[Federal Register Volume 76, Number 54 (Monday, March 21, 2011)]
[Rules and Regulations]
[Pages 15554-15606]
From the Federal Register Online via the Government Publishing 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:
[email protected].
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
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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
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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
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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.
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\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.
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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\
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3% Discount rate 7% Discount rate
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Final MACT/GACT Approach: Selected
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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
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Proposed MACT Approach: Alternative
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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
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\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