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

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

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

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

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

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

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

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.

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

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.

    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).

    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

                                           <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.

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

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)

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)

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

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