
[Federal Register Volume 76, Number 54 (Monday, March 21, 2011)]
[Rules and Regulations]
[Pages 15554-15606]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2011-4493]



[[Page 15553]]

Vol. 76

Monday,

No. 54

March 21, 2011

Part IV





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. 76 , No. 54 / Monday, March 21, 2011 / Rules 
and Regulations  

[[Page 15554]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2006-0790; FRL-9273-5]
RIN 2060-AM44


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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is promulgating national emission standards for control of 
hazardous air pollutants from two area source categories: Industrial 
boilers and commercial and institutional boilers. The final emission 
standards for control of mercury and polycyclic organic matter 
emissions from coal-fired area source boilers are based on the maximum 
achievable control technology. The final emission standards for control 
of hazardous air pollutants emissions from biomass-fired and oil-fired 
area source boilers are based on EPA's determination as to what 
constitutes the generally available control technology or management 
practices.

DATES: Effective Date: This final rule is effective on May 20, 2011. 
The incorporation by reference of certain publications listed in this 
final rule were approved by the Director of the Federal Register as of 
May 20, 2011.

ADDRESSES: EPA established a 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., CBI 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 EPA's Docket Center, 
Public Reading Room, EPA West Building, Room 3334, 1301 Constitution 
Ave., NW., Washington, DC. 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) 566-1742.

FOR FURTHER INFORMATION CONTACT: Mr. James Eddinger, Energy Strategies 
Group, Sector Policies and Programs Division, (D243-01), Office of Air 
Quality Planning and Standards, U.S. Environmental Protection Agency, 
Research Triangle Park, North Carolina 27711; Telephone number: (919) 
541-5426; Fax number (919) 541-5450; e-mail address: 
eddinger.jim@epa.gov.

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

    Btu British thermal unit
CAA Clean Air Act
CBI Confidential Business Information
CEMS Continuous Emission Monitoring System
CFR Code of Federal Regulations
CO Carbon monoxide
ERT Electronic Reporting Tool
FR Federal Register
GACT Generally Available Control Technology
HAP Hazardous Air Pollutant
HCl Hydrogen chloride
ICR Information Collection Request
kWh Kilowatt hour
MACT Maximum Achievable Control Technology
MMBtu/h Million Btu per hour
NAICS North American Industry Classification System
NESHAP National Emission Standards for Hazardous Air Pollutants
NOX Nitrogen oxides
NSPS New Source Performance Standards
PM Particulate matter
PM2.5 Fine particulate matter
POM Polycyclic organic matter
ppm Parts per million
RCRA Resource Conservation and Recovery Act
TBtu Trillion British thermal units
tpy Tons per year
SO2 Sulfur dioxide
UPL Upper Prediction limit
VOC Volatile organic compound

    Organization of This Document. The information 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
    A. What is the statutory authority and regulatory approach for 
this final rule?
    B. What source categories are affected by the standards?
    C. What is the relationship between this rule and other related 
national emission standards?
    D. How did we gather information for this rule?
    E. How are the area source boiler HAP addressed by this rule?
    F. What are the costs and benefits of this final rule?
III. Summary of This Final Rule
    A. Do these standards apply to my source?
    B. What is the affected source?
    C. When must I comply with the final standards?
    D. What are the MACT and GACT standards?
    E. What are the Startup, Shutdown, and Malfunction (SSM) 
requirements?
    F. What are the initial compliance requirements?
    G. What are the continuous compliance requirements?
    H. What are the notification, recordkeeping and reporting 
requirements?
    I. Submission of Emissions Test Results to EPA
IV. Summary of Significant Changes Following Proposal
    A. Changes to Subcategories
    B. Change From MACT to GACT for Biomass and Oil Subcategories
    C. MACT Floor UPL Methodology/Emission Limits
    D. Clarification of Energy Assessment Requirements
    E. Revised Subcategory Limits
    F. Demonstrating Compliance
    G. Affirmative Defense
    H. Technical/Editorial Corrections
V. Significant Area Source Public Comments and Rationale for Changes 
to Proposed Rule
    A. Legal and Applicability Issues
    B. CO Limits
    C. MACT Floor Analysis
    D. Beyond the Floor Analysis
    E. GACT Standards
    F. Subcategories
    G. Startup, Shutdown, and Malfunction
    H. Compliance Requirements
    I. Cost/Economic Impacts
    J. Title V Permitting Requirements
VI. Relationship of this Action to CAA Section 112(c)(6)
VII. Summary of the Impacts of This Final Rule
    A. What are the air impacts?
    B. What are the cost impacts?
    C. What are the economic impacts?
    D. What are the benefits?
    E. What are the water and solid waste impacts?
    F. What are the energy impacts?
VIII. Statutory and Executive Order Review
    A. Executive Order 12866 and 13563: Regulatory Planning and 
Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act, as Amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996
    D. Unfunded Mandates Reform Act of 1995
    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

[[Page 15555]]

I. General Information

A. Does this action apply to me?

    The regulated categories and entities potentially affected by the 
final standards include:

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

    This table is not intended to be exhaustive, but rather provides a 
guide for readers regarding entities likely to be affected by this 
action. To determine whether your facility, company, business, 
organization, etc., is regulated 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 action to a particular 
entity, consult either the delegated regulatory 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 final action will also be available on the Worldwide Web (WWW) 
through the Technology Transfer Network (TTN). Following signature, a 
copy of the final 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 section 307(b)(1) of the CAA, 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 (the Court) by 
May 20, 2011. 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. CAA 
section 307(d)(7)(B) also provides a mechanism for EPA to convene a 
proceeding for reconsideration, ``[i]f the person raising an objection 
can demonstrate to EPA that it was impracticable to raise such 
objection within [the period for public comment] 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.'' Any person seeking to 
make such a demonstration to us should submit a Petition for 
Reconsideration to the Office of the Administrator, Environmental 
Protection Agency, Room 3000, Ariel Rios Building, 1200 Pennsylvania 
Ave., NW., Washington, DC 20460, with a copy to the person listed in 
the preceding FOR FURTHER GENERAL INFORMATION CONTACT section, and the 
Associate General Counsel for the Air and Radiation Law Office, Office 
of General Counsel (Mail Code 2344A), Environmental Protection Agency, 
1200 Pennsylvania Ave., NW., Washington, DC 20004. Note, 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

A. What is the statutory authority and regulatory approach for this 
final rule?

    Section 112(d) of the CAA requires us to establish NESHAP for both 
major and area sources of HAP that are listed for regulation under CAA 
section 112(c). A major source 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 HAP-emitting stationary source that is not a 
major source.
    Section 112(k)(3)(B) of the CAA calls for EPA to identify at least 
30 HAP which, as the result of emissions from area sources, pose the 
greatest threat to public health in the largest number of urban areas. 
EPA implemented this provision in 1999 in the Integrated Urban Air 
Toxics Strategy (Strategy), (64 FR 38715, July 19, 1999). Specifically, 
in the Strategy, 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.'' CAA section 112(c)(3) requires 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. A primary goal of the Strategy is to achieve a 
75 percent reduction in cancer incidence attributable to HAP emitted 
from stationary sources.
    Under CAA section 112(d)(5), we may elect to promulgate standards 
or requirements for area sources ``which provide for the use of 
generally

[[Page 15556]]

available control technologies [``GACT''] or management practices by 
such sources to reduce emissions of hazardous air pollutants.'' 
Additional information on GACT is found in the Senate report on the 
legislation (Senate Report Number 101-228, December 20, 1989), which 
describes GACT as:

* * * methods, practices and techniques which are commercially 
available and appropriate for application by the sources in the 
category considering economic impacts and the technical capabilities 
of the firms to operate and maintain the emissions control systems.

    Consistent with the legislative history, we can consider costs and 
economic impacts in determining GACT, which is particularly important 
when developing regulations for source categories that may have many 
small businesses such as these.
    Determining what constitutes GACT involves considering the control 
technologies and management practices that are generally available to 
the area sources in the source category. We also consider the standards 
applicable to major sources in the analogous source category to 
determine if the control technologies and management practices are 
transferable and generally available to area sources. In appropriate 
circumstances, we may also consider technologies and practices at area 
and major sources in similar categories to determine whether such 
technologies and practices could be considered generally available for 
the area source categories at issue. Finally, as noted above, in 
determining GACT for a particular area source category, we consider the 
costs and economic impacts of available control technologies and 
management practices on that category.
    While GACT may be a basis for standards for most types of HAP 
emitted from area sources, CAA section 112(c)(6) requires that 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, mercury, 
polychlorinated biphenyls (PCBs), 2,3,7,8-tetrachlorodibenzofurans, and 
2,3,7,8-tetrachlorodibenzo-p-dioxin.
    The CAA section 112(c)(6) list of source categories currently 
includes industrial coal combustion, industrial oil combustion, 
industrial wood combustion, commercial coal combustion, commercial oil 
combustion, and commercial wood combustion. (See 63 FR 17849, April 10, 
1998.) We listed these source categories under CAA section 112(c)(6) 
based on the source categories' contribution of mercury and POM. In the 
documentation for the CAA section 112(c)(6) listing, the commercial 
fuel combustion categories included institutional fuel combustion. (See 
``1990 Emissions Inventory of Section 112(c)(6) Pollutants, Final 
Report,'' April 1998.) As discussed in the preamble to the proposed 
rule, we concluded we only needed to address mercury emissions from the 
coal-fueled portion of these categories in order to ensure that 90 
percent of the aggregate emissions of mercury would be subject to 
standards under CAA sections 112(d)(2) or 112(d)(4). (See 75 FR 31898, 
June 4, 2010.) As discussed in this preamble, based on public comments 
received, we re-examined the emission inventory and the need to address 
POM emissions from the area source subcategories to meet the CAA 
section 112(c)(6) 90 percent requirement, and concluded we only need to 
address POM emissions from the coal-fueled portion of these categories 
under CAA section 112(d)(2) or 112(d)(4).
    With this final rule and the major source boilers rule, we believe 
that we have subjected to regulation at least 90 percent of the CAA 
section 112(c)(6) 1990 emissions inventory for mercury and POM. 
Consequently, we are regulating coal-fired area source boilers under 
MACT because we need these sources to meet the 90 percent requirement 
for mercury and POM in CAA section 112(c)(6).
    The ``MACT'' required by CAA sections 112(d)(2) or 112(d)(4) can be 
based on the emissions reductions achievable through application of 
measures, processes, methods, systems, or techniques including, but not 
limited to: (1) Reducing the volume of, or eliminating emissions of, 
such pollutants through process changes, substitutions of materials, or 
other modifications; (2) enclosing systems or processes to eliminate 
emissions; (3) collecting, capturing, or treating such pollutants when 
released from a process, stack, storage or fugitive emission point; (4) 
design, equipment, work practices, or operational standards as provided 
in CAA section 112(h); or (5) a combination of the above.
    The MACT floor is the minimum control level allowed for NESHAP and 
is defined under CAA section 112(d)(3). For new sources, MACT based 
standards cannot be less stringent than the emission control achieved 
in practice by the best-controlled similar source, as determined by the 
Administrator. The MACT based standards for existing sources can be 
less stringent than standards for new sources, but they cannot be less 
stringent than the average emission limitation achieved by the best 
performing 12 percent of existing sources in the category or 
subcategory (for which the Administrator has emission information) for 
source categories and subcategories with 30 or more sources, or the 
best performing 5 sources for categories and subcategories with fewer 
than 30 sources (CAA section 112(d)(3)(A) and (B)).
    Although emission standards are often structured in terms of 
numerical emissions limits, alternative approaches are sometimes 
necessary and authorized pursuant to CAA section 112. For example, in 
some cases, physically measuring emissions from a source may not be 
practicable due to technological and economic limitations. Section 
112(h) of the CAA authorizes the Administrator to promulgate a design, 
equipment, work practice, or operational standard, or combination 
thereof, consistent with the provisions of CAA sections 112(d) or (f), 
in those cases where, in the judgment of the Administrator, it is not 
feasible to prescribe or enforce an emission standard. Section 
112(h)(2) of the CAA provides that the phrase ``not feasible to 
prescribe or enforce an emission standard'' includes ``the situation in 
which the Administrator determines that * * * the application of 
measurement methodology to a particular class of sources is not 
practicable due to technological and economic limitations.''
    As noted above in this section of the preamble, we listed 
industrial coal combustion, industrial oil combustion, industrial wood 
combustion, commercial coal combustion, commercial oil combustion, and 
commercial wood combustion under CAA section 112(c)(6) based on the 
source categories' contribution of mercury and POM. We listed these 
same categories under CAA section 112(c)(3) for their contribution of 
mercury, arsenic, beryllium, cadmium, lead, chromium, manganese, 
nickel, POM (as 7-PAH (polynuclear aromatic hydrocarbons)), ethylene 
dioxide, and PCBs.
    We have developed final standards to reflect the application of 
MACT for mercury and POM from coal-fired area source boilers and have 
applied GACT for the urban HAP noted above for boilers firing other 
fuels and for urban

[[Page 15557]]

HAP (other than mercury and POM) from coal-fired area source boilers.

B. What source categories are affected by the standards?

    The source categories affected by the standards are industrial 
boilers and commercial and institutional boilers. Both source 
categories were included in the area source list published on July 19, 
1999 (64 FR 38721). The inclusion of these two source categories on the 
CAA section 112(c)(3) area source category list is based on 1990 
emissions data, as EPA used 1990 as the baseline year for that listing. 
We describe above in Section II.A of this preamble the pollutants that 
formed the basis of the listings.
    This rule applies to all existing and new industrial boilers, 
institutional boilers, and commercial boilers located at area sources. 
Boiler means an enclosed combustion device having the primary purpose 
of recovering thermal energy in the form of steam or hot water. The 
industrial boiler source category includes boilers used in 
manufacturing, processing, mining, refining, or any other industry. The 
commercial boiler source category includes boilers used in commercial 
establishments such as stores/malls, laundries, apartments, 
restaurants, and hotels/motels. The institutional boiler source 
category includes boilers used in medical centers (e.g., hospitals, 
clinics, nursing homes), educational and religious facilities (e.g., 
schools, universities, churches), and municipal buildings (e.g., 
courthouses, prisons).

C. What is the relationship between this rule and other related 
national emission standards?

    This rule regulates industrial boilers and institutional/commercial 
boilers that are located at area sources of HAP. Today, in a parallel 
action, a NESHAP for industrial, commercial, and institutional boilers 
and process heaters located at major sources is being promulgated 
reflecting the application of MACT. The major source NESHAP regulates 
emissions of PM (as a surrogate for non-mercury metals), mercury, HCl 
(as a surrogate for acid gases), dioxins/furans, and CO (as a surrogate 
for non-dioxin organic HAP) from existing and new major source boilers.
    This rule covers boilers located at area source facilities. In 
addition to the major source MACT for boilers being issued today, the 
Agency is also issuing emission standards today pursuant to CAA section 
129 for commercial and industrial solid waste incineration units. In a 
parallel action, EPA is finalizing a solid waste definition rulemaking 
pursuant to subtitle D of RCRA. That action is relevant to this 
proceeding because if an industrial, commercial, or institutional 
boiler located at an area source combusts secondary materials that are 
``solid waste,'' as that term is defined by the Administrator under 
RCRA, those boilers would be subject to section 129 of the CAA, not 
section 112.
    As background, in 2007, the United States Court of Appeals for the 
District of Columbia Circuit (DC Circuit) vacated the ``CISWI 
Definitions Rule'' (70 FR 55568, September 22, 2005), which amended the 
definitions of ``commercial and industrial solid waste incinerator 
(CISWI),'' ``commercial or industrial waste,'' and ``solid waste'' in 
40 CFR 60, subparts CCCC and DDDD, and which EPA issued pursuant to CAA 
section 129. The Court found that the definitions in that rule were 
inconsistent with the CAA. Specifically, the Court held that the term 
``solid waste incineration unit'' in CAA section 129(g)(1) 
``unambiguously include[s] among the incineration units subject to its 
standards any facility that combusts any commercial or industrial solid 
waste material at all--subject to the four statutory exceptions 
identified [in CAA section 129(g)(1)].'' NRDC v. EPA, 489 F.3d at 1257-
58.
    Based on the information available to the Agency, we determined 
that the boilers that are subject to this area source rule combust 
predominantly coal, oil, or biomass. We have further determined that 
the boilers subject to this rule may combust non-hazardous secondary 
materials that do not meet the definition of ``solid waste'' pursuant 
to the rulemaking of subtitle D of RCRA. A boiler located at an area 
source burning any secondary materials considered ``solid waste'' would 
be considered a solid waste incineration unit subject to regulation 
under CAA section 129. In the final area source boiler rulemaking, EPA 
is providing specific language to ensure clarity regarding the 
necessary steps that must be followed for combustion units that begin 
combusting non-hazardous solid waste materials and become subject to 
section 129 standards instead of section 112 standards or combustion 
units that discontinue combustion of non-hazardous solid waste 
materials and become subject to section 112 standards instead of 
section 129 standards.
    Some of the affected sources subject to this rule may also be 
subject to the NSPS for industrial, commercial, and institutional 
boilers (40 CFR part 60, subparts Db and Dc). EPA codified these NSPS 
in 1986, and revised portions of them in 1999 and 2006. The two NSPS 
regulate emissions of PM, SO2, and NOX from 
boilers constructed after June 19, 1984. Sources subject to the NSPS 
that are located at area source facilities are also subject to this 
rule because this rule regulates HAP. In developing this rule, we have 
streamlined the monitoring and recordkeeping requirements to avoid 
duplicating requirements in the NSPS.

D. How did we gather information for this rule?

    We gathered information for this rule from states' boiler 
inspection lists, company Web sites, published literature, state 
permits, current state and federal regulations, and from an ICR 
conducted for the major source NESHAP. After proposal, we received 
additional emission test reports during the public comment period.
    We developed an initial nationwide population of area source 
boilers based on boiler inspector data-bases from 13 states. The boiler 
inspector data-bases include steam boilers that are required to be 
inspected for safety or insurance purposes. We classified the area 
source boilers to NAICS codes based on the ``name'' of the facility at 
which the boiler was located. However, many of the boilers in the 
boiler inspector data-base could not be readily assigned to an NAICS 
code and, thus, we did not categorize them.
    We reviewed state and other federal regulations that apply to the 
area sources in the source categories for information concerning 
existing HAP emission control approaches. For example, as noted above, 
the NSPS for small industrial, commercial, and institutional boilers in 
40 CFR part 60, subpart Dc apply to boilers at some area sources. 
Similarly, permit requirements established by the Ohio, Illinois, 
Vermont, New Hampshire, and Maine air regulatory agencies apply to some 
area sources. We also reviewed standards for boilers at major sources 
that would be appropriate for and transferable to boilers at area 
sources. For example, we determined that management practices, such as, 
tune-ups and operator training applicable to major source boilers are 
also feasible for boilers at area sources.

[[Page 15558]]

E. How are the area source boiler HAP addressed by this rule?

    As explained in Section II.A of this preamble, industrial coal 
combustion, industrial oil combustion, industrial wood combustion, 
commercial coal combustion, commercial oil combustion, and commercial 
wood combustion are listed under CAA section 112(c)(6) due to 
contributions of mercury and POM and these same categories are listed 
under CAA section 112(c)(3) for their contribution of mercury, arsenic, 
beryllium, cadmium, lead, chromium, manganese, nickel, POM, ethylene 
dioxide, and PCB.
    With respect to the CAA section 112(c)(3) pollutants, we used 
surrogates because, as explained in this section of the preamble, it 
was not practical to establish individual standards for each specific 
HAP. We grouped the CAA section 112(c)(3) pollutants, which formed the 
basis for the listing of these two source categories, into three common 
groupings: Mercury, non-mercury metallic HAP (arsenic, beryllium, 
cadmium, chromium, lead, manganese, and nickel), and organic HAP (POM, 
ethylene dichloride, and PCB). In general, the pollutants within each 
group have similar characteristics and can be controlled with the same 
techniques.
    For the non-mercury metallic HAP, we selected PM as a surrogate. 
The inherent variability and unpredictability of the non-mercury metal 
HAP compositions and amounts in fuel has a material effect on the 
composition and amount of non-mercury metal HAP in the emissions from 
the boiler. As a result, establishing individual numerical emissions 
limits for each non-mercury HAP metal species is difficult given the 
level of uncertainty about the individual non-mercury metal HAP 
compositions of the fuels that will be combusted. An emission 
characteristic common to all boilers is that the non-mercury metal HAP 
are a component of the PM contained in the fly ash emitted from the 
boiler. A sufficient correlation exists between PM and non-mercury 
metallic HAP to rely on PM as a surrogate for these HAP and for their 
control.\1\ Therefore, the same control techniques that would be used 
to control the fly-ash PM will control non-mercury metallic HAP. 
Emissions limits established to achieve control of PM will also achieve 
control of non-mercury metallic HAP. Furthermore, establishing separate 
standards for each individual HAP would impose costly and significantly 
more complex compliance and monitoring requirements and achieve little, 
if any, HAP emissions reductions beyond what would be achieved using 
the surrogate pollutant approach.
---------------------------------------------------------------------------

    \1\ In National Lime Ass'n v. EPA, 233 F. 3d 625, 633 (DC Cir. 
2000), the court upheld EPA's use of particulate matter as a 
surrogate for HAP metals.
---------------------------------------------------------------------------

    For organic urban HAP, we selected CO as a surrogate for organic 
compounds, including POM, emitted from the various fuels burned in 
boilers. The presence of CO is an indicator of incomplete combustion. A 
high level of CO in emissions is a potential indication of elevated 
organic HAP emissions because organic HAP, like CO, are formed as a 
byproduct of combustion, and both would increase with an increase in 
the level of incomplete combustion. Monitoring equipment for CO is 
readily available, which is not the case for organic HAP. Also, it is 
significantly easier and less expensive to measure and monitor CO 
emissions than to measure and monitor emissions of each individual 
organic HAP. We considered other surrogates, such as total hydrocarbon 
(THC), but lacked data on emissions and permit limits for area source 
boilers. Therefore, using CO as a surrogate for organic urban HAP is a 
reasonable approach because minimizing CO emissions will result in 
minimizing organic urban HAP emissions.
    Based on these considerations, we are promulgating GACT standards 
for PM (as a surrogate for the individual urban metal HAP) for coal, 
biomass, and oil-fired boilers and CO (as a surrogate pollutant for the 
individual urban organic HAP) for biomass-fired and oil-fired boilers. 
We are also establishing MACT standards for mercury and for POM (using 
CO as a surrogate pollutant) for coal-fired boilers. The MACT standard 
for POM from coal-fired boilers would also be GACT for urban organic 
HAP other than POM.

F. What are the costs and benefits of this final rule?

    EPA estimated the costs and benefits associated with the final 
rule, and the results are shown in the following table. For more 
information on the costs and benefits for this rule, see the Regulatory 
Impact Analysis (RIA).

    Summary of the Monetized Benefits, Social Costs, and Net Benefits for the Boiler Area Source Rule in 2014
                                             [Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                                    3% Discount rate                   7% Discount rate
----------------------------------------------------------------------------------------------------------------
                                       Final MACT/GACT Approach: Selected
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\.............  $210 to $520.....................  $190 to $470
Total Social Costs \3\...................  $490.............................  $490
Net Benefits.............................  -$280 to $30.....................  -$300 to -$20
                                           1,100 tons of carbon monoxide
                                           340 tons of HCl
                                           8 tons of HF
                                           90 pounds of mercury
Non-monetized Benefits;..................  320 tons of other metals
                                           < 1 gram of dioxins/furans (TEQ)
                                           Health effects from SO2 exposure
                                           Ecosystem effects
                                           Visibility impairment
----------------------------------------------------------------------------------------------------------------
                                       Proposed MACT Approach: Alternative
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\.............  $200 to $490.....................  $180 to $440
Total Social Costs \3\...................  $850.............................  $850

[[Page 15559]]

 
Net Benefits.............................  -$650 to -$360...................  -$670 to -$410
Non-monetized Benefits...................  1,100 tons of carbon monoxide
                                           340 tons of HCl
                                           8 tons of HF
                                           90 pounds of mercury
                                           320 tons of other metals
                                           <1 gram of dioxins/furans (TEQ)
                                           Health effects from SO2 exposure
                                           Ecosystem effects
                                           Visibility impairment
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2014), and are rounded to two significant figures. These
  results include units anticipated to come online and the lowest cost disposal assumption.
\2\ The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5
  through reductions of directly emitted PM2.5 and PM2.5 precursors such as SO2. It is important to note that
  the monetized benefits include many but not all health effects associated with PM2.5 exposure. Benefits are
  shown as a range from Pope et al. (2002) to Laden et al. (2006). These models assume that all fine particles,
  regardless of their chemical composition, are equally potent in causing premature mortality because there is
  no clear scientific evidence that would support the development of differential effects estimates by particle
  type. These estimates include energy disbenefits valued at less than $1 million.
\3\ The methodology used to estimate social costs for one year in the multimarket model using surplus changes
  results in the same social costs for both discount rates.

III. Summary of This Final Rule

A. Do these standards apply to my source?

    This rule applies to you if you own or operate a boiler combusting 
solid fossil fuels, biomass, or liquid fuels located at an area source. 
The standards do not apply to boilers that are subject to another 
standard under 40 CFR part 63 or to a standard developed under CAA 
section 129.
    This rule applies to you if you own or operate a boiler combusting 
natural gas, located at an area source, which switches to combusting 
solid fossil fuels, biomass, or liquid fuel after June 4, 2010.

B. What is the affected source?

    This final rule affects industrial boilers, institutional boilers, 
and commercial boilers. The affected source is the collection of all 
existing boilers within a subcategory located at an area source 
facility or each new boiler located at an area source facility.

C. When must I comply with these standards?

    The owner or operator of an existing source subject to a work 
practice or management practice standard of a tune-up is required to 
comply with this final rule no later than March 21, 2012. The owner or 
operator of an existing source subject to emission limits or an energy 
assessment requirement is required to comply with this final rule no 
later than March 21, 2014. The owner or operator of a new source is 
required to comply on May 20, 2011 or upon startup of the facility, 
whichever is later. Owners and operators subject to 40 part CFR 60, 
subpart CCCC or subpart DDDD who cease combusting solid waste must be 
in compliance with this subpart on the effective date that the unit 
ceased combusting solid waste, consistent with 40 CFR part 60, subpart 
CCCC or subpart DDDD.

D. What are the MACT and GACT standards?

    Emission standards are in the form of numerical emission limits for 
new and existing area source boilers. The MACT emission limits for 
mercury and CO (as a surrogate for POM) are presented, along with the 
GACT emission limits for PM (as a surrogate for urban metals), in Table 
1 of this preamble. The units are pounds of PM or mercury per million 
British thermal units (lb/MMBtu) and ppm for CO.

                                Table 1--Emission Limits for Area Source Boilers
----------------------------------------------------------------------------------------------------------------
                                   Heat input
          Subcategory               (MMBtu/h)        Pollutants                    Emission limits
----------------------------------------------------------------------------------------------------------------
New coal-fired boiler.........  >=30              a. Particulate    0.03 lb per MMBtu of heat input.
                                                   Matter.
                                                  b. Mercury......  0.0000048 lb per MMBtu of heat input.
                                                  c. Carbon         400 ppm by volume on a dry basis corrected
                                                   Monoxide.         to 3 percent oxygen.
                                >=10 and <30      a. Particulate    0.42 lb per MMBtu of heat input.
                                                   Matter.
                                                  b. Mercury......  0.0000048 lb per MMBtu of heat input.
                                                  c. Carbon         400 ppm by volume on a dry basis corrected
                                                   Monoxide.         to 3 percent oxygen.
New biomass-fired boiler......  >=30              Particulate       0.03 lb per MMBtu of heat input.
                                                   Matter.
                                >=10 and <30      Particulate       0.07 lb per MMBtu of heat input.
                                                   Matter.
New oil-fired boiler..........  >=30              Particulate       0.03 lb per MMBtu of heat input.
                                                   Matter.
                                >=10 and <30      Particulate       0.03 lb per MMBtu of heat input.
                                                   Matter.
Existing coal-Fired boiler....  >=10              a. Mercury......  0.0000048 lb per MMBtu of heat input.

[[Page 15560]]

 
                                                  b. Carbon         400 ppm by volume on a dry basis corrected
                                                   Monoxide.         to 7 percent oxygen.
----------------------------------------------------------------------------------------------------------------

    The emission limits for PM apply only to new boilers. The emission 
limits for mercury and CO apply only to boilers in the coal 
subcategory; the emission limits for existing area source boilers in 
the coal subcategory are applicable only to area source boilers that 
have a designed heat input capacity of 10 million MMBtu/h or greater.
    If your boiler burns any solid fossil fuel and no more than 15 
percent biomass on a total fuel annual heat input basis, the boiler is 
in the coal subcategory. If your boiler burns at least 15 percent 
biomass on a total fuel annual heat input basis, the unit is in the 
biomass subcategory. If your boiler burns any liquid fuel and is not in 
either the coal or the biomass subcategory, the unit is in the oil 
subcategory, except if the unit burns oil only during periods of gas 
curtailment.
    As allowed under CAA section 112(h), a work practice standard is 
being promulgated for new and existing coal-fired area source boilers 
with a designed heat input capacity of less than 10 MMBtu/h. The work 
practice standard for new and existing coal-fired area source boilers 
requires the implementation of a tune-up program. We are also requiring 
all biomass-fired and oil-fired area source boilers to implement a 
tune-up program as a management practice.
    An additional standard is being promulgated for existing area 
source facilities having an affected boiler with a designed heat input 
capacity of 10 MMBtu/h or greater that requires the performance of an 
energy assessment, by qualified personnel, on the boiler and its energy 
use systems to identify cost-effective energy conservation measures.

E. What are the startup, shutdown, and malfunction (SSM) requirements?

    The United States Court of Appeals for the District of Columbia 
Circuit vacated portions of two provisions in EPA's CAA section 112 
regulations governing the emissions of HAP during periods of startup, 
shutdown, and malfunction (SSM). Sierra Club v. EPA, 551 F.3d 1019 (DC 
Cir. 2008), cert. denied, 130 S. Ct. 1735 (U.S. 2010). Specifically, 
the Court vacated the SSM exemption contained in 40 CFR 63.6(f)(1) and 
40 CFR 63.6(h)(1), that are part of a regulation, commonly referred to 
as the ``General Provisions Rule'' (40 CFR 63, subpart A), that EPA 
promulgated under CAA section 112 of the CAA. When incorporated into 
CAA section 112(d) regulations for specific source categories, these 
two provisions exempted sources from the requirement to comply with the 
otherwise applicable CAA section 112(d) emission standard during 
periods of SSM.
    Consistent with Sierra Club v. EPA, EPA has established standards 
in this rule that apply at all times. EPA has attempted to ensure that 
we have not incorporated into the regulatory language any provisions 
that are inappropriate, unnecessary, or redundant in the absence of an 
SSM exemption.
    In establishing the standards in this rule, EPA has taken into 
account startup and shutdown periods and, for the reasons explained 
below, has established different standards for those periods.
    EPA has revised this final rule to require sources to meet a work 
practice standard, including following the manufacturer's recommended 
procedures for minimizing startup and shutdown periods, to demonstrate 
compliance with the emission limits for all subcategories of new and 
existing area source boilers (that would otherwise be subject to 
numeric emission limits) during periods of startup and shutdown. As 
discussed in Section V.G of this preamble, we considered whether 
performance testing, and therefore, enforcement of numeric emission 
limits, would be practicable during periods of startup and shutdown. 
With regards to performance testing, EPA determined that it is not 
technically feasible to complete stack testing--in particular, to 
repeat the multiple required test runs--during periods of startup and 
shutdown due to physical limitations and the short duration of startup 
and shutdown periods. Operating in startup and shutdown mode for 
sufficient time to conduct the required test runs could result in 
higher emissions than would otherwise occur. Based on these specific 
facts for the boilers and process heater source category, EPA has 
developed a separate standard for these periods, and we are finalizing 
work practice standards to meet this requirement. The work practice 
standard requires sources to minimize periods of startup and shutdown 
following the manufacturer's recommended procedures, if available. If 
manufacturer's recommended procedures are not available, sources must 
follow recommended procedures for a unit of similar design for which 
manufacturer's recommended procedures are available.
    Periods of startup, normal operations, and shutdown are all 
predictable and routine aspects of a source's operations. However, by 
contrast, malfunction is defined as a ``sudden, infrequent, and not 
reasonably preventable failure of air pollution control and monitoring 
equipment, process equipment or a process to operate in a normal or 
usual manner * * *'' (40 CFR 63.2). EPA has determined that 
malfunctions should not be viewed as a distinct operating mode and, 
therefore, any emissions that occur at such times do not need to be 
factored into development of CAA section 112(d) standards, which, once 
promulgated, apply at all times. In Mossville Environmental Action Now 
v. EPA, 370 F.3d 1232, 1242 (DC Cir. 2004), the court upheld as 
reasonable standards that had factored in variability of emissions 
under all operating conditions. However, nothing in section 112(d) or 
in case law requires that EPA anticipate and account for the 
innumerable types of potential malfunction events in setting emission 
standards. See, Weyerhaeuser v. Costle, 590 F.2d 1011, 1058 (DC Cir. 
1978) (``In the nature of things, no general limit, individual permit, 
or even any upset provision can anticipate all upset situations. After 
a certain point, the transgression of regulatory limits caused by 
`uncontrollable acts of third parties,' such as strikes, sabotage, 
operator intoxication or insanity, and a variety of other 
eventualities, must be a matter for the administrative exercise of 
case-by-case enforcement discretion, not for specification in advance 
by regulation.'').
    Further, it is reasonable to interpret CAA section 112(d) as not 
requiring EPA to account for malfunctions in setting emissions 
standards. For example, we note that CAA section 112 uses the concept 
of ``best performing'' sources in defining MACT, the level of

[[Page 15561]]

stringency that major source standards must meet. Applying the concept 
of ``best performing'' to a source that is malfunctioning presents 
significant difficulties. The goal of best performing sources is to 
operate in such a way as to avoid malfunctions of their units. 
Similarly, although standards for area sources are generally not 
required to be set based on ``best performers,'' we believe that what 
is ``generally available'' should not be based on periods in which 
there is a ``failure to operate.''
    Moreover, even if malfunctions were considered a distinct operating 
mode, we believe it would be impracticable to take malfunctions into 
account in setting CAA section 112(d) standards for area source 
boilers. As noted above, by definition, malfunctions are sudden and 
unexpected events and it would be difficult to set a standard that 
takes into account the myriad different types of malfunctions that can 
occur across all sources in the category. Moreover, malfunctions can 
vary in frequency, degree, and duration, further complicating standard 
setting.
    In the event that a source fails to comply with the applicable CAA 
section 112(d) standards as a result of a malfunction event (see 40 CFR 
63.2 (definition of malfunction), EPA must determine an appropriate 
response based on, among other things, the good faith efforts of the 
source to minimize emissions during malfunction periods, including 
preventative and corrective actions, as well as root cause analyses to 
ascertain and rectify excess emissions. EPA would also consider whether 
the source's failure to comply with the CAA section 112(d) standard 
was, in fact, ``sudden, infrequent, not reasonably preventable'' and 
was not instead ``caused in part by poor maintenance or careless 
operation.'' (See 40 CFR 63.2 (definition of malfunction).)
    Finally, EPA recognizes that even equipment that is properly 
designed and maintained can sometimes fail and that such failure can 
sometimes cause an exceedance of the relevant emission standard. (See, 
e.g., State Implementation Plans: Policy Regarding Excessive Emissions 
During Malfunctions, Startup, and Shutdown (September 20, 1999); Policy 
on Excess Emissions During Startup, Shutdown, Maintenance, and 
Malfunctions (February 15, 1983)). EPA is therefore adding to this 
final rule an affirmative defense to civil penalties for exceedances of 
emission limits that are caused by malfunctions. (See 40 CFR 63.11226 
(defining ``affirmative defense'' to mean, in the context of an 
enforcement proceeding, a response or defense put forward by a 
defendant, regarding which the defendant has the burden of proof, and 
the merits of which are independently and objectively evaluated in a 
judicial or administrative proceeding).) We also have added other 
regulatory provisions to specify the elements that are necessary to 
establish this affirmative defense; the source must prove by a 
preponderance of the evidence that it has met all of the elements set 
forth in 63.11226. (See 40 CFR 22.24.) The criteria ensure that the 
affirmative defense is available only where the event that causes an 
exceedance of the emission limit meets the narrow definition of 
malfunction in 40 CFR 63.2 (sudden, infrequent, not reasonable 
preventable and not caused by poor maintenance and or careless 
operation). For example, to successfully assert the affirmative 
defense, the source must prove by a preponderance of the evidence that 
excess emissions ``[w]ere caused by a sudden, infrequent, and 
unavoidable failure of air pollution control and monitoring equipment, 
process equipment, or a process to operate in a normal or usual manner 
* * *.'' The criteria also are designed to ensure that steps are taken 
to correct the malfunction, to minimize emissions in accordance with 40 
CFR 63.11205(a), and to prevent future malfunctions. For example, the 
source must prove by a preponderance of the evidence that ``[r]epairs 
were made as expeditiously as possible when the applicable emission 
limitations were being exceeded * * *'' and that ``[a]ll possible steps 
were taken to minimize the impact of the excess emissions on ambient 
air quality, the environment and human health * * *.'' In any judicial 
or administrative proceeding, the Administrator may challenge the 
assertion of the affirmative defense and, if the respondent has not met 
its burden of proving all of the requirements in the affirmative 
defense, appropriate penalties may be assessed in accordance with CAA 
section 113 of the CAA (see also 40 CFR 22.77).

F. What are the initial compliance requirements?

    For new and existing area source boilers with applicable emission 
limits, you must conduct initial performance tests to determine 
compliance with the PM, mercury, and CO emission limits. The 
performance tests to demonstrate compliance with the mercury emission 
limit can be either a stack test, which also requires a fuel analysis, 
or only a fuel analysis.
    As part of the initial compliance demonstration, you must monitor 
specified operating parameters during the initial performance tests 
that demonstrate compliance with the PM, mercury, and CO emission 
limits for area source boilers. The test average establishes your site-
specific operating levels.
    For owners or operators of existing and new coal-fired area source 
boilers having a heat input capacity of less than 10 MMBtu/h and all 
existing and new biomass-fired and oil-fired area source boilers, you 
must submit to the delegated authority or EPA, as appropriate, 
documentation that a tune-up was conducted.
    For owners or operators of existing area source facilities having a 
boiler with a heat input capacity of 10 MMBtu/h or greater and subject 
to this rule, you must submit to the delegated authority or EPA, as 
appropriate, documentation that the energy assessment was performed and 
the cost-effective energy conservation measures identified.

G. What are the continuous compliance requirements?

    If you demonstrate initial compliance with the emission limits by 
performance (stack) tests, then you must conduct stack tests every 3 
years. Furthermore, to demonstrate continuous compliance with the PM, 
CO, and mercury emission limits, you must monitor and comply with the 
applicable site-specific operating limits.
    For area source boilers that must comply with the PM and mercury 
emission limits, you must continuously monitor opacity and maintain the 
opacity at or below 10 percent (daily block average) or:
    1. If the boiler is controlled with a fabric filter, the fabric 
filter may be continuously operated such that the alarm on the bag leak 
detection system does not sound more than 5 percent of the operating 
time during any 6-month period.
    2. If the boiler is controlled with an electrostatic precipitator 
(ESP), you must maintain the minimum voltage and secondary amperage (or 
total power input) of the ESP at or above the minimum operating limits 
established during the performance test.
    3. If the boiler is controlled with a wet scrubber, you must 
monitor pressure drop and liquid flow rate of the scrubber and maintain 
the daily block averages at or above the minimum operating limits 
established during the performance test.
    4. For boilers with sorbent or carbon injection systems which must 
comply with an applicable mercury emission limit, you must maintain the 
daily block averages at or above the minimum sorbent flow rate, as 
calculated according to 40 CFR 63.11221(a)(5).

[[Page 15562]]

    If you elected to demonstrate initial compliance with the mercury 
emission limit by fuel analysis, as determined according to 40 CFR 
63.11211(b), you must conduct a monthly fuel analysis and maintain the 
annual average at or below the limit indicated in Table 1 of this 
preamble.
    For boilers that demonstrate compliance with the PM and mercury 
emission limits by performance (stack) tests, you must maintain monthly 
fuel records that demonstrate that you burned no new fuel type or new 
mixture (monthly average) as set during the performance test. If you 
plan to burn a new fuel type or new mixture that is different from what 
was burned during the initial performance test, then you must conduct a 
new performance test to demonstrate continuous compliance with the PM 
emission limit and mercury emission limit.
    For boilers that must comply with the CO emission limits, you must 
continually monitor oxygen and maintain an oxygen concentration level, 
on a 30-day rolling average basis, at no less than 90 percent of the 
average oxygen concentration measured during the most recent 
performance test.
    Biomass and oil-fired boilers must meet the management practice 
standards defined in Table 2 to 40 CFR part 63, subpart JJJJJJ.

H. What are the notification, recordkeeping and reporting requirements?

    All new and existing sources will be required to comply with some 
requirements of the General Provisions (40 CFR part 63, subpart A), 
which are identified in Table 6 to subpart JJJJJJ. The General 
Provisions include specific requirements for notifications, 
recordkeeping, and reporting. If performance tests are required under 
subpart JJJJJJ, then the notification and reporting requirements for 
performance tests in the General Provisions also apply.
    Each owner or operator is required to submit a notification of 
compliance status report, as required by 40 CFR 63.9(h) of the General 
Provisions. Subpart JJJJJJ rule requires the owner or operator to 
include in the notification of compliance status report certifications 
of compliance with rule requirements.
    If your unit is subject to an emission limit, then you must 
prepare, by March 1 of each year, an annual compliance certification 
report for the previous calendar year 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.
    This rule requires records to demonstrate compliance with each 
emission limit, work practice standard, and management practice. These 
recordkeeping requirements are specified directly in the General 
Provisions to 40 CFR part 63.
    Records for applicable management practices must be maintained. 
Specifically, the owner or operator must keep records of the dates and 
the results of each boiler tune-up.
    Records are required for either continuously monitored parameter 
data for a control device, if a device is used to control the 
emissions, or continuous opacity monitoring system (COMS) data.
    Each owner and operator is required to keep the following records:
    (1) All reports and notifications submitted to comply with this 
final rule;
    (2) Continuous monitoring data as required in this final rule;
    (3) Each instance in which you did not meet each emission limit, 
work/management practice, and operating limit (i.e., deviations from 
this final rule);
    (4) Monthly fuel use by each boiler including a description of the 
type(s) of fuel(s) burned, amount of each fuel type burned, and units 
of measure;
    (5) A copy of the results of all performance tests, energy 
assessments, opacity observations, performance evaluations, or other 
compliance demonstrations conducted to demonstrate initial or 
continuous compliance with this final rule; and
    (6) A copy of your site-specific monitoring plan developed for this 
final rule, if applicable.
    Records must be retained for at least 5 years. In addition, 
monitoring plans, operating and maintenance plans, and other plans must 
be updated as necessary and kept for as long as they are still current.

I. Submission of Emissions Test Results to EPA

    Compliance test data are necessary for many purposes including 
compliance determinations, development of emission factors, and 
determining annual emission rates. EPA has found it burdensome and time 
consuming to collect emission test data because of varied locations for 
data storage and varied data storage methods.
    One improvement that has occurred in recent years is the 
availability of stack test reports in electronic format as a 
replacement for bulky paper copies.
    In this action, we are taking a step to improve data accessibility 
for stack tests (and in the future continuous monitoring data). Boiler 
area sources are required to submit to WebFIRE (an EPA electronic data 
base) an electronic copy of stack test reports as well as process data. 
Data entry requires only access to the Internet and is expected to be 
completed by the stack testing company as part of the work that it is 
contracted to perform.
    Please note that the requirement to submit source test data 
electronically to EPA does not require any additional performance 
testing. In addition, when a facility submits performance test data to 
WebFIRE, there are no additional requirements for data compilation; 
instead, we believe industry will greatly benefit from improved 
emissions factors, fewer information requests, and better regulation 
development as discussed below. Because the information that is being 
reported is already required in the existing test methods and is 
necessary to evaluate the conformance to the test methods, facilities 
are already collecting and compiling these data. The Electronic 
Reporting Tool (ERT) was developed with input from stack testing 
companies, who already collect and compile performance test data 
electronically. One major advantage of submitting source test data 
through ERT is that it provides a standardized method to compile and 
store all the documentation required by subpart JJJJJJ. Another 
important benefit of submitting these data to EPA at the time the 
source test is conducted is that these data should reduce the effort 
involved in data collection activities in the future for these source 
categories. This results in a reduced burden on both affected 
facilities (in terms of reduced manpower to respond to data collection 
requests) and EPA (in terms of preparing and distributing data 
collection requests). Finally, another benefit of submitting these data 
to WebFIRE electronically is that these data will greatly improve the 
overall quality of the existing and new emissions factors by 
supplementing the pool of emissions test data upon which emissions 
factors are based and by ensuring that data are more representative of 
current industry operational procedures. A common complaint we hear 
from industry and regulators is that emissions factors are out-dated or 
not representative of a particular source category. Receiving recent 
performance test results would ensure that emissions factors are 
updated and more accurate. In summary, receiving these test data 
already collected for other purposes and using them in the emissions 
factors development program will save

[[Page 15563]]

industry, state/local/tribal agencies, and EPA time and money.
    As mentioned earlier, the electronic data-base that will be used is 
EPA's WebFIRE, which is a Web site accessible through EPA's TTN 
(technology transfer network). The WebFIRE Web site was constructed to 
store emissions test data for use in developing emission factors. A 
description of the WebFIRE data-base can be found at http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main. The ERT will be able 
to transmit the electronic report through EPA's Central Data Exchange 
(CDX) network for storage in the WebFIRE data base. Although ERT is not 
the only electronic interface that can be used to submit source test 
data to the CDX for entry into WebFIRE, it makes submittal of data very 
straightforward and easy. A description of the ERT can be found at 
http://www.epa.gov/ttn/chief/ert/ert_tool.html.
    The ERT can be used to document the conduct of stack tests for 
various pollutants including PM, mercury, dioxin/furan, and HCl. 
Presently, the ERT does not accept opacity data or CEMS data.

IV. Summary of Significant Changes Following Proposal

A. Changes to Subcategories

    We have redefined the coal, biomass and oil subcategories for area 
source boilers to clarify the fuel-type inputs that would define each 
subcategory. The proposed rule defined the biomass subcategory to 
include any boiler that burns any amount of biomass, either alone or in 
combination with a liquid or gaseous fuel. This definition excluded 
boilers that burned biomass with coal; boilers burning greater than 10 
percent coal on an annual fuel heat input basis were defined under the 
coal-fired subcategory. This final rule defines the biomass subcategory 
to include any boiler that burns at least 15 percent of biomass on an 
annual heat input basis.
    Similarly, the proposed rule defined the oil subcategory to include 
any boiler that burns any liquid fuel either alone or in combination 
with gaseous fuels, and excluded boilers that burned solid fuels. We 
have revised this final rule to define the oil subcategory to include 
any boiler that burns any liquid fuel and is not in either the biomass 
or coal subcategory.
    The coal subcategory in this final rule has been revised to include 
any boiler combusting any solid fossil fuels and no more than 15 
percent biomass. This final rule defines solid fossil fuels to include, 
but not limited to, coal, petroleum coke, and tire derived fuel (TDF).

B. Change From MACT to GACT for Biomass and Oil Subcategories

    The proposed rule set MACT-based emission limits for CO (as a 
surrogate pollutant for the individual urban organic HAP) from new and 
existing biomass-fired and oil-fired boilers. For POM from area source 
boilers classified as biomass-fired or oil-fired, as well as with 
respect to other urban HAP besides POM, we have revised this final rule 
standards to reflect GACT for these two area source subcategories (see 
Section V.D of this preamble). We are implementing management practice 
standards, as allowed by CAA section 112(d)(5), for control of POM from 
new and existing area source boilers in the biomass and oil 
subcategories. The management practice standard requires the 
implementation of a tune-up program.

C. MACT Floor UPL Methodology/Emission Limits

    At proposal, we used a 99 percent UPL calculation to determine 
variability. In this final rule, we have determined that 99 percent UPL 
is appropriate for fuel based HAP and a 99.9 percent UPL is appropriate 
for combustion dependent HAP (i.e., CO). We have modified our 
assumptions when results of the skewness and kurtosis tests result in a 
tie between normal and log-normal calculations, or when there is not 
enough data to complete the skewness and kurtosis tests, to choose the 
log-normal results. We have also revised the UPL calculation to convert 
log-normally distributed data to an arithmetic mean instead of a 
geometric mean. Further, for fuel based HAP (i.e., mercury), we have 
implemented an additional fuel variability factor in the emission 
limits.

D. Clarification of Energy Assessment Requirements

    The proposed rule required owners and operators of existing area 
source boilers with a heat input capacity of 10 MMBtu/h and greater to 
have an energy assessment performed by a qualified professional. The 
proposed rule defined an energy assessment as an ``in-depth assessment 
of a facility to identify immediate and long-term opportunities to save 
energy, focusing on the steam and process heating systems which 
involves a thorough examination of potential savings from energy 
efficiency improvements, waste minimization and pollution prevention, 
and productivity improvement.'' The requirements for the energy 
assessment, defined in Table 3 of the proposed rule, included visually 
inspecting the boiler system, establishing operating characteristics 
and energy system specifications, identifying the boiler's major energy 
consuming systems, listing major energy conservation measures, and a 
comprehensive report detailing the ways to improve efficiency, the cost 
of specific improvements, and the benefits associated with such.
    This final rule requires an energy assessment for all existing 
boilers with a heat input capacity of 10 MMBtu/h or greater, and 
clarifies the definition of energy assessment with respect to the 
requirements of Table 3 of this final rule. The revised definition 
provides a maximum duration for performing the energy assessment and 
defines the evaluation requirements for each boiler system and energy 
use system. These requirements are based on the total annual heat input 
of the affected boilers.
    This final rule requires an energy assessment for facilities with 
affected boilers using less than 0.3 trillion Btu per year heat input 
to be one day in length maximum. The boiler system and energy use 
system accounting for at least 50 percent of the energy output from the 
boilers must be evaluated to identify energy savings opportunities 
within the limit of performing a one-day energy assessment. An energy 
assessment for a facility with affected boilers using 0.3 to 1 TBtu/
year must be three days in length maximum. From these boilers, the 
boiler system and any energy use system accounting for at least 33 
percent of the energy output will be evaluated, within the limit of 
performing a three day energy assessment. For facilities with affected 
boilers using greater than 1 TBtu/year heat input, the energy 
assessment must comprise the boiler system and any energy use system 
accounting for at least 20 percent of the energy output to identify 
energy savings opportunities.
    We have also added a definition for ``energy use systems'' to 
clarify the components, in addition to the boiler system, which must be 
considered during the energy assessment.

E. Revised Subcategory Limits

    The proposed rule set emission limits for PM (as a surrogate for 
the individual urban metal HAP) for all new area source boilers and CO 
(as a surrogate pollutant for the individual urban organic HAP) for all 
new area source boilers and for existing area source boilers with a 
heat input capacity of 10 MMBtu/h or greater. The proposed rule also 
set emission limits for mercury from new and existing coal-fired 
boilers.

[[Page 15564]]

    In this final rule, the emission limits for mercury and CO have 
been revised for existing coal-fired boilers with a heat input capacity 
greater than 10 MMBtu/h. The MACT emission limits for the coal 
subcategory have been revised based on the revised MACT floor approach 
(see Section V of this preamble). Existing boilers in the biomass and 
oil subcategories are not required to meet emission limits for CO in 
this final rule; these units must meet the management practice 
standards of implementing a boiler tune-up program.
    In this final rule, the PM emission limits for new area source 
boilers have been revised based on the size category. For new boilers 
in the coal, biomass, and oil subcategories with a heat input capacity 
less than 10 MMBtu/h, GACT is a management practice of a tune-up. For 
new boilers between 10 and 30 MMBtu/h heat input, the PM limit has been 
revised to reflect the performance of GACT, which is a multiclone. The 
emission limits for mercury and CO have been revised for new coal-fired 
boilers with a heat input capacity greater than 10 MMBtu/h. New boilers 
in the biomass and oil subcategories are not required to meet emission 
limits for CO; these units must meet the management practice standards 
of a tune-up.
    Table 2 of this preamble summarizes the revised emission limits for 
each pollutant for each subcategory.

                                                   Table 2--Revised Emission Limits for Subpart JJJJJJ
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                    Heat input (MMBtu/
           Subcategory                      hr)                Pollutant        Proposed emission limit                Final emission limit
--------------------------------------------------------------------------------------------------------------------------------------------------------
New coal-fired boiler............  >=30                  Particulate Matter..  0.03 lb per MMBtu of      0.03 lb per MMBtu of heat input
                                                                                heat input.
                                                         Mercury.............  0.000003 lb per MMBtu of  0.0000048 lb per MMBtu of heat input
                                                                                heat input.
                                                         Carbon Monoxide.....  310 ppm by volume on a    400 ppm by volume on a dry basis corrected to 3
                                                                                dry basis corrected to    percent oxygen
                                                                                7 percent oxygen
                                   >=10 and <30          Particulate Matter..  0.03 lb per MMBtu of      0.42 lb per MMBtu of heat input
                                                                                heat input
                                                         Mercury.............  0.000003 lb per MMBtu of  0.0000048 lb per MMBtu of heat input
                                                                                heat input.
                                                         Carbon Monoxide.....  310 ppm by volume on a    400 ppm by volume on a dry basis corrected to 3
                                                                                dry basis corrected to    percent oxygen
                                                                                7 percent oxygen
New biomass-fired boiler.........  >=30                  Particulate Matter..  0.03 lb per MMBtu of      0.03 lb per MMBtu of heat input
                                                                                heat input.
                                                         Carbon Monoxide.....  100 ppm by volume on a    Management Practice Standards (see Table 2 to
                                                                                dry basis corrected to    subpart JJJJJJ)
                                                                                7 percent oxygen.
                                   >=10 and <30          Particulate Matter..  0.03 lb per MMBtu of      0.07 lb per MMBtu of heat input
                                                                                heat input.
                                                         Carbon Monoxide.....  100 ppm by volume on a    Management Practice Standards (see Table 2 to
                                                                                dry basis corrected to    subpart JJJJJJ)
                                                                                7 percent oxygen.
New oil-fired boiler.............  >=30                  Particulate Matter..  0.03 lb per MMBtu of      0.03 lb per MMBtu of heat input
                                                                                heat input.
                                                         Carbon Monoxide.....  1 ppm by volume on a dry  Management Practice Standards (see Table 2 to
                                                                                basis corrected to 3      subpart JJJJJJ)
                                                                                percent oxygen.
                                   >=10 and <30          Particulate Matter..  0.03 lb per MMBtu of      0.03 lb per MMBtu of heat input
                                                                                heat input.
                                                         Carbon Monoxide.....  1 ppm by volume on a dry  Management Practice Standards (see Table 2 to
                                                                                basis corrected to 3      subpart JJJJJJ)
                                                                                percent oxygen.
Existing coal-Fired boiler.......  >=10                  Mercury.............  0.000003 lb per MMBtu of  0.0000048 lb per MMBtu of heat input
                                                                                heat input.
                                                         Carbon Monoxide.....  310 ppm by volume on a    400 ppm by volume on a dry basis corrected to 3
                                                                                dry basis corrected to    percent oxygen
                                                                                7 percent oxygen
Existing biomass-fired boiler....                        Carbon Monoxide.....  160 ppm by volume on a    Management Practice Standards (see Table 2 to
                                                                                dry basis corrected to    subpart JJJJJJ)
                                                                                7 percent oxygen
Existing coal-fired boiler.......                        Carbon Monoxide.....  2 ppm by volume on a dry  Management Practice Standards (see Table 2 to
                                                                                basis corrected to 3      subpart JJJJJJ)
                                                                                percent oxygen
--------------------------------------------------------------------------------------------------------------------------------------------------------

F. Demonstrating Compliance

    We have revised the compliance dates for existing affected sources 
according to the applicable provisions for each affected source (e.g., 
work practice standards, emission limits, management practice 
standards, and/or an energy assessment). Under the proposed rule, 
owners and operators of existing sources would have had to comply with 
this final rule within 3 years following March 21, 2011. This final 
rule requires that if you own or operate an existing source subject to 
a work practice or management practice standard of a tune-up, you must 
comply with this final rule no later than March 21, 2012. If you own or 
operate an existing source subject to an emission limit or an energy 
assessment requirement, you must comply with this final rule no later 
than March 21, 2014. Under the proposed rule, the owner or operator of 
a new source would have been required to comply on the date of 
publication of the final rule or upon startup of the facility, which 
ever was later. Because this rule is subject to the Congressional 
Review Act, the owner or operator of a new source is required to comply 
on May 20, 2011 or upon startup of the facility, whichever is later.
    Additionally, we have clarified the compliance requirements for 
commercial and industrial solid waste incineration units subject to 40 
CFR part 60, subpart CCCC or subpart DDDD that cease combusting solid 
waste and become subject to Subpart JJJJJJ. Owners and operators of 
commercial and industrial solid waste incineration units must be in 
compliance with this subpart on the effective date of the waste to fuel 
switch (at least 12 months from the date that the owner or operator 
ceased

[[Page 15565]]

combusting solid waste), if the effective date is after the applicable 
compliance dates discussed above.
    We have also revised the proposed continuous compliance 
requirements to be consistent with changes to the emission limits in 
this final rule, and are no longer requiring CO CEMS for biomass, oil, 
and coal-fired units. For new and existing coal units with a heat input 
capacity greater than 10 MMBtu/h, we are requiring stack testing every 
3 years to demonstrate compliance with the CO emission limits. Because 
boilers in the biomass and oil subcategories are only required to meet 
the management practice standards in Table 2 of 40 CFR part 63, subpart 
JJJJJJ, no testing for CO emissions is required for these units.

G. Affirmative Defense

    We have added provisions to this final rule to include an 
affirmative defense to civil penalties for exceedances of emission 
limits that are caused by malfunctions. Consistent with Sierra Club v. 
EPA, EPA has established standards in this rule that apply at all 
times. However, in response to an action to enforce the standards set 
forth in 40 CFR 63.11201, you may assert an affirmative defense for 
exceedances of such standards that are caused by malfunction, as 
defined at 40 CFR 63.2. (See 40 CFR 63.11226 (defining ``affirmative 
defense'' to mean, in the context of an enforcement proceeding, a 
response or defense put forward by a defendant, regarding which the 
defendant has the burden of proof, and the merits of which are 
independently and objectively evaluated in a judicial or administrative 
proceeding). The included provisions specify the elements that are 
necessary to establish an affirmative defense for periods of 
malfunction, including evidence and notification requirements that must 
be prepared by the source.

H. Technical/Editorial Corrections

    In this final action, we are making a number of technical 
corrections and clarifications to subpart JJJJJJ. These changes improve 
the clarity and procedures for implementing the emission limitations to 
affected sources. We are also clarifying several definitions to help 
affected sources determine their applicability. We have modified some 
of the regulatory language that we proposed based on public comments.
    We made several changes to the initial compliance demonstration 
requirements. We revised 40 CFR 63.11211(a) to clarify that sources 
using a second fuel only for start up, shutdown, and/or transient flame 
stability are still considered to be sources using a single fuel. We 
deleted 40 CFR 63.11210(b) to remove the requirement that boilers with 
a heat input capacity above 100 MMBtu/h are required to demonstrate 
compliance by conducting a performance evaluation of their CO CEMS.
    We made a change to the monitoring requirements in 40 CFR 63.11225 
(40 CFR 63.11224 in the proposed rule). We deleted paragraph (e) to 
remove the requirement that boilers having a heat input capacity of 100 
MMBtu/h and subject to a CO limit install a CO CEMS.
    In response to comments asking for clarification, we have added 
definitions to 40 CFR 63.11237 for ``Annual heat input basis,'' 
``Energy use system,'' ``Hot water heater,'' ``Minimum scrubber 
pressure drop,'' ``Minimum voltage or amperage,'' ``Qualified energy 
assessor,'' and ``Solid fossil fuel.'' We have also revised several 
definitions in that section based on public comments. For example, we 
revised the definition of ``Boiler'' to describe what is meant by the 
term ``controlled flame combustion'' as used in that definition.
    Several of the definitions in 40 CFR 64.11237 were revised to 
clarify the types of equipment to which different standards apply. For 
example, the definition of ``Waste heat boiler'' was revised to remove 
the criteria that 50 percent of total rated heat input capacity had to 
be from supplemental burners. We also revised the definition of 
``Natural gas'' to include gas derived from naturally occurring 
mixtures found in geological formations as long as the principal 
constituent is methane, consistent with the definition provided in 40 
CFR part 60 subpart Db. A definition of propane was also incorporated 
into the definition of natural gas.

V. Significant Area Source Public Comments and Rationale for Changes to 
Proposed Rule

    This section contains a brief summary of major comments and 
responses. EPA received many comments on this subpart covering numerous 
topics. EPA's responses to all comments, including those below, can be 
found in the comment response document for Area Source Industrial, 
Commercial, and Institutional Boilers in the docket.

A. Legal and Applicability Issues

Section 112(c)(6) of the CAA
    Comment: Some commenters stated that EPA misinterpreted the statute 
in using MACT instead of GACT for area sources. These commenters argued 
that the statute allows for setting a standard under CAA section 
112(d)(2) that can be satisfied using the alternative GACT procedure 
specified in CAA section 112(d)(5) to meet the 112(c)(6) requirements.
    Response: We disagree with the comment that the CAA gives EPA 
discretion to promulgate GACT standards pursuant to section 112(d)(5) 
for area source categories required to be regulated under section 
112(c)(6). Section 112(c)(6) of the CAA explicitly requires that 
``sources accounting for not less than 90 per centum of the aggregate 
emissions of each [pollutant specified in this provision] are subject 
to standards under subsection 112(d)(2) or (d)(4) * * *.'' (Emphasis 
added). The plain language of section 112(c)(6) requires that the 
Agency set standards under section 112(d)(2) or (d)(4). There is no 
ambiguity in this language and thus the legislative history cited by 
the commenter is irrelevant. As such, the Agency is appropriately 
setting standards for the sources at issue pursuant to section 
112(d)(2).
    The commenter argues that section 112(d)(5) trumps the very 
specific language in section 112(c)(6). We disagree. Congress 
unambiguously required the Agency to set standards for these 
persistent, bioaccumulative HAP under section 112(d)(2) or (d)(4). Had 
Congress wanted us to permit EPA to issue GACT standards for the 
112(c)(6) HAP, it would have said that EPA could issue standards under 
section 112(d), as it did in section 112(k)(3)(B) of the Act, noting 
that area sources shall be subject to standards issued pursuant to 
``subsection (d) of this section.'' Congress could not have been more 
precise in section 112(c)(6), and we reject the commenter's 
interpretation.
    EPA has consistently maintained that standards under section 
112(d)(2) or (d)(4) are required for the pollutants listed in section 
112(c)(6). In this case, we are setting a section 112(d)(2) MACT 
standard for mercury and CO (as a surrogate for POM) for coal-fired 
area source boilers, which are the 112(c)(6) pollutants that form the 
basis for the listing of the source category at issue here.
    Comment: One commenter argued that EPA did not provide 
justification for its decision that mercury and POM must be regulated 
pursuant to CAA section 112(c)(6) at area source boilers to satisfy the 
requirements that 90 percent of nationwide emissions of these 
pollutants must be reduced. The commenter further stated that the 
proposed rule and supporting documentation provide no rational basis or 
adequate factual justification for the need to regulate area source POM 
or

[[Page 15566]]

mercury emissions to satisfy CAA section 112(c)(6). Specifically, the 
commenter stated that neither the proposed rule nor the MACT floor memo 
provide data that support the proposed determination that 90.3 percent 
of the 1990 emissions inventory for mercury is already subject to 
regulation. In contrast, another commenter said that, once a category 
is listed under CAA section 112(c)(6), the only procedure available to 
EPA for refraining from promulgating a MACT-based standard for the 
category is to remove the category from the CAA section 112(c) list 
through the use of CAA section 112(c)(9), regardless of whether the 
category is needed to meet the 90 percent requirement in CAA section 
112(c)(6).
    Response: The statute does not limit EPA's discretion as to how it 
fulfills its obligations under CAA section 112(c)(6). To the extent 
that the commenters seek to challenge whether EPA has selected 
appropriate categories to meet its obligations under CAA section 
112(c)(6) or whether EPA has met the requirement in CAA section 
112(c)(6) to regulate categories emitting at least 90 percent of the 
specified pollutants (in this case, mercury and POM), such challenges 
should not be reviewed in the context of a review of an individual 
NESHAP. Rather, if review is appropriate, it should be in the context 
of an EPA finding that it has fulfilled its obligations under CAA 
section 112(c)(6), and an accounting by the agency of how it reached 
the 90 percent threshold for each pollutant. Nevertheless, the docket 
for this rulemaking contains a spreadsheet that demonstrates our belief 
that we have met the 90 percent requirement for POM and for mercury 
with this final rule.
    While we are promulgating GACT-based provisions at this time for 
mercury and POM from biomass-fired and oil-fired area source boilers, 
note that we have not removed or ``delisted'' oil-fired and biomass-
fired area source boilers by this action. We are not promulgating MACT-
based regulations at this time because they are unnecessary to meet the 
requirements of CAA section 112(c)(6).
    Comment: Comments received suggested EOM was not appropriate for 
representing POM emissions. The commenters noted a drawback to using 
EOM as a surrogate for POM is the limited amount of data available to 
quantify emissions and the few EOM inventories or emission factors in 
existence. Commenters also stated that EOM includes other extractible 
organics in addition to the PAHs. The commenters suggest that the 
reasonable assumption is that any observed health effects come from the 
PAH fraction and since EOM includes compounds other than PAH, it should 
not be used as a surrogate for POM.
    Response: This issue primarily affects whether biomass-fired and 
oil-fired boilers are needed to meet the CAA section 112(c)(6) 
requirements. EPA has considered commenter input and revised the final 
rule based on our re-examination of our section 112(c)(6) baseline 
inventory for POM. As we noted in the proposed rule, we reexamine the 
inventory associated with the original listing as we learn more about 
the source category in the rule development process (75 FR 31904). 
Based on a re-examination of the emission inventory in light of 
comments, we have determined that we only need to address the coal-
fired portion of the area source segments of these categories under CAA 
section 112(c)(6) in order to meet the 90 percent threshold requirement 
of that provision for both mercury and POM.
    As discussed in the preamble to the June 2010 proposed rule (75 FR 
31896), we have determined that we must regulate mercury and POM from 
coal-fired area source boilers in order to meet the requirements in CAA 
section 112(c)(6), and we are establishing MACT-based limits for 
mercury and POM (using CO as a surrogate) for this subcategory. We are 
implementing work practice standards, as allowed by CAA section 112(h), 
for control of mercury and POM from new and existing area source 
boilers in the coal subcategory with a designed heat input capacity 
less than 10 MMBtu/h.
    In the CAA section 112(c)(6) source listing, we used three 
indicators (7-PAH, 16-PAH, and extractable organic matter (EOM)) to 
represent POM emissions and compiled three separate baseline 
inventories for POM, one for each indicators. In light of the comment 
described above regarding EOM, we re-examined our three section 
112(c)(6) baseline inventories for POM. For the reason stated below, we 
have decided to use only the baseline inventory for 16-PAH in 
determining the 90 percent threshold under section 112(c)(6).
    We agree with the commenters who have identified data gaps in our 
knowledge of what source categories are emitting EOM. While we have 
data on 16-PAH emissions for 94 categories, we only have available data 
on EOM emissions for 18 source categories. The lack of available data 
on EOM emission creates a distorted picture of the relative 
contributions of source categories for which there are available EOM 
data. The lack of source categories making up the total EOM inventory 
makes the relative contribution of the few categories that do have data 
unrealistically inflated.\2\ We therefore cannot say with confidence 
that by using the baseline inventory for EOM we are capturing 90 
percent of the baseline POM emissions, as required by section 
112(c)(6). Similarly, we have data on 7-PAH for 32 categories, 
considerably fewer than the 94 categories for which we have 16-PAH 
data. Because the 16-PAH inventory allows for the most accurate 
representation of the universe of categories that emit POM, we have 
decided to use that baseline inventory for determining the 90 percent 
threshold for POM under section 112(c)(6). Based on the baseline 
inventory for 16-PAH, regulating POM emissions from area source biomass 
and oil boilers are not needed to meet the CAA section 112(c)(6) 
obligations. Thus, POM emissions from area source boilers in the 
biomass and oil subcategories can be regulated under GACT, instead of 
MACT.
---------------------------------------------------------------------------

    \2\ When justifying its use in the 1998 inventory, we said that 
EPA would undertake an effort to develop a robust inventory for EOM 
sources to feed into the CAA section 112(c)(6) inventory. Had more 
data been gathered, perhaps EOM would have proved to be a more 
useful indicator of POM. However, the anticipated inventory was not 
developed.
---------------------------------------------------------------------------

    With respect to mercury and POM from area source boilers classified 
as biomass-fired or oil-fired, as well as with respect to other urban 
HAP besides POM, we have revised the final rule standards to reflect 
GACT for these two area source subcategories (see Section IV.B of this 
preamble). We are implementing management practice standards, as 
allowed by CAA section 112(d)(5), for control of POM from new and 
existing area source boilers in the biomass and oil subcategories. The 
management practice standard for new and existing area source boilers 
requires the implementation of a tune-up program.
    As stated previously in the preamble to the June 2010 proposed 
rule, we determined that the control technologies currently used by 
facilities in the source category to reduce non-mercury metallic HAP 
and PM (multiclone, fabric filters, and ESP) are generally available 
and cost effective for new area source boilers. Additionally, these 
controls are commonly required by state and other federal regulations 
that apply to the area source boilers in the source category. 
Therefore, we are establishing numeric emission limits representing 
GACT for all new area source boilers with a heat

[[Page 15567]]

input capacity greater than 10 MMBtu/h (using PM as a surrogate).
Emission Standards for HAP Other Than Mercury
    Comment: One commenter stated that CAA section 112(c)(6) provides 
that EPA must ``list categories and subcategories of sources assuring 
that sources accounting for not less than 90 percent of each 
[enumerated] pollutant are subject to standards under subsection (d)(2) 
or (d)(4) of this section.'' The commenter also stated that the DC 
Circuit has held repeatedly that when EPA sets standards for a category 
or subcategory of sources under section 112(d)(2), EPA has a statutory 
duty to set emission standards for each HAP that the sources in that 
category or subcategory emit. The commenter concluded that when EPA 
sets standards for area source boilers under section 112(d)(2), as 
section 112(c)(6) requires it to do, EPA must set section 112(d)(2) 
emission standards for all the HAP that area source boilers emit.
    The commenter said that EPA appears to believe that because area 
source boilers are needed only to reach the section 112(c)(6) 
requirement of 90 percent for mercury and POM and not for the other 
pollutants enumerated in section 112(c)(6), EPA's only obligation under 
section 112(c)(6) is to set section 112(d)(2) standards for mercury and 
POM. The commenter said that section 112(c)(6) expressly requires EPA 
to issue section 112(d)(2) standards for the ``sources'' in the 
categories listed under section 112(c)(6), not some subset of the 
pollutants that those sources emit, and that section 112(d)(2) 
standards must include emission standards for each HAP that a source 
category emits. The commenter continued by stating that nothing in the 
CAA exempts EPA from this requirement. The commenter concluded that, 
had Congress wished to give EPA discretion to set standards for only 
some of the pollutants emitted by a category listed under section 
112(c)(6), it would have done so expressly.
    Response: EPA disagrees with the comment that, even though EPA 
lists a category under section 112(c)(6) due to the emissions of one or 
more HAP specified in that section, EPA must issue emission standards 
for all HAP (including HAP not listed in section 112(c)(6)) that 
sources in that category emit. The commenter cited in support the 
opinion by the United States Court of Appeals for the DC Circuit in 
National Lime Ass'n v. EPA, 233 F.3d 625, 633-634 (DC Cir. 2000)). The 
part of the National Lime opinion referenced in the comment dealt with 
EPA's failure to set emission standards for certain HAP emitted by 
major sources of cement manufacturing because the Agency found no 
sources using control technologies for those HAP. In rejecting EPA's 
argument, the court stated that EPA has ``a statutory obligation to set 
emission standards for each listed HAP.'' Id. at 634. The Court noted 
the list of HAP in section 112(b) and stated that section 112(d)(1) 
requires that EPA ``promulgate regulations establishing emission 
standards for each category or subcategory of major sources * * * of 
hazardous air pollutants listed for regulation * * *'' Id. (Emphasis 
added). For the reasons stated below, we do not believe that today's 
final rule is controlled by or otherwise conflicts with the National 
Lime decision.
    National Lime did not involve section 112(c)(6). That provision is 
ambiguous as to whether standards for listed source categories must 
address all HAP or only the section 112(c)(6) HAP for which the source 
category was listed. Section 112(c)(6) requires that ``sources 
accounting for not less than 90 per centum of the aggregate emissions 
of each such [specific] pollutant are subject to standards under 
subsection (d)(2) or (d)(4).'' This language can reasonably be read to 
mean standards for the section 112(c)(6) HAP or standards for all HAP 
emitted by the source. Under either reading, the source would be 
subject to a section 112(d)(2) or (d)(4) standard.
    The commenter insists that once a section 112(d)(2) standard comes 
into play, all HAP must be controlled (per National Lime). But this 
result is not compelled by the pertinent provision, section 112(c)(6). 
That provision is obviously intended to ensure controls for specific 
persistent, bioaccumulative HAP, and this purpose is served by a 
reading which compels regulation under section 112(d)(2) only of the 
HAP for which a source category is listed under section 112(c)(6), 
rather than for all HAP.
    The facts here support the reasonableness of EPA's approach. Area 
source boilers are included in source categories listed under section 
112(c)(6) for regulation under section 112(d)(2) solely due to its 
mercury and POM emissions. There is special statutory sensitivity to 
regulation of area source categories in section 112. For example, an 
area source category may be listed for regulation under section 112 if 
EPA makes an adverse effects finding pursuant to Section 112(c)(3) or 
if EPA determines that the area source category is needed to meet its 
section 112(c)(3) obligations to regulate urban HAP or its section 
112(c)(6) obligations to regulate certain persistent bioaccumulative 
HAP. Moreover, to the extent EPA lists an area source category pursuant 
to section 112(c)(3) (whether that finding is based on adverse effects 
to human health or the environment or a finding that the source is 
needed to meet the 90 percent requirement in section 112(c)(3)), the 
statute gives EPA discretion to set GACT standards for such sources (42 
U.S.C. 7412(d)(5)).
    EPA does not interpret section 112 (c)(6) to create a means of 
automatically compelling regulation of all HAP emitted by area sources 
unrelated to the core object of section 112(c)(6), which is control of 
the specific persistent, bioaccumulative HAP, and thereby bypassing 
these otherwise applicable preconditions to setting section 112(d) 
standards for area sources. Nor does National Lime address the issue, 
since the case dealt exclusively with major sources (233 F. 3d at 633). 
Consequently, EPA disagrees with the comment that it is compelled to 
promulgate section 112(d)(2) MACT standards for all HAP emitted by area 
source boilers.
Beyond-the-Floor Option
    We are promulgating the proposed standard requiring the performance 
of an energy assessment for existing area source facilities having an 
affected boiler with a designed heat input capacity of 10 MMBtu/h or 
greater. This final rule requires the performance of an energy 
assessment, by qualified personnel, on the boiler and its energy use 
systems to identify cost-effective energy conservation measures. As 
discussed in the June 2010 proposed rule, an energy assessment provides 
valuable information on improving energy efficiency. Owners and 
operators are encouraged, but not required, to use the results of the 
energy assessment to increase the energy-efficiency and cost-efficiency 
of their boiler system.
    In the proposed rule, the energy assessment requirement was a 
beyond-the-floor option for the MACT-based mercury and CO emission 
standards because additional emission reductions would be realized as 
the results of these energy assessments, if implemented. In this final 
rule, the energy assessment requirement is both a beyond-the-floor 
control for the MACT-based standards for the coal subcategory and a 
GACT for the biomass and oil subcategory because energy assessments are 
generally available and have already been performed at numerous 
facilities.
    The principal arguments against an energy assessment requirement 
are: (1) EPA lacks authority to impose requirements on portions of the 
source that are not designated as part of the

[[Page 15568]]

affected source, such as non-emitting energy using systems at a 
facility; (2) EPA has not quantified the reductions associated with the 
energy assessment requirement, therefore it cannot be ``beyond the 
floor;'' and (3) the bare requirement to perform an audit without being 
required to implement its findings is not a standard under CAA section 
112(d).
    With respect to the first argument, we have carefully limited the 
requirement to perform an energy assessment to specific portions of the 
source that directly affect emissions from the affected boiler, as 
indicated by the revised definition of an energy assessment in section 
63.11237 of subpart JJJJJJ. The emissions that are being controlled 
come from the affected source. For coal-fired units, the process 
changes resulting from a change in an energy using system will reduce 
the volume of emissions at the affected source. For biomass-fired and 
oil-fired area sources, better management practices at energy using 
systems will reduce the emissions of HAP from the affected source by 
reducing fuel consumption and the HAP released through combustion of 
fuel. In either case, the requirement controls the emissions of the 
affected source.
    With respect to the second argument, the energy assessment will 
generate emission reductions through the reduction in fuel use beyond 
those required by the floor. While the precise quantity of emission 
reductions will vary from source to source and cannot be precisely 
estimated, the requirement is clearly directionally sound and thus 
consistent with the requirement to examine beyond the floor controls. 
By definition, any emission reduction would be cost effective or else 
it would not be implemented.
    Finally, with respect to the third argument, the requirement to 
perform the energy audit is, of course, a requirement that can be 
enforced and thus a standard. As noted, while we do not know the 
precise reductions that will occur at individual sources, the record 
indicates that energy assessments reduce fuel consumption and that 
parties will implement recommendations from an auditor that they 
believe are prudent.\3\ Therefore, the requirement to perform an energy 
assessment can both be enforced and will result in emission reductions.
---------------------------------------------------------------------------

    \3\ Case studies and success stories highlighting energy savings 
achieved by companies that have participated in Save Energy Now 
energy assessments and used Industrial Technologies Program software 
tools to improve energy efficiency can be found at http://www1.eere.energy.gov/industry/saveenergynow/case_studies.html and 
at the Department of Energy's Energy Assessment Centers Database 
http://iac.rutgers.edu/database.
---------------------------------------------------------------------------

Section 112(h) of the CAA
    Comment: Commenters stated that setting work practice standards in 
lieu of emission standards for area source boilers with a heat input 
capacity less than 10 MMBtu/h is unlawful and arbitrary. Commenters 
cited EPA's determination with respect to the technical and economic 
limitations on the enforcement of emission standards for boilers with 
heat input capacity less than 10 MMBtu/h, and stated that these 
limitations do not satisfy CAA section 112(h) conditions for setting 
work practice standards in lieu of emission standards. Some commenters 
argued that the technical limitations of measuring PM using Method 5, 
as discussed in the preamble to the proposed June 2010 rule, do not 
apply to mercury and CO. Other commenters remarked that the absence of 
sampling ports and stacks at area source boilers does not provide a 
basis for a technical or economic limitation, stating that sources are 
able to work around this issue. Multiple commenters said that the lack 
of measuring ports (which can affect retrofitting new boiler 
installations into existing buildings), other design requirements for 
efficient exhaust from smaller boilers, and the inapplicability of 
approved test methods would make measurement technically and 
economically impractical for both existing and new sources. Commenters 
specifically cited CAA section 112(h)(1) and (2), which allows the 
agency to prescribe work practice standards only if it is ``not 
feasible to prescribe or enforce an emission standard * * * due to 
technological or economic limitations.''
    Response: EPA disagrees with commenters. As discussed in the 
preamble to the June 2010 proposed rule, CAA section 112(h) authorizes 
the Administrator to promulgate ``a design, equipment, work practice, 
or operational standard, or combination thereof,'' consistent with the 
provisions of CAA sections 112(d) or (f), in those cases where, in the 
judgment of the Administrator, it is not feasible to prescribe or 
enforce an emission standard. CAA section 112(h)(2)(B) further defines 
the term ``not feasible'' to mean when ``the application of measurement 
technology to a particular class of sources is not practicable due to 
technological and economic limitations.'' We have elected to implement 
work practice standards for coal-fired boilers with a heat input 
capacity of less than 10 MMBtu/h because we have determined that the 
standard reference methods for measuring emissions of mercury, CO (as a 
surrogate for POM), and PM (as a surrogate for urban non-mercury 
metals) are not applicable for sampling small diameter (less than 12 
inches) stacks. Furthermore, through the comment process, we have 
learned that common, very small boilers (less than 5 MMBtu/h) typically 
exhaust through vents and not stacks, and that the installation of 
ports into small diameter vents for smaller boilers would likely 
interfere with the functionality of exhaust systems for new and 
existing boilers. Because many existing area source boilers with a 
capacity below 10 MMBtu/h generally have stacks with diameters less 
than 12 inches, and because many area source boilers do not currently 
have sampling ports or a platform for accessing the exhaust stack, we 
have determined that the testing and monitoring costs that area source 
boiler facilities would incur to demonstrate compliance with the 
proposed emission limits would present an excessive burden for smaller 
sources. Thus, we are establishing work practice standards to limit the 
emissions of mercury and CO (as a surrogate for POM) for existing and 
new coal-fired area source boilers having a heat input capacity of less 
than 10 MMBTU/h.
De minimis Levels
    Comment: Several commenters stated that EPA should establish a de 
minimis heat input level (less than 1 MMBtu/h heat input capacity) 
below which area sources are not subject to regulation or only subject 
to work practice standards. These commenters referenced water heaters 
and small comfort heating units that are not used in industrial, 
commercial, or institutional processes but instead used to provide hot 
water for personal use or seasonal comfort heating. Other commenters 
noted that State rules that require work practice requirements for 
boilers all have a lower limit on applicability of typically 1 to 5 
MMBtu/h; these commenters stated that EPA has provided no basis for 
applying work practice standards to boilers of this size.
    Response: EPA must establish standards for each category or 
subcategory of major sources and area sources of HAP listed pursuant to 
CAA section 112(c). EPA may distinguish among classes, types, and size 
in establishing such standards but the standards established must be 
applicable to new and existing sources of HAP within the category. 
However, we agree with the commenters that the categories of boiler 
covered by this rule are industrial boilers, commercial

[[Page 15569]]

boilers, and institutional boilers. In the proposed rule, we did not 
list hot water heaters as exempted as we did in the proposed Boiler 
MACT for major sources. As stated in the preamble to the proposed 
Boiler MACT, hot water heaters meet the definition of a boiler but are 
more appropriately described as residential-type boilers, not 
industrial, commercial, or institutional boilers because their output 
is intended for personal use rather than for use in an industrial, 
commercial, or institutional process. The primary reason for exempting 
hot water heaters in the Boiler MACT was that hot water heaters are not 
part of the listed source category. Because hot water heaters generally 
use natural gas and gas-fired boilers were not part of the area source 
category, we did not include a similar exemption in the proposed rule. 
To be consistent with the Boiler MACT, we have included in this final 
rule a similar exemption and definition for hot water heaters.

B. CO Limits

    Comment: Multiple commenters argued that EPA's determination of 
using CO as a surrogate for POM is inappropriate. Several of these 
commenters reiterated that there is no reliable correlation between CO 
and POM. Some commenters stated that CO is not an appropriate surrogate 
for POM or organic HAP at lower CO emission levels. For instance, one 
commenter stated that while there is a linear correlation between 
decreasing CO and decreasing HAP at higher levels, once CO values fall 
under 100 ppm, further reduction of CO does not provide any substantial 
correlating reduction of HAP. Other commenters stated that CO is an 
inadequate surrogate for POM because there is no POM invariably present 
in CO; likewise, commenters stated that because CO and POM have 
different mechanisms of formation and reduction, CO cannot be 
considered as a reliable surrogate.
    Several commenters suggested total hydrocarbon (THC) as a better 
surrogate, stating that THC levels are often more stable and less 
reactive to load swings than CO. Commenters noted that THC has been 
used as a surrogate for organic HAP emissions in other regulatory 
efforts, including the hazardous waste incinerator MACT.
    Response: EPA acknowledges commenters' concerns. Based on new data 
received during the public comment period, we have re-examined our 
analysis and revised the final standards for CO. As previously 
discussed, this final rule only establishes CO emission limits for 
coal-fired boilers pursuant to CAA section 112(c)(6). We are 
implementing management practice standards, as allowed by CAA section 
112(d)(5), for control of CO from new and existing area source boilers 
in the biomass and oil subcategories. Additionally, for the coal 
subcategory, we have revised the final CO emission limits to ensure a 
more accurate correlation between POM and CO levels. EPA is aware of 
one European study \4\ that finds the correlation between CO and POM 
(or organic HAP, in general) is weaker at lower CO concentrations (less 
than 100 ppmv) but we did not have the opportunity to examine the data 
relied on by the study and no data supporting this supposition were 
submitted as part of the public comments. We have revised the final 
standards (400 ppm) based on 99.9 percent UPL as discussed in Section 
IV.C of this preamble. EPA believes that CO is a reliable surrogate for 
POM at this emission level. EPA considered using THC as a surrogate for 
POM, however, we did not have available THC data for area sources.
---------------------------------------------------------------------------

    \4\ European Wood-Heating Technology Survey: An Overview of 
Combustion Principles and the Energy and Emissions Performance 
Characteristics of Commercially Available Systems in Austria, 
Germany, Denmark, Norway, and Sweden; Final Report; Prepared for the 
New York State Energy Research and Development Authority; NYSERDA 
Report 10-01; April 2010.
---------------------------------------------------------------------------

    Comment: Several commenters expressed concern with respect to the 
proposed CO limits. Some commenters stated that the proposed CO limits 
are unachievable for some units, including liquid-fired boilers. 
Commenters further stated that meeting the CO limits would be more 
burdensome for area sources than major sources. Specifically, many 
commenters argued that the CO limits are unfeasible from a measurement, 
operability, and cost standpoint, particularly when considered 
simultaneously with other limits (NOX, VOC). Some commenters 
expressed concern that prioritizing CO reduction may promote boiler 
inefficiency and result in higher emissions of NOX.
    Other commenters suggested that the CO emission limits should be 
determined using long-term CEMS data to account for natural variability 
in CO emissions. Commenters also offered alternatives for control of 
POM. One commenter suggested that EPA consider cleaner fuels or end of 
stack technologies for control, such as fabric filters and scrubbers 
that capture POM and POM-precursors.
    Response: As discussed above, this final rule establishes MACT-
based emission limits for CO only for new and existing coal-fired 
boilers. In this final rule, area source boilers in the biomass and 
oil-fired subcategories are not required to meet CO emission limits; 
these boilers are instead required to meet the management practice 
standard which consists of a tune-up. The MACT-based CO emission limits 
are still required for coal-fired area source boilers in order to meet 
our obligation under CAA section 112(c)(6). Based on the available CO 
data and the revised UPL calculation methodology, the final CO emission 
limits for coal-fired area source boilers are higher than the proposed 
limits which should provide more assurance that the limit can be 
achieved at all times. EPA notes that the available dataset did not 
include sufficient long-term CEMS data for area sources to be used to 
set a limit. Therefore, we have established the CO standards based on 
the data provided using the revised UPL methodology to account for 
variability over the operating cycle of typical industrial, commercial, 
and institutional boilers. We also considered other appropriate control 
options for sources in each subcategory, including switching to clean 
fuels and end of stack technologies. We considered whether fuel 
switching could be technically achieved by boilers in the subcategory 
considering the existing design of boilers and the availability of 
various types of fuel. We determined that fuel switching was not an 
appropriate control technology based on the overall effect of fuel 
switching on HAP emissions and the technical and design considerations 
discussed previously in the preamble to the proposed June 2010 rule (75 
FR 31896). This determination is discussed in the memorandum 
``Development of Fuel Switching Costs and Emission Reductions for 
Industrial, Commercial, and Institutional Boilers and Process Heaters 
National Emission Standards for Hazardous Air Pollutants--Area Source'' 
located in the docket. Additionally, EPA did not identify add-on 
control technologies available for control of CO in use at area source 
boilers.
C. MACT Floor Analysis
Pollutant-by-Pollutant Approach
    Comment: Several commenters argued that the pollutant-by-pollutant 
approach used by EPA is not appropriate. Commenters rejected the 
pollutant-by-pollutant approach on the basis that both PM and CO 
emission limits are not achievable even for the best performing 
sources. These commenters argued that because the proposed area source 
MACT standards rely on a different set of best performing sources for 
each separate HAP standard, no single source is in the

[[Page 15570]]

population of units for both the PM and CO emission limits, and 
therefore, the approach does not reflect the performance of the best 
performing boilers. Rather, commenters asserted that the proposed 
limits were unrealistic, unnecessarily stringent, and unachievable. 
Commenters further stated that the provisions of CAA sections 
112(d)(1), (2), and (3) of the CAA require that standards must be based 
on actual sources, and cannot be the product of pollutant-by-pollutant 
``cherry-picking.'' Commenters stated that EPA does not have the 
authority to ``distinguish'' units and sources by individual pollutant. 
Other commenters stated that EPA must set limits for each HAP that the 
sources in the subcategory emit, and not solely mercury or POM. These 
commenters stated that to ignore the emitted HAP violates the CAA and 
the court order.
    Response: EPA is mindful that MACT floors must reflect achieved 
performance. EPA is also mindful that that costs cannot be considered 
by EPA in ascertaining the level of the MACT floor. See, e.g., Brick 
MACT, 479 F. 3d at 880-81, 882-83; NRDC v. EPA, 489 F. 3d 1364, 1376 
(DC Cir. 2007) (``Plywood MACT''); see also Cement Kiln Recycling 
Coalition v. EPA, 255 F. 3d 855, 861-62 (DC Cir. 2001) 
(``achievability'' requirement of CAA section 112(d)(2) cannot override 
the requirement that floors be calculated on the basis of what best 
performers actually achieved).
    EPA has carefully developed data for each standard, assessing both 
technological controls and HAP inputs in doing so. The MACT floor 
variability methodology is discussed in a later response.
    Among all boilers at area sources, only new and existing coal-fired 
ones will need to meet MACT-based limits. Nevertheless, it is true that 
at least some coal-fired area source boilers will need to install 
controls to meet these standards, and that these controls have 
significant costs. This is part of the expected MACT process where, by 
definition, the averaged performance of the very best performers sets 
the minimum level of the standard. The Agency believes that it has 
followed the statute and applicable case law in developing its floor 
methodology. Although industry commenters maintain these sources cannot 
meet the standards, which are predicated on their own performance 
without adding controls, this contention lacks a basis in the record. 
For mercury, 6 of the 7 boilers for which EPA has emissions data are 
meeting the MACT floor standards for mercury. For CO, 13 of the 16 
boilers in the MACT pool meet the promulgated standard. In those 
instances where commenters provided actual data on these plants' 
performance, EPA took the information into account in developing the 
final standards. Indeed, EPA adjusted all of the standards based on 
actual data presented. We have emissions data on a limited number of 
area source units. The available information does indicate that at 
least one unit meets both the final PM and CO emission limits.
Dataset for the MACT Floor Analysis
    Comment: Commenters stated numerous objections to the dataset used 
for the MACT floor analysis. Some commenters stated that it is 
inappropriate to apply limits from data submitted as part of the major 
source industrial boiler MACT ICR to area sources. Commenters objected 
to EPA's assertion that boilers at area sources are similar in size and 
operation to major source boilers; one commenter noted that EPA did not 
use test data from area source facilities to set major source floors.
    Other commenters stated that the emission limits are significantly 
flawed because they are based on inadequate data and not representative 
of the units in the source category. These commenters stated that the 
data collected is insufficient because it represents the performance of 
less than 1 percent of almost 183,000 existing area source boilers, 
particularly given that EPA based the analysis on the top 12 percent of 
units for which data were available. Commenters further stated that 
there was insufficient data available to establish appropriate boiler-
type subcategories.
    Some commenters expressed that EPA must include emissions data 
collected by state and local permitting authorities in establishing the 
MACT floor; these commenters stated that these data are more objective 
than the newer industry testing and are also necessary to fill in 
``gaps'' in the existing data. Other commenters requested that certain 
data should be excluded from the MACT floor analysis. For instance, 
some commenters stated that non-detect data should be excluded or that 
the analysis should be adjusted to account for the capabilities of the 
test methods. These commenters stated that the non-detect data results 
in an unreasonably low MACT floor; some commenters stated that the 
proposed limits are in some cases below the detection capability of the 
required test method. Commenters also stated that EPA has not justified 
using three times the detection level in its analysis. These commenters 
stated that this method biases the results towards higher HAP 
emissions, results in a hypothetical standard that is unrealistic and 
not determined as required by statute.
    Response: EPA acknowledges commenters' concerns. As mentioned 
elsewhere in this preamble, EPA is required to establish MACT floor 
levels using existing emissions information. For all data sets, the 
final emission limits are based on the available data and EPA's 
assessment of variability. Since proposal we have received updated data 
on certain boilers and used that data to revise our emission estimates 
from the best performing sources. We re-evaluated the information 
available for the area source category and revised the proposed MACT-
based CO emission limits such that they only apply to boilers in the 
coal subcategory. As discussed above, based on information received 
during the public comment period, we determined that regulating POM 
emissions from area source biomass and oil boilers is not needed to 
meet our CAA section 112(c)(6) obligations; we only need to regulate 
coal-fired area source boilers under section 112(d)2) to meet the 90 
percent requirement set forth in CAA section 112(c)(6) for POM. The 
emissions limits for CO for coal-fired boilers were based on the 
available information from the ICR and state operating permits, as well 
as that received in comments.
    EPA disagrees with commenters who stated that we excluded emissions 
data collected by state and local permitting authorities in 
establishing the MACT floor. The available state permits obtained for 
coal-fired area source boilers limiting CO emissions were for 11 units 
located in Ohio (3 units), and Illinois (8 units). We also obtained CO 
emission data from five coal-fired area source boilers as part of the 
information collection effort for the major source NESHAP. Even though 
the latter data were gathered in the course of collecting data on major 
sources, the emission data on these five boilers is from emission 
sources in the area source coal-fired boiler subcategory.
    With respect to non-detect data, EPA considered and accounted for 
non-detect data when conducting the MACT analysis for mercury for 
existing and new coal-fired boilers in this final rule. EPA developed a 
methodology to account for the imprecision introduced by incorporating 
non-detect data into the MACT floor calculation. At very low emission 
levels where emissions tests result in non-detect values, the inherent 
imprecision in the pollutant measurement method has a large influence 
on the reliability of the data

[[Page 15571]]

underlying the MACT floor emission limit. Because of sample and 
emission matrix effects, laboratory techniques, sample size, and other 
factors, method detection levels normally vary from test to test for 
any specific test method and pollutant measurement. The confidence 
level that a value, measured at the detection level is greater than 
zero, is about 99 percent. The expected measurement imprecision for an 
emissions value occurring at or near the method detection level is 
about 40 to 50 percent. Pollutant measurement imprecision decreases to 
a consistent level of 10 to 15 percent for values measured at a level 
about three times the method detection level.\5\
---------------------------------------------------------------------------

    \5\ American Society of Mechanical Engineers, Reference Method 
Accuracy and Precision (ReMAP): Phase 1, Precision of Manual Stack 
Emission Measurements, CRTD Vol. 60, February 2001.
---------------------------------------------------------------------------

    One approach that we believe can be applied to account for 
measurement variability in this situation starts with defining a method 
detection level that is representative of the data used in the data 
pool. The first step in this approach would be to identify the highest 
test-specific method detection level reported in a data set that is 
also equal to or less than the average emission calculated for the data 
set. This approach has the advantage of relying on the data collected 
to develop the MACT floor emission limit, while to some degree, 
minimizing the effect of a test(s) with an inordinately high method 
detection level (e.g., the sample volume was too small, the laboratory 
technique was insufficiently sensitive or the procedure for determining 
the detection level was other than that specified).
    The second step is to determine the value equal to three times the 
representative method detection level and compare it to the calculated 
MACT floor emission limit. If three times the representative method 
detection level were less than the calculated MACT floor emission 
limit, we would conclude that measurement variability is adequately 
addressed, and we would not adjust the calculated MACT floor emission 
limit. If, on the other hand, the value equal to three times the 
representative method detection level were greater than the calculated 
MACT floor emission limit, we would conclude that the calculated MACT 
floor emission limit does not account entirely for measurement 
variability. Therefore, we revised the approach we used for the 
proposal and, for the final rule, we used the value equal to 3 times 
the method detection level in place of the calculated MACT floor 
emission limit to ensure that the MACT floor emission limit for mercury 
accounts for measurement variability and imprecision.
Variability
    Comment: Numerous commenters stated that the floor methodology used 
by EPA is unlawful. Some commenters criticized EPA's application of the 
UPL to all the test results for all sources in the top twelve percent. 
These commenters stated that while EPA can consider variability in 
estimating an individual source's performance over time, it cannot 
account for differences in performance between sources. Specifically, 
these commenters stated that EPA may only account for differences in 
performance between sources except as CAA section 112(d)(3) provides, 
by averaging the emission levels achieved by the sources in the top 12 
percent. Commenters stated that the UPL is not equivalent to the 
``average'' emission level. For instance, some commenters stated that 
the methodology for the mercury and CO emission limits for new coal 
fired units does not reflect the emission levels achieved by the single 
best performing source; these commenters stated that the proposed 
method results in higher emission levels for new sources than the 
average level of the best 12 percent.
    Commenters further stated that EPA erred by relying on the 99 
percent UPL only to reflect variability. Some commenters stated that 
EPA must collect and consider data on additional variability, such as 
that related to variable fuel quality or longer term variability, to 
supplement its analysis. These commenters stated that the short-term 
test data are not representative of long-term operation of a unit nor 
are they likely to reflect the ``worst reasonably foreseeable 
circumstances'' a unit may experience. Other commenters stated that EPA 
should use the upper tolerance limit (UTL) in lieu of the UPL; these 
commenters claimed that the UTL is more appropriate for situations 
where the available data does not represent the entire population.
    Response: EPA disagrees with commenters and believes that the final 
emission limits appropriately account for variability. The Court has 
recognized that EPA may consider variability in estimating the degree 
of emission reduction achieved by the best-performing sources and in 
setting MACT floors that the best performing sources can expect to meet 
``every day and under all operating conditions''. See Mossville 
Environmental Action Now v. EPA, 370 F.3d 1232, 1241-42 (DC Cir 2004). 
Furthermore, CAA section 112(d)(3) includes a provision stating that 
the MACT floor for existing sources cannot be less stringent than ``the 
average emission limitation achieved by the best-performing 12 percent 
of the existing sources (for which the Administrator has emissions 
information).'' We see no statutory prohibition in considering inter-
source variability of the best performing sources (which is all our 
floor calculation does, by considering the pooled variability of the 
best performing sources). Section 112(d)(3) of the CAA does not specify 
any single method of ascertaining an average. Considering the average 
variability among the group of best performing sources is well within 
the language of the provision (and was upheld in Chemical Manufacturers 
Association v. EPA; see 870 F. 2d at 228). The commenters' argument 
that ``average'' can only mean average of emission levels achieved in 
performance tests of an individual unit is inconsistent with the 
holding in Mossville, 370 F. 3d at 1242, that EPA must account for 
variability in developing MACT floors and that individual performance 
tests do not by themselves account for such variability. Therefore, we 
believe that it is reasonable and necessary to account for inter-source 
variability of the best performing sources by taking the pooled average 
of the best performing sources' variability. This is an aspect of 
identifying the average performance of those sources.
    Furthermore, EPA is confident that the UPL is an appropriate 
statistical tool to use in determining variability when there is a 
limited sampling of the source category. EPA has considered comments 
regarding suggested alternatives to the UPL statistic, such as the 
upper tolerance limit (UTL). Whereas a confidence interval covers a 
population parameter with a stated confidence, that is, a certain 
proportion of the time, a tolerance interval covers a fixed proportion 
of the population with a stated confidence. That is, confidence limits 
are limits within which we expect a given population parameter, such as 
the mean, to lie; statistical tolerance limits are limits within which 
we expect a stated proportion of the population to lie. Given this 
definition, the 99 percent UTL represents the value which we can expect 
99 percent of the measurements to fall below 99 percent of the time in 
repeated sampling. In other words, if we were to obtain another set of 
emission observations from the floor sources, we can be 99 percent 
confident that 99 percent of these measurements will fall below a 
specified level. Since you must calculate the sample percentile, and 
the sample sizes for the area source boiler

[[Page 15572]]

floor data are small, the 99th percentile is underestimated. Therefore, 
EPA notes that the UTL should only be used where one can calculate a 
sample percentile, e.g., where there is a sample size of at least 100. 
On the other hand, a prediction interval for a future observation is an 
interval that will, with a specified degree of confidence, contain the 
next (or some other pre-specified) randomly selected observation from a 
population. In other words, the prediction interval estimates what 
future values will be, based upon present or past background samples 
taken. The UPL represents the value which we can expect the mean of 3 
future observations (3-run average) to fall below, based upon the 
results of the independent sample of size n from the same population. 
Given the above considerations, EPA notes that only the UPL adequately 
gets at the notion of average emissions for a small sample size.
    EPA has revised its default selection of data distributions 
consistent with its guidance document ``Data Quality Assessment: 
Statistical Methods for Practitioners EPA QA/G-9S''. This document 
indicates that most environmental data is lognormally distributed, so 
EPA has modified its assumptions when the results of the skewness and 
kurtosis tests result in a tie, or when there is not enough data to 
complete the skewness and kurtosis tests. With respect to the methods 
used to compute the UPL for a dataset that is determined to be 
lognormally distributed, EPA also considered the commenters suggested 
revisions to the calculations in order to avoid skewing the UPL by 
calculating the UPL of an arithmetic mean instead of the UPL of a 
geometric mean. To adjust the calculation EPA considered a scale bias 
correction approach as well as a new UPL equation based on a Bhaumik 
and Gibbons 2004 paper, which calculates ``An Upper Prediction Limit 
for the Arithmetic Mean of a Lognormal Random Variable \6\''. Given 
data availability, EPA selected the Bhaumik and Gibbons 2004 approach 
which addresses commenters concerns with the proposed computations.
---------------------------------------------------------------------------

    \6\ Bhaumik, D. K. and R. D. Gibbons. 2004. An Upper Prediction 
Limit for the Arithmetic Mean of a Lognormal Random Variable. May 1, 
2004. Technometrics 46(2): 239-248. doi:10.1198/004017004000000284
---------------------------------------------------------------------------

    Additionally, EPA has determined that 99 percent UPL is appropriate 
for fuel based HAP, and a 99.9 percent UPL is appropriate for CO. For 
fuel-based HAP the 99 percent confidence level is consistent with other 
recent rulemakings (75 FR 54975). Further, as commenters have noted 
elsewhere, the sample sizes were limited and EPA determined that a 
level of 99 percent is a good compromise and represents emission levels 
that are protective of human health and the environment. Given that the 
subcategories had limited data to establish the floor calculations, EPA 
determined it was inappropriate to use a confidence level lower than 99 
percent. Further, for fuel based HAP mercury, EPA has implemented an 
additional fuel variability analysis. Additionally, there are well 
established control measures currently used on units in the source 
category (fabric filters for PM and mercury) that serve to mitigate, to 
some degree, the variability in emissions that can be expected. Given 
these additional considerations for fuel-based HAP, but recognizing the 
emission limits must be met at all times yet are based on short term 
stack test data, EPA selected the 99 percent confidence level. For CO, 
EPA considered both quantitative and qualitative comments received 
during the public comment period on how CO emissions vary with load, 
fuel mixes and other routine operating conditions. After considering 
these comments EPA determined that a 99.9 percent confidence level for 
CO would better account for some of these fluctuations.
    Finally, EPA notes that where appropriate, we have accounted for 
variable fuel quality. EPA first took fuel into consideration, among 
other boiler design factors when it divided the source category into 
subcategories. EPA is aware that differences between given types of 
units, and fuel, can affect technical feasibility of applying emission 
control techniques. As noted in the preamble to the June 2010 proposed 
rule, EPA attempted to assess the impact of fuel variability for 
development of the mercury standard. However, no fuel analysis data 
from boilers in the top 12 percent were available for assessing the 
impact of fuel variability on mercury emissions. EPA realizes that 
mercury is a fuel dependent HAP, and that the amount of mercury emitted 
from the boiler depends on the amount of mercury contained in the fuel. 
For this final rule, we have implemented a fuel variability factor into 
the mercury emission limit by determining a factor relating the highest 
mercury content to the average mercury content in coal that may be used 
at sources comprising the best 12 percent of sources. We also note that 
fuel usage can be reduced by improving the combustion efficiency of the 
boiler. Therefore, in the development of the final standards, we are 
establishing requirements for larger existing boilers (greater than 10 
MMBtu/h heat input capacity) to conduct an energy assessment, and 
smaller boilers (both existing and new boilers with a heat input 
capacity less than 10 MMBtu/h) to meet a work practice or management 
practice requirements of a tune-up, in order to improve combustion 
efficiency.

D. Beyond the Floor Analysis

    Comment: Several commenters objected to EPA's beyond-the-floor 
determination for new area source boilers. Many of these commenters 
stated that the beyond the floor approach must consider fuel switching 
as an option. Other commenters objected to EPA's beyond-the-floor 
determination for existing boilers, specifically stating that EPA 
should require existing facilities to either comply with emission 
limits for larger units, or require fuel switching to the cleanest fuel 
in their class (fuel type). Commenters noted that while EPA identified 
substantial emissions reductions for mercury and POM from switching 
coal-fired boilers to natural gas, EPA failed to rationalize why fuel-
switching is not a technically feasible or economically achievable 
option. Commenters debated EPA's stated concerns regarding fuel 
availability and curtailment, arguing that there is sufficient capacity 
to meet the expected increased demand for natural gas. Furthermore, 
these commenters stated that the potential increases in metallic HAP 
emissions from fuel-switching were minor and should be considered in 
light of overall reductions for POM.
    Response: EPA has considered this comment and concluded that fuel 
switching is not an appropriate option for the beyond the floor level 
of control. EPA originally considered whether fuel switching would be 
an appropriate control option for sources in each subcategory under the 
proposed rule, including the feasibility of fuel switching to other 
fuels used in the subcategory and to fuels from other subcategories. 
This consideration included determining whether switching fuels would 
achieve lower HAP emissions. We also gave consideration to whether fuel 
switching could be technically achieved by boilers in the subcategory 
considering the existing design of boilers and the availability of 
various types of fuel. After considering these factors, we determined 
that fuel switching was not an appropriate control technology for 
purposes of determining the MACT floor level or beyond the floor level 
of control for any subcategory. This decision is based on the overall 
effect of

[[Page 15573]]

fuel switching on HAP emissions, technical and design considerations 
discussed previously in the preamble to the proposed June 2010 rule (75 
FR 31896), and concerns about fuel availability. This determination is 
discussed in the memorandum ``Development of Fuel Switching Costs and 
Emission Reductions for Industrial, Commercial, and Institutional 
Boilers and Process Heaters National Emission Standards for Hazardous 
Air Pollutants--Area Source'' located in the docket.
Energy Assessments
    Comment: Several commenters disagreed with EPA's determination to 
require energy assessments as a beyond the floor option. Commenters 
specifically stated that EPA cannot require an energy assessment 
because an assessment is not an emission standard and there is no 
proven relationship between HAP emissions and the assessment. Other 
commenters argued that the proposed requirements for an energy 
assessment were not stringent enough; these commenters stated that an 
energy assessment cannot impose standards more stringent than the MACT 
floor. For instance, one commenter argued that if EPA did not require 
implementation of the energy assessment findings, no reductions in fuel 
use or HAP would result. The commenter further asserted that even an 
implemented energy assessment would not reduce HAP emissions consistent 
with the requirements of CAA section 112(d)(2). One commenter 
specifically stated that by only considering energy audits, EPA did not 
consider the full range of potential emission measures.
    Other commenters argued that EPA does not have the authority to 
require an energy assessment, and that the proposed requirements were 
``too broad'' or ``too intrusive.'' Commenters were concerned that the 
energy assessment would include not only the affected source, but also 
the entire facility, which EPA does not have the authority to regulate.
    Response: EPA disagrees with commenters that state that EPA does 
not have the authority to require an energy assessment. An energy 
assessment is an appropriate beyond-the-floor control technology 
because it is one of the measures identified in CAA section 112(d)(2). 
CAA section 112(d)(2) states that ``Emission standards promulgated * * 
* and applicable to new or existing sources * * * is achievable * * * 
through application of measures, processes, methods, systems or 
techniques including, but not limited to measures which--
    (A) Reduce the volume of, or eliminate emissions of, such 
pollutants through process changes, substitution of materials or other 
modifications, * * *
    (D) Are design, equipment, work practice, or operational standards 
(including requirements for operator training or certification) as 
provided in subsection (h), or
    (E) Are a combination of the above.''
    The purpose of an energy assessment is to identify energy 
conservation measures (such as, process changes or other modifications 
to the facility) that can be implemented to reduce the facility energy 
demand which would result in reduced fuel use. Reduced fuel use will 
result in a corresponding reduction in HAP, and non-HAP, emissions. 
Thus, an energy assessment, in combination with the MACT emission 
limits will result in the maximum degree of reduction in emissions as 
required by CAA section 112(d)(2).
    It is not EPA's intent to require an energy assessment for the 
entire facility; the energy assessment is only applied to existing 
boilers and their energy use systems located at area sources. EPA 
acknowledges that the proposed definition for ``energy assessment'' is 
unclear, and we have revised this final rule to clarify the definition 
with respect to the requirements of Table 3 of subpart JJJJJJ (see 40 
CFR 63.11237). In order to account for variability among boiler systems 
and energy use systems and to ensure that affected sources can 
adequately comply with the requirements, we have distinguished the 
requirements for the energy assessment based on the heat input use of 
the affected source. We have also added a definition for ``energy use 
systems'' to clarify the components for each boiler system and energy 
use system which must be considered during the energy assessment, 
including elements such as combustion management, thermal energy 
recovery, energy resource selection, and the steam end-use management 
of each affected boiler. These revisions clarify that an energy 
assessment is only required for those portions of the facility using 
the energy generated from the affected boiler system.
    Additionally, a facility may elect, but is not required, to 
implement the cost-effective energy conservation measures identified in 
the energy assessment. Because we lack information on whether 
implementation of the conservation measures will prove cost-effective 
or economically feasible for facilities, we are allowing the owner or 
operator to determine the implementation of energy conservation 
measures identified in the energy assessment. EPA notes that the cost 
of an energy assessment is minimal, in most cases, compared to the cost 
for testing and monitoring to demonstrate compliance with an emission 
limit. Furthermore, the costs of any energy conservation improvement 
for the owner or operator will be offset, at least in part, by the cost 
savings in lower fuel costs. Therefore, after considering the structure 
of the requirement, the incentives it presents, and the likely behavior 
of sources, it is our judgment that sources will find it cost-effective 
to implement the conservation measures identified in the energy 
assessment, and we have elected to promulgate requirements for an 
energy assessment for all existing boilers with a heat input capacity 
greater than 10 MMBtu/h as a beyond the floor option or GACT.
    EPA disagrees with commenters that state that the option for an 
energy assessment included in the June 2010 proposed rule is not 
stringent enough. An energy assessment refers to a process which 
involves a thorough examination of potential savings from energy 
efficiency improvements, pollution prevention, and productivity 
improvement. It leads to the reduction of pollutants through process 
changes and other efficiency modifications. Improving energy efficiency 
reduces negative impacts on the environment as well as operating and 
maintenance costs; improvements in energy efficiency result in 
decreased fuel use which results in a corresponding decrease in 
emissions (both HAP and non-HAP) from the boiler. The revised 
definitions of ``energy assessment'' and ``energy use systems,'' as 
discussed above, have been expanded to include the specific components 
that must be considered for an energy assessment. These changes 
elucidate the in-depth nature of the energy assessment, which requires 
identifying all energy conservation measures appropriate for a facility 
given its operating parameters.
    EPA proposed the energy assessment as a beyond the floor option for 
existing area source boilers having a heat input capacity of greater 
than 10 MMBtu/h, rather than focusing on smaller boilers. We also 
examined other emission measures currently in place. EPA did not have 
sufficient information to determine if requiring an energy assessment 
for area boilers with a heat input capacity of less than 10 MMBtu/h is 
economically feasible. For boilers with a heat input capacity less than 
10 MMBtu/h, the data that we have suggests that area source boilers 
typically conduct boiler tune-ups. We also examined work practices 
listed in

[[Page 15574]]

state regulations for area source boilers with a heat input capacity 
less than 10 MMBtu/h. These regulations included tune-ups (10 states), 
operator training (one state), periodic inspections (two states), and 
operation in accordance with manufacturer specifications (one state).
    When energy assessments have been undertaken in the past, they 
typically result in 10 to 15 percent reduction in fuel use, according 
to the Department of Energy who has conducted energy assessment at 
selected manufacturing facilities.\7\ While the efficiency gains may be 
somewhat less when the assessment is mandated for a source rather than 
voluntary, the absence of a requirement to implement the particular 
findings of the assessment should still result in measures being 
implemented that are cost-effective for the source and in emission 
reductions over and above what is otherwise required by MACT and other 
GACT measures. Therefore, we elected to promulgate requirements for an 
energy assessment for all existing boilers with a heat input capacity 
greater than 10 MMBtu/h, and require area source boilers in the biomass 
and oil subcategories with a heat input capacity of greater than 10 
MMBtu/h to meet the management practice standard of a tune-up. These 
requirements represent the generally available and cost-effective 
pollution reduction measures that are already required or in place.
---------------------------------------------------------------------------

    \7\ Case studies and success stories highlighting energy savings 
achieved by companies that have participated in energy assessments 
can be found at http://www1.eere.energy.gov/industry/saveenergynow/case_studies.html and at the Department of Energy's Energy 
Assessment Centers Database http://iac.rutgers.edu/database.
---------------------------------------------------------------------------

E. GACT Standards

    Comment: Commenters stated that the GACT standards should consist 
of work practice standards, rather than numeric emission limits. One 
commenter specifically stated that in order to reduce the burden on 
small facilities operating boilers, EPA should establish work practice 
standards for CO instead of emission limits, referencing requirements 
from the state of New Jersey. Other commenters stated that the emission 
limits and testing procedures proposed for new boilers impose onerous 
capital and annual costs on potential project owners, which typically 
include schools, small businesses, hospitals, and other institutions in 
rural areas. Some commenters stated that the CO emission limits were 
not achievable for small boilers over a range of operating periods, and 
that EPA should consider work practice standards in order to account 
for load variability.
    Response: CAA section 112(d)(5) allows the Administrator, with 
respect to area sources, to promulgate standards which provide for the 
use of generally available control technologies or management practices 
to reduce emissions of HAP. Therefore, with respect to mercury and POM 
from area source boilers classified as biomass-fired or oil-fired, as 
well as with respect to other urban HAP besides POM, we have developed 
standards that reflect GACT for these two area source categories.
    While the June 2010 proposed rule (75 FR 31896) set numeric MACT 
standards for CO (as a surrogate pollutant for the individual urban 
organic HAP) and mercury, and numeric GACT emission limits for PM (as a 
surrogate for the individual urban metal HAP), EPA has revised the 
standards for area source boilers classified in the biomass and oil 
subcategories. Rather than require a numeric MACT emission limit for 
POM, new and existing area source boilers in the biomass or oil 
subcategories must meet the requirements of GACT, which are management 
practice standards as described in Table 2 of 40 CFR part 63, subpart 
JJJJJJ.
    However, for the purposes of regulating PM from new area source 
boilers, EPA has determined that the GACT standards should consist of 
numeric emission limits. PM is used as a surrogate for urban metals, 
which we are required to regulate pursuant to CAA section 112(c)(6). 
The data that we have available suggests that the control technologies 
currently used by facilities in the source category for reduction of 
non-mercury metallic HAP and PM are multiclones, which are generally 
used at area sources using solid fuel. We previously determined during 
the development of the June 2010 proposed rule that these controls are 
generally available and cost effective for new area source boilers. 
Additionally, we noted that new area source boilers with heat input 
capacity of 30 MMBtu/h or greater are subject to the NSPS for boilers 
(either subpart Db or Dc of 40 CFR part 60), which regulate emissions 
of PM and require performance testing. Furthermore, new coal-fired area 
source boilers with heat input capacity of 10 MMBtu/h or greater will 
likely require a PM control device to comply with the proposed mercury 
MACT standard and required performance testing. Therefore, a numerical 
limit for PM consistent with the devices required to meet mercury MACT 
should be generally achievable.
    EPA has also revised the PM emission limits for area source boilers 
with a heat input capacity between 10 and 30 MMBtu/h; these limits have 
been revised to reflect the performance of GACT, which are multiclones. 
The PM GACT limits were calculated as the average of the data from 
units using GACT technology. EPA has determined that the promulgated 
numeric emission limits for PM are appropriate GACT standards for new 
area source boilers with a heat input capacity greater than 10 MMBtu/h. 
For new boilers with a heat input capacity less than 10 MMBtu/h, GACT 
is a management practice of a tune-up because, as previously discussed, 
there are technical and economic limitations of conducting PM testing 
on boilers with small diameter stacks.
Tune-Ups
    Comment: Several commenters expressed concern regarding proposed 
work practice standards for existing area source boilers, including the 
requirement of a tune-up for control of POM and mercury. Commenters 
stated that tune-ups aimed at reducing CO may increase NOX 
emissions, reduce combustion efficiency, and/or increase fuel use. 
Commenters noted that many typical tune-up requirements, including 
states' requirements, are aimed at minimization of NOX. and 
not CO. These commenters stated that the proposed tune-up requirements 
could violate the state tune-up requirements due to increases of 
NOX. Multiple commenters requested that EPA specify that 
tune-ups consider optimizing efficiency and limiting increases of 
NOX, and not only require minimizing CO.
    Other commenters requested that EPA allow the use of portable 
instruments to measure CO for the tune-up requirements. Several 
commenters requested that EPA clarify that, for the tune-up procedures, 
gases do not have to be measured using EPA Reference Methods. These 
commenters indicated that requiring EPA Methods would increase the cost 
burden for small facilities.
    Response: EPA disagrees with commenters and is requiring tune-ups 
as a work practice standard for coal-fired area source boilers with a 
heat input capacity less than 10 MMBtu/h and as a management practice 
standard for all biomass-fired and oil-fired area source boilers. EPA 
acknowledges that that a tune-up designed to specifically decrease CO 
emissions from an area source boiler would potentially increase 
emissions of NOX. However, it was not EPA's intent to 
require that area source

[[Page 15575]]

boilers be specifically tuned for the reduction of CO emissions, but 
rather to require good combustion practices (GCP) by ensuring that area 
source boilers are tuned to manufacturer's specifications. As discussed 
in the preamble to the June 2010 proposed rule, boilers may be, at 
best, 85 percent efficient, and untuned boilers may have combustion 
efficiencies of 60 percent or lower. Furthermore, as the combustion 
efficiency decreases, fuel usage increases to maintain energy output 
resulting in increased emissions. A tune-up performed to the 
manufacturer's specifications would ensure the highest energy 
efficiency and reduce fuel usage, which will ultimately reduce HAP 
emissions. As commenters noted, the tune-up requirements specified by 
area source boiler manufacturers are generally aimed at reducing 
NOX and would not increase emissions of NOX. The 
tune-up provisions incorporated in this final rule for area source 
boilers require that the owner or operator measure the concentration in 
the effluent stream of CO in ppm, by volume, dry basis (ppmvd), before 
and after adjustments are made to the boiler. EPA does not specify the 
instrument that must be used for measuring these concentrations, and 
allows owners and operators to choose the method of measurement. 
Therefore, EPA agrees with commenters that portable instruments are 
permissible for this purpose.

F. Subcategories

    Comment: Several commenters raised concerns regarding the 
subcategories defined by EPA in the development of the proposed rule. 
Multiple commenters argued that the proposed subcategories are unlawful 
and arbitrary because they are not based on different classes, types, 
or sizes. At least one commenter specifically stated that the proposed 
subcategorization defied the explicit recommendation of the Small 
Entity Representatives (SERs) to the Small Business Advocacy Review 
(SBAR) Panel, which recommended that ``EPA should subcategorize based 
on fuel type, boiler type, duty cycle, and location.'' Many of these 
commenters suggested subcategories based on limited use, type of 
biomass (wood, bark, agricultural residue, moisture level) and/or coal 
(bituminous, anthracite), boiler design (stoker, fluidized bed, or 
suspension), heat input capacity smaller than 1 MMBtu/h, and combustion 
of secondary materials. Other commenters recommended that the same 
subcategories applied to major sources should be used for area sources.
    Response: EPA disagrees with commenters. Section 112(d)(1) of the 
CAA states ``the Administrator may distinguish among classes, types, 
and sizes of sources within a category or subcategory'' in establishing 
emission standards. Thus, we have discretion in determining appropriate 
subcategories based on classes, types, and sizes of sources. We used 
this discretion in developing subcategories for the boiler area source 
category. Through subcategorization, we are able to define subsets of 
similar emission sources within a source category if differences in 
emissions characteristics, technical feasibility of applying emission 
control techniques, or opportunities for pollution prevention exist 
within the source category. The design, operating, and emissions 
information that EPA reviewed during the area source rulemaking 
indicates the need to subcategorize based on boiler design which is 
based on the fuel type. EPA continues to believe that this 
subcategorization is appropriate. As noted in the preamble to the June 
2010 proposed rule, boiler systems are designed for specific fuel types 
(e.g., coal, biomass, oil or a mixture/combination) and will encounter 
problems if a fuel or mixture with characteristics other than those 
originally specified is fired. EPA has noted that emissions from 
boilers burning coal, biomass, and oil will also differ, and that HAP 
formation, including emissions of metals and mercury, is dependent upon 
the composition of the fuel. Organic HAP, on the other hand, are formed 
from incomplete combustion, which are a function of time, turbulence, 
and temperature, and are influenced by the design of the boiler and 
dependent in part on the type of fuel being burned. Because these 
different types of boilers have different emission characteristics 
which may influence the feasibility and effectiveness of emission 
control, we believe that subcategorizing them by fuel type is 
appropriate.
    Additionally, EPA notes that we lack sufficient emissions data for 
area source boilers to develop limits for additional subcategories. We 
have elected to establish different subcategories for the major and 
area source rulemakings, as major source boilers have a different scale 
of operation and often different combustor designs. There is also more 
detailed emissions data available for the major source category, which 
favors the development of more specific subcategories. Because we lack 
the same level of detail for the area source category, EPA has 
determined that it would be inappropriate to establish the same 
subcategories for major and area source boilers.
    We believe that area source boilers are generally designed to burn 
a standard fuel type and less capable of switching fuel type as some 
major source boilers. However, as was done for the major source NESHAP, 
we have redefined how to determine the appropriate subcategory. Instead 
of considering whether the boiler is designed to combust at least 10 
percent coal as the first step (as proposed), the first step in 
determining the appropriate subcategory is to consider the percentage 
of biomass that is combusted in the boiler.ies are determine.
    In addition, as discussed in the comments below, we have 
established a small units subcategory for each type of fuel (area 
source boilers with a heat input capacity of less than 10 MMBtu/h), and 
see no further need for smaller subcategories. We have also adjusted 
the definition for each fuel subcategory to account for the combustion 
of secondary materials. The definitions have been clarified to specify 
that the fuel subcategories are based on the fuel that the boiler is 
designed to combust, rather than the actual fuel that the boiler is 
combusting.
    Finally, as discussed earlier in this section, we have revised the 
MACT and GACT limits for the coal, oil, and biomass subcategories in 
this final rule. Existing oil and biomass-fired boilers are no longer 
required to meet emission limits, and are only required to meet 
management practice standards under this final rule. Furthermore, coal-
fired boilers with a heat input capacity of less than 10 MMBtu/h are 
only required to meet work practice standards. While more stringent 
limits under this final rule may have required subcategories based on 
the size of the unit, EPA has determined that the subcategories chosen 
are reasonable based on the applicable requirements of this final rule.
Combustion of Secondary Fuels
    Comment: Multiple commenters sought clarity for the combustion of 
secondary materials and/or alternative fuels within the proposed 
subcategories for area source boilers. Several of these commenters 
requested clarification of the defined fuels for the biomass, coal, and 
oil-fired subcategories, as well as additional clarification regarding 
gas-fired boilers. Some commenters stated that EPA's determination that 
the boilers subject to this rule do not combust any non-hazardous 
secondary materials is erroneous, and that to not

[[Page 15576]]

consider standards for units burning secondary materials would be 
unlawful.
    Many commenters recommended that EPA classify boilers based on 
predominant use of a particular fuel; several commenters recommended 
redefining the subcategories to allow minimal burning of other fuels or 
for further clarification. For instance, some commenters expressed 
concern regarding ``combination boilers'' (boilers that co-fire coal in 
an amount greater than 10 percent heat input basis with at least 10 
percent biomass), which do not cleanly fit into either the coal-fired 
boiler subcategory or the biomass-fired boiler subcategory. Other 
commenters argued that the definition of gas-fired boilers should allow 
for units burning less than 10 percent liquid fuels. Many of the 
commenters suggested alternative definitions for the proposed 
subcategories or provided alternative thresholds.
    Alternatively, there were some commenters who expressed concern 
regarding the use of alternative fuels. Commenters specifically stated 
that allowing 10 percent alternative fuel use, or use of multiple 
alternatives from year to year, would create significant enforcement 
issues for states without detailed requirements for tracking, 
recordkeeping, and reporting.
    Response: EPA has considered these comments and revised the 
subcategories based on a revised MACT floor approach. As discussed in 
Section IV.A of this preamble, we have redefined the coal, biomass and 
oil subcategories for area source boilers to clarify the fuel inputs 
that define each subcategory. While the subcategories under the 
proposed rule accounted for secondary materials such as biomass, liquid 
or gaseous fuels combusted in combination with traditional fuels, we 
wished to clarify each subcategory in order to account for the 
combustion of an array of secondary fuels. Area source boilers 
combusting coal, biomass or oil may also combust secondary materials as 
part of their fuel mix. It was not our intent to exclude boilers 
combusting these non-hazardous secondary materials that do not meet the 
definition of ``solid waste'' from the coal, biomass or oil-fired 
subcategories. Therefore, we have revised the definition for each 
subcategory to account for the combustion of these non-hazardous 
secondary materials.
    For instance, the proposed rule limited the coal subcategory to 
boilers combusting coal or coal in combination with biomass, liquid, or 
gaseous fuels. We have redefined the coal subcategory to include 
boilers that burn any solid fossil fuel and no more than 15 percent 
biomass on an annual heat input basis. ``Solid fossil fuels'' has been 
defined to include, but not limited to, coal, petroleum coke, coal 
refuse, and tire derived fuel (TDF). Similarly, we have revised the 
biomass subcategory to account for boilers that may burn biomass and 
secondary materials. The biomass subcategory includes boilers 
combusting at least 15 percent of biomass. This definition 
differentiates these primarily biomass-fired boilers from the coal 
subcategory. Additionally, the oil subcategory has been revised to 
include boilers that burn any liquid fuel but are not included in 
either the coal or biomass subcategories.
    Based on new data submitted during the public comment period, EPA 
has determined that area source boilers may combust secondary 
materials. Data submitted indicates that as much as 15 percent of 
secondary materials, or alternative traditional fuel, may be mixed 
without causing problems with boiler operations. We wished to 
differentiate boilers combusting greater than 15 percent of biomass 
from the remaining subcategories, as these fuels will have higher rates 
of organic HAP due to the higher moisture content of biomass compared 
to fossil fuel. The revised definitions for the coal, biomass and oil 
subcategories clarify this by establishing the fuel type and the input 
ratio of each fuel type combusted. Therefore, the revised definitions 
more accurately reflect EPA's intent to include and account for boilers 
combusting secondary materials in the coal, biomass, and oil 
subcategories and the effect of biomass on the combustion process.
    Comment: A number of commenters requested that EPA provide 
exemptions for specific unit types, including limited use boilers, 
recovery boilers, hot water heaters, boilers firing ultra low sulfur 
2 fuel oil, and boilers with a heat input capacity of less 
than 1 MMBtu/h. Other commenters stated that EPA is not justified in 
providing an exemption for gas-fired boilers.
    Response: As noted in Section VII of the proposed June 2010 rule, 
in the Federal Register notice ``Source Category Listing for Section 
112(d)(2) Rulemaking Pursuant to Section 112(c)(6) Requirements,'' (63 
FR 17838, 17849), Table 2 (1998), EPA identified ``Industrial Coal 
Combustion,'' ``Industrial Oil Combustion,'' ``Industrial Wood/Wood 
Residue Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil 
Combustion,'' and ``Commercial Wood/Wood Residue Combustion'' as source 
categories ``subject to regulation'' for purposes of CAA section 
112(c)(6). Notably, gas-fired units are not included in the source 
category listing for area source boilers. Without such a listing, EPA 
cannot address gas-fired boilers in this regulation. We have also 
included in this final rule an exemption for hot water heaters because 
these units are, as defined in this final rule, considered residential 
boilers. In addition, recovery boilers would be exempt because they are 
regulated under another section 112 MACT standard (See 40 CRF part 63, 
subpart MM).
    Conversely, EPA is required to set standards for other unit types, 
including limited use boilers and boilers firing ultra low sulfur fuel 
oil. These boilers are included in the source category listing for CAA 
section 112(d)(2) and emit the pollutants identified in CAA section 
112(c)(3). As discussed above, EPA has set appropriate MACT and GACT 
limits to boilers based on fuel type and size, including area source 
boilers with a heat input capacity of less than 10 MMBtu/h. EPA also 
notes that waste heat boilers have been excluded from the definition of 
boiler.

G. Startup, Shutdown, and Malfunction

    Comment: Several commenters stated that a separate standard must be 
developed for periods of startup and shutdown. Commenters stated that 
requiring emission limits during SSM directly conflicts with the 
requirement that MACT be achievable and is technically feasible; 
therefore EPA could not require emission limits during periods of SSM. 
Some commenters requested a separate standard for CO for startup; at 
least one commenter specifically stated that many area source boilers 
must operate under conditions driven by safety considerations, 
operational concerns, and warranty requirements that would likely 
generate unavoidable increases in CO emissions during startup and 
shutdown. The commenter therefore concluded that requiring a CO 
emission limit during startup and shutdown would not only be 
technically unachievable, but would promote unsafe and improper 
operation. Several commenters suggested that work practice standards 
are more appropriate than emission limits, citing a lack of relevant 
data for periods of SSM. Other commenters specifically objected to 
EPA's decision to base the SSM requirements on data from the proposed 
major source NESHAP for industrial, commercial, and institutional 
boilers and stated that the data from the proposed major source rule 
cannot be applied to area sources.
    Response: EPA has considered these comments and has revised this 
final rule to incorporate a work practice standard

[[Page 15577]]

for periods of startup and shutdown. As part of the development of the 
proposed rule, we reviewed the cost information for CO CEMS provided by 
commenters on the NESHAP for major source boilers and determined that 
requiring CO CEMS for units with heat input capacities greater or equal 
to 100 MMBtu/hr was reasonable. However, EPA has revised this final 
rule to only require emission limits for mercury and CO for coal-fired 
boilers. Furthermore, we are only requiring sources to perform a work 
practice standard, following the manufacturer's recommended procedures, 
to demonstrate compliance with the emission limits for area source 
coal-fired boilers during periods of startup and shutdown. Based on the 
available dataset for facilities in the affected area source category, 
EPA determined that there are currently no existing coal-fired boilers 
with a heat input capacity greater than 100 MMBtu/h located at area 
sources. Coal-fired boilers with a heat input capacity of greater than 
50 MMBtu/h are generally major sources of HAP. Therefore, requiring 
CEMS for boilers of this size is unnecessary for the defined source 
category.
    In lieu of CEMS, we also considered whether requirements for 
performance testing would be feasible for area source boilers during 
periods of startup and shutdown. Upon review of these requirements, EPA 
determined that it is not feasible to require stack testing--in 
particular, to complete the multiple required test runs--during periods 
of startup and shutdown due to physical limitations and the short 
duration of startup and shutdown periods. Therefore, a separate 
standard must be developed for these periods.
    In regards to malfunctions, EPA had previously determined in the 
development of the proposed rule that malfunctions should not be viewed 
as a distinct operating mode and, therefore, any emissions that occur 
at such times do not need to be factored into development of CAA 
section 112(d) standards, which, once promulgated, apply at all times. 
As discussed in Section III.E of this preamble, EPA has added to this 
final rule an affirmative defense for civil penalties for exceedances 
of numerical emission limits that are caused by malfunctions.
    Therefore, as allowed under CAA section 112(h), we are requiring a 
work practice standard for all coal-fired area source boilers during 
periods of startup and shutdown. The work practice standard requires 
following the boiler manufacturer's specifications for periods of 
startup and shutdown.

H. Compliance Requirements

Rationale for Demonstrating Compliance
    Comment: Several commenters expressed concern that, given the large 
numbers of boilers that would be affected by the proposed rule and the 
limited capacity of existing vendors, contractors, and engineers, a 3-
year time period would not be sufficient to allow completion of all of 
the required modifications.
    Response: EPA has re-evaluated the compliance dates for this final 
rule following the revised MACT and GACT standards. We have revised the 
initial compliance dates for existing affected sources according to the 
applicable provisions for each affected source (e.g., work practice or 
management practice standards, emission limits, and/or an energy 
assessment), as discussed in Section VI.E of this preamble. EPA has 
determined that existing sources subject to a work practice standard of 
a tune-up must comply with this final rule no later than one year after 
publication of this final rule. We have determined that one year is 
adequate time for affected sources to meet the work practice or 
management practice standard, which includes a tune-up based on the 
manufacturer's recommendations. Existing sources subject to an emission 
limit or an energy assessment requirement are required to comply with 
this final rule no later than 3 years after publication of the final 
rule. Section 112(i)(3)(B) allows EPA, on a case-by-case basis to grant 
an extension permitting an existing source up to one additional year to 
comply with standards if such additional period is necessary for the 
installation of controls. The EPA feels that this provision is 
sufficient for those sources where the 3-year deadline would not 
provide adequate time to retrofit as necessary to comply with the 
requirements of the standard.
    Comment: Commenters objected to proposed requirements to use CEMS 
and in some circumstances COMS. Commenters stated that these 
requirements are extremely burdensome on area sources considering the 
testing requirements and costs, and that the requirements for CO CEMS 
for units less than 100 MMBtu/h are too onerous. Commenters noted that 
many units at this size in the industrial and institutional sector do 
not operate frequently; therefore the cost of installing CO CEMS was 
not justified for units with such limited operation. Other commenters 
argued that requiring boilers to test for CO poses a significant 
regulatory burden. Several commenters stated that the proposed testing 
frequency was burdensome.
    Response: EPA has considered these comments, and we have revised 
the proposed continuous compliance requirements to not require a CO 
CEMS for area source boilers. Per the revised MACT and GACT 
determinations, this final rule only requires emission limits for 
mercury and CO for coal-fired units. Therefore, for new and existing 
coal units with a heat input capacity greater than 10 MMBtu/h, we are 
requiring stack testing every 3 years to demonstrate compliance with 
the CO emission limits. In the development of the proposed rule, we 
reviewed the cost information for CO CEMS provided by commenters on the 
NESHAP for major source boilers and determined that requiring CO CEMS 
for units with heat input capacities greater or equal to 100 MMBtu/h 
was reasonable. However, based on a review of the available dataset for 
facilities in the affected area source category, we have determined 
that there are currently no existing coal-fired boilers with a heat 
input capacity greater than 100 MMBtu/h located at area sources. 
Therefore, requiring CEMS for coal-fired boilers of this size is 
unnecessary for the defined source category. Additionally, boilers in 
the biomass and oil subcategories with a heat input capacity greater 
than 10 MMBtu/h are not required to meet emission limits for CO in this 
final rule; these boilers are subject to the management practice 
standards in Table 2 of 40 CFR part 63, subpart JJJJJJ, and therefore, 
no CO testing is required for these units.

I. Cost/Economic Impacts

    Comment: Multiple commenters stated that the economic impacts of 
the proposed rule were significantly underestimated. Many commenters 
stated that the CO limits would require costly controls, and 
specifically, that the cost of particulate control for biomass boilers 
was severely underestimated. Other commenters stated that EPA made 
erroneous assumptions in performing the cost calculations. For 
instance, one commenter stated that EPA does not have enough data to 
support the assumption that fabric filters alone will be sufficient for 
area source coal-fired boilers to meet the proposed mercury limit.
    Response: In light of changes to this final rule, EPA believes that 
these concerns are no longer an issue. We have revised the costs 
estimates for this final rule to reflect EPA's determination of the 
final MACT standards for coal-fired boilers and GACT standards for 
biomass and oil-fired boilers. For

[[Page 15578]]

instance, EPA is only requiring particulate emission limits for new 
boilers with a heat input capacity of greater than 10 MMBtu/h; smaller 
boilers must only meet the management practice standard of a tune-up. 
These changes have significantly decreased the costs presented in the 
proposed June 2010 rule. Additionally, commenters provided additional 
cost information during the public comment period; EPA has incorporated 
this information into the analysis for this final rule. Based on this 
re-analysis, EPA has determined that fabric filter controls are 
generally available and cost effective for new area source boilers. As 
noted previously, new area source boilers with a heat input capacity of 
30 MMBtu/h or greater are subject to the NSPS for boilers (either 
subpart Db or Dc of 40 CFR part 60), which regulate emissions of PM and 
require performance testing. Furthermore, new coal-fired area source 
boilers will likely require a PM control device to comply with the 
proposed mercury MACT standard and required performance testing. We 
determined in the context of the major source rulemaking, and from 
further analysis of new data submitted during the public comment 
period, that fabric filters are the most effective technology employed 
by industrial, commercial, and institutional boilers for controlling 
mercury and particulate emissions. Therefore, EPA has determined it is 
appropriate and cost-effective to estimate the cost of compliance based 
on fabric filters for new area source boilers.
    Comment: Some commenters stated that this final rule would have 
substantial impacts on rural communities. Commenters noted that many 
rural communities rely upon or significantly benefit from the use of 
biomass boilers for energy at manufacturing facilities, schools and 
hospitals. These commenters stated that the proposed rule will 
negatively impact both boiler owners and fuel suppliers in these 
communities. Similarly, other commenters stated that this final rule 
would have a significant adverse impact on the use of biomass renewable 
energy throughout the economy.
    Response: In light of the changes made to the final regarding 
biomass-fired area source boilers, we believe these concerns are no 
longer an issue. In the final rule, existing biomass area source 
boilers are only subject to the management practice of a tune-up and 
only existing biomass-fired area source boilers with a heat input 
capacity of 10 MMBtu/h or greater are required to have an energy 
assessment performed. There are no testing or monitoring requirements 
in this final rule for existing biomass-fired area source boilers. For 
a typical existing biomass-fired boilers, this change resulted in 
reducing the annualized cost of compliance from about $420,000 to about 
$2,200.
    New biomass-fired area source boilers with a heat input capacity of 
10 MMBtu/h or greater are only subject to a PM emission limit which 
requires a PM test be conducted once every 3 years.

J. Title V Permitting Requirements

    In response to comments received and after further evaluation of 
the record, EPA has decided to exempt all area sources subject to this 
subpart from title V permitting. In evaluating the record, we have 
determined that observations and data we have relied upon in other 
rulemakings for distinguishing between sources that became synthetic 
area sources due to controls and other synthetic and natural area 
sources did not necessarily apply to this source category. Therefore, 
we lack sufficient information at this juncture to distinguish the 
sources which have applied controls to boilers in order to become area 
sources from other synthetic and natural area sources. As a result, the 
rationale for exempting most area sources subject to this rule as 
explained in the proposal preamble (see pages 31910 to 31913) is also 
now relevant for sources which we proposed to permit. Thus, no area 
sources subject to this subpart are required to obtain a title V permit 
as a result of being subject to this subpart.
    A source subject to this subpart may be subject to title V 
permitting for another reason or reasons, e.g., being located at a 
major source. If more than one requirement triggers a source's 
obligation to apply for a title V permit, the 12-month timeframe for 
submitting a title V application is triggered by the requirement which 
first causes the source to be subject to title V. See 40 CFR 70.3(a) 
and (b) or 71.3(a) and (b).

VI. Relationship of This Action to CAA Section 112(c)(6)

    CAA section 112(c)(6) requires EPA to identify categories of 
sources of seven specified pollutants to assure that sources accounting 
for not less than 90 percent of the aggregate emissions of each such 
pollutant are subject to standards under CAA section 112(d)(2) or 
112(d)(4). EPA has identified ``Industrial Coal Combustion,'' 
``Industrial Oil Combustion,'' Industrial Wood/Wood Residue 
Combustion,'' ``Commercial Coal Combustion,'' ``Commercial Oil 
Combustion,'' and ``Commercial Wood/Wood Residue Combustion'' as source 
categories that emit two of the seven CAA section 112(c)(6) pollutants: 
POM and mercury. (The POM emitted is composed of 16 polyaromatic 
hydrocarbons (PAH).) In the Federal Register notice, Source Category 
Listing for Section 112(d)(2) Rulemaking Pursuant to Section 112(c)(6) 
Requirements, 63 FR 17838, 17849, Table 2 (April 10, 1998), EPA 
identified ``Industrial Coal Combustion,'' ``Industrial Oil 
Combustion,'' Industrial Wood/Wood Residue Combustion,'' ``Commercial 
Coal Combustion,'' ``Commercial Oil Combustion,'' and ``Commercial 
Wood/Wood Residue Combustion'' as source categories ``subject to 
regulation'' for purposes of CAA section 112(c)(6) with respect to the 
CAA section 112(c)(6) pollutants that these units emit.
    Specifically, as by-products of combustion, the formation of POM is 
effectively reduced by the combustion and post-combustion practices 
required to comply with the CAA section 112 standards. Any POM that 
does form during combustion is further controlled by the various post-
combustion controls. The add-on PM control systems (fabric filter) used 
to reduce mercury and/or PM emissions further reduce emissions of these 
organic pollutants, as is evidenced by performance data. Specifically, 
the emission tests obtained at currently operating major source boilers 
show that the MACT regulations for coal-fired area source boilers will 
reduce Hg emissions by about 86 percent. It is, therefore, reasonable 
to conclude that POM emissions from coal-fired area source boilers will 
be substantially controlled.
    In lieu of establishing numerical emissions limits for pollutants 
such as POM, we regulate surrogate substances. While we have not 
identified specific numerical limits for POM, we believe CO serves as 
an effective surrogate for this HAP, because CO, like POM, is formed as 
a product of incomplete combustion.
    Consequently, we have concluded that the emissions limits for CO 
function as a surrogate for control of POM, such that it is not 
necessary to establish numerical emissions limits for POM with respect 
to coal-fired area source boilers to satisfy CAA section 112(c)(6).
    To further address POM and mercury emissions, this rule also 
includes an energy assessment provision that encourages modifications 
to the facility to reduce energy demand that lead to these emissions.

[[Page 15579]]

VII. Summary of the Impacts of This Final Rule

A. What are the air impacts?

    Table 3 of this preamble illustrates, for each subcategory, the 
estimated emissions reductions achieved by this rule (i.e., the 
difference in emissions between an area source boiler controlled to the 
MACT/GACT level of control and boilers at the current baseline) for new 
and existing sources. Nationwide emissions of total HAP (HCl, hydrogen 
fluoride, non-mercury metals, mercury, and VOC (for organic HAP) will 
be reduced by about 667 tpy for existing units and 74 tpy for new 
units. Emissions of mercury will be reduced by about 88 pounds per year 
for existing units and by about 9 pounds per year for new units. 
Emissions of filterable PM will be reduced by about 2,300 tpy for 
existing units and 280 tpy for new units. Emissions of non-mercury 
metals (i.e., antimony, arsenic, beryllium, cadmium, chromium, cobalt, 
lead, manganese, nickel, and selenium) will be reduced by about 280 tpy 
for existing units and will be reduced by 40 tpy for new units. 
Additionally, EPA has estimated that conducting an biennial tune-up 
will likely reduce emissions of organic HAP as a result of improved 
combustion and reduced fuel use. POM reductions are represented by 7-
PAH, a group of polycyclic aromatic hydrocarbons. EPA estimates that 
the work practices, management practices, and CO emission limits may 
reduce emissions of 7-PAH by 8 tpy for existing units and by 1 tpy for 
new units. A discussion of the methodology used to estimate baseline 
emissions and emissions reductions is presented in ``Estimation of 
Impacts for Industrial, Commercial, and Institutional Boilers Area 
Source NESHAP'' in the docket.

                 Table 3--Summary of HAP Emissions Reductions for Existing and New Sources (tpy)
----------------------------------------------------------------------------------------------------------------
                                                                                    Non
                                                                                  mercury
                 Source                           Subcategory             PM       metals    Mercury    POM \b\
                                                                                    \a\
----------------------------------------------------------------------------------------------------------------
Existing Units..........................  Coal......................      1,092          4      0.003        0.2
                                          Biomass...................        815         11      0.003          5
                                          Oil.......................        349        269       0.04          3
New Units...............................  Coal......................          7       0.03     0.0001       0.02
                                          Biomass...................        121          2     0.0002        0.5
                                          Oil.......................        149         36      0.004        0.5
----------------------------------------------------------------------------------------------------------------
\a\ Includes antimony, arsenic, beryllium, cadmium, chromium, cobalt, lead, manganese, nickel, and selenium.
\b\ POM is represented by total emissions of polycyclic aromatic hydrocarbons (7-PAH). It is assumed that
  compliance with work practice standard and management practice will reduce fuel usage by 1 percent, which may
  reduce emissions of 7-PAH by an equivalent amount.

B. What are the cost impacts?

    To estimate the national cost impacts of this rule for existing 
sources, EPA developed several model boilers and determined the cost of 
control for these model boilers. EPA assigned a model boiler to each 
existing unit based on the fuel, size, and current controls. The 
analysis considered all air pollution control equipment currently in 
operation at existing boilers. Model costs were then assigned to all 
existing units that could not otherwise meet the proposed standards. 
The resulting total national cost impact of this rule for existing 
units is $487 million dollars in total annualized costs. The total 
annualized costs (new and existing) for installing controls, conducting 
biennial tune-ups and an energy assessment, and implementing testing 
and monitoring requirements is $535 million. Table 4 of this preamble 
shows the total annualized cost impacts for each subcategory.

                          Table 4--Summary of Annual Costs for New and Existing Sources
----------------------------------------------------------------------------------------------------------------
                                                                                     Estimated/
                                                                                     projected        Total
                     Source                                 Subcategory                No. of    annualized cost
                                                                                      affected   (TAC) ($10 \6\/
                                                                                       units         yr) \a\
----------------------------------------------------------------------------------------------------------------
Existing Units.................................  Coal.............................        3,710             37
                                                 Biomass..........................       10,958             24
                                                 Oil..............................      168,003            374
Facility Energy Assessment.....................  All..............................  ...........             52
New Units \b\..................................  Coal.............................          155              0.4
                                                 Biomass..........................          200              2.6
                                                 Oil..............................        6,424             45
----------------------------------------------------------------------------------------------------------------
\a\ TAC does not include fuel savings from improving combustion efficiency.
\b\ Impacts for new units assume the number of units online in the first 3 years of this rule (2010 to 2013).

    Using Department of Energy projections on fuel expenditures, as 
well as the history of installation dates of area source boilers in the 
dataset, the number of additional boilers that could be potentially 
constructed was estimated. The resulting total national cost impact of 
this proposed rule on new sources by the third year, 2013, is $48 
million dollars in total annualized costs. When accounting for a 1 
percent fuel savings resulting from improvements to combustion 
efficiency, the total national cost impact on new sources is -$3.6 
million.
    A discussion of the methodology used to estimate cost impacts is 
presented in the memorandum, ``Estimation of Impacts for Industrial, 
Commercial, and Institutional Boilers Area Source NESHAP'' in the 
Docket.

C. What are the economic impacts?

    The economic impact analysis (EIA) that is included in the RIA 
shows that the expected prices for industrial sectors could be 0.01 
percent higher and

[[Page 15580]]

domestic production may fall by less than 0.01 percent. Because of 
higher domestic prices, imports may rise by less than 0.01 percent. 
Energy prices will not be affected.
    Social costs are estimated to be also $0.49 billion in 2008 
dollars. This is estimated to made up of a $0.24 billion loss in 
domestic consumer surplus, a $0.25 billion loss in domestic producer 
surplus, a $0.004 billion increase in rest of the world surplus, and a 
$0.003 billion net loss associated with new source costs and fuel 
savings not modeled in a way that can be used to attribute it to 
consumers and producers.
    EPA performed a screening analysis for impacts on small entities by 
comparing compliance costs to sales/revenues (e.g., sales and revenue 
tests). EPA's analysis found the tests were typically higher for small 
entities included in the screening analysis. EPA has prepared an 
Initial Regulatory Flexibility Analysis (IRFA) that discusses 
alternative regulatory or policy options that minimize this final 
rule's small entity impacts. It includes key information about key 
results from the Small Business Advocacy Review (SBAR) panel. The IRFA 
is discussed in section 5.2 of the report ``Regulatory Impact Analysis: 
National Emission Standards for Hazardous Air Pollutants for 
Industrial, Commercial, and Institutional Boilers and Process Heater'' 
located in the docket. EPA has also prepared A Final Regulatory 
Flexibility Analysis (FRFA) that is found in section 5 of the RIA.
    In addition to estimating this rule's social costs and benefits, 
EPA has estimated the employment impacts of the final rule. We expect 
that the rule's direct impact on employment will be small. We have not 
quantified the rule's indirect or induced impacts. For further 
explanation and discussion of our analysis, see Chapter 4 of the RIA.

D. What are the benefits?

    The benefit categories associated with the emission reduction 
anticipated for this rule can be broadly categorized as those benefits 
attributable to reduced exposure to hazardous air pollutants (HAPs) and 
those attributable to exposure to other pollutants. Because we were 
unable to monetize the benefits associated with reducing HAPs, all 
monetized benefits reflect improvements in ambient PM2.5 and 
ozone concentrations. This results in an underestimate of the total 
monetized benefits. We estimated the total monetized benefits of this 
final regulatory action to be $210 million to $520 million (2008$, 3 
percent discount rate) in the implementation year (2014). The monetized 
benefits at a 7 percent discount rate are $190 million to $470 million 
(2008$). Using alternate relationships between PM2.5 and 
premature mortality supplied by experts, higher and lower benefits 
estimates are plausible, but most of the expert-based estimates fall 
between these two estimates.\8\ A summary of the monetized benefits 
estimates at discount rates of 3 percent and 7 percent are provided in 
Table 6 of this preamble. A summary of the avoided health benefits are 
provided in Table 7 of this preamble.
---------------------------------------------------------------------------

    \8\ Roman et al., 2008. Expert Judgment Assessment of the 
Mortality Impact of Changes in Ambient Fine Particulate Matter in 
the U.S. Environ. Sci. Technol., 42, 7, 2268--2274.

           Table 6--Summary of the Monetized Benefits Estimates for the Final Boiler Area Source Rule
                                             [Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                      Emissions reductions    Total monetized benefits  Total monetized benefits
             Pollutant                       (tons)            (at 3%  discount rate)    (at 7%  discount rate)
----------------------------------------------------------------------------------------------------------------
Direct PM2.5.......................  678                     $79 to $190                $72 to $180
SO2................................  3,197                   130 to 320                 120 to 290
                                    ----------------------------------------------------------------------------
    Total..........................  ......................  210 to 520                 190 to 470
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2014), and are rounded to two significant figures so numbers
  may not sum across rows. All fine particles are assumed to have equivalent health effects. Benefits from
  reducing HAP are not included. These estimates do not include energy disbenefits valued at less than $1
  million. These benefits reflect existing boilers and 6,779 new boilers anticipated to come online by 2014.


 Table 7--Summary of the Avoided Health Incidences for the Final Boiler
                                  MACT
------------------------------------------------------------------------
                                               Avoided health incidences
------------------------------------------------------------------------
Avoided Premature Mortality..................  24 to 61
Avoided Morbidity:
    Chronic Bronchitis.......................  17
    Acute Myocardial Infarction..............  40
    Hospital Admissions, Respiratory.........  6
    Hospital Admissions, Cardiovascular......  13
    Emergency Room Visits, Respiratory.......  21
    Acute Bronchitis.........................  38
Work Loss Days...............................  3,200
Asthma Exacerbation..........................  420
Minor Restricted Activity Days...............  19,000
Lower Respiratory Symptoms...................  460
Upper Respiratory Symptoms...................  350
------------------------------------------------------------------------
Note: All estimates are for the implementation year (2014), and are
  rounded to two significant figures and whole numbers. All fine
  particles are assumed to have equivalent health effects. Benefits from
  reducing HAP are not included. These benefits reflect existing boilers
  and 6,779 new boilers anticipated to come online by 2014.


[[Page 15581]]

    These quantified benefits estimates represent the human health 
benefits associated with reducing exposure to PM2.5. The PM 
reductions are the result of emission limits on PM as well as emission 
limits on other pollutants, including HAP. To estimate the human health 
benefits, we used the environmental Benefits Mapping and Analysis 
Program (BenMAP) model to quantify the changes in PM2.5-
related health impacts and monetized benefits based on changes in air 
quality. This approach is consistent with the recently proposed 
Transport Rule RIA.\9\
---------------------------------------------------------------------------

    \9\ U.S. Environmental Protection Agency, 2010. RIA for the 
Proposed Federal Transport Rule. Prepared by Office of Air and 
Radiation. June. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/proposaltrria_final.pdf.
---------------------------------------------------------------------------

    For this final rule, we have expanded and updated the analysis 
since the proposal in several important ways. Using the Comprehensive 
Air Quality Model with extensions (CAMx) model, we are able to provide 
boiler sector-specific air quality impacts attributable to the emission 
reductions anticipated from this final rule. We believe that this 
modeling provides estimates that are more appropriate for 
characterizing the health impacts and monetized benefits from boilers 
than the generic benefit-per-ton estimates used for the proposal 
analysis.
    To generate the boiler sector-specific benefit-per-ton estimates, 
we used CAMx to convert emissions of direct PM2.5 and 
PM2.5 precursors into changes in ambient PM2.5 
levels and BenMAP to estimate the changes in human health associated 
with that change in air quality. Finally, the monetized health benefits 
were divided by the emission reductions to create the boiler sector-
specific benefit-per-ton estimates. These models assume that all fine 
particles, regardless of their chemical composition, are equally potent 
in causing premature mortality because there is no clear scientific 
evidence that would support the development of differential effects 
estimates by particle type. Directly emitted PM2.5 and 
SO2 are the dominant PM2.5 precursors affected by 
this rule. Even though we assume that all fine particles have 
equivalent health effects, the benefit-per-ton estimates vary between 
precursors because each ton of precursor reduced has a different 
propensity to form PM2.5. For example, SO2 has a 
lower benefit-per-ton estimate than direct PM2.5 because it 
does not directly transform into PM2.5, and because sulfate 
particles formed from SO2 emissions can transport many 
miles, including over areas with low populations. Direct 
PM2.5 emissions convert directly into ambient 
PM2.5, thus, to the extent that emissions occur in 
population areas, exposures to direct PM2.5 will tend to be 
higher, and monetized health benefits will be higher than for 
SO2 emissions.
    Furthermore, CAMx modeling allows us to model the reduced mercury 
deposition that would occur as a result of the estimated reductions of 
mercury emissions. Although we are unable to model mercury methylation 
and human consumption of mercury-contaminated fish, the mercury 
deposition maps provide an improved qualitative characterization of the 
mercury benefits associated with this final rulemaking.
    For context, it is important to note that the magnitude of the PM 
benefits is largely driven by the concentration response function for 
premature mortality. Experts have advised EPA to consider a variety of 
assumptions, including estimates based on both empirical 
(epidemiological) studies and judgments elicited from scientific 
experts, to characterize the uncertainty in the relationship between 
PM2.5 concentrations and premature mortality. For this rule, 
we cite two key empirical studies, one based on the American Cancer 
Society cohort study \10\ and the extended Six Cities cohort study.\11\ 
In the RIA for this rule, which is available in the docket, we also 
include benefits estimates derived from expert judgments and other 
assumptions.
---------------------------------------------------------------------------

    \10\ Pope et al, 2002. ``Lung Cancer, Cardiopulmonary Mortality, 
and Long-term Exposure to Fine Particulate Air Pollution.'' Journal 
of the American Medical Association. 287:1132-1141.
    \11\ Laden et al., 2006. ``Reduction in Fine Particulate Air 
Pollution and Mortality.'' American Journal of Respiratory and 
Critical Care Medicine. 173:667-672.
---------------------------------------------------------------------------

    EPA strives to use the best available science to support our 
benefits analyses. We recognize that interpretation of the science 
regarding air pollution and health is dynamic and evolving. After 
reviewing the scientific literature and recent scientific advice, we 
have determined that the no-threshold model is the most appropriate 
model for assessing the mortality benefits associated with reducing 
PM2.5 exposure. Consistent with this recent advice, we are 
replacing the previous threshold sensitivity analysis with a new LML 
assessment. While an LML assessment provides some insight into the 
level of uncertainty in the estimated PM mortality benefits, EPA does 
not view the LML as a threshold and continues to quantify PM-related 
mortality impacts using a full range of modeled air quality 
concentrations.
    Most of the estimated PM-related benefits in this rule would accrue 
to populations exposed to higher levels of PM2.5. Using the 
Pope, et al., (2002) study, 79 percent of the population is exposed at 
or above the LML of 7.5 [mu]g/m\3\. Using the Laden, et al., (2006) 
study, 34 percent of the population is exposed above the LML of 10 
[mu]g/m\3\. It is important to emphasize that we have high confidence 
in PM2.5-related effects down to the lowest LML of the major 
cohort studies. This fact is important, because as we estimate PM-
related mortality among populations exposed to levels of 
PM2.5 that are successively lower, our confidence in the 
results diminishes. However, our analysis shows that the great majority 
of the impacts occur at higher exposures.
    It should be emphasized that the monetized benefits estimates 
provided above do not include benefits from several important benefit 
categories, including reducing other air pollutants, ecosystem effects, 
and visibility impairment. The benefits from reducing other pollutants 
have not been monetized in this analysis, including reducing 1,100 tons 
of CO, 340 tons of HCl, 8 tons of HF, 90 pounds of mercury, and 320 
tons of other metals each year. Specifically, we were unable to 
estimate the benefits associated with HAPs that would be reduced as a 
result of this rule due to data, resource, and methodology limitations. 
Challenges in quantifying the HAP benefits include a lack of exposure-
response functions, uncertainties in emissions inventories and 
background levels, the difficulty of extrapolating risk estimates to 
low doses, and the challenges of tracking health progress for diseases 
with long latency periods. Although we do not have sufficient 
information or modeling available to provide monetized estimates for 
this rulemaking, we include a qualitative assessment of the health 
effects of these air pollutants in the RIA for this rule, which is 
available in the docket.
    In addition, the monetized benefits estimates provided in Table 6 
do not reflect the disbenefits associated with increased electricity 
usage from operation of the control devices. We estimate that the 
increases in emissions of CO2 would have disbenefits valued 
at less than $1 million at a 3 percent discount rate (average). 
CO2-related disbenefits were calculated using the social 
cost of carbon, which is discussed further in the RIA. However, these 
disbenefits do not change the rounded total monetized benefits. In the 
RIA, we also provide the monetized CO2 disbenefits using 
discount rates of 5 percent (average), 2.5 percent (average), and 3 
percent (95th percentile).

[[Page 15582]]

    This analysis does not include the type of detailed uncertainty 
assessment found in the 2006 PM2.5 NAAQS RIA or 2008 Ozone 
NAAQS RIA. However, the benefits analyses in these RIAs provide an 
indication of the sensitivity of our results to various assumptions, 
including the use of alternative concentration-response functions and 
the fraction of the population exposed to low PM2.5 levels.
    For more information on the benefits analysis, please refer to the 
RIA for this final rule that is available in the docket.

E. What are the water and solid waste impacts?

    EPA estimated that no additional water usage would result from the 
MACT floor level of control or GACT requirement. The fabric filter, 
multiclone, or combustion control devices used to meet the standards of 
this rule do not require any water to operate, nor do they generate any 
wastewater.
    EPA estimated the additional solid waste that would result from 
this rule to be 1,800 tpy for existing sources due to the dust and fly 
ash captured by mercury and PM control devices. The cost of handling 
the additional solid waste generated from existing sources is $75,700 
per year. For new sources installed by 2013, the EPA estimated the 
additional solid waste that would result from this rule to be 540 tpy 
for new sources due to the dust and fly ash captured by mercury and PM 
control devices. The cost of handling the additional solid waste 
generated from new sources is $22,900 per year. These costs are also 
accounted for in the control costs estimates.
    A discussion of the methodology used to estimate impacts is 
presented in ``Estimation of Impacts for Industrial, Commercial, and 
Institutional Boilers Area Source NESHAP'' in the Docket.

F. What are the energy impacts?

    EPA expects an increase of approximately 25 million kWh in national 
annual energy usage from existing sources as a result of this rule. The 
increase results from the electricity required to operate control 
devices installed to meet this rule, such as fabric filters. 
Additionally, for new sources installed by 2013, EPA expects an 
increase of approximately 8 million kWh in national annual energy usage 
in order to operate the control devices.
    The Department of Energy has conducted energy assessments at 
selected manufacturing facilities and reports that facilities can 
reduce fuel/energy use by 10 to 15 percent by using best practices to 
increase their energy efficiency. Additionally, the EPA expects work 
practice standards, such as boiler tune-ups, and combustion controls 
such as new replacement burners, will improve the efficiency of 
boilers. EPA estimates existing area source facilities can save 20 
trillion Btu of fuel each year. For new sources online by 2013, the EPA 
estimates 2.3 trillion BTU per year of fuel can be conserved. This fuel 
savings estimate includes only those fuel savings resulting from liquid 
and coal fuels and it is based on the assumption that the work practice 
standards will achieve 1 percent improvement in efficiency.

VIII. Statutory and Executive Order Review

A. Executive Order 12866 and 13563: Regulatory Planning and Review

    Under section 3(f)(1) of Executive Order 12866 (58 FR 51735, 
October 4, 1993) and 13563 (76 FR 3821, January 21, 2011), this action 
is an ``economically significant regulatory action'' because it is 
likely to have an annual effect on the economy of $100 million or more 
or adversely affect in a material way the economy, a sector of the 
economy, productivity, competition, jobs, the environment, public 
health or safety, or state, local, or tribal governments or 
communities. Accordingly, EPA submitted this action to OMB for review 
under EO 12866 and any changes in response to OMB recommendations have 
been documented in the docket for this action.
    In addition, EPA prepared an analysis of the potential costs and 
benefits associated with this action. This analysis is contained in the 
Regulatory Impact Analysis (RIA) report. For more information on the 
costs and benefits for this rule, see the following table.

    Summary of the Monetized Benefits, Social Costs, and Net Benefits for the Boiler Area Source Rule in 2014
                                             [Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                                    3% Discount rate                    7% Discount rate
----------------------------------------------------------------------------------------------------------------
                                       Final MACT/GACT Approach: Selected
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\.............  $210 to $520                        $190 to $470
Total Social Costs \3\...................  $490                                $490
Net Benefits.............................  -$280 to $30                        -$300 to -$20
                                           1,100 tons of carbon monoxide
                                           340 tons of HCl
                                           8 tons of HF
                                           90 pounds of mercury
Non-monetized Benefits...................  320 tons of other metals
                                           <1 gram of dioxins/furans (TEQ)
                                           Health effects from SO2 exposure
                                           Ecosystem effects
                                           Visibility impairment
----------------------------------------------------------------------------------------------------------------
                                       Proposed MACT Approach: Alternative
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\.............  $200 to $490                        $180 to $440
Total Social Costs \3\...................  $850                                $850
Net Benefits.............................  -$650 to -$360                      -$670 to -$410
Non-monetized Benefits...................  1,100 tons of carbon monoxide
                                           340 tons of HCl
                                           8 tons of HF
                                           90 pounds of mercury
                                           320 tons of other metals

[[Page 15583]]

 
                                           <1 gram of dioxins/furans (TEQ)
                                           Health effects from SO2 exposure
                                           Ecosystem effects
                                           Visibility impairment
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2014), and are rounded to two significant figures. These
  results include units anticipated to come online and the lowest cost disposal assumption.
\2\ The total monetized benefits reflect the human health benefits associated with reducing exposure to PM2.5
  through reductions of directly emitted PM2.5 and PM2.5 precursors such as SO2. It is important to note that
  the monetized benefits include many but not all health effects associated with PM2.5 exposure. Benefits are
  shown as a range from Pope et al. (2002) to Laden et al. (2006). These models assume that all fine particles,
  regardless of their chemical composition, are equally potent in causing premature mortality because there is
  no clear scientific evidence that would support the development of differential effects estimates by particle
  type. These estimates include energy disbenefits valued at less than $1 million.
\3\ The methodology used to estimate social costs for one year in the multimarket model using surplus changes
  results in the same social costs for both discount rates.

B. Paperwork Reduction Act

    The information collection requirements in this rule have been 
submitted for approval to OMB under the Paperwork Reduction Act, 44 
U.S.C. 3501 et seq. The information collection requirements are not 
enforceable until OMB approves them. The ICR document prepared by EPA 
has been assigned EPA ICR number 2253.01. The recordkeeping and 
reporting requirements in this rule are based on the information 
collection requirements in EPA's NESHAP General Provisions (40 CFR part 
63, subpart A). The recordkeeping and reporting requirements in the 
General Provisions are mandatory pursuant to CAA section 114 (42 U.S.C. 
7414). All information other than emissions data submitted to EPA 
pursuant to the information collection requirements for which a claim 
of confidentiality is made is safeguarded according to CAA section 
114(c) and EPA's implementing regulations at 40 CFR part 2, subpart B.
    This NESHAP would require applicable one-time notifications 
according to the NESHAP General Provisions. Facility owners or 
operators are required to include compliance certifications for the 
work practices and management practices in their Notifications of 
Compliance Status. Recordkeeping is required to demonstrate compliance 
with emission limits, work practices, management practices, monitoring, 
and applicability provisions. New affected facilities are required to 
comply with the requirements for startup, shutdown, and malfunction 
reports and to submit a compliance report if a deviation occurred 
during the semiannual reporting period.
    When a malfunction occurs, sources must report them according to 
the applicable reporting requirements of this Subpart JJJJJJ. An 
affirmative defense to civil penalties for exceedances of emission 
limits that are caused by malfunctions is available to a source if it 
can demonstrate that certain criteria and requirements are satisfied. 
The criteria ensure that the affirmative defense is available only 
where the event that causes an exceedance of the emission limit meets 
the narrow definition of malfunction in 40 CFR 63.2 (sudden, 
infrequent, not reasonably preventable and not caused by poor 
maintenance and or careless operation) and where the source took 
necessary actions to minimize emissions. In addition, the source must 
meet certain notification and reporting requirements. For example, the 
source must prepare a written root cause analysis and submit a written 
report to the Administrator documenting that it has met the conditions 
and requirements for assertion of the affirmative defense.
    To provide the public with an estimate of the relative magnitude of 
the burden associated with an assertion of the affirmative defense 
position adopted by a source, EPA provides an administrative adjustment 
to this ICR that shows what the notification, recordkeeping and 
reporting requirements associated with the assertion of the affirmative 
defense might entail. EPA's estimate for the required notification, 
reports and records, including the root cause analysis, totals $3,141 
and is based on the time and effort required of a source to review 
relevant data, interview plant employees, and document the events 
surrounding a malfunction that has caused an exceedance of an emission 
limit. The estimate also includes time to produce and retain the record 
and reports for submission to EPA. EPA provides this illustrative 
estimate of this burden because these costs are only incurred if there 
has been a violation and a source chooses to take advantage of the 
affirmative defense.
    The annual monitoring, reporting, and recordkeeping burden for this 
collection (averaged over the first 3 years after the effective date of 
the standards) is estimated to be $407 million. This includes 2.7 
million labor hours per year at a cost of $254 million and total non-
labor capital costs of $153 million per year. This estimate includes 
initial and triennial performance tests, conducting and documenting an 
energy assessment, conducting and documenting a tune-up, semiannual 
excess emission reports, maintenance inspections, developing a 
monitoring plan, notifications, and recordkeeping. Monitoring, testing, 
tune-up and energy assessment costs were also included in the cost 
estimates presented in the control cost impacts estimates in Section 
VII.B of this preamble. The total burden for the federal government 
(averaged over the first 3 years after the effective date of the 
standard) is estimated to be 286,000 hours per year at a total labor 
cost of $13 million per year. Burden is defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless the collection 
displays a currently valid OMB control number. The OMB control numbers 
for EPA's regulations in 40 CFR part 63 are listed in 40 CFR part 9. 
When this ICR is approved by OMB, the Agency will publish a technical 
amendment to 40 CFR part 9 in the Federal Register to display the OMB 
control number for the approved information collection requirements 
contained in this final rule.

[[Page 15584]]

C. Regulatory Flexibility Act, as Amended by the Small Business 
Regulatory Enforcement Fairness Act of 1996

    Pursuant to section 603 of the RFA, EPA prepared an initial 
regulatory flexibility analysis (IRFA) for the proposed rule and 
convened a Small Business Advocacy Review Panel to obtain advice and 
recommendations of representatives of the regulated small entities. A 
detailed discussion of the Panel's advice and recommendations is found 
in the final Panel Report (Docket ID No. EPA-HQ-OAR-2002-0058-0797). A 
summary of the Panel's recommendations is also presented in the 
preamble to the proposed rule at 75 FR 32044-32045 (June 4, 2010). In 
the proposed rule, EPA included provisions consistent with four of the 
Panel's recommendations. As required by section 604 of the RFA, we also 
prepared a final regulatory flexibility analysis (FRFA) the final rule.
    The rule is intended to reduce emissions of HAP as required under 
section 112 of the CAA. Section II.A of this preamble describes the 
reasons that EPA is finalizing this action.
    Many significant issues were raised during the public comment 
period, and EPA's responses to those comments are presented in section 
V of this preamble or in the response to comments document contained in 
the docket. Significant changes to the rule that resulted from the 
public comments are described in section IV of the final rule's 
preamble.
    The primary comments on the IRFA were provided by SBA, with the 
remainder of the comments generally supporting SBA's comments. Those 
comments applicable to the proposal regarding area source boilers 
included the following: EPA should have adopted additional 
subcategories, including the following: Unit design type (e.g. 
fluidized bed, stoker, fuel cell, suspension burner), duty cycle, 
geographic location, boiler size, burner type (with and without low-
NOX burners), and hours of use (limited use); EPA should 
have minimized facility monitoring and reporting requirements; EPA 
should not have proposed the energy audit requirement; and EPA's 
proposed emissions standards are too stringent.
    In response to the comments on the IRFA and other public comments, 
EPA made the following changes to the final rule. EPA is promulgating 
management practice standards requiring the implementation of a boiler 
tune-up program for area source boilers in the biomass and oil 
subcategories instead of the proposed CO emission limits. This change 
will significantly reduce the monitoring and testing costs for existing 
and new biomass-fired and oil-fired area source boilers. EPA also 
decreased monitoring and testing costs for coal-fired area source 
boilers by eliminating the CO CEMS requirement for boilers greater than 
100 MMBtu/h. The final rule also includes work practice standards or 
management practice standards, instead of emission limits, for new area 
source boilers less than 10 MMBtu/h. Finally, EPA is finalizing 
emission limits that are less stringent than the proposed limits. The 
emission limit changes are largely due to the changes in data 
corrections and incorporation of new data into the floor calculations. 
Additional details on the changes discussed in this paragraph are 
included in sections IV and V of the final rule's preamble.
    Table 5 of this preamble summarizes the EPA estimates of the number 
of area source facilities expected to be affected by the area source 
rule. EPA does not have sufficient information to estimate the number 
of small entities expected to be covered by the area source rule.
    As discussed in section 5.1 of the RIA for this rule, using these 
cost data and the Census estimates of average establishment receipts, a 
substantial number of SUSB NAICS/enterprise categories have ratios over 
3%. The following types of representative small area source public 
facilities would have cost-to-revenue ratios exceeding 1 percent but 
below 3 percent: Other public facilities (ratio >1.7 percent) and 
churches (ratio = 1.5 percent).

 Table 5--Estimated Affected Facilities Using 13 State Boiler Inspector
                         Inventory: Area Sources
------------------------------------------------------------------------
                                                           Total number
                                                            of affected
                           SIC                             facilities in
                                                             SIC Code
------------------------------------------------------------------------
01......................................................               0
02......................................................             247
07......................................................               0
09......................................................               0
14......................................................              83
16......................................................               0
17......................................................             247
20......................................................           5,733
23......................................................              83
24......................................................           2,676
26......................................................               0
40......................................................             329
41......................................................               0
42......................................................              83
43......................................................               0
44......................................................               0
45......................................................               0
47......................................................               0
48......................................................             741
50......................................................             165
51......................................................             247
52......................................................               0
53......................................................             494
54......................................................               0
55......................................................             801
56......................................................               0
57......................................................               0
58......................................................             905
59......................................................             288
60......................................................             329
64......................................................               0
65......................................................           2,878
70......................................................           4,893
72......................................................           2,138
73......................................................             165
75......................................................           1,606
76......................................................               0
79......................................................           1,151
80......................................................          15,293
81......................................................               0
82......................................................          33,303
83......................................................               0
84......................................................             165
86......................................................           3,330
87......................................................             666
91 to 98................................................           5,098
Unknown.................................................             576
------------------------------------------------------------------------

    The information collection activities in this ICR include initial 
and triennial stack tests, fuel analyses, operating parameter 
monitoring, continuous oxygen monitoring for all coal-fired area source 
boilers greater than 10 MMBtu/h, certified energy assessments for area 
source facilities having a boiler greater than 10 MMBtu/h, biennial 
tune-ups, preparation of a startup, shutdown, malfunction plan (SSMP), 
preparation of a site-specific monitoring plan and a site-specific fuel 
monitoring plan, one-time and periodic reports, and the maintenance of 
records. Based on 13 states' inventories of boilers, there are an 
estimated 92,000 existing facilities with affected boilers. It is 
estimated that 53 percent are located in the private sector and the 
remaining 47 percent are located in the public sector. Of these, only 
about 0.3 percent of the area source facilities are subject to emission 
limits and the testing and monitoring requirements in the final rule. A 
table included in the FRFA summarizes the types and number of each type 
of small entities expected to be affected by the area source rule.
    The Agency expects that persons with knowledge of .pdf software, 
spreadsheet and relational database programs will be

[[Page 15585]]

necessary in order to prepare the report or record. Based on experience 
with previous emission stack testing, we expect most facilities to 
contract out preparation of the reports associated with emission stack 
testing, including creation of the Electronic Reporting Tool submittal 
which will minimize the need for in depth knowledge of databases or 
spreadsheet software at the source. We also expect affected sources 
will need to work with web-based applicability tools and flowcharts to 
determine the requirements applicable to them, knowledge of the heat 
input capacity and fuel use of the combustion units at each facility 
will be necessary in order to develop the reports and determine initial 
applicability to the rule. Affected facilities will also need skills 
associated with vendor selection in order to identify service providers 
that can help them complete their compliance requirements, as 
necessary.
    While EPA did make significant changes based on public comment, EPA 
is maintaining, but clarifying, the energy assessment requirement. Some 
changes to the energy assessment requirement that will reduce costs for 
small entities include a the following provisions: The energy 
assessment for facilities with affected boilers using less than 0.3 
trillion Btu per year heat input will be one day in length maximum. The 
boiler system and energy use system accounting for at least 50 percent 
of the energy output will be evaluated to identify energy savings 
opportunities, within the limit of performing a one-day energy 
assessment; and the energy assessment for facilities with affected 
boilers using 0.3 to 1.0 trillion Btu per year will be 3 days in length 
maximum. The boiler system and any energy use system accounting for at 
least 33 percent of the energy output will be evaluated to identify 
energy savings opportunities, within the limit of performing a 3-day 
energy assessment. In addition, the final rule allows facilities to use 
a previously completed energy assessment to satisfy the energy 
assessment requirement.
    As required by section 212 of SBREFA, EPA also is preparing a Small 
Entity Compliance Guide to help small entities comply with this rule. 
Small entities will be able to obtain a copy of the Small Entity 
Compliance guide at the following Web site: http://www.epa.gov/ttn/atw/boiler/boilerpg.html.

D. Unfunded Mandates Reform Act of 1995

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), Public 
Law 104-4, establishes requirements for Federal agencies to assess the 
effects of their regulatory actions on state, local, and tribal 
governments and the private sector. Under section 202 of the UMRA, we 
generally must prepare a written statement, including a cost-benefit 
analysis, for proposed and final rules with ``federal mandates'' that 
may result in expenditures to state, local, and tribal governments, in 
the aggregate, or to the private sector, of $100 million or more in any 
1 year. Before promulgating a rule for which a written statement is 
needed, section 205 of the UMRA generally requires us to identify and 
consider a reasonable number of regulatory alternatives and adopt the 
least costly, most cost-effective or least burdensome alternative that 
achieves the objectives of this final rule. The provisions of section 
205 do not apply when they are inconsistent with applicable law. 
Moreover, section 205 allows us to adopt an alternative other than the 
least costly, most cost-effective or least burdensome alternative if 
the Administrator publishes with this final rule an explanation why 
that alternative was not adopted. Before we establish any regulatory 
requirements that may significantly or uniquely affect small 
governments, including tribal governments, we must develop a small 
government agency plan under section 203 of the UMRA. The plan must 
provide for notifying potentially affected small governments, enabling 
officials of affected small governments to have meaningful and timely 
input in the development of regulatory proposals with significant 
Federal intergovernmental mandates, and informing, educating, and 
advising small governments on compliance with the regulatory 
requirements.
    We have determined that this rule contains a Federal mandate that 
may result in expenditures of $100 million or more for state, local, 
and tribal governments, in the aggregate, or the private sector in any 
1 year. Accordingly, we have prepared a written statement entitled 
``Unfunded Mandates Reform Act Analysis for the Boiler Area Source 
NESHAP'' under section 202 of the UMRA which is summarized below.
1. Statutory Authority
    As discussed in Section I of this preamble, the statutory authority 
for this rulemaking is CAA section 112. Title III of the CAA was 
enacted to reduce nationwide air toxic emissions. Section 112(b) of the 
CAA lists the 188 chemicals, compounds, or groups of chemicals deemed 
by Congress to be HAP. These toxic air pollutants are to be regulated 
by NESHAP.
    Section 112(d) of the CAA requires us to establish NESHAP for both 
major and area sources of HAP that are listed for regulation under CAA 
section 112(c). CAA section 112(k)(3)(B) calls for EPA to identify at 
least 30 HAP which, as the result of emissions from area sources, pose 
the greatest threat to public health in the largest number of urban 
areas. CAA section 112(c)(3) requires 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), we may elect to promulgate standards 
or requirements for area sources based on GACT used by those sources to 
reduce emissions of HAP. Determining what constitutes GACT involves 
considering the control technologies and management practices that are 
generally available to the area sources in the source category. We also 
consider the standards applicable to major sources in the analogous 
source category and, as appropriate, the control technologies and 
management practices at area and major sources in similar categories, 
to determine if the standards, technologies, and/or practices are 
transferable and generally available to area sources. In determining 
GACT for a particular area source category, we consider the costs and 
economic impacts of available control technologies and management 
practices on that category.
    While GACT may be a basis for standards for most types of HAP 
emitted from area source, CAA section 112(c)(6) requires that source 
categories accounting for emissions of the HAP listed in CAA section 
112(c)(6) be subject to standards under CAA section 112(d)(2) for the 
listed pollutants. Thus, CAA section 112(c)(6) requires that emissions 
of each listed HAP for the listed categories be subject to MACT 
regulation. The CAA section 112(c)(6) list of source categories 
includes industrial boilers and institutional/commercial boilers. 
Within these two source categories, coal combustion, oil combustion, 
and wood combustion have been on the CAA section 112(c)(6) list because 
of emissions of mercury and POM. We currently believe that regulation 
of coal-fired boilers will ensure that we fulfill our obligation under 
CAA section 112(c)(6) with respect to mercury and POM reductions. 
Consequently, we deem it reasonable to regulate the coal-fired boilers 
under MACT, rather than the biomass and oil-fired boilers, to obtain 
additional mercury and POM reductions towards achieving the CAA section 
112(c)(6)

[[Page 15586]]

obligation. We are regulating biomass-fired and oil-fired boilers under 
GACT.
    This NESHAP will apply to all existing and new industrial boilers, 
institutional boilers, and commercial boilers located at area sources. 
In compliance with section 205(a) of the UMRA, we identified and 
considered a reasonable number of regulatory alternatives. Additional 
information on the costs and environmental impacts of these regulatory 
alternatives is presented in the docket.
    The emission limits for existing area source boilers are only 
applicable to area source boilers that have a designed heat input 
capacity of 10 MMBtu/h or greater. The regulatory alternative upon 
which the standards are based represents the MACT floor for the listed 
CAA section 112(c)(6) pollutants (mercury and POM) for coal-fired units 
and GACT for the other urban HAP which formed the basis for the listing 
of these two area source categories. The standards will require new 
coal-fired boilers to meet MACT-based emission limits for mercury and 
CO (as a surrogate for POM) and GACT-based emission limits for PM (as a 
surrogate for urban metals). New biomass and oil-fired boilers will be 
required to meet GACT for CO, which are tune-ups, and GACT-based 
emission limits for PM. Existing large coal-fired boilers will be 
required to meet MACT-based emission limits for mercury and CO for 
coal-fired units, and existing large biomass and oil-fired boilers will 
be subject to GACT, which is a tune-up. As allowed under CAA section 
112(h), a work practice standard requiring the implementation of a 
tune-up program is being established for existing and new area source 
boilers with a designed heat input capacity of less than 10 MMBtu/h. An 
additional ``beyond-the-floor'' standard is being established for 
existing area source facilities having an affected boiler with a heat 
input capacity of 10 MMBtu/h or greater that requires the performance 
of an energy assessment on the boiler and the facility to identify 
cost-effective energy conservation measures.
2. Social Costs and Benefits
    The regulatory impact analysis prepared for this final rule 
including the Agency's assessment of costs and benefits, is detailed in 
the ``Regulatory Impact Analysis: National Emission Standards for 
Hazardous Air Pollutants for Industrial, Commercial, and Institutional 
Boilers and Process Heaters'' in the docket. Based on estimated 
compliance costs associated with this final rule and the predicted 
change in prices and production in the affected industries, the 
estimated social costs of this final rule are $0.49 billion (2008 
dollars).
    It is estimated that 3 years after implementation of this final 
rule, HAP will be reduced by hundreds of tons, including reductions in 
metallic HAP including mercury, hydrochloric acid, hydrogen fluoride, 
and several other organic HAP from area source boilers. Studies have 
determined a relationship between exposure to these HAP and the onset 
of cancer; however, the Agency is unable to provide a monetized 
estimate of the HAP benefits at this time. In addition, there are 
reductions in PM2.5 and in SO2 that will occur, 
including 678 tons of PM2.5 and 3,197 tons of 
SO2. These reductions occur within 3 years after the 
implementation of the regulation and are expected to continue 
throughout the life of the affected sources. The major health effect 
associated with reducing PM2.5 and PM2.5 
precursors (such as SO2) is a reduction in premature 
mortality. Other health effects associated with PM2.5 
emission reductions include avoiding cases of chronic bronchitis, heart 
attacks, asthma attacks, and work-lost days (i.e., days when employees 
are unable to work). While we are unable to monetize the benefits 
associated with the HAP emissions reductions, we are able to monetize 
the benefits associated with the PM2.5 and SO2 
emissions reductions. For SO2.5 and PM2.5, we 
estimated the benefits associated with health effects of PM but were 
unable to quantify all categories of benefits (particularly those 
associated with ecosystem and visibility effects). Our estimates of the 
monetized benefits in 2013 associated with the implementation of this 
final rule range from $0.21 billion (2008 dollars) to $0.52 billion 
(2008 dollars) when using a 3 percent discount rate (or from $0.19 
billion (2008 dollars) to $0.47 billion (2008 dollars) when using a 7 
percent discount rate. The general approach used to value benefits is 
discussed in more detail in Section VII.D of this preamble. For more 
detailed information on the benefits estimated for the rulemaking, 
refer to the RIA in the docket.
3. Future and Disproportionate Costs
    The Unfunded Mandates Reform Act requires that we estimate, where 
accurate estimation is reasonably feasible, future compliance costs 
imposed by this final rule and any disproportionate budgetary effects. 
Our estimates of the future compliance costs of this final rule are 
discussed in Section VII.C of this preamble.
    We do not believe that there will be any disproportionate budgetary 
effects of this final rule on any particular areas of the country, 
state or local governments, types of communities (e.g., urban, rural), 
or particular industry segments. See the results of the ``Economic 
Impact Analysis of the Proposed Industrial Boilers and Process Heaters 
NESHAP,'' the results of which are discussed in Section VII.C of this 
preamble.
4. Effects on the National Economy
    The Unfunded Mandates Reform Act requires that we estimate the 
effect of the proposed rule on the national economy. To the extent 
feasible, we must estimate the effect on productivity, economic growth, 
full employment, creation of productive jobs, and international 
competitiveness of the U.S. goods and services, if we determine that 
accurate estimates are reasonably feasible and that such effect is 
relevant and material.
    The nationwide economic impact of this final rule is presented in 
the Economic Impact Analysis chapter (Section 4) of the RIA in the 
docket. This analysis provides estimates of the effect of this final 
rule on some of the categories mentioned above. The results of the 
economic impact analysis are summarized in Section VII.C of this 
preamble. The results show that there will be a small impact on prices 
and output (less than 0.01 percent). In addition, there should be 
little impact on energy markets (in this case, coal, natural gas, 
petroleum products, and electricity). Hence, the potential impacts on 
the categories mentioned above should be small.
5. Consultation With Government Officials
    The Unfunded Mandates Reform Act requires that we describe the 
extent of the Agency's prior consultation with affected state, local, 
and tribal officials, summarize the officials' comments or concerns, 
and summarize our response to those comments or concerns. In addition, 
section 203 of the UMRA requires that we develop a plan for informing 
and advising small governments that may be significantly or uniquely 
impacted by a proposal. Consistent with the intergovernmental 
consultation provisions of section 204 of the UMRA, EPA has initiated 
consultations with governmental entities affected by this rule. EPA 
invited the following 10 national organizations representing state and 
local elected officials to a meeting held on March 24, 2010 in 
Washington, DC: (1) National Governors Association; (2)

[[Page 15587]]

National Conference of State Legislatures, (3) Council of State 
Governments, (4) National League of Cities, (5) U.S. Conference of 
Mayors, (6) National Association of Counties, (7) International City/
County Management Association, (8) National Association of Towns and 
Townships, (9) County Executives of America, and (10) Environmental 
Council of States. These 10 organizations of elected state and local 
officials have been identified by EPA as the ``Big 10'' organizations 
appropriate to contact for purpose of consultation with elected 
officials. The purposes of the consultation were to provide general 
background on the proposal, answer questions, and solicit input from 
state/local governments. During the meeting, officials expressed 
uncertainty with regard to how boilers owned/operated by state and 
local entities would be impacted, as well as with regard to the 
potential burden associated with implementing this final rule on state 
and local entities. To that end, officials requested and EPA provided 
(1) model boiler costs, (2) inventory of area source boilers (coal, 
oil, biomass only) for the 13 states for which we have an inventory, 
and (3) information on potential size of boilers used for various 
facility types and sizes. EPA has not received additional questions or 
requests from state or local officials.
    Consistent with section 205, EPA identified and considered a 
reasonable number of regulatory alternatives. Because an initial 
screening analysis for impact on small entities indicated a likely 
significant impact for substantial numbers, EPA convened a SBAR Panel 
to obtain advice and recommendation of representatives of the small 
entities that potentially would be subject to the requirements of this 
final rule. As part of that process, EPA considered several options. 
Those options included establishing emission limits, establishing work 
practice standards, and establishing work practice standards and 
requiring an energy assessment. The regulatory alternative selected is 
a combination of the options considered and includes provisions 
regarding each of the SBAR Panel's recommendations for area source 
boilers. The recommendations regard the use of subcategories, work 
practice standards, and compliance costs (see section IX.C of this 
preamble for more detail on the RFA).
    EPA determined subcategories based on boiler type to be appropriate 
because different types of units have different emission 
characteristics which may affect the feasibility and effectiveness of 
emission control. Thus, this final rule identifies three subcategories 
of area source boilers: (1) Boilers designed for coal firing, (2) 
boilers designed for biomass firing, and (3) boilers designed for oil 
firing.
    The emission limits for existing and new area source boilers are 
only applicable to area source boilers that have a designed heat input 
capacity of 10 MMBtu/h or greater. A work practice standard (for 
mercury from coal-fired boilers and for POM from all boilers) or 
management practice (for all other HAP, including mercury from biomass-
fired and oil-fired boilers) requiring the implementation of a tune-up 
program is being established for existing area source boilers with a 
designed heat input capacity of less than 10 MMBtu/h. The regulatory 
alternative upon which the standards are based represents the MACT 
floor for mercury and POM (CO is used as a surrogate for POM) for coal-
fired boilers, and GACT for the other urban HAP (PM is used as a 
surrogate for urban HAP metals and CO is used as a surrogate for urban 
organic pollutants) for new coal, biomass, and oil-fired boilers. An 
additional ``beyond-the-floor'' standard is being established for 
existing area source facilities having an affected boiler with a heat 
input capacity of 10 MMBtu/h or greater that requires the performance 
of an energy assessment on the boiler and the facility to identify 
cost-effective energy conservation measures.
    The use of surrogate pollutants will result in reduced compliance 
costs because testing is only required for the surrogate pollutants 
(i.e., CO and PM) versus for the HAP (i.e., POM and metals). The work 
practice standard/management practice also will result in reduced 
compliance costs with respect to monitoring/testing for the smaller 
existing area source boilers. EPA's exemption of area source facilities 
from title V permit requirements also will reduce burden on area source 
boiler facilities.
    This rule is not subject to the requirements of section 203 of the 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. While some small 
governments may have boilers that will be affected by this final rule, 
EPA's analysis shows that other public facilities that are located at 
area source facilities owned by small entities will not have cost-to-
revenue ratios exceeding 10 percent. Hospitals' and schools' revenue 
tests fall below 1 percent. Because this final rule's requirements 
apply equally to boilers owned and/or operated by governments and to 
boilers owned and/or operated by private entities, there will be no 
requirements that uniquely apply to such governments or impose any 
disproportionate impacts on them.

E. Executive Order 13132: Federalism

    Under Executive Order 13132, EPA may not issue an action that has 
federalism implications, that imposes substantial direct compliance 
costs, and that is not required by statute, unless the federal 
government provides the funds necessary to pay the direct compliance 
costs incurred by state and local governments, or EPA consults with 
state and local officials early in the process of developing the 
proposed action.
    EPA has concluded that this action may have federalism 
implications, because it may impose substantial direct compliance costs 
on state or local governments, and the federal government will not 
provide the funds necessary to pay those costs. Accordingly, EPA 
provides the following federalism summary impact statement as required 
by section 6(b) of Executive Order 13132.
    Based on the estimates in EPA's RIA for today's action, the 
regulatory option may have federalism implications because the action 
may impose approximately $276 million in annual direct compliance costs 
on an estimated 57,000 state or local governments. Boiler inventories 
for the health services, educational services, and government-owned 
buildings sectors from 13 States were used to estimate the nationwide 
number of potentially impacted state or local governments. Because the 
inventories for these sectors include privately owned and federal 
government owned facilities, the estimate may include many facilities 
that are not state or local government owned. Table 8 of this preamble 
presents estimates of the number of potentially impacted state and 
local governments and their potential annual compliance costs for each 
of the three sectors. In addition to an estimate of the total number of 
potentially impacted facilities, estimates for facilities with small 
boilers and for facilities with large boilers are presented. Small 
boilers (boilers with heat input capacity of less than 10 MMBtu/h) will 
be subject to a work practice standard or management practice that 
requires a boiler tune-up every 2 years. Large coal-fired boilers 
(boilers with heat input capacity of 10 MMBtu/h or greater) will be 
subject to emission limits for mercury and CO. Large biomass and oil-
fired boilers will be subject to a biennial boiler tune-up requirement 
for CO. All facilities with

[[Page 15588]]

large boilers will be required to conduct a one-time energy assessment.

Table 8--State and Local Governments Potentially Impacted by the Standards for Boilers at Area Source Facilities
----------------------------------------------------------------------------------------------------------------
                                                           Number of potentially impacted
                                                                     facilities              Annual compliance
                         Sector                          ---------------------------------     costs to meet
                                                            Total      Small      Large        standards  ($)
----------------------------------------------------------------------------------------------------------------
Health Services.........................................     17,206     15,293      1,913  $84 million.
Educational Services....................................     34,052     33,303        749  159 million.
Government-Owned Buildings..............................      5,796      5,098        698  33 million.
                                                         -------------------------------------------------------
    Total...............................................     57,054     53,694      3,360  276 million.
----------------------------------------------------------------------------------------------------------------

    EPA consulted with state and local officials in the process of 
developing the action to permit them to have meaningful and timely 
input into its development. EPA met with 10 national organizations 
representing state and local elected officials to provide general 
background on the proposed rule, answer questions, and solicit input 
from state/local governments. The UMRA discussion in Section IX.D of 
this preamble includes a description of the consultation. As required 
by section 8(a) of Executive Order 13132, EPA included a certification 
from its Federalism Official stating that EPA had met the Executive 
Order's requirements in a meaningful and timely manner, when it sent 
the draft of this final action to OMB for review pursuant to Executive 
Order 12866. A copy of this certification has been included in the 
public version of the official record for this final 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). This final rule 
imposes requirements on owners and operators of specified area sources 
and not tribal governments. We do not know of any industrial, 
commercial, or institutional boilers owned or operated by Indian tribal 
governments. However, if there are any, the effect of this final rule 
on communities of tribal governments would not be unique or 
disproportionate to the effect on other communities. Thus, Executive 
Order 13175 does not apply to this action.

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

    This action is not subject to Executive Order 13045 because the 
Agency does not believe the environmental health risks or safety risks 
addressed by this action present a disproportionate risk to children. 
In addition, this action is not subject to Executive Order 13045 
because this final rule 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. For more 
information on the estimated energy effects, please refer to Section VI 
of this preamble. The analysis is available in the public docket.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act (NTTAA) of 1995 (Pub. L. 104-113, Section 12(d), 15 U.S.C. 272 
note) directs EPA to use voluntary consensus standards (VCS) in its 
regulatory activities, unless to do so would be inconsistent with 
applicable law or otherwise impractical. The VCS are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
VCS bodies. The NTTAA directs EPA to provide Congress, through OMB, 
explanations when the Agency does not use available and applicable VCS.
    This final rule involves technical standards. EPA cites the 
following standards in this final rule: EPA Methods 1, 2, 2F, 2G, 3A, 
3B, 4, 5, 5D, 10, 10A, 10B, 17, 19, 29 of 40 CFR part 60; 101A of 40 
CFR part 61; and voluntary consensus standards: American Society of 
Mechanical Engineers (ASME) PTC 19 (manual methods only), American 
Society for Testing and Materials (ASTM) D6522-00, ASTM D6784-02, ASTM 
D2234/D2234M-10, ASTM D6323-98, ASTM D2013-04, ASTM D5198-92, ASTM 
D5865-04, ASTM E711-87, ASTM D3173-03, ASTM E871-82, and ASTM D6722-01.
    Consistent with the NTTAA, EPA conducted searches to identify 
voluntary consensus standards in addition to these EPA methods. No 
applicable voluntary consensus standards were identified as 
alternatives for EPA Methods 2F, 2G, 5D, and 19. The search and review 
results are in the docket for this rule.
    The search for emissions measurement procedures identified 16 other 
voluntary consensus standards. EPA determined that these 16 standards 
identified for measuring emissions of the HAP or surrogates subject to 
emission standards in this rule were impractical alternatives to EPA 
test methods for the purposes of this rule. Therefore, EPA did not 
adopt these standards for this purpose. The reasons for the 
determinations for the 16 methods can be found in the docket to this 
rule.
    Table 4 to subpart JJJJJJ of this rule lists the testing methods 
included in the regulation. Under 40 CFR 63.7(f) and 63.8(f) of the 
General Provisions, a source may apply to EPA for permission to use 
alternative test methods or alternative monitoring requirements in 
place of any required testing methods, performance specifications, or 
procedures.

[[Page 15589]]

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 (EJ). Its main 
provision directs federal agencies, to the greatest extent practicable 
and permitted by law, to make EJ 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, low-income, and tribal populations 
in the United States.
    This action establishes national emission standards for industrial, 
commercial, and institutional boilers that are area sources. The 
industrial boiler source category includes boilers used in 
manufacturing, processing, mining, refining, or any other industry. The 
commercial boiler source category includes boilers used in commercial 
establishments such as stores/malls, laundries, apartments, 
restaurants, theatres, and hotels/motels. The institutional boiler 
source category includes boilers used in medical centers (e.g., 
hospitals, clinics, nursing homes), educational and religious 
facilities (e.g., schools, universities, places of worship), and 
municipal buildings (e.g., courthouses, arts centers, prisons). There 
are approximately 92,000 facilities affected by this final rule, most 
of which are small entities. By the defined nature of the category, 
many of these sources are located in close proximity to residential 
areas, commercial centers, and other locations where large numbers of 
people live and work.
    Due to the large number of these sources, their nation-wide 
dispersal, and the absence of site specific coordinates, EPA is unable 
to examine the distributions of exposures and health risks attributable 
to these sources among different socio-demographic groups for this 
rule, or to relate the locations of expected emission reductions to the 
locations of current poor air quality. However, this final rule is 
anticipated to have substantial emissions reductions of toxic air 
pollutants (see Table 2 of this preamble), some of which are potential 
carcinogens, neurotoxins, and respiratory irritants. This final rule 
will also result in reductions in criteria pollutants such as CO, PM, 
SO2, as well as ozone precursors.
    Because of the close proximity of these source categories to 
people, the substantial emission reductions of air toxics resulting 
from the implementation of this rule is anticipated to have health 
benefits for all persons living or going near these types of sources. 
(Please refer to the RIA for this rulemaking, which is available in the 
docket.) For example, there will be reductions of mercury emissions 
which will reduce potential exposures due to the atmospheric deposition 
of mercury for populations such as subsistence fisherman. In addition, 
there will be reductions in other air toxics which can cause adverse 
health effects such as ozone precursors that contribute to ``smog.'' 
EPA has determined that this rule will not have disproportionately high 
and adverse human health or environmental effects on minority or low-
income populations because it increases the level of environmental 
protection for all affected populations without having any 
disproportionately high and adverse human health or environmental 
effects on any population, including any minority, low-income, or 
tribal populations.
    EPA defines ``Environmental Justice'' to include meaningful 
involvement of all people regardless of race, color, national origin, 
or income with respect to the development, implementation, and 
enforcement of environmental laws, regulations, and polices. To promote 
meaningful involvement, EPA has developed an EJ communication strategy 
to ensure that interested communities have access to this rule, are 
aware of its content, and have an opportunity to comment. In addition, 
state and federal permitting requirements will provide state and local 
governments and communities the opportunity to provide their comments 
on the permit conditions associated with permitting these sources.

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 
this final rule must submit a rule report, which includes a copy of 
this final rule, to each House of the Congress and to the Comptroller 
General of the United States. 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 publication of this final 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 ``major rule'' as defined by 5 
U.S.C. 804(2). This rule will be effective May 20, 2011.

List of Subjects in 40 CFR Part 63

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Hazardous substances, Intergovernmental 
relations, Incorporation by reference, Reporting and recordkeeping 
requirements.

    Dated: February 21, 2011.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, part 
63 of the Code of Federal Regulations is 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)(27), (b)(35), (b)(39) through (44), (b)(47) 
through (52), (b)(57), (b)(61), (b)(64), and (i)(1).
0
b. Removing and reserving paragraphs (b)(45), (b)(46), (b)(55), 
(b)(56), (b)(58) through (60), and (b)(62).
0
c. Adding paragraphs (b)(66) through (68).
0
d. Adding paragraphs (p) and (q).


Sec.  63.14  Incorporation by reference.

* * * * *
    (b) * * *
    (27) ASTM D6522-00, Standard Test Method for Determination of 
Nitrogen Oxides, Carbon Monoxide, and Oxygen Concentrations in 
Emissions from Natural Gas Fired Reciprocating Engines, Combustion 
Turbines, Boilers, and Process Heaters Using Portable Analyzers, IBR 
approved for Sec.  63.9307(c)(2).
* * * * *
    (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 12 to subpart DDDDD of this part, and table 4 to subpart 
JJJJJJ of this part.
* * * * *
    (39) ASTM Method D388-05, Standard Classification of Coals by Rank, 
approved September 15, 2005, IBR approved for Sec.  63.7575 and Sec.  
63.11237.

[[Page 15590]]

    (40) ASTM D396-10 Standard Specification for Fuel Oils, approved 
October 1, 2010, IBR approved for Sec.  63.7575.
    (41) ASTM Method D1835-05, Standard Specification for Liquefied 
Petroleum (LP) Gases, approved April 1, 2005, IBR approved for Sec.  
63.7575 and Sec.  63.11237.
    (42) ASTM D2013/D2013M-09 Standard Practice for Preparing Coal 
Samples for Analysis, approved November 1, 2009, IBR approved for table 
6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this 
part.
    (43) ASTM D2234/D2234M-10 Standard Practice for Collection of a 
Gross Sample of Coal, approved January 1, 2010, IBR approved for table 
6 to subpart DDDDD of this part and table 5 to subpart JJJJJJ of this 
part.
    (44) ASTM D3173-03 (Reapproved 2008) Standard Test Method for 
Moisture in the Analysis Sample of Coal and Coke, approved February 1, 
2008, IBR approved for table 6 to subpart DDDDD of this part and table 
5 to subpart JJJJJJ of this part.
* * * * *
    (47) ASTM D5198-09 Standard Practice for Nitric Acid Digestion of 
Solid Waste, approved February 1, 2009, IBR approved for table 6 to 
subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
    (48) ASTM D5865-10a Standard Test Method for Gross Calorific Value 
of Coal and Coke, approved May 1, 2010, IBR approved for table 6 to 
subpart DDDDD of this part and table 5 to subpart JJJJJJ of this part.
    (49) ASTM D6323-98 (Reapproved 2003), Standard Guide for Laboratory 
Subsampling of Media Related to Waste Management Activities, approved 
August 10, 2003, IBR approved for table 6 to subpart DDDDD of this part 
and table 5 to subpart JJJJJJ of this part.
    (50) ASTM E711-87 (Reapproved 2004) Standard Test Method for Gross 
Calorific Value of Refuse-Derived Fuel by the Bomb Calorimeter, 
approved August 28, 1987, IBR approved for table 6 to subpart DDDDD of 
this part and table 5 to subpart JJJJJJ of this part.
    (51) ASTM E776-87 (Reapproved 2009) Standard Test Method for Forms 
of Chlorine in Refuse-Derived Fuel, approved July 1, 2009, IBR approved 
for table 6 to subpart DDDDD of this part.
    (52) ASTM E871-82 (Reapproved 2006) Standard Test Method for 
Moisture Analysis of Particulate Wood Fuels, approved November 1, 2006, 
IBR approved for table 6 to subpart DDDDD of this part and table 5 to 
subpart JJJJJJ of this part.
* * * * *
    (57) ASTM D6721-01 (Reapproved 2006) Standard Test Method for 
Determination of Chlorine in Coal by Oxidative Hydrolysis 
Microcoulometry, approved April 1, 2006, IBR approved for table 6 to 
subpart DDDDD of this part.
* * * * *
    (61) ASTM D6722-01 (Reapproved 2006) Standard Test Method for Total 
Mercury in Coal and Coal Combustion Residues by the Direct Combustion 
Analysis, approved April 1, 2006, IBR approved for Table 6 to subpart 
DDDDD and Table 5 to subpart JJJJJJ of this part.
* * * * *
    (64) ASTM D6522-00 (Reapproved 2005), Standard Test Method for 
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen 
Concentrations in Emissions from Natural Gas Fired Reciprocating 
Engines, Combustion Turbines, Boilers, and Process Heaters Using 
Portable Analyzers, approved October 1, 2005, IBR approved for table 4 
to subpart ZZZZ of this part, table 5 to subpart DDDDD of this part, 
and table 4 to subpart JJJJJJ of this part.
* * * * *
    (66) ASTM D4084-07 Standard Test Method for Analysis of Hydrogen 
Sulfide in Gaseous Fuels (Lead Acetate Reaction Rate Method), approved 
June 1, 2007, IBR approved for table 6 to subpart DDDDD of this part.
    (67) ASTM D5954-98 (Reapproved 2006), Test Method for Mercury 
Sampling and Measurement in Natural Gas by Atomic Absorption 
Spectroscopy, approved December 1, 2006, IBR approved for table 6 to 
subpart DDDDD of this part.
    (68) ASTM D6350-98 (Reapproved 2003) Standard Test Method for 
Mercury Sampling and Analysis in Natural Gas by Atomic Fluorescence 
Spectroscopy, approved May 10, 2003, IBR approved for table 6 to 
subpart DDDDD of this part.
    (i) * * *
    (1) ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses [Part 
10, Instruments and Apparatus],'' IBR approved for Sec. Sec.  
63.309(k)(1)(iii), 63.865(b), 63.3166(a)(3), 63.3360(e)(1)(iii), 
63.3545(a)(3), 63.3555(a)(3), 63.4166(a)(3), 63.4362(a)(3), 
63.4766(a)(3), 63.4965(a)(3), 63.5160(d)(1)(iii), 63.9307(c)(2), 
63.9323(a)(3), 63.11148(e)(3)(iii), 63.11155(e)(3), 63.11162(f)(3)(iii) 
and (f)(4), 63.11163(g)(1)(iii) and (g)(2), 63.11410(j)(1)(iii), 
63.11551(a)(2)(i)(C), table 5 to subpart DDDDD of this part, table 1 to 
subpart ZZZZZ of this part, and table 4 to subpart JJJJJJ of this part.
* * * * *
    (p) The following material is available from the U.S. Environmental 
Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, 
(202) 272-0167, http://www.epa.gov.
    (1) National Emission Standards for Hazardous Air Pollutants 
(NESHAP) for Integrated Iron and Steel Plants--Background Information 
for Proposed Standards, Final Report, EPA-453/R-01-005, January 2001, 
IBR approved for Sec.  63.7491(g).
    (2) Office Of Air Quality Planning And Standards (OAQPS), Fabric 
Filter Bag Leak Detection Guidance, EPA-454/R-98-015, September 1997, 
IBR approved for Sec.  63.7525(j)(2) and Sec.  63.11224(f)(2).
    (3) SW-846-3020A, Acid Digestion of Aqueous Samples And Extracts 
For Total Metals For Analysis By GFAA Spectroscopy, Revision 1, July 
1992, 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 of this part and table 5 to subpart JJJJJJ of this 
part.
    (4) SW-846-3050B, Acid Digestion of Sediments, Sludges, And Soils, 
Revision 2, December 1996, 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 of this part and table 5 to 
subpart JJJJJJ of this part.
    (5) SW-846-7470A, Mercury In Liquid Waste (Manual Cold-Vapor 
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 of this part 
and table 5 to subpart JJJJJJ of this part.
    (6) SW-846-7471B, Mercury In Solid Or Semisolid Waste (Manual Cold-
Vapor Technique), Revision 2, 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 of 
this part and table 5 to subpart JJJJJJ of this part.
    (7) SW-846-9250, Chloride (Colorimetric, Automated Ferricyanide 
AAI), 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 of this part.
    (q) The following material is available for purchase from the 
International

[[Page 15591]]

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.
    (1) ISO 6978-1:2003(E), Natural Gas--Determination of Mercury--Part 
1: Sampling of Mercury by Chemisorption on Iodine, First edition, 
October 15, 2003, IBR approved for table 6 to subpart DDDDD of this 
part.
    (2) ISO 6978-2:2003(E), Natural gas--Determination of Mercury--Part 
2: Sampling of Mercury by Amalgamation on Gold/Platinum Alloy, First 
edition, October 15, 2003, IBR approved for table 6 to subpart DDDDD of 
this part.
0
3. Part 63 is amended by adding subpart JJJJJJ to read as follows:

Subpart JJJJJJ--National Emission Standards for Hazardous Air 
Pollutants for Industrial, Commercial, and Institutional Boilers 
Area Sources

Sec.

What This Subpart Covers

63.11193 Am I subject to this subpart?
63.11194 What is the affected source of this subpart?
63.11195 Are any boilers not subject to this subpart?
63.11196 What are my compliance dates?

Emission Limits, Work Practice Standards, Emission Reduction Measures, 
and Management Practices

63.11200 What are the subcategories of boilers?
63.11201 What standards must I meet?

General Compliance Requirements

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

Initial Compliance Requirements

63.11210 What are my initial compliance requirements and by what 
date must I conduct them?
63.11211 How do I demonstrate initial compliance with the emission 
limits?
63.11212 What stack tests and procedures must I use for the 
performance tests?
63.11213 What fuel analyses and procedures must I use for the 
performance tests?
63.11214 How do I demonstrate initial compliance with the work 
practice standard, emission reduction measures, and management 
practice?

Continuous Compliance Requirements

63.11220 When must I conduct subsequent performance tests?
63.11221 How do I monitor and collect data to demonstrate continuous 
compliance?
63.11222 How do I demonstrate continuous compliance with the 
emission limits?
63.11223 How do I demonstrate continuous compliance with the work 
practice and management practice standards?
63.11224 What are my monitoring, installation, operation, and 
maintenance requirements?
63.11225 What are my notification, reporting, and recordkeeping 
requirements?
63.11226 How can I assert an affirmative defense if I exceed an 
emission limit during a malfunction?

Other Requirements and Information

63.11235 What parts of the General Provisions apply to me?
63.11236 Who implements and enforces this subpart?
63.11237 What definitions apply to this subpart?
Table 1 to Subpart JJJJJJ of Part 63--Emission Limits
Table 2 to Subpart JJJJJJ of Part 63--Work Practice Standards
Table 3 to Subpart JJJJJJ of Part 63--Operating Limits for Boilers 
With Emission Limits
Table 4 to Subpart JJJJJJ of Part 63--Performance (Stack) Testing 
Requirements
Table 5 to Subpart JJJJJJ of Part 63--Fuel Analysis Requirements
Table 6 to Subpart JJJJJJ of Part 63 -- Establishing Operating Limit
Table 7 to Subpart JJJJJJ of Part 63--Demonstrating Continuous 
Compliance
Table 8 to Subpart JJJJJJ of Part 63--Applicability of General 
Provisions to Subpart JJJJJJ

Subpart JJJJJJ--National Emission Standards for Hazardous Air 
Pollutants for Industrial, Commercial, and Institutional Boilers 
Area Sources

What This Subpart Covers


Sec.  63.11193  Am I subject to this subpart?

    You are subject to this subpart if you own or operate an 
industrial, commercial, or institutional boiler as defined in Sec.  
63.11237 that is located at, or is part of, an area source of hazardous 
air pollutants (HAP), as defined in Sec.  63.2, except as specified in 
Sec.  63.11195.


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

    (a) This subpart applies to each new, reconstructed, or existing 
affected source as defined in paragraphs (a)(1) and (2) of this 
section.
    (1) The affected source is the collection of all existing 
industrial, commercial, and institutional boilers within a subcategory 
(coal, biomass, oil), as listed in Sec.  63.11200 and defined in Sec.  
63.11237, located at an area source.
    (2) The affected source of this subpart is each new or 
reconstructed industrial, commercial, or institutional boiler within a 
subcategory, as listed in Sec.  63.11200 and as defined in Sec.  
63.11237, located at an area source.
    (b) An affected source is an existing source if you commenced 
construction or reconstruction of the affected source on or before June 
4, 2010.
    (c) An affected source is a new source if you commenced 
construction or reconstruction of the affected source after June 4, 
2010 and you meet the applicability criteria at the time you commence 
construction.
    (d) A boiler is a new affected source if you commenced fuel 
switching from natural gas to solid fossil fuel, biomass, or liquid 
fuel after June 4, 2010.
    (e) If you are an owner or operator of an area source subject to 
this subpart, you are exempt from the obligation to obtain a permit 
under 40 CFR part 70 or part 71 as a result of this subpart. You may, 
however, be required to obtain a title V permit due to another reason 
or reasons. See 40 CFR 70.3(a) and (b) or 71.3(a) and (b). 
Notwithstanding the exemption from title V permitting for area sources 
under this subpart, you must continue to comply with the provisions of 
this subpart.


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

    The types of boilers listed in paragraphs (a) through (g) of this 
section are not subject to this subpart and to any requirements in this 
subpart.
    (a) Any boiler specifically listed as, or included in the 
definition of, an affected source in another standard(s) under this 
part.
    (b) Any boiler specifically listed as an affected source in another 
standard(s) established under section 129 of the Clean Air Act.
    (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).
    (d) A boiler that is used specifically for research and 
development. This exemption does not include boilers that solely or 
primarily provide steam (or heat) to a process or for heating at a 
research and development facility. This exemption does not prohibit the 
use of the steam (or heat) generated from the boiler during research 
and development, however, the boiler must be concurrently and primarily 
engaged in research and development for the exemption to apply.
    (e) A gas-fired boiler as defined in this subpart.
    (f) A hot water heater as defined in this subpart.
    (g) Any boiler that is used as a control device to comply with 
another subpart of this part, 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.


Sec.  63.11196  What are my compliance dates?

    (a) If you own or operate an existing affected boiler, you must 
achieve

[[Page 15592]]

compliance with the applicable provisions in this subpart as specified 
in paragraphs (a)(1) through (3) of this section.
    (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 standard no later than 
March 21, 2012.
    (2) If the existing affected boiler is subject to emission limits, 
you must achieve compliance with the emission limits no later than 
March 21, 2014.
    (3) If the existing affected boiler is subject to the energy 
assessment requirement, you must achieve compliance with the energy 
assessment requirement no later than March 21, 2014.
    (b) If you start up a new affected source on or before May 20, 
2011, you must achieve compliance with the provisions of this subpart 
no later than May 20, 2011.
    (c) If you start up a new affected source after May 20, 2011, you 
must achieve compliance with the provisions of this subpart upon 
startup of your affected source.
    (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.

Emission Limits, Work Practice Standards, Emission Reduction Measures, 
and Management Practices


Sec.  63.11200  What are the subcategories of boilers?

    The subcategories of boilers are coal, biomass, and oil. Each 
subcategory is defined in Sec.  63.11237.


Sec.  63.11201  What standards must I meet?

    (a) You must comply with each emission limit specified in Table 1 
to this subpart that applies to your boiler.
    (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 the requirements in Table 2 to this 
subpart satisfies the energy assessment portion of this requirement.
    (c) You must comply with each operating limit specified in Table 3 
to this subpart that applies to your boiler.
    (d) These standards apply at all times.

General Compliance Requirements


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

    (a) At all times you must operate and maintain any affected source, 
including associated air pollution control equipment and monitoring 
equipment, in a manner consistent with safety and good air pollution 
control practices for minimizing emissions. The general duty to 
minimize emissions does not require you to make any further efforts to 
reduce emissions if levels required by this standard have been 
achieved. Determination of whether such operation and maintenance 
procedures are being used will be based on information available to the 
Administrator that may include, but is not limited to, monitoring 
results, review of operation and maintenance procedures, review of 
operation and maintenance records, and inspection of the source.
    (b) You can demonstrate compliance with any 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 continuous parameter monitoring 
system), 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 
continuous parameter monitoring system. This requirement also applies 
to you if you petition the EPA Administrator for alternative monitoring 
parameters under Sec.  63.8(f).
    (1) For each continuous monitoring system required in this section 
(including CEMS, COMS, or continuous parameter monitoring system), you 
must develop, and submit to the delegated authority 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 monitoring plans that apply to CEMS and COMS 
prepared under Appendix B to part 60 of this chapter and which meet the 
requirements of Sec.  63.11224.
    (i) Installation of the continuous monitoring system 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);
    (ii) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems; and
    (iii) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations).
    (iv) Ongoing operation and maintenance procedures in accordance 
with the general requirements of Sec.  63.8(c)(1)(ii), (c)(3), and 
(c)(4)(ii);
    (v) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec.  63.8(d); and
    (vi) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec.  63.10(c) (as applicable in Table 
8 to this subpart), (e)(1), and (e)(2)(i).
    (2) You must conduct a performance evaluation of each CMS in 
accordance with your site-specific monitoring plan.
    (3) You must operate and maintain the CMS in continuous operation 
according to the site-specific monitoring plan.

Initial Compliance Requirements


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

    (a) You must demonstrate initial compliance with each emission 
limit specified in Table 1 to this subpart that applies to you by 
either conducting performance (stack) tests, as applicable, according 
to Sec.  63.11212 and Table 4 to this subpart or, for mercury, 
conducting fuel analyses, as applicable, according to Sec.  63.11213 
and Table 5 to this subpart.
    (b) For existing affected boilers that have applicable emission 
limits, you must demonstrate initial compliance 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).
    (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).
    (d) For new or reconstructed affected sources, you must demonstrate 
initial

[[Page 15593]]

compliance no later than 180 calendar days after March 21, 2011 or 
within 180 calendar days after startup of the source, whichever is 
later, according to Sec.  63.7(a)(2)(ix).
    (e) For affected boilers that ceased burning solid waste consistent 
with Sec.  63.11196(d), you must demonstrate compliance within 60 days 
of the effective date of the waste-to-fuel switch. If you have not 
conducted your compliance demonstration for this subpart within the 
previous 12 months, you must complete all compliance demonstrations 
before you commence or recommence combustion of solid waste.


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 continuous monitoring system (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) You must establish parameter operating limits according to 
paragraphs (b)(1) through (4) of this section.
    (1) For a wet scrubber, you must establish the minimum liquid 
flowrate and 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 
particulate matter and mercury emissions, you must establish one set of 
minimum scrubber liquid flowrate and pressure drop operating limits. If 
you conduct multiple performance stack tests, you must set the minimum 
liquid flowrate 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 voltage and secondary amperage (or total 
electric power input), as defined in Sec.  63.11237, as your operating 
limits during the three-run performance stack test. (These operating 
limits do not apply to electrostatic precipitators that are operated as 
dry controls without a wet scrubber.)
    (3) For activated carbon injection, you must establish the minimum 
activated carbon injection rate, as defined in Sec.  63.11237, as your 
operating limit during the three-run performance stack test.
    (4) The operating limit for boilers with fabric filters that 
demonstrate continuous compliance through bag leak detection systems is 
that a bag leak detection system be installed according to the 
requirements in Sec.  63.11224, and that each fabric filter must be 
operated such that the bag leak detection system alarm does not sound 
more than 5 percent of the operating time during a 6-month period.
    (c) If you elect to demonstrate compliance with an applicable 
mercury emission limit through fuel analysis, you must conduct fuel 
analyses according to Sec.  63.11213 and Table 5 to this subpart and 
follow the procedures in paragraphs (c)(1) through (3) of this section.
    (1) If you burn more than one fuel type, you must determine the 
fuel type, or mixture, you could burn in your boiler that would result 
in the maximum emission rates of mercury.
    (2) You must determine the 90th percentile confidence level fuel 
mercury concentration of the composite samples analyzed for each fuel 
type using Equation 1 of this section.
[GRAPHIC] [TIFF OMITTED] TR21MR11.021

    Where:

    P90 = 90th percentile confidence level mercury 
concentration, in pounds per million Btu.
    mean = Arithmetic average of the fuel mercury concentration in 
the fuel samples analyzed according to Sec.  63.11213, in units of 
pounds per million Btu.
    SD = Standard deviation of the mercury concentration in the fuel 
samples analyzed according to Sec.  63.11213, in units of pounds per 
million Btu.
    t = t distribution critical value for 90th percentile (0.1) 
probability for the appropriate degrees of freedom (number of 
samples minus one) as obtained from a Distribution Critical Value 
Table.

    (3) To demonstrate compliance with the applicable mercury emission 
limit, the emission rate that you calculate for your boiler using 
Equation 1 of this section must be less than the applicable mercury 
emission limit.


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

    (a) You must conduct all performance tests according to Sec.  
63.7(c), (d), (f), and (h). You must also develop a site-specific test 
plan according to the requirements in Sec.  63.7(c).
    (b) You must conduct each stack test according to the requirements 
in Table 4 to this subpart.
    (c) You must conduct performance stack tests at the representative 
operating load conditions while burning the type of fuel or mixture of 
fuels that have the highest emissions potential for each regulated 
pollutant, and you must demonstrate initial compliance and establish 
your operating limits based on these performance stack tests. For 
subcategories with more than one emission limit, these requirements 
could result in the need to conduct more than one performance stack 
test. Following each performance stack test and until the next 
performance stack test, you must comply with the operating limit for 
operating load conditions specified in Table 3 to this subpart.
    (d) You must conduct a minimum of three separate test runs for each 
performance stack test required in this section, as specified in Sec.  
63.7(e)(3) and in accordance with the provisions in Table 4 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 particulate matter concentrations and the measured mercury 
concentrations that result from the initial performance test to pounds 
per million Btu heat input emission rates.

[[Page 15594]]

Sec.  63.11213  What fuel analyses and procedures must I use for the 
performance tests?

    (a) You must conduct fuel analyses according to the procedures in 
paragraphs (b) and (c) of this section and Table 5 to this subpart, as 
applicable. You are not required to conduct fuel analyses for fuels 
used for only startup, unit shutdown, and transient flame stability 
purposes. You are required to conduct fuel analyses only for fuels and 
units that are subject to emission limits for mercury in Table 1 of 
this subpart.
    (b) At a minimum, you must obtain three composite fuel samples for 
each fuel type according to the procedures in Table 5 to this subpart. 
Each composite sample must consist of a minimum of three samples 
collected at approximately equal intervals during a test run period.
    (c) Determine the concentration of mercury in the fuel in units of 
pounds per million Btu of each composite sample for each fuel type 
according to the procedures in Table 5 to this subpart.


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

    (a) If you own or operate an existing or new coal-fired boiler with 
a heat input capacity of less than 10 million Btu per hour, you must 
conduct a performance tune-up according to Sec.  63.11223(b) and you 
must submit a signed statement in the Notification of Compliance Status 
report that indicates that you conducted a tune-up of the boiler.
    (b) If you own or operate an existing or new biomass-fired boiler 
or an existing or new oil-fired boiler, you must conduct a performance 
tune-up according to Sec.  63.11223(b) and you must submit a signed 
statement in the Notification of Compliance Status report that 
indicates that you conducted a tune-up of the boiler.
    (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 and submit, upon request, the energy assessment report.
    (d) 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.

Continuous Compliance Requirements


Sec.  63.11220  When must I conduct subsequent performance tests?

    (a) If your boiler has a heat input capacity of 10 million Btu per 
hour or greater, you must conduct all applicable performance (stack) 
tests according to Sec.  63.11212 on an triennial basis, unless you 
follow the requirements listed in paragraphs (b) through (d) of this 
section. Triennial performance tests must be completed no more than 37 
months after the previous performance test, unless you follow the 
requirements listed in paragraphs (b) through (d) of this section.
    (b) You can conduct performance stack tests less often for 
particulate matter or mercury if your performance stack tests for the 
pollutant for at least 3 consecutive years show that your emissions are 
at or below 75 percent of the emission limit, and if there are no 
changes in the operation of the affected source or air pollution 
control equipment that could increase emissions. In this case, you do 
not have to conduct a performance stack test for that pollutant for the 
next 2 years. You must conduct a performance stack test during the 
third year and no more than 37 months after the previous performance 
stack test.
    (c) If your boiler continues to meet the emission limit for 
particulate matter or mercury, you may choose to conduct performance 
stack tests for the pollutant every third year if your emissions are at 
or below 75 percent of the emission limit, and if there are no changes 
in the operation of the affected source or air pollution control 
equipment that could increase emissions, but each such performance 
stack test must be conducted no more than 37 months after the previous 
performance test.
    (d) If you have an applicable CO emission limit, you must conduct 
triennial performance tests for CO according to Sec.  63.11212. Each 
triennial performance test must be conducted between no more than 37 
months after the previous performance test.
    (e) If you demonstrate compliance with the mercury emission limit 
based on fuel analysis, you must conduct a fuel analysis according to 
Sec.  63.11213 for each type of fuel burned monthly. If you plan to 
burn a new type of fuel or fuel mixture, you must conduct a fuel 
analysis before burning the new type of fuel or mixture in your boiler. 
You must recalculate the mercury emission rate using Equation 1 of 
Sec.  63.11211. The recalculated mercury emission rate must be less 
than the applicable emission limit.


Sec.  63.11221  How do I monitor and collect data to demonstrate 
continuous compliance?

    (a) You must monitor and collect data according to this section.
    (b) You must operate the monitoring system and collect data at all 
required intervals at all times the affected source is operating except 
for periods of monitoring system malfunctions or out-of-control 
periods, repairs associated with monitoring system malfunctions or out-
of-control periods (see section 63.8(c)(7) of this part), and required 
monitoring system quality assurance or quality control activities 
including, as applicable, calibration checks and required zero and span 
adjustments. A monitoring system malfunction is any sudden, infrequent, 
not reasonably preventable failure of the monitoring system to provide 
valid data. Monitoring system failures that are caused in part by poor 
maintenance or careless operation are not malfunctions. You are 
required to effect monitoring system repairs in response to monitoring 
system malfunctions or out-of-control periods and to return the 
monitoring system to operation as expeditiously as practicable.
    (c) You may not use data recorded 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 control activities in 
calculations used to report emissions or operating levels. 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 out-of-
control periods, repairs associated with monitoring system malfunctions 
or out-of-control periods, and required monitoring system quality 
assurance or quality control activities including, as applicable, 
calibration checks and required zero and span adjustments,

[[Page 15595]]

failure to collect required data is a deviation of the monitoring 
requirements.


Sec.  63.11222  How do I demonstrate continuous compliance with the 
emission limits?

    (a) You must demonstrate continuous compliance with each emission 
limit and operating limit in Tables 1 and 3 to this subpart that 
applies to you according to the methods specified in Table 7 to this 
subpart and to paragraphs (a)(1) through (4) of this section.
    (1) Following the date on which the initial compliance 
demonstration is completed or is required to be completed under 
Sec. Sec.  63.7 and 63.11196, whichever date comes first, you must 
continuously monitor the operating parameters. Operation above the 
established maximum, below the established minimum, or outside the 
allowable range of the operating limits specified in paragraph (a) of 
this section constitutes a deviation from your operating limits 
established under this subpart, except during performance tests 
conducted to determine compliance with the emission and operating 
limits or to establish new operating limits. Operating limits are 
confirmed or reestablished during performance tests.
    (2) If you have an applicable mercury or PM emission limit, you 
must keep records of the type and amount of all fuels burned in each 
boiler during the reporting period to demonstrate that all fuel types 
and mixtures of fuels burned would result in lower emissions of mercury 
than the applicable emission limit (if you demonstrate compliance 
through fuel analysis), or result in lower fuel input of mercury than 
the maximum values calculated during the last performance stack test 
(if you demonstrate compliance through performance stack testing).
    (3) If you have an applicable mercury emission limit and you plan 
to burn a new type of fuel, you must determine the mercury 
concentration for any new fuel type in units of pounds per million Btu, 
using the procedures in Equation 1 of Sec.  63.11211 based on supplier 
data or your own fuel analysis, and meet the requirements in paragraphs 
(a)(3)(i) or (ii) of this section.
    (i) The recalculated mercury emission rate must be less than the 
applicable emission limit.
    (ii) If the mercury concentration is higher than mercury fuel input 
during the previous performance test, then you must conduct a new 
performance test within 60 days of burning the new fuel type or fuel 
mixture according to the procedures in Sec.  63.11212 to demonstrate 
that the mercury emissions do not exceed the emission limit.
    (4) If your unit is controlled with a fabric filter, and you 
demonstrate continuous compliance using a bag leak detection system, 
you must initiate corrective action within 1 hour of a bag leak 
detection system alarm and operate and maintain the fabric filter 
system such that the alarm does not sound more than 5 percent of the 
operating time during a 6-month period. You must also keep records of 
the date, time, and duration of each alarm, the time corrective action 
was initiated and completed, and a brief description of the cause of 
the alarm and the corrective action taken. You must also record the 
percent of the operating time during each 6-month period that the alarm 
sounds. In calculating this operating time percentage, if inspection of 
the fabric filter demonstrates that no corrective action is required, 
no alarm time is counted. If corrective action is required, each alarm 
is counted as a minimum of 1 hour. If you take longer than 1 hour to 
initiate corrective action, the alarm time is counted as the actual 
amount of time taken to initiate corrective action.
    (b) You must report each instance in which you did not meet each 
emission limit and operating limit in Tables 1 and 3 to this subpart 
that apply to you. These instances are deviations from the emission 
limits in this subpart. These deviations must be reported according to 
the requirements in Sec.  63.11225.


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 biennial 
performance tune-up according to paragraphs (b) of this section and 
keep records as required in Sec.  63.11225(c) to demonstrate continuous 
compliance. Each biennial tune-up must be conducted no more than 25 
months after the previous tune-up.
    (b) 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.
    (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, but you must inspect 
each burner at least once every 36 months).
    (2) Inspect the flame pattern, as applicable, and adjust the burner 
as necessary to optimize the flame pattern. The adjustment should be 
consistent with the manufacturer's specifications, if available.
    (3) Inspect the system controlling the air-to-fuel ratio, as 
applicable, and ensure that it is correctly calibrated and functioning 
properly.
    (4) Optimize total emissions of carbon monoxide. This optimization 
should be consistent with the manufacturer's specifications, if 
available.
    (5) Measure the concentrations in the effluent stream of carbon 
monoxide in parts per million, by volume, and oxygen in volume percent, 
before and after the adjustments are made (measurements may be either 
on a dry or wet basis, as long as it is the same basis before and after 
the adjustments are made).
    (6) Maintain onsite and submit, if requested by the Administrator, 
biennial 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 before and 
after the tune-up of the boiler.
    (ii) A description of any corrective actions taken as a part of the 
tune-up of the boiler.
    (iii) The type and amount of fuel used over the 12 months prior to 
the biennial tune-up of the boiler.
    (7) If the unit is not operating on the required date for a tune-
up, the tune-up must be conducted within one week of startup.
    (c) If you own or operate an existing or new coal-fired boiler with 
a heat input capacity of 10 million Btu per hour or greater, you must 
minimize the boiler's time spent during startup and shutdown following 
the manufacturer's recommended procedures and you must submit a signed 
statement in the Notification of Compliance Status report that 
indicates that you conducted startups and shutdowns according to the 
manufacturer's recommended procedures.


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

    (a) If your boiler is subject to a carbon monoxide emission limit 
in Table 1 to this subpart, you must install, operate, and maintain a 
continuous oxygen monitor according to the procedures in paragraphs 
(a)(1) through (6) of this section by the compliance date specified in 
Sec.  63.11196. The oxygen level shall be monitored at the outlet of 
the boiler.

[[Page 15596]]

    (1) Each monitor must be installed, operated, and maintained 
according to the applicable procedures under Performance Specification 
3 at 40 CFR part 60, appendix B, and 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 Specification 3 at 40 CFR part 60, appendix B.
    (3) Each CEMS must complete a minimum of one cycle of operation 
(sampling, analyzing, and data recording) for each successive 15-minute 
period.
    (4) The CEMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must calculate and record the 12-hour block average 
concentrations.
    (6) For purposes of calculating data averages, you must use all the 
data collected during all periods in assessing compliance, excluding 
data collected during periods when the monitoring system malfunctions 
or is out of control, during associated repairs, and during required 
quality assurance or control activities (including, as applicable, 
calibration checks and required zero and span adjustments). Monitoring 
failures that are caused in part by poor maintenance or careless 
operation are not malfunctions. Any period for which the monitoring 
system malfunctions or is out of control and data are not available for 
a required calculation constitutes a deviation from the monitoring 
requirements. Periods when data are unavailable because of required 
quality assurance or control activities (including, as applicable, 
calibration checks and required zero and span adjustments) do not 
constitute monitoring deviations.
    (b) If you are using a control device to comply with the emission 
limits specified in Table 1 to this subpart, you must maintain each 
operating limit in Table 3 to this subpart that applies to your boiler 
as specified in Table 7 to this subpart. If you use a control device 
not covered in Table 3 to this subpart, or you wish to establish and 
monitor an alternative operating limit and alternative monitoring 
parameters, you must apply to the United States Environmental 
Protection Agency (EPA) Administrator for approval of alternative 
monitoring under Sec.  63.8(f).
    (c) If you demonstrate compliance with any applicable emission 
limit through stack testing and subsequent compliance with operating 
limits, you must develop a site-specific monitoring plan according to 
the requirements in paragraphs (c)(1) through (4) of this section. This 
requirement also applies to you if you petition the EPA Administrator 
for alternative monitoring parameters under Sec.  63.8(f).
    (1) For each continuous monitoring system (CMS) required in this 
section, you must develop, and submit to the EPA Administrator for 
approval upon request, a site-specific monitoring plan that addresses 
paragraphs (b)(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.
    (i) Installation of the CMS sampling probe or other interface at a 
measurement location relative to each affected unit such that the 
measurement is representative of control of the exhaust emissions 
(e.g., on or downstream of the last control device).
    (ii) Performance and equipment specifications for the sample 
interface, the pollutant concentration or parametric signal analyzer, 
and the data collection and reduction systems.
    (iii) Performance evaluation procedures and acceptance criteria 
(e.g., calibrations).
    (2) In your site-specific monitoring plan, you must also address 
paragraphs (b)(2)(i) through (iii) of this section.
    (i) Ongoing operation and maintenance procedures in accordance with 
the general requirements of Sec.  63.8(c)(1), (3), and (4)(ii).
    (ii) Ongoing data quality assurance procedures in accordance with 
the general requirements of Sec.  63.8(d).
    (iii) Ongoing recordkeeping and reporting procedures in accordance 
with the general requirements of Sec.  63.10(c), (e)(1), and (e)(2)(i).
    (3) You must conduct a performance evaluation of each CMS in 
accordance with your site-specific monitoring plan.
    (4) You must operate and maintain the CMS in continuous operation 
according to the site-specific monitoring plan.
    (d) If you have an operating limit that requires the use of a CMS, 
you must install, operate, and maintain each continuous parameter 
monitoring system according to the procedures in paragraphs (d)(1) 
through (5) of this section.
    (1) The continuous parameter monitoring system must complete a 
minimum of one cycle of operation for each successive 15-minute period. 
You must have a minimum of four successive cycles of operation to have 
a valid hour of data.
    (2) Except for monitoring malfunctions, associated repairs, and 
required quality assurance or control activities (including, as 
applicable, calibration checks and required zero and span adjustments), 
you must conduct all monitoring in continuous operation at all times 
that the unit is operating. A monitoring malfunction is any sudden, 
infrequent, not reasonably preventable failure of the monitoring to 
provide valid data. Monitoring failures that are caused in part by poor 
maintenance or careless operation are not malfunctions.
    (3) For purposes of calculating data averages, you must not use 
data recorded during monitoring malfunctions, associated repairs, out 
of control periods, or required quality assurance or control 
activities. You must use all the data collected during all other 
periods in assessing compliance. Any period for which the monitoring 
system is out-of-control and data are not available for a required 
calculation constitutes a deviation from the monitoring requirements.
    (4) Determine the 12-hour block average of all recorded readings, 
except as provided in paragraph (d)(3) of this section.
    (5) 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 continuous 
opacity monitoring system (COMS) according to the procedures in 
paragraphs (e)(1) through (7) of this section by the compliance date 
specified in Sec.  63.11196.
    (1) Each COMS must be installed, operated, and maintained according 
to Performance Specification 1 of 40 CFR part 60, appendix B.
    (2) You must conduct a performance evaluation of each COMS 
according to the requirements in Sec.  63.8 and according to 
Performance Specification 1 of 40 CFR part 60, appendix B.
    (3) As specified in Sec.  63.8(c)(4)(i), each COMS must complete a 
minimum of one cycle of sampling and analyzing for each successive 10-
second period and one cycle of data recording for each successive 6-
minute period.
    (4) The COMS data must be reduced as specified in Sec.  63.8(g)(2).
    (5) You must include in your site-specific monitoring plan 
procedures and acceptance criteria for operating and maintaining each 
COMS according to the requirements in Sec.  63.8(d). At a minimum, the 
monitoring plan must include a daily calibration drift assessment, a 
quarterly performance audit, and an annual zero alignment audit of each 
COMS.
    (6) You must operate and maintain each COMS according to the 
requirements in the monitoring plan

[[Page 15597]]

and the requirements of Sec.  63.8(e). 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 determine and record all the 1-hour block averages 
collected for periods during which the COMS is not out of control.
    (f) If you use a fabric filter bag leak detection system to comply 
with the requirements of this subpart, you must install, calibrate, 
maintain, and continuously operate the bag leak detection system as 
specified in paragraphs (f)(1) through (8) of this section.
    (1) You must install and operate a bag leak detection system for 
each exhaust stack of the fabric filter.
    (2) Each bag leak detection system must be installed, operated, 
calibrated, and maintained in a manner consistent with the 
manufacturer's written specifications and recommendations and in 
accordance with EPA-454/R-98-015 (incorporated by reference, see Sec.  
63.14).
    (3) The bag leak detection system must be certified by the 
manufacturer to be capable of detecting particulate matter emissions at 
concentrations of 10 milligrams per actual cubic meter or less.
    (4) The bag leak detection system sensor must provide output of 
relative or absolute particulate matter loadings.
    (5) The bag leak detection system must be equipped with a device to 
continuously record the output signal from the sensor.
    (6) The bag leak detection system must be equipped with an audible 
or visual alarm system that will activate automatically when an 
increase in relative particulate matter emissions over a preset level 
is detected. The alarm must be located where it is easily heard or seen 
by plant operating personnel.
    (7) For positive pressure fabric filter systems that do not duct 
all compartments of cells to a common stack, a bag leak detection 
system must be installed in each baghouse compartment or cell.
    (8) Where multiple bag leak detectors are required, the system's 
instrumentation and alarm may be shared among detectors.


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

    (a) You must submit the notifications specified in paragraphs 
(a)(1) through (a)(5) of this section to the delegated authority.
    (1) You must submit all of the notifications in Sec. Sec.  63.7(b): 
63.8(e) and (f); 63.9(b) through (e); and 63.9(g) and (h) that apply to 
you by the dates specified in those sections.
    (2) As specified in Sec.  63.9(b)(2), you must submit the Initial 
Notification no later than 120 calendar days after May 20, 2011 or 
within 120 days after the source becomes subject to the standard.
    (3) If you are required to conduct a performance stack test you 
must submit a Notification of Intent to conduct a performance test at 
least 60 days before the performance stack test is scheduled to begin.
    (4) You must submit the Notification of Compliance Status in 
accordance with Sec.  63.9(h) 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. In addition to 
the information required in Sec.  63.9(h)(2), 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.  
63.11214 to conduct an initial tune-up of the boiler.''
    (ii) ``This facility has had an energy assessment performed 
according to Sec.  63.11214(c).''
    (iii) For an owner or operator that installs bag leak detection 
systems: ``This facility has prepared a bag leak detection system 
monitoring plan in accordance with Sec.  63.11224 and will operate each 
bag leak detection system according to the plan.''
    (iv) 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.''
    (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 consistent with Sec.  
63.7(e)(2)(iv), you must submit the test data in lieu of the initial 
performance test results with the Notification of Compliance Status 
required under paragraph (a)(4) of this section.
    (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 tune-up according to Sec.  
63.11223(a) and not subject to emission limits or operating limits, you 
may prepare only a biennial compliance report as specified in 
paragraphs (b)(1) through (4) of this section, instead of a semi-annual 
compliance report.
    (1) Company name and address.
    (2) Statement by a responsible official, with the official's name, 
title, phone number, e-mail 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.
    (3) If the source experiences any deviations from the applicable 
requirements during the reporting period, include a description of 
deviations, the time periods during which the deviations occurred, and 
the corrective actions taken.
    (4) The total fuel use by each affected boiler subject to an 
emission limit, for each calendar month within the reporting period, 
including, but not limited to, a description of the fuel, whether the 
fuel has received a non-waste determination by you or EPA through a 
petition process to be a non-waste under Sec.  241.3(c), whether the 
fuel(s) were processed from discarded non-hazardous secondary materials 
within the meaning of Sec.  241.3, and the total fuel usage amount with 
units of measure.
    (c) You must maintain the records specified in paragraphs (c)(1) 
through (5) of this section.
    (1) As required in Sec.  63.10(b)(2)(xiv), you must keep a copy of 
each notification and report that you submitted to comply with this 
subpart and all documentation supporting any Initial Notification or 
Notification of Compliance Status that you submitted.
    (2) You must keep records to document conformance with the work 
practices, emission reduction measures, and management practices 
required by Sec.  63.11214 as specified in paragraphs (c)(2)(i) and 
(ii) of this section.
    (i) Records must identify each boiler, the date of tune-up, the 
procedures followed for tune-up, and the manufacturer's specifications 
to which the boiler was tuned.
    (ii) Records documenting the fuel type(s) used monthly by each 
boiler, including, but not limited to, a description of the fuel, 
including whether the fuel has received a non-waste determination by 
you or EPA, and the total fuel usage amount with units

[[Page 15598]]

of measure. If you combust non-hazardous secondary materials that have 
been determined not to be solid waste pursuant to Sec.  241.3(b)(1), 
you must keep a record which documents how the secondary material meets 
each of the legitimacy criteria. If you combust a fuel that has been 
processed from a discarded non-hazardous secondary material pursuant to 
Sec.  241.3(b)(4), you must keep records as to how the operations that 
produced the fuel satisfies the definition of processing in Sec.  
241.2. If the fuel received a non-waste determination pursuant to the 
petition process submitted under Sec.  241.3(c), you must keep a record 
that documents how the fuel satisfies the requirements of the petition 
process.
    (3) For sources that demonstrate compliance through fuel analysis, 
a copy of all calculations and supporting documentation that were done 
to demonstrate compliance with the mercury emission limits. Supporting 
documentation should include results of any fuel analyses. You can use 
the results from one fuel analysis for multiple boilers provided they 
are all burning the same fuel type.
    (4) Records of the occurrence and duration of each malfunction of 
the boiler, or of the associated air pollution control and monitoring 
equipment.
    (5) Records of actions taken during periods of malfunction to 
minimize emissions in accordance with the general duty to minimize 
emissions in Sec.  63.11205(a), including corrective actions to restore 
the malfunctioning boiler, air pollution control, or monitoring 
equipment to its normal or usual manner of operation.
    (6) You must keep the records of all inspection and monitoring data 
required by Sec. Sec.  63.11221 and 63.11222, and the information 
identified in paragraphs (c)(6)(i) through (vi) of this section for 
each required inspection or monitoring.
    (i) The date, place, and time of the monitoring event.
    (ii) Person conducting the monitoring.
    (iii) Technique or method used.
    (iv) Operating conditions during the activity.
    (v) Results, including the date, time, and duration of the period 
from the time the monitoring indicated a problem to the time that 
monitoring indicated proper operation.
    (vi) Maintenance or corrective action taken (if applicable).
    (7) If you use a bag leak detection system, you must keep the 
records specified in paragraphs (c)(7)(i) through (iii) of this 
section.
    (i) Records of the bag leak detection system output.
    (ii) Records of bag leak detection system adjustments, including 
the date and time of the adjustment, the initial bag leak detection 
system settings, and the final bag leak detection system settings.
    (iii) The date and time of all bag leak detection system alarms, 
and for each valid alarm, the time you initiated corrective action, the 
corrective action taken, and the date on which corrective action was 
completed.
    (d) Your records must be in a form suitable and readily available 
for expeditious review, according to Sec.  63.10(b)(1). As specified in 
Sec.  63.10(b)(1), you must keep each record for 5 years following the 
date of each recorded action. You must keep each record onsite for at 
least 2 years after the date of each recorded action according to Sec.  
63.10(b)(1). You may keep the records off site for the remaining 3 
years.
    (e) As of January 1, 2012 and within 60 days after the date of 
completing each performance test, as defined in Sec.  63.2, conducted 
to demonstrate compliance with this subpart, you must submit relative 
accuracy test audit (i.e., reference method) data and performance test 
(i.e., compliance test) data, except opacity data, electronically to 
EPA's Central Data Exchange (CDX) by using the Electronic Reporting 
Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/ert tool.html/) or 
other compatible electronic spreadsheet. Only data collected using test 
methods compatible with ERT are subject to this requirement to be 
submitted electronically into EPA's WebFIRE database.
    (f) If you intend to commence or recommence combustion of solid 
waste, you must provide 30 days prior notice of the date upon which you 
will commence or recommence combustion of solid waste. The notification 
must identify:
    (1) The name of the owner or operator of the affected source, the 
location of the source, the boiler(s) that will commence burning solid 
waste, and the date of the notice.
    (2) The currently applicable subcategory under this subpart.
    (3) The date on which you became subject to the currently 
applicable emission limits.
    (4) The date upon which you will commence combusting solid waste.
    (g) If you intend to switch fuels, and this fuel switch may result 
in the applicability of a different subcategory or a switch out of 
subpart JJJJJJ due to a switch to 100 percent natural gas, you must 
provide 30 days prior notice of the date upon which you will switch 
fuels. The notification must identify:
    (1) The name of the owner or operator of the affected source, the 
location of the source, the boiler(s) that will switch fuels, and the 
date of the notice.
    (2) The currently applicable subcategory under this subpart.
    (3) The date on which you became subject to the currently 
applicable standards.
    (4) The date upon which you will commence the fuel switch.


Sec.  63.11226  How can I assert an affirmative defense if I exceed an 
emission limit during a malfunction?

    In response to an action to enforce the standards set forth in 
paragraph Sec.  63.11201 you may assert an affirmative defense to a 
claim for civil penalties for exceedances of numerical emission limits 
that are caused by malfunction, as defined at Sec.  63.2. Appropriate 
penalties may be assessed, however, 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) To establish the affirmative defense in any action to enforce 
such a limit, you must timely meet the notification requirements in 
paragraph (b) of this section, and must prove by a preponderance of 
evidence that:
    (1) The excess emissions:
    (i) Were caused by a sudden, infrequent, and unavoidable failure of 
air pollution control and monitoring 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) Were not part of a recurring pattern indicative of inadequate 
design, operation, or maintenance; and
    (2) Repairs were made as expeditiously as possible when the 
applicable emission limitations were being exceeded. Off-shift and 
overtime labor were used, to the extent practicable to make these 
repairs; and
    (3) The frequency, amount and duration of the excess emissions 
(including any bypass) were minimized to the maximum extent practicable 
during periods of such emissions; and
    (4) If the excess emissions 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 
excess

[[Page 15599]]

emissions 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 excess emissions were 
documented by properly signed, contemporaneous operating logs; and
    (8) At all times, the facility 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 excess emissions resulting from the malfunction 
event at issue. The analysis shall also specify, using best monitoring 
methods and engineering judgment, the amount of excess emissions that 
were the result of the malfunction.
    (b) Notification. The owner or operator of the facility 
experiencing an exceedance of its emission limit(s) during a 
malfunction shall notify the Administrator by telephone or facsimile 
(FAX) transmission as soon as possible, but no later than two business 
days after the initial occurrence of the malfunction, if it wishes to 
avail itself of an affirmative defense to civil penalties for that 
malfunction. The owner or operator seeking to assert an affirmative 
defense shall also submit a written report to the Administrator within 
45 days of the initial occurrence of the exceedance of the standard in 
Sec.  63.11201 to demonstrate, with all necessary supporting 
documentation, that it has met the requirements set forth in paragraph 
(a) of this section. The owner or operator may seek an extension of 
this deadline for up to 30 additional days by submitting a written 
request to the Administrator before the expiration of the 45 day 
period. Until a request for an extension has been approved by the 
Administrator, the owner or operator is subject to the requirement to 
submit such report within 45 days of the initial occurrence of the 
exceedance.

Other Requirements and Information


Sec.  63.11235  What parts of the General Provisions apply to me?

    Table 8 to this subpart shows which parts of the General Provisions 
in Sec. Sec.  63.1 through 63.15 apply to you.


Sec.  63.11236  Who implements and enforces this subpart?

    (a) This subpart can be implemented and enforced by EPA or a 
delegated authority 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.
    (b) In delegating implementation and enforcement authority of this 
subpart to a state, local, or tribal agency under 40 CFR part 63, 
subpart E, the authorities contained in paragraphs (c) of this section 
are retained by the EPA Administrator and are not transferred to the 
state, local, or tribal agency.
    (c) The authorities that cannot be delegated to state, local, or 
tribal agencies are specified in paragraphs (c)(1) through (5) of this 
section.
    (1) Approval of an alternative non-opacity emission standard and 
work practice standards in Sec.  63.11223(a).
    (2) Approval of alternative opacity emission standard under Sec.  
63.6(h)(9).
    (3) Approval of major change to test methods under Sec.  
63.7(e)(2)(ii) and (f). A ``major change to test method'' is defined in 
Sec.  63.90.
    (4) Approval of a major change to monitoring under Sec.  63.8(f). A 
``major change to monitoring'' is defined in Sec.  63.90.
    (5) Approval of major change to recordkeeping and reporting under 
Sec.  63.10(f). A ``major change to recordkeeping/reporting'' is 
defined in Sec.  63.90.


Sec.  63.11237  What definitions apply to this subpart?

    Terms used in this subpart are defined in the Clean Air Act, in 
Sec.  63.2 (the General Provisions), and in this section as follows:
    Affirmative defense means, in the context of an enforcement 
proceeding, a response or defense put forward by a defendant, regarding 
which the defendant has the burden of proof, and the merits of which 
are independently and objectively evaluated in a judicial or 
administrative proceeding.
    Annual heat input basis means the heat input for the 12 months 
preceding the compliance demonstration.
    Bag leak detection system means a group of instruments that is 
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.
    Biomass means any biomass-based solid fuel that is not a solid 
waste. This includes, but is not limited to, wood residue and wood 
products (e.g., trees, tree stumps, tree limbs, bark, lumber, sawdust, 
sander dust, chips, scraps, slabs, millings, and shavings); animal 
manure, including litter and other bedding materials; vegetative 
agricultural and silvicultural materials, such as logging residues 
(slash), nut and grain hulls and chaff (e.g., almond, walnut, peanut, 
rice, and wheat), bagasse, orchard prunings, corn stalks, coffee bean 
hulls and grounds. This definition of biomass is not intended to 
suggest that these materials are or are not solid waste.
    Biomass subcategory includes any boiler that burns at least 15 
percent biomass on an annual heat input basis.
    Boiler means an enclosed device using controlled flame combustion 
in which water is heated to recover thermal energy in the form of steam 
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. Waste heat boilers are excluded from this definition.
    Boiler system means the boiler and associated components, such as, 
the feedwater system, the combustion air system, the boiler fuel system 
(including burners), blowdown system, combustion control system, steam 
system, and condensate return system.
    Coal means all solid fuels classifiable as anthracite, bituminous, 
sub-bituminous, or lignite by the American Society for Testing and 
Materials in ASTM D388 (incorporated by reference, see Sec.  63.14), 
coal refuse, and petroleum coke. For the purposes of this subpart, this 
definition of ``coal'' includes synthetic fuels derived from coal 
including, but not limited to, solvent-refined coal, coal-oil mixtures, 
and coal-water mixtures. Coal derived gases are excluded from this 
definition.
    Coal subcategory includes any boiler that burns any solid fossil 
fuel and no more than 15 percent biomass on an annual heat input basis.
    Commercial boiler means a boiler used in commercial establishments 
such as hotels, restaurants, and laundries to provide electricity, 
steam, and/or hot water.
    Deviation (1) Deviation 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 requirement or obligation established by this 
subpart including, but not limited to, any emission limit, operating 
limit, or work practice standard;

[[Page 15600]]

    (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; or
    (2) A deviation is not always a violation. The determination of 
whether a deviation constitutes a violation of the standard is up to 
the discretion of the entity responsible for enforcement of the 
standards.
    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 
in fluidized bed boilers are included in this definition. A dry 
scrubber is a dry control system.
    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 a dry control system, except 
when it is operated with a wet scrubber.
    Energy assessment means the following only as this term is used in 
Table 3 to this subpart:
    (1) Energy assessment for facilities with affected boilers using 
less than 0.3 trillion Btu (TBtu) per year heat input will be one day 
in length maximum. The boiler system and energy use system accounting 
for at least 50 percent of the affected boiler(s) energy output will be 
evaluated to identify energy savings opportunities, within the limit of 
performing a one day energy assessment.
    (2) Energy assessment for facilities with affected boilers and 
process heaters using 0.3 to 1 TBtu/year will be three days in length 
maximum. The boiler system(s) and any energy use system(s) accounting 
for at least 33 percent of the affected boiler(s) energy output will be 
evaluated to identify energy savings opportunities, within the limit of 
performing a 3-day energy assessment.
    (3) Energy assessment for facilities with affected boilers and 
process heaters using greater than 1.0 TBtu/year, the boiler system(s) 
and any energy use system(s) accounting for at least 20 percent of the 
affected boiler(s) energy output will be evaluated to identify energy 
savings opportunities.
    Energy use system includes, but not limited to, process heating; 
compressed air systems; machine drive (motors, pumps, fans); process 
cooling; facility heating, ventilation, and air-conditioning (HVAC) 
systems; hot heater systems;, building envelop; and lighting.
    Equivalent means the following only as this term is used in Table 5 
to this subpart:
    (1) An equivalent sample collection procedure means a published 
voluntary consensus standard or practice (VCS) or
    EPA method that includes collection of a minimum of three composite 
fuel samples, with each composite consisting of a minimum of three 
increments collected at approximately equal intervals over the test 
period.
    (2) An equivalent sample compositing procedure means a published 
VCS or EPA method to systematically mix and obtain a representative 
subsample (part) of the composite sample.
    (3) An equivalent sample preparation procedure means a published 
VCS or EPA method that: Clearly states that the standard, practice or 
method is appropriate for the pollutant and the fuel matrix; or is 
cited as an appropriate sample preparation standard, practice or method 
for the pollutant in the chosen VCS or EPA determinative or analytical 
method.
    (4) An equivalent procedure for determining heat content means a 
published VCS or EPA method to obtain gross calorific (or higher 
heating) value.
    (5) An equivalent procedure for determining fuel moisture content 
means a published VCS or EPA method to obtain moisture content. If the 
sample analysis plan calls for determining mercury using an aliquot of 
the dried sample, then the drying temperature must be modified to 
prevent vaporizing this metal. On the other hand, if metals analysis is 
done on an ``as received'' basis, a separate aliquot can be dried to 
determine moisture content and the mercury concentration mathematically 
adjusted to a dry basis.
    (6) An equivalent mercury determinative or analytical procedure 
means a published VCS or EPA method that clearly states that the 
standard, practice, or method is appropriate for mercury and the fuel 
matrix and has a published detection limit equal or lower than the 
methods listed in Table 5 to this subpart for the same purpose.
    Fabric filter means an add-on air pollution control device used to 
capture particulate matter by filtering gas streams through filter 
media, also known as a baghouse. A fabric filter is a dry control 
system.
    Federally enforceable means all limitations and conditions that are 
enforceable by the EPA Administrator, including the requirements of 40 
CFR part 60 and 40 CFR part 61, requirements within any applicable 
state implementation plan, and any permit requirements established 
under Sec. Sec.  52.21 or under 51.18 and Sec.  51.24.
    Fuel type means each category of fuels that share a common name or 
classification. Examples include, but are not limited to, bituminous 
coal, sub-bituminous coal, lignite, anthracite, biomass, distillate 
oil, residual oil. Individual fuel types received from different 
suppliers are not considered new fuel types.
    Gaseous fuels includes, but is not limited to, natural gas, process 
gas, landfill gas, coal derived gas, refinery gas, hydrogen, and 
biogas.
    Gas-fired boiler includes any boiler that burns gaseous fuels not 
combined with any solid fuels, burns liquid fuel only during periods of 
gas curtailment, gas supply emergencies, 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, or returned condensate.
    Hot water heater means a closed vessel with a capacity of no more 
than 120 U.S. gallons in which water is heated by combustion of gaseous 
or liquid fuel and is withdrawn for use external to the vessel at 
pressures not exceeding 160 psig, including the apparatus by which the 
heat is generated and all controls and devices necessary to prevent 
water temperatures from exceeding 210 degrees Fahrenheit (99 degrees 
Celsius).
    Industrial boiler means a boiler used in manufacturing, processing, 
mining, and refining or any other industry to provide steam, hot water, 
and/or electricity.
    Institutional boiler means a boiler used in institutional 
establishments such as medical centers, research centers, and 
institutions of higher education to provide electricity, steam, and/or 
hot water.
    Liquid fuel means, but not limited to, petroleum, distillate oil, 
residual oil, any form of liquid fuel derived from petroleum, used oil, 
liquid biofuels, and biodiesel.
    Minimum activated carbon injection rate means load fraction 
(percent) multiplied by the lowest 1-hour 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 limits.
    Minimum oxygen level means the lowest 1-hour average oxygen level

[[Page 15601]]

measured according to Table 6 of this subpart during the most recent 
performance stack test demonstrating compliance with the applicable CO 
emission limit.
    Minimum PM scrubber pressure drop means the lowest 1-hour average 
PM 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 flow rate means the boiler load (percent) 
multiplied by the lowest 2-hour average sorbent (or 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 limits.
    Minimum voltage or amperage means the lowest 1-hour average total 
electric power value (secondary voltage x secondary current = secondary 
electric power) 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 the earth's surface, of 
which the principal constituent is methane including intermediate gas 
streams generated during processing of natural gas at production sites 
or at gas processing plants; 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).
    (3) A mixture of hydrocarbons that maintains a gaseous state at ISO 
conditions. Additionally, natural gas must either be composed of at 
least 70 percent methane by volume or have a gross calorific value 
between 34 and 43 megajoules (MJ) per dry standard cubic meter (910 and 
1,150 Btu per dry standard cubic foot).
    (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 during periods of gas curtailment, gas supply 
emergencies, or for periodic testing not to exceed 48 hours during any 
calendar year are not included in this definition.
    Opacity means the degree to which emissions reduce the transmission 
of light and obscure the view of an object in the background.
    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 alternative method.
    Performance testing means the collection of data resulting from the 
execution of a test method used (either by stack testing or fuel 
analysis) to demonstrate compliance with a relevant emission standard.
    Period of natural gas curtailment or supply interruption means a 
period of time during which the supply of natural gas to an affected 
facility is halted for reasons beyond the control of the facility. The 
act of entering into a contractual agreement with a supplier of natural 
gas established for curtailment purposes does not constitute a reason 
that is under the control of a facility for the purposes of this 
definition. An increase in the cost or unit price of natural gas does 
not constitute a period of natural gas curtailment or supply 
interruption.
    Qualified energy assessor means:
    (1) someone who has demonstrated capabilities to evaluate a set of 
the typical energy savings opportunities available in opportunity areas 
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.
    (vi) 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.
    Responsible official means responsible official as defined in Sec.  
70.2.
    Solid fossil fuel includes, but not limited to, coal, petroleum 
coke, and tire derived fuel.
    Waste heat boiler means a device that recovers normally unused 
energy and converts it to usable heat. Waste heat boilers are also 
referred to as heat recovery steam generators.
    Work practice standard means any design, equipment, work practice, 
or operational standard, or combination thereof, which is promulgated 
pursuant to section 112(h) of the Clean Air Act.

          Table 1 to Subpart JJJJJJ of Part 63--Emission Limits
    [As stated in Sec.   63.11201, you must comply with the following
                      applicable 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 boiler with   a. Particulate     0.03 lb per MMBtu of
 heat input capacity of 30       Matter.            heat input.
 million Btu per hour or
 greater.
                                b. Mercury.......  0.0000048 lb per
                                                    MMBtu of heat input.
                                c. Carbon          400 ppm by volume on
                                 Monoxide.          a dry basis
                                                    corrected to 3
                                                    percent oxygen.
2. New coal-fired boiler with   a. Particulate     0.42 lb per MMBtu of
 heat input capacity of          Matter.            heat input.
 between 10 and 30 million Btu
 per hour.

[[Page 15602]]

 
                                b. Mercury.......  0.0000048 lb per
                                                    MMBtu of heat input.
                                c. Carbon          400 ppm by volume on
                                 Monoxide.          a dry basis
                                                    corrected to 3
                                                    percent oxygen.
3. New biomass-fired boiler     a. Particulate     0.03 lb per MMBtu of
 with heat input capacity of     Matter.            heat input.
 30 million Btu per hour or
 greater.
4. New biomass fired boiler     a. Particulate     0.07 lb per MMBtu of
 with heat input capacity of     Matter.            heat input.
 between 10 and 30 million Btu
 per hour.
5. New oil-fired boiler with    a. Particulate     0.03 lb per MMBtu of
 heat input capacity of 10       Matter.            heat input.
 million Btu per hour or
 greater.
6. Existing coal (units with    a. Mercury.......  0.0000048 lb per
 heat input capacity of 10                          MMBtu of heat input.
 million Btu per hour or
 greater).
                                b. Carbon          400 ppm by volume on
                                 Monoxide.          a dry basis
                                                    corrected to 3
                                                    percent oxygen.
------------------------------------------------------------------------


 Table 2 to Subpart JJJJJJ of Part 63--Work Practice Standards, Emission
              Reduction Measures, and Management Practices
    [As stated in Sec.   63.11201, you must comply with the following
  applicable work practice standards, emission reduction measures, and
                         management practices:]
------------------------------------------------------------------------
  If your boiler is in this
       subcategory. . .             You must meet the following. . .
------------------------------------------------------------------------
1. Existing or new coal, new   Minimize the boiler's startup and
 biomass, and new oil (units    shutdown periods following the
 with heat input capacity of    manufacturer's recommended procedures.
 10 million Btu per hour or     If manufacturer's recommended procedures
 greater).                      are not available, you must follow
                                recommended procedures for a unit of
                                similar design for which manufacturer's
                                recommended procedures are available.
2. Existing or new coal        Conduct a tune-up of the boiler
 (units with heat input         biennially as specified in Sec.
 capacity of less than 10       63.11223.
 million Btu per hour).
3. Existing or new biomass or  Conduct a tune-up of the boiler
 oil.                           biennially as specified in Sec.
                                63.11223.
4. Existing coal, biomass, or  Must have a one-time energy assessment
 oil (units with heat input     performed by a qualified energy
 capacity of 10 million Btu     assessor. An energy assessment completed
 per hour and greater).         on or after January 1, 2008, that meets
                                or is amended to meet the energy
                                assessment requirements in this table
                                satisfies the energy assessment
                                requirement. The energy assessment must
                                include:
                               (1) A visual inspection of the boiler
                                system,
                               (2) An evaluation of operating
                                characteristics of the facility,
                                specifications of energy using systems,
                                operating and maintenance procedures,
                                and unusual operating constraints,
                               (3) Inventory of major systems consuming
                                energy from affected boiler(s),
                               (4) A review of available architectural
                                and engineering plans, facility
                                operation and maintenance procedures and
                                logs, and fuel usage,
                               (5) A list of major energy conservation
                                measures,
                               (6) A list of the energy savings
                                potential of the energy conservation
                                measures identified,
                               (7) A comprehensive report detailing the
                                ways to improve efficiency, the cost of
                                specific improvements, benefits, and the
                                time frame for recouping those
                                investments.
------------------------------------------------------------------------


 Table 3 to Subpart JJJJJJ of Part 63--Operating Limits for Boilers With
                             Emission Limits
   [As stated in Sec.   63.11201, you must comply with the applicable
                           operating limits:]
------------------------------------------------------------------------
If you demonstrate compliance
   with applicable emission    You must meet these operating limits. . .
      limits using . . .
------------------------------------------------------------------------
1. Fabric filter control.....  a. Maintain opacity to less than or equal
                                to 10 percent opacity (daily block
                                average); OR
                               b. Install and operate a bag leak
                                detection system according to Sec.
                                63.11224 and operate the fabric filter
                                such that the bag leak detection system
                                alarm does not sound more than 5 percent
                                of the operating time during each 6-
                                month period.
2. Electrostatic precipitator  a. Maintain opacity to less than or equal
 control.                       to 10 percent opacity (daily block
                                average); OR
                               b. Maintain the secondary power input of
                                the electrostatic precipitator at or
                                above the lowest 1-hour average
                                secondary electric power measured during
                                the most recent performance test
                                demonstrating compliance with the
                                particulate matter emission limitations.
3. Wet PM scrubber control...  Maintain the pressure drop at or above
                                the lowest 1-hour average pressure drop
                                across the wet scrubber and the liquid
                                flow-rate at or above the lowest 1-hour
                                average liquid flow rate measured during
                                the most recent performance test
                                demonstrating compliance with the PM
                                emission limitation.

[[Page 15603]]

 
4. Dry sorbent or carbon       Maintain the sorbent or carbon injection
 injection control.             rate at or above the lowest 2-hour
                                average sorbent flow rate measured
                                during the most recent performance test
                                demonstrating compliance with the
                                mercury emissions limitation. When your
                                boiler operates at lower loads, multiply
                                your sorbent or carbon injection rate by
                                the load fraction (e.g., actual heat
                                input divided by the heat input during
                                performance stack test, for 50 percent
                                load, multiply the injection rate
                                operating limit by 0.5).
5. Any other add-on air        This option is for boilers that operate
 pollution control type.        dry control systems. Boilers must
                                maintain opacity to less than or equal
                                to 10 percent opacity (daily block
                                average).
6. Fuel analysis.............  Maintain the fuel type or fuel mixture
                                (annual average) such that the mercury
                                emission rates calculated according to
                                Sec.   63.11211(b) is less than the
                                applicable emission limits for mercury.
7. Performance stack testing.  For boilers that demonstrate compliance
                                with a performance stack test, maintain
                                the operating load of each unit such
                                that is does not exceed 110 percent of
                                the average operating load recorded
                                during the most recent performance stack
                                test.
8. Continuous Oxygen Monitor.  Maintain the oxygen level at or above the
                                lowest 1-hour average oxygen level
                                measured during the most recent CO
                                performance stack test.
------------------------------------------------------------------------


    Table 4 to Subpart JJJJJJ of Part 63--Performance (Stack) Testing
                              Requirements
    [As stated in Sec.   63.11212, you must comply with the following
    requirements for performance (stack) test for affected sources:]
------------------------------------------------------------------------
  To conduct a performance
   test for the following         You must. . .          Using. . .
       pollutant. . .
------------------------------------------------------------------------
1. Particulate Matter.......  a. Select sampling    Method 1 in appendix
                               ports location and    A-1 to part 60 of
                               the number of         this chapter.
                               traverse points.
                              b. Determine          Method 2, 2F, or 2G
                               velocity and          in appendix A-2 to
                               volumetric flow-      part 60 of this
                               rate of the stack     chapter.
                               gas.
                              c. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A-2 to
                               concentrations of     part 60 of this
                               the stack gas.        chapter, or ASTM
                                                     D6522-00
                                                     (Reapproved
                                                     2005),\a\ or ANSI/
                                                     ASME PTC 19.10-
                                                     1981. \a\
                              d. Measure the        Method 4 in appendix
                               moisture content of   A-3 to part 60 of
                               the stack gas.        this chapter.
                              e. Measure the        Method 5 or 17
                               particulate matter    (positive pressure
                               emission              fabric filters must
                               concentration.        use Method 5D) in
                                                     appendix A-3 and A-
                                                     6 to part 60 of
                                                     this chapter and a
                                                     minimum 1 dscm of
                                                     sample volume per
                                                     run.
                              f. Convert emissions  Method 19 F-factor
                               concentration to lb/  methodology in
                               MMBtu emission        appendix A-7 to
                               rates.                part 60 of this
                                                     chapter.
2. Mercury..................  a. Select sampling    Method 1 in appendix
                               ports location and    A-1 to part 60 of
                               the number of         this chapter.
                               traverse points.
                              b. Determine          Method 2, 2F, or 2G
                               velocity and          in appendix A-2 to
                               volumetric flow-      part 60 of this
                               rate of the stack     chapter.
                               gas.
                              c. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A-2 to
                               concentrations of     part 60 of this
                               the stack gas.        chapter, or ASTM
                                                     D6522-00
                                                     (Reapproved 2005)
                                                     ,\a\ or ANSI/ASME
                                                     PTC 19.10-1981. \a\
                              d. Measure the        Method 4 in appendix
                               moisture content of   A-3 to part 60 of
                               the stack gas.        this chapter.
                              e. Measure the        Method 29, 30A, or
                               mercury emission      30B in appendix A-8
                               concentration.        to part 60 of this
                                                     chapter or Method
                                                     101A in appendix B
                                                     to part 61 of this
                                                     chapter or ASTM
                                                     Method D6784-02.\a\
                                                     Collect a minimum 2
                                                     dscm of sample
                                                     volume with Method
                                                     29 of 101A per run.
                                                     Use a minimum run
                                                     time of 2 hours
                                                     with Method 30A.
                              f. Convert emissions  Method 19 F-factor
                               concentration to lb/  methodology in
                               MMBtu emission        appendix A-7 to
                               rates.                part 60 of this
                                                     chapter.
3. Carbon Monoxide..........  a. Select the         Method 1 in appendix
                               sampling ports        A-1 to part 60 of
                               location and the      this chapter.
                               number of traverse
                               points.
                              b. Determine oxygen   Method 3A or 3B in
                               and carbon dioxide    appendix A-2 to
                               concentrations of     part 60 of this
                               the stack gas.        chapter, or ASTM
                                                     D6522-00
                                                     (Reapproved
                                                     2005),\a\ or ANSI/
                                                     ASME PTC 19.10-
                                                     1981.\a\
                              c. Measure the        Method 4 in appendix
                               moisture content of   A-3 to part 60 of
                               the stack gas.        this chapter.

[[Page 15604]]

 
                              d. Measure the        Method 10, 10A, or
                               carbon monoxide       10B in appendix A-4
                               emission              to part 60 of this
                               concentration.        chapter or ASTM
                                                     D6522-00
                                                     (Reapproved 2005)
                                                     \a\ and a minimum 1
                                                     hour sampling time
                                                     per run.
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.


    Table 5 to Subpart JJJJJJ of Part 63--Fuel Analysis Requirements
    [As stated in Sec.   63.11213, you must comply with the following
      requirements for fuel analysis testing for affected sources:]
------------------------------------------------------------------------
 To conduct a fuel analysis
 for the following pollutant      You must. . .          Using . . .
            . . .
------------------------------------------------------------------------
1. Mercury..................  a. Collect fuel       Procedure in Sec.
                               samples.              63.11213(b) or ASTM
                                                     D2234/D2234M \a\
                                                     (for coal) or ASTM
                                                     D6323 \a\ (for
                                                     biomass) or
                                                     equivalent.
                              b. Compose fuel       Procedure in Sec.
                               samples.              63.11213(b) or
                                                     equivalent.
                              c. Prepare            EPA SW-846-3050B \a\
                               composited fuel       (for solid samples)
                               samples.              or EPA SW-846-3020A
                                                     \a\ (for liquid
                                                     samples) or ASTM
                                                     D2013/D2013M \a\
                                                     (for coal) or ASTM
                                                     D5198 \a\ (for
                                                     biomass) or
                                                     equivalent.
                              d. Determine heat     ASTM D5865 \a\ (for
                               content of the fuel   coal) or ASTM E711
                               type.                 \a\ (for biomass)
                                                     or equivalent.
                              e. Determine          ASTM D3173 \a\ or
                               moisture content of   ASTM E871 \a\ or
                               the fuel type         equivalent.
                              f. Measure mercury    ASTM D6722 \a\ (for
                               concentration in      coal) or EPA SW-846-
                               fuel sample           7471B \a\ (for
                                                     solid samples) or
                                                     EPA SW-846-7470A
                                                     \a\ (for liquid
                                                     samples) or
                                                     equivalent.
                              g. Convert            ....................
                               concentrations into
                               units of lb/MMBtu
                               of heat content
------------------------------------------------------------------------
\a\ Incorporated by reference, see Sec.   63.14.


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

[[Page 15605]]

 
2. Mercury.....................  a. Activated       i. Establish a     (1) Data from the  (a) You must collect
                                  carbon injection.  site-specific      activated carbon   activated carbon
                                                     minimum            rate monitors      injection rate data
                                                     activated carbon   and mercury        every 15 minutes
                                                     injection rate     performance        during the entire
                                                     operating limit    stack tests.       period of the
                                                     according to                          performance stack
                                                     Sec.                                  tests;
                                                     63.11211(b).                         (b) Determine the
                                                                                           average activated
                                                                                           carbon injection rate
                                                                                           for each individual
                                                                                           test run in the three-
                                                                                           run performance stack
                                                                                           test by computing the
                                                                                           average of all the 15-
                                                                                           minute readings taken
                                                                                           during each test run.
                                                                                          (c) When your unit
                                                                                           operates at lower
                                                                                           loads, multiply your
                                                                                           activated carbon
                                                                                           injection rate by the
                                                                                           load fraction (e.g.,
                                                                                           actual heat input
                                                                                           divided by heat input
                                                                                           during performance
                                                                                           stack test, for 50
                                                                                           percent load,
                                                                                           multiply the
                                                                                           injection rate
                                                                                           operating limit by
                                                                                           0.5) to determine the
                                                                                           required injection
                                                                                           rate.
3. Carbon monoxide.............  a. Oxygen........  i. Establish a     (1) Data from the  (a) You must collect
                                                     unit-specific      oxygen monitor     oxygen data every 15
                                                     limit for          specified in       minutes during the
                                                     minimum oxygen     Sec.               entire period of the
                                                     level according    63.11224(a).       performance stack
                                                     to Sec.                               tests;
                                                     63.11211(b).                         (b) Determine the
                                                                                           average 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.
----------------------------------------------------------------------------------------------------------------


Table 7 to Subpart DDDDD of Part 63--Demonstrating Continuous Compliance
 [As stated in Sec.   63.11222, you must show continuous compliance with
     the emission limitations for affected sources according to the
                               following:]
------------------------------------------------------------------------
     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 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 12-hour block
                                averages; and
                               c. Maintaining the 12-hour average
                                pressure drop and liquid flow-rate at or
                                above the operating limits established
                                during the performance test according to
                                Sec.   63.1140.
4. Dry scrubber sorbent or     a. Collecting the sorbent or carbon
 carbon injection rate.         injection rate monitoring system data
                                for the dry scrubber according to Sec.
                                Sec.   63.11224 and 63.11220; and
                               b. Reducing the data to 12-hour block
                                averages; and
                               c. Maintaining the 12-hour average
                                sorbent or carbon injection rate at or
                                above the minimum sorbent or carbon
                                injection rate as defined in Sec.
                                63.11237.
5. Electrostatic precipitator  a. Collecting the secondary amperage and
 secondary amperage and         voltage, or total power input monitoring
 voltage, or total power        system data for the electrostatic
 input.                         precipitator according to Sec.  Sec.
                                63.11224 and 63.11220; and
                               b. Reducing the data to 12-hour block
                                averages; and
                               c. Maintaining the 12-hour average
                                secondary amperage and voltage, or total
                                power input at or above the operating
                                limits established during the
                                performance test according to Sec.
                                63.11214.
6. Fuel pollutant content....  a. Only burning the fuel types and fuel
                                mixtures used to demonstrate compliance
                                with the applicable emission limit
                                according to Sec.   63.11214 as
                                applicable; and
                               b. Keeping monthly records of fuel use
                                according to Sec.   63.11222.
7. Oxygen content............  a. Continuously monitor the oxygen
                                content in the combustion exhaust
                                according to Sec.   63.11224.
                               b. Maintain the 12-hour average oxygen
                                content at or above the operating limit
                                established during the most recent
                                carbon monoxide performance test.
------------------------------------------------------------------------


[[Page 15606]]


     Table 8 to Subpart JJJJJJ of Part 63--Applicability of General
                      Provisions to Subpart JJJJJJ
   [As stated in Sec.   63.11235, you must comply with the applicable
             General Provisions according to the following:]
------------------------------------------------------------------------
     General provisions cite            Subject         Does it apply?
------------------------------------------------------------------------
Sec.   63.1.....................  Applicability.....  Yes.
Sec.   63.2.....................  Definitions.......  Yes. Additional
                                                       terms defined in
                                                       Sec.   63.11237.
Sec.   63.3.....................  Units and           Yes.
                                   Abbreviations.
Sec.   63.4.....................  Prohibited          Yes.
                                   Activities and
                                   Circumvention.
Sec.   63.5.....................  Preconstruction     No
                                   Review and
                                   Notification
                                   Requirements.
Sec.   63.6(a), (b)(1)-(b)(5),    Compliance with     Yes.
 (b)(7), (c), (f)(2)-(3), (g),     Standards and
 (i), (j).                         Maintenance
                                   Requirements.
Sec.   63.6(e)(1)(i)............  General Duty to     No. See Sec.
                                   minimize            63.11205 for
                                   emissions.          general duty
                                                       requirement.
Sec.   63.6(e)(1)(ii)...........  Requirement to      No.
                                   correct
                                   malfunctions ASAP.
Sec.   63.6(e)(3)...............  SSM Plan..........  No.
Sec.   63.6(f)(1)...............  SSM exemption.....  No.
Sec.   63.6(h)(1)...............  SSM exemption.....  No.
Sec.   63.6(h)(2) to (9)........  Determining         Yes.
                                   compliance with
                                   opacity emission
                                   standards.
Sec.   63.7(a), (b), (c), (d) ,   Performance         Yes.
 (e)(2)-(e)(9), (f), (g), and      Testing
 (h).                              Requirements.
Sec.   63.7(e)(1)...............  Performance         No. See Sec.
                                   testing.            63.11210.
Sec.   63.8(a), (b), (c)(1),      Monitoring          Yes.
 (c)(1)(ii), (c)(2) to (c)(9),     Requirements.
 (d)(1) and (d)(2), (e),(f), and
 (g).
Sec.   63.8(c)(1)(i)............  General duty to     No.
                                   minimize
                                   emissions and CMS
                                   operation.
Sec.   63.8(c)(1)(iii)..........  Requirement to      No.
                                   develop SSM Plan
                                   for CMS.
Sec.   63.8(d)(3)...............  Written procedures  Yes, except for
                                   for CMS.            the last
                                                       sentence, which
                                                       refers to an SSM
                                                       plan. SSM plans
                                                       are not required.
Sec.   63.9.....................  Notification        Yes.
                                   Requirements.
Sec.   63.10(a) and (b)(1)......  Recordkeeping and   Yes.
                                   Reporting
                                   Requirements.
Sec.   63.10(b)(2)(i)...........  Recordkeeping of    No.
                                   occurrence and
                                   duration of
                                   startups or
                                   shutdowns.
Sec.   63.10(b)(2)(ii)..........  Recordkeeping of    No. See Sec.
                                   malfunctions.       63.11225 for
                                                       recordkeeping of
                                                       (1) occurrence
                                                       and duration and
                                                       (2) actions taken
                                                       during
                                                       malfunctions.
Sec.   63.10(b)(2)(iii).........  Maintenance         Yes.
                                   records.
Sec.   63.10(b)(2)(iv) and (v)..  Actions taken to    No.
                                   minimize
                                   emissions during
                                   SSM.
Sec.   63.10(b)(2)(vi)..........  Recordkeeping for   Yes.
                                   CMS malfunctions.
Sec.   63.10(b)(2)(vii) to (xiv)  Other CMS           Yes.
                                   requirements.
Sec.   63.10(b)(3)..............  Recordkeeping       No.
                                   requirements for
                                   applicability
                                   determinations.
Sec.   63.10(c)(1) to (9).......  Recordkeeping for   Yes.
                                   sources with CMS.
Sec.   63.10(c)(10).............  Recording nature    No. See Sec.
                                   and cause of        63.11225 for
                                   malfunctions.       malfunction
                                                       recordkeeping
                                                       requirements.
Sec.   63.10(c)(11).............  Recording           No. See Sec.
                                   corrective          63.11225 for
                                   actions.            malfunction
                                                       recordkeeping
                                                       requirements.
Sec.   63.10(c)(12) and (13)....  Recordkeeping for   Yes.
                                   sources with CMS.
Sec.   63.10(c)(15).............  Allows use of SSM   No.
                                   plan.
Sec.   63.10(d)(1) and (2)......  General reporting   Yes.
                                   requirements.
Sec.   63.10(d)(3)..............  Reporting opacity   No.
                                   or visible
                                   emission
                                   observation
                                   results.
Sec.   63.10(d)(4)..............  Progress reports    Yes.
                                   under an
                                   extension of
                                   compliance.
Sec.   63.10(d)(5)..............  SSM reports.......  No. See Sec.
                                                       63.11225 for
                                                       malfunction
                                                       reporting
                                                       requirements.
Sec.   63.10(e) and (f).........  ..................  Yes.
Sec.   63.11....................  Control Device      No.
                                   Requirements.
Sec.   63.12....................  State Authority     Yes.
                                   and Delegation.
Sec.   63.13-63.16..............  Addresses,          Yes.
                                   Incorporation by
                                   Reference,
                                   Availability of
                                   Information,
                                   Performance Track
                                   Provisions.
Sec.   63.1(a)(5), (a)(7)-        Reserved..........  No.
 (a)(9), (b)(2), (c)(3)-(4),
 (d), 63.6(b)(6), (c)(3),
 (c)(4), (d), (e)(2),
 (e)(3)(ii), (h)(3), (h)(5)(iv),
 63.8(a)(3), 63.9(b)(3), (h)(4),
 63.10(c)(2)-(4), (c)(9).
------------------------------------------------------------------------


[FR Doc. 2011-4493 Filed 3-18-11; 8:45 am]
BILLING CODE 6560-50-P


