(a)(2)
                                and 63.11225(b)(4).
7. Oxygen content............  a. Continuously monitoring the oxygen
                                content of flue gas according to Sec.
                                63.11224 (This requirement does not
                                apply to units that install an oxygen
                                trim system since these units will set
                                the trim system to the level specified
                                in Sec.   63.11224(a)(7)); and
                               b. Reducing the data to 30-day rolling
                                averages; and
                               c. Maintaining the 30-day rolling average
                                oxygen content at or above the minimum
                                oxygen level established during the most
                                recent CO performance test.
8. CO emissions..............  a. Continuously monitoring the CO
                                concentration in the combustion exhaust
                                according to Sec.  Sec.   63.11224 and
                                63.11221; and
                               b. Correcting the data to 3 percent
                                oxygen, and reducing the data to 1-hour
                                averages; and
                               c. Reducing the data from the hourly
                                averages to 10-day rolling averages; and
                               d. Maintaining the 10-day rolling average
                                CO concentration at or below the
                                applicable emission limit in Table 1 to
                                this subpart.
9. Boiler operating load.....  a. Collecting operating load data (fuel
                                feed rate or steam generation data)
                                every 15 minutes; and
                               b. Reducing the data to 30-day rolling
                                averages; and
                               c. Maintaining the 30-day rolling average
                                at or below the operating limit
                                established during the performance test
                                according to Sec.   63.11212(c) and
                                Table 6 to this subpart.
------------------------------------------------------------------------


0
26. Table 8 to subpart JJJJJJ is amended by:
0
a. Revising the entry for ``Sec.  63.9''.
0
b. Revising the entry for ``Sec.  63.10(e) and (f)''.
0
c. Adding an entry for ``Sec.  63.10(f)''.
    The revisions read as follows:
* * * * *

[[Page 7522]]



           Table 8 to Subpart JJJJJJ of Part 63--Applicability of General Provisions to Subpart JJJJJJ
----------------------------------------------------------------------------------------------------------------
      General  provisions cite                      Subject                            Does it apply?
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Sec.   63.9........................  Notification Requirements............  Yes, excluding the information
                                                                             required in Sec.
                                                                             63.9(h)(2)(i)(B), (D), (E) and (F).
                                                                             See Sec.   63.11225.
 
                                                  * * * * * * *
Sec.   63.10(e)....................  Additional reporting requirements for  Yes.
                                      sources with CMS.
Sec.   63.10(f)....................  Waiver of recordkeeping or reporting   Yes.
                                      requirements.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2012-31645 Filed 1-31-13; 8:45 am]
BILLING CODE 6560-50-P


