determined for that test. An effect of reporting data in this manner is
that the resulting database is truncated at the lower end of the
measurement range (i.e., no values reported below the test-specific
method detection level). A floor or emissions limit based on a
truncated database or otherwise including values measured near the
method detection level may not adequately account for measurement
imprecision contribution to the data variability. That is, an emission
limit set based on the use of the MDL to represent data below the MDL
may be significantly different than the actual levels achieved by the
best performing units due to the imprecision of the measurements. This
fact, combined with the low levels of emissions measured from many of
the best performing units, led EPA to develop a procedure to account
for the contribution of measurement imprecision to data variability.
    We applied the following procedures to account for the effect of
measurement imprecision associated with a database that includes method
detection level data. The first step was to define a method detection
level that is representative of the data used in establishing the floor
or emissions limit and that also minimizes the influence of an outlier
test-specific method detection level value. We reviewed each pollutant-
specific data set to identify the highest test-specific method
detection level reported that was also equal to or less than the
average emissions level (i.e., unadjusted for probability confidence
level) calculated for the data set. We believe that this approach is
representative of the data collected to develop the floor or emissions
limit while to some degree minimizing the effect of a test(s) with an
inordinately high method detection level (e.g., the sample volume was
too small, the laboratory technique was insufficiently sensitive, or
the procedure for determining the detection level was other than that
specified).
    The second step in the process is to calculate three times the
representative

method detection level \6\ and compare that value to the calculated
floor or emissions limit. If three times the representative method
detection level were less than the calculated floor or emissions limit
calculated from the upper prediction limit (UPL), we would conclude
that measurement variability was adequately addressed because the
measurement inprecision at that level is a consistent 10 to 15 percent.
The calculated floor or emissions limit would need no adjustment. If,
on the other hand, the value equal to three times the representative
method detection level were greater than the UPL-based emission limit,
we would conclude that the calculated floor or emission limit does not
account entirely for measurement variability. If indicated, we
substituted the value equal to three times the representative method
detection level to apply as the adjusted floor or emissions limit. This
adjusted value would ensure measurement variability is adequately
addressed in the floor or the emissions limit.
---------------------------------------------------------------------------

    \6\ Ibid.
---------------------------------------------------------------------------

    In response to comments that EPA should have used the PQL, RL, or
LOQ values in place of non-detect values, we disagree that use of those
values is appropriate for calculating the MACT floors for two reasons.
First, these terms are not defined statistically or consistently from
method to method but are relatively arbitrary multiples (e.g., 3 times,
5 times, or 10 times) of the MDL. In some cases, a RL, LOQ, or PQL is a
value determined based on a laboratory-specific procedure and not
standardized by the method. We could not apply data arbitrarily
adjusted or subject to laboratory-specific variables in establishing
the floor. Second, we used a value equal to three times a
representative MDL to compare with the floor and to adjust the
applicable emissions limit, if necessary. We believe that using a value
equal to three times the MDL sufficiently accounts for measurement
uncertainty for the purposes of establishing compliance and there is no
need to try to define or apply a PQL, LOQ, or RL for this purpose.
 4. Instrument Span for CO
    Comment: Many commenters stated that the reported data and limits
for CO are within the error range of analyzers and CO CEMS. For Method
10, the calibrated analyzers have an error of 2 percent of
the instrument span, with spans ranging from 50 parts per million (ppm)
to 1000 ppm or greater. As such, at a minimum there is a potential
error of 1 ppm to 20 ppm (2 percent of 50 ppm and 1000 ppm,
respectively) while the liquid and other process gas categories have
floor limits set at 1 ppm. Similarly, commenters noted that CO CEMS
have an allowable drift of 5 percent of the span, with similar span
ranges as Method 10. Commenters questioned the technical feasibility of
complying with such low limits given the range in span values and
suggested that EPA should review the data and establish more
appropriate limits in consideration of measurement precision concerns.
    Response: EPA agrees with the comment that many of the CO
measurements are within the error range of analyzers, and EPA has taken
steps to mitigate the potential bias of such measurements. The
resulting emission limits represent a level of performance that has
been demonstrated to be achieved by the average of the best performing
12 percent of sources while considering variability introduced by
imprecision of the CO analyzers. As explained below, our assessment
indicated that the site-specific estimated measurement errors in some
cases may be higher than some of the reported emissions levels.
Therefore, for each emission test used in the MACT floor calculations
we substituted the site-specific estimated measurement error for
reported values below those values in order to ensure the quality of
the data used to set the floors.
    In response to the comments received, we reviewed the quality of
the data relative to information provided for each emissions test.
Method 10 is structured such that we can assess measurement data
quality relative to the calibration span of the instrument (see http://www.epa.gov/ttn/emc/promgate/method10r06.pdf and http://www.epa.gov/ttn/emc/promgate/method7E.pdf). For example, the allowable calibration
error, system bias, and drift requirements are directly proportional to
the site-specific instrument calibration span (i.e.,  2.0
percent of the calibration span value). For instrument calibration span
values of 25 ppmv and less, the allowable calibration error, bias, or
drift values are each  0.5 ppmv.
    We can estimate the equivalent of the method detection level for a
measurement with an instrumental test method (e.g., EPA Methods 3A, 6C,
7E, and 10) using a square root formula and these allowable data
quality criteria. For example, in the case of a calibration span value
of 25 ppmv, the square root formula (i.e., square root of the sum of
the squares) would indicate a value of 0.9 ppmv. Consistent with the
methodology we applied for non-instrumental methods, discussed in the
previous comment response where we established limits no less than 3
times the MDL in order to avoid a large degree of measurement
imprecision, this estimated measurement error value would translate to
a limit of 3.0 ppmv (rounded up from 2.7 ppmv). For tests done with
calibration spans of greater than 25 ppmv, the corresponding estimated
measurement error would be greater. For example, the estimated
measurement error using the square root formula for a calibration span
of 100 ppmv would be about 4 ppmv which would translate to a limit of
12 ppmv. For a calibration span of 1000 ppmv, the estimated measurement
error would be 35 ppmv or a limit of about 100 ppmv.
5. Achievability of Limits
    Comment: Several commenters were concerned that only small subsets
of sources in each subcategory have emissions stack test data. These
commenters added that less data means the pool from which the best
performing 12 percent of the existing sources are drawn is smaller and,
therefore, the actual number of sources used to determine the MACT
floor is smaller. The commenters suggested that EPA should collect more
data or provide assurances that the limited available data are
representative for each subcategory. Commenters suggested that EPA
could supplement testing data with ``emissions information'' such as
fuel records, production records and associated emission factors,
commercial warranties and guarantees.
    Commenters raised concerns that existing units would have
difficulty demonstrating compliance with the MACT floor limits. They
suggested best performers with advanced air pollution control
technologies should not be required to install additional add-on
equipment to meet the emission limits. Commenters requested that EPA
assess how many existing boilers and process heaters in each
subcategory will be able to meet the standards without taking any
further control measures. Several commenters contacted manufacturers
regarding a retrofit project for their boilers and process heaters and
they noted that manufacturers were unwilling to guarantee a retrofit
would meet the limits.
    Similarly, commenters raised concerns that new units would have
even more difficulty demonstrating compliance with the MACT floor
limits. These commenters had difficulty identifying a single source
whose emissions testing data demonstrated they could achieve all of the
MACT

floors for new sources in combination. Several commenters contacted
boiler and process heater manufacturers; all were unable to offer
commercial emissions guarantees that a new unit would meet the proposed
limits. Some commenters raised concerns about the impacts of these
stringent new unit floors including: Deterring sources from upgrading
to new boilers as efficiency gains provided by a new unit would be
offset by extensive controls and threatening fuel diversity.
    Some commenters expressed concern that EPA had not properly
evaluated whether there are technically feasible means of achieving the
MACT floors. The commenters contended that the approach does not
identify reasons why best performing sources achieve emissions levels
reflected in the test data and they suggested that the intent of the
MACT floor standard setting process is to discover effective control
techniques so that other performers in the source category could
emulate those techniques, reduce their emissions, and achieve similar
emission levels. Commenters added that EPA has not adequately
considered air pollution control device (APCD) conflicts with one
another or compatibility of controls on certain boilers. Additionally,
choosing to optimize controls for one pollutant may preclude
optimization of controls for another pollutant e.g., minimizing CO in
the combustion system is opposed to minimizing NOX in most
boiler burners.
    Response: As mentioned elsewhere in this preamble, EPA is required
to establish MACT floor levels based on emissions limits achieved by
sources for which emissions information is available to the
Administrator. EPA has revised the proposed MACT floors as well as the
proposed subcategories, as explained above. EPA also examined several
ways in which it might be able to use other types of emissions
information in addition to actual emissions measurements. However, EPA
concluded that there was no appropriate method of using different types
of information in a manner that could be incorporated into the
variability analyses. EPA first assessed the potential for estimating
emissions for sources that lacked actual emissions data through the use
of emission factors. However, the emission factors lack any degree of
variability. Therefore, the use of such data in this rulemaking would
have distorted the data variability in many cases, leading to standards
that were more stringent than those developed using emissions data only
and that likely underestimated actual variability. EPA also considered
whether it could otherwise estimate emissions of sources that did not
provide emissions data. However, EPA concluded that such estimations
were not possible without the development of a technically appropriate
approach to evaluate relevant information, and commenters did not
provide any such approaches. EPA's approach provides MACT floors that
are consistent with the requirements of section 112, because the floors
are based on the average emissions performance of the best performers
for which the Administrator has emissions information that is
appropriate to use in setting the floors.
    EPA agrees with commenters who note that many of the data sets are
small. However, stakeholders were encouraged to provide additional
data, and EPA significantly revised some of the proposed emission
limits based on new test data. We received little or no additional data
for some subcategories for which data sets were small at proposal. For
all data sets, the final emission limits are based on the available
data and reflect EPA's assessment of variability. Moreover, after
consideration of the comments on the achievability of the emission
limits, EPA performed additional analyses and detailed examinations of
the data and developed revised limits that are based on what has been
demonstrated to be achieved in practice. As described in more detail in
the docket memorandum entitled ``Revised MACT Floor Analysis (2011) for
the Industrial, Commercial, and Institutional Boilers and Process
Heaters National Emission Standards for Hazardous Air Pollutants--Major
Source,'' EPA has made adjustments to treatment of non-detect values,
the statistical methodology, and monitoring requirements, and also
incorporated new data and data corrections into our analyses.
Accordingly, the final emission limits better reflect the performance
of the MACT floor units than the proposed limits. EPA notes that for
each subcategory, there are existing units that are meeting the MACT
floor limits or are expected to meet the limits through application of
available control technology.
    Finally, in response to comments about low CO limits conflicting
with a unit's ability to meet NOX requirements, EPA does not
have specific information on the NOX limits and
NOX emissions for most of the units that will be subject to
the standard. However, the CO limits have been revised as discussed
elsewhere in this preamble, and compliance is based on a full load
test, while periods of startup and shutdown are subject to a work
practice standard. To the extent that units cannot meet the CO floor
and maintain NOX at the required level, oxidation catalysts
can be used to reduce CO without an increase in NOX. EPA has
included costs for these controls for many units in the cost analysis,
although data on NOX requirements were not sufficient to
allow NOX to be part of the analyses. Commenters did not
provide any data supporting claims that any of the other emission
limits or projected control devices would interfere with a source's
ability to meet any of the other emission limits.
6. Comments on Technical Approaches
    Comment: Several commenters offered suggestions for adjusting the
treatment of data from common stacks. Commenters suggested that it is
improper to count the data twice if two boilers, in the same
subcategory, exhaust through a common stack. A test conducted on the
common stack does not represent the actual emissions from a single
boiler, but rather reflects emissions from the combined simultaneous
operation of the two boilers and their associated control device(s).
The commenters contended that it is impossible to claim the test result
would be exactly the same for each boiler and they added that if a
common stack test turns out to be in the lowest 12 percent in a
subcategory, counting it twice distorts the average of the best
performers and skews the variability calculations. Commenters also
noted that it is also not appropriate to divide emissions evenly
between each boiler. Instead these commenters suggested that EPA use
the data from common stacks only a single time in the MACT floor
ranking and UPL calculations.
    Response: EPA's current approach is a reasonable approach for
comingled emissions, particularly in light of the limited dataset
available for some subcategories, because EPA can not accurately
separate the fraction of the emissions that came from the combustion
units and process emission points that are comingled in the same stack.
Applying the emissions equally to multiple units exhausting through a
common stack accurately represents the emissions of those units on
average. Further, although the use of a data point twice may dampen
variability, the inclusion of an extra unit in the floor has the
opposite effect on the overall emission limit by increasing the
denominator of the floor calculation. Either method could be used, but
the results would not differ significantly. Furthermore, for existing
sources, MACT cannot be less stringent than the average emission
limitation achieved by

the best performing 12 percent of existing sources (for which emission
information is available). If EPA ignored boilers that exhaust through
a common stack, it would be ignoring available emissions information
that is relevant to setting the MACT floor standards.
    Comment: Some commenters raised concerns that the MACT floor
methodology doesn't adequately address the inherent variability with
respect to operating conditions and control device performance.
Operational variability can include warm-ups, shutdowns, load swings,
and variations in fuel quality. They contended that emissions data
relied upon in the proposal were produced during reference method
performance testing under very limited operating conditions and with a
very limited variation in potential fuel quality. Other commenters
raised concerns that EPA has not properly acknowledged the impact of
fuel quality on emissions. One commenter urged caution to EPA when
considering variability to generate compliance margins that are
palatable to industry; suggesting that this concept is not incorporated
in the statute.
    Response: EPA is mindful of the need to account for sources'
variability in assessing sources' performance when developing
technology-based standards. EPA reviewed subcategory floor calculations
in light of these comments and believes that the two-step MACT floor
analysis process adequately addresses: (1) Performance testing
variability and (2) fuel analysis variability estimations. EPA revised
the MACT floor calculations in light of data submitted during and after
the public comment period and also modified the approaches used at
proposal for various aspects of the floor calculations.
    EPA first took fuel into consideration, to the extent it is
reflected in differences in boiler design, when we 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, and has addressed this concern in
the final rule. For a fuel based pollutant, such as PM, performance
testing must be conducted under representative full load operating
conditions, which, along with the parameter monitoring requirements,
provides an assurance that the standards are being met at all times.
For Hg and HCl, we modified the fuel based variability analysis in
consideration of comments received on this approach. The first
modification to the analysis was the introduction of a solid fuel
subcategory, which includes any unit burning at least 10 percent, on an
annual heat input basis, of any coal, fossil solid, biomass, or bio-
based solid fuel. Given the wide variety in fuel types that compose the
floor, the statistical analysis accounts for some of the inter-unit
variability for different fuel types identified to be in the floor. The
second modification was the development of a fuel variability factor
(FVF). The FVF calculations were similar to the calculations used at
proposal, but they were simplified to remove the control efficiency
calculation and the method for identifying outliers in the data was
also adjusted. The revised FVF analysis calculated a ratio for all fuel
analysis data points for units in the top 12 percent for existing units
and the top performing unit for new units in each subcategory. This
ratio compared the reported fuel analysis data, converted to units of
lb/MMBtu, to the emission test outlet data, converted to units of lb/
MMBtu, during the stack tests. At proposal we conducted an outlier
analysis of only the maximum ratios for each unit, but we revised the
outlier analysis to consider all of the ratios from top performers
within each subcategory. We then defined and identified outliers using
the test of 3 times the standard deviation and 3 minus the standard
deviation for all of the ratios in the subcategory. After removing
outliers, the remaining maximum ratio for each subcategory was
identified and multiplied by the 99 percent UPL.
    For a discussion of how EPA considered other non-fuel variability
operations, such as boiler load, see response to the comments provided
under ``What did we do with the CO Limits''.
    Comment: Several commenters argued that it is inappropriate to rank
units according to the minimum stack test since any boiler can
experience a good compliance test if conditions are favorable. Many of
these commenters suggested that EPA should instead rank the data on the
average of all stack tests. Another commenter suggested that the
different emission levels achieved by different sources are just
differences in performance and basing the ranking on the average would
be more appropriate. This commenter suggested that at a minimum, the
data used to rank and the data used as inputs into the MACT floor upper
prediction limit calculation should be consistent.
    Response: In this final rule, EPA has reasonably determined that
the best-controlled source is the source with the lowest stack test.
EPA selected the lowest stack test as a measure of best performer
because many units had only a single test available, and the comparison
of average performance from two or more tests is not directly
comparable to a single test measurement. However, all emission tests of
acceptable quality were used to assess variability. As such, all data
were considered in the floor analyses. EPA recognizes that each stack
test data point represents a true assessment of the emissions for a
combustor at a given point in time. However, where units had more than
one test available, EPA also considers these other tests to be
representative of the unit and relevant to assess run-to-run and test-
to-test variability in the MACT floor UPL calculation. EPA did screen
and remove certain test data from the MACT floor calculations if that
data were not deemed representative of current operating conditions.
7. Statistical Approach
    There were several comments made on specific aspects of the
statistical variability analysis including suggestions for the
appropriate confidence interval, appropriate statistic, and EPA's
methods for determining the distribution of the dataset. The specific
comments and EPA responses are outlined below.
    Comment: Industry, industry representatives, and environmental
advocacy groups had different perspectives on the appropriateness of
the proposed 99 percent UPL. Commenters from environmental advocacy
groups requested a lower UPL with suggestions ranging between 50 to 95
percent. One commenter stated that EPA over-counts for the potential
for future variability by using the 99 percent UPL for the entire data
set and it does not adequately account for all variability, such as how
unit maintenance and operator training may limit upward variability's
effect on emission levels, and requests that EPA explain and justify
the selection of the 99 percent UPL as opposed to the 90 or 95 percent
UPL. Another commenter stated that most statistical analyses use 90 or
95 percent confidence intervals and prediction intervals. The commenter
also claimed that 99 percent is overly conservative and results in
twice as much HAP emissions and reduced health benefits compared to a
lower UPL. Consequently the commenter stated a lower UPL would better
withstand judicial review. One commenter mentioned that there is
precedent for setting limits based on the 90th percentile and cited a
2006 analysis where EPA determined the best demonstrated technology,
which found Hg reductions based on 90th percentile

and deemed the 90th percentile ``reasonable'' because of how compliance
was to be determined and the high Hg content of the fuel used when the
emissions data were collected. These commenters also suggested that EPA
did not provide adequate rationale for selecting the 99th percentile
instead of the 50th. These commenters noted that civil enforcement of
environmental standards is based on a ``preponderance of the evidence''
which merely requires that a violation be more likely than not.
    Commenters from industry and industry representatives advocated for
a higher UPL. Commenters requested that EPA increase the UPL to 99.9
percent in order to better encompass unit emissions variability and
represent a manageable risk. Industry, like environmental advocacy
groups, also requested that EPA take into account operator training and
its effect on emissions. The commenters claimed that operators are
compelled to set emissions targets lower than limits to create a
compliance margin which helps avoid violations and their consequences.
Commenters also cited recent consideration of a 99.9 percent UPL in the
proposed HMIWI MACT rule. Commenters claimed that since the HMIWI
database consisted of a small dataset, it was unlikely full variability
was observed and thus EPA had no valid statistical basis for the
decisions to use 99 percent in the final HWIMI rule. The commenters
suggested similar data limitations in the boiler dataset and argued
that the 99.9 percent UPL should be used to allow more of a margin for
all operating conditions and sample collection variation due to the
limited data for the boiler MACT rule.
    Response: In this final rule, EPA has reasonably determined that 99
percent UPL is appropriate for fuel based HAP, and dioxin/furan, 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.
See 75 FR 54975. Many of the subcategories had limited data to
establish the MACT floor calculations and EPA determined it was
inappropriate to use a confidence level lower than 99 percent to set
the standard because doing so would result in limits that the best
performers would be expected to exceed, while this final rule requires
that units meet the limits at all times. Finally, for the fuel-based
pollutants, there are well established control measures currently used
on units in the source category (fabric filters for PM and Hg and wet
or dry scrubbers for HCl) that serve to mitigate, to some degree, the
variability in emissions that can be expected. Given this additional
consideration 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. A lower confidence level
would result in emission limits that even the best performing sources
would be expected to exceed.
    For CO, EPA considered several comments from industry and States,
which provided both quantitative and qualitative comments 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. While a good deal of CO data are available, at least for
some of the subcategories, the data show highly variable emissions that
can result from situations beyond the control of the operator, such as
fuel moisture content after a rain event, elevated moisture in the air,
and fuel feed issues or inconsistency in the fuel. The higher
confidence level selected for CO is intended to reflect the high degree
of variability in the emissions. For dioxin/furan, we also are
maintaining the 99 percent UPL. Although much of the uncertainty
associated with dioxin/furan testing will be mitigated by the
requirement in EPA Method 23 to report non-detect values as zero for
compliance purposes, the dioxin emission limits remain quite low and
the 99 percent UPL provides a high degree of confidence that the best
performing units will be able to meet the standards.
    Comment: Several commenters also addressed concerns with how EPA
determined the distribution of the dataset. Many commenters stated that
normal distribution theory has been incorrectly applied to positively
skewed or log normally distributed emissions data. Based on this,
commenters claimed that sample means, and consequently the 99 percent
UPL calculation, were incorrectly determined. Commenters suggested that
sample means should be computed based on the arithmetic mean of
lognormal distribution. One commenter requested that EPA consider using
non-normal distributions or non-parametric methods in the analysis. Two
commenters noted that the technique used by EPA based on logarithmic
transformation underestimates the prediction limit for the mean and
requested that EPA use the 2004 Bhaumik and Gibbons procedure for
computing the UPL for log-normally distributed data. Three commenters
stated that EPA is not following its own guidance document, Data
Quality Assessment: Statistical Methods for Practitioners EPA QA/G-9S,
for determining whether or not a data set is normally distributed and
should explain the reasons for not doing so. The commenters then go on
to request that EPA follow its guidance documents which recommend use
other tests aside from the skewness and kurtosis tests when data are
limited or if critical test values are not available.
    Response: EPA appreciates the detailed suggestions for alternative
approaches to determine the dataset and it 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 are
lognormally distributed, so EPA has modified its assumptions when the
results of the skewness and kurtosis tests result in a tie, or when
there are not enough data to complete the skewness and kurtosis tests.
Some of the commenters suggested that more advanced tests are necessary
to determine the dataset, such as the Shapiro-Wilkes test. These tests
needs a sample size of 50 or more, and would not be appropriate for
many of the small sample sizes used to compute the MACT floor UPL.
    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''. Given data availability, EPA selected the Bhaumik
and Gibbons 2004 approach which addresses commenters concerns with the
proposed computations.
    Comment: Several commenters suggested alternatives to the UPL
statistics such as upper tolerance limit (UTL), upper limit (UL) and
upper confidence limit (UCL). Several commenters stated that EPA's UPL
calculation was flawed and did not fully account for variability.
Commenters then suggested that if the proposed UPL approach was
maintained EPA should adopt the modified UPL equation in the Portland
cement NESHAP. Commenters argued that this statistic would

represent floors achieved in practice and account for total variability
instead of EPA's proposed UPL statistic based on sample variability.
Several commenters claimed the data set was limited and suggested that
EPA should use the UTL when data available do not represent the entire
population. One commenter claimed that the upper UCL used in the HMIWI
MACT rule was not a true prediction limit because it did not adjust the
standard deviation for the number of test runs in the future compliance
average and it should not be used in the boiler MACT rule.
    Response: EPA considered these comments and reviewed each of the
separate statistics. Because statistics is a tool and many statistical
approaches could be considered valid, EPA considered the comments and
adjusted the approach used to provide a reasonable and technically
correct statistical methodology. MACT floors for existing sources must
reflect the average emission limitation achieved by the best-performing
12 percent of existing sources. As explained below, only the UCL and
UPL adequately get at the notion of average emissions. Use of the UPL
is also consistent with other recent rulemakings. See 75 FR 54975.
    In general, confidence intervals are used to quantify one's
knowledge of a parameter or some other characteristic of a population
based on a random sample from that population. The most frequently used
type of confidence interval is the one that contains the population
mean. Given this definition, the 99 percent UCL represents the value
which we can expect the mean of the population to fall below 99 percent
of the time in repeated sampling. Whereas a confidence interval covers
a population parameter with a stated confidence, that is, a certain
proportion of the time, there is also a way to cover a fixed proportion
of the population with a stated confidence. Such an interval is called
a tolerance interval. 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 these definitions, 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 five 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 boiler MACT floor data are small, the 99th percentile is
underestimated. 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,
and we do not have that many sources represented in any MACT floor.
    In contrast to a confidence interval or a tolerance interval, 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. Given this
definition, 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.
Finally, the upper limit (UL) is roughly equivalent to the percentile
of the actual data distribution for the sample. The UL does not have a
robust statistical foundation. Basically, the UL formulation assumes
that the data: (1) Represent the population rather than a random sample
from that population, and (2) are normally distributed. The data used
to develop the MACT floors for this rule do not represent the entire
population for any subcategory, and most of the data sets are not
normally distributed. For these reasons, EPA concluded that it is not
appropriate to use the UL in setting the MACT floor limits.
    Comment: Some commenters suggested that EPA's UPL approach fails to
accomplish predicting the level of performance achieved by the best
performing sources under all operating conditions, not because of a
poor statistical framework but because of an inadequate database. These
commenters added that as a result, the inputs into the UPL equations
are not representative of a distribution of values that reflect all
operating conditions.
    Response: Section 112(d) of the Act requires EPA to base MACT floor
standards for existing sources on the average emission limitation
achieved by the best performing 12 percent of existing sources for
which EPA has emissions information. EPA has incorporated new data and
data corrections received during the public comment period. EPA also
has considered the requests for further subcategorization of the source
category in light of limits on the dataset that caution against over-
partitioning of the database. The revised analysis is based on all
emission stack test data of appropriate quality available to EPA, and
the UPL approach provides as complete a picture of variability as
possible given the limited data available.
    Comment: Some commenters questioned whether the statistical
approach met EPA's legal obligations under Section 112 of the CAA. One
commenter stated that in order to withstand judicial review, the UPL
should be calculated based on the best 6 percent of sources instead of
the best 12 percent in order to establish a floor that would require 94
percent of sources to reduce emissions. One commenter stated that the
courts did not endorse the proposed UPL procedure and that its
appropriateness should be reviewed. The commenter goes on to say that
on a statistical and technical basis, the UPL procedure is antithetical
to the instruction in Section 112(d)(3)(A) and contradicts the strong
endorsement of the high floor implementation as the best reading of the
statutory language.
    Response: While the commenter is correct that the entire MACT floor
data pool was used in the calculation of the UPL, EPA notes that
statistics is a tool that is used to estimate variability and it is
entirely appropriate to consider the variability within the best
forming 12 percent of sources in developing emission limits based on
the average performance of those sources. As far as the concept that
the floors should require 94 percent of the sources to reduce
emissions, that is not what is required by the statute. Rather, the
statute requires that the MACT floor standards for existing sources be
no less stringent than the average emission limitation achieved by the
best performing 12 percent of existing sources for which EPA has
emissions information. For example, if a category had 100 units and the
performance of the best 50 of those units was the same, the emission
limits would be based on those 50 units and they all would be projected
to meet the limits. While this is a hypothetical scenario, it
illustrates that there is no specific percentage of sources that must
reduce emissions in order for the MACT floor limits to be consistent
with the statutory requirement.
    Comment: One commenter suggested that EPA should incorporate
different statistical methods according to the amount and type of data
available in each subcategory instead of a one-size-fits-all approach.
This commenter also suggested that the approach taken by EPA must be
validated by looking at the result it creates and examining whether the
end result is reasonable. The commenter suggested applying a simple
test to identify whether the resulting

floor requires a substantial majority of each subcategory to make some
degree of emission reduction.
    Response: EPA has revised its statistical approach to include a
mixed use of confidence levels, as discussed above, as well as a mix of
statistical tools to consider the distribution of the datasets and what
types of data are used as inputs into the floor analysis. For example,
the MACT floor computations for Hg emissions from liquid fuel units
were modified to consider data from both fuel analysis and stack test
results. EPA appreciates the suggestion for validating the results of
the statistical computations and has determined that the final floor
levels require a significant number of sources to make some degree of
emission reduction. However, EPA also notes that the number of sources
that will need to achieve some degree of emissions reduction from
current levels is not the statutory basis for establishing emissions
standards under section 112(d), as noted above.
    Comment: One commenter representing manufacturers of monitoring and
control technologies suggested that statistical variability should not
be incorporated into the floor computations for CO and Hg. This
commenter suggested that EPA base the floors on the straight averages
of each data set.
    Other commenters suggested that emissions variability is not
statistical but instead based on different operating conditions of
individual units. The commenters added that the variability of each
unit should be averaged based on individual units and then used to
establish UPL calculations instead of assessing a UPL based on
individual tests or test runs.
    Response: The UPL calculation is a statistical formula designed to
estimate a MACT floor level that is equivalent to the average of the
best performing sources based on future compliance tests. If we did not
account for variability in this manner and instead set the limit based
solely on the average (mean) performance, then these units could exceed
the limit half the time or more. The MACT floors for existing sources
must reflect the average emission limitation achieved by the best-
performing 12 percent of existing sources. Therefore, it is appropriate
to consider statistical variability in order to ensure that units could
meet the floors at all times. EPA agrees with the commenter that the
variability of emissions is not solely statistical, but also represents
some operational variability that may occur between different tests at
the same unit (intra-unit variability) as well as different tests at
different units (inter-unit variability) in the floor. Since the floor
calculations represent the average of the best-performing 12 percent of
existing sources, it is reasonable for EPA to use an appropriate
statistical analysis to assess the impact both intra-unit and inter-
unit variability have on the emissions profiles.
8. Alternative Units for Emission Limits
    Comment: Several commenters from industry, State agencies, and
environmental non-governmental organizations submitted a variety of
alternatives to the concentration-based and mass-based MACT floor
limits. Some commenters suggested emission reductions or removal
efficiencies. These commenters cited regulatory precedence for a
percent reduction limit in 40 CFR part 60 subpart Db, the New Source
Performance Standards for Industrial, Commercial Institutional Boilers
as well as New Source Performance Standards and Emission Guidelines for
Large and Small Municipal Waste Combustors (40 CFR part 60 subparts Ca,
Cb, Ea and Eb). Several other commenters suggested that EPA adopt an
alternative output-based emissions standard to promote boiler
efficiency improvements as a pollution prevention technique. One
commenter called attention to several previous examples of output-based
standards in recent air regulations, including the New Source
Performance Standard for Electric Utility Steam Generating Units (40
CFR part 60 subpart Da) which includes an output-based emissions
standard for Hg, PM, SO2, and NOX) as well as the
New Source Performance Standard for Industrial Commercial Institutional
Boilers (40 CFR part 60 subpart Db) which includes an output-based
emissions standard for NOX. This commenter also provided
examples of output-based emissions regulations in 12 states, including
4 that regulate non-electricity thermal output, such as from combined
heat and power systems. Many commenters encouraged EPA to investigate
opportunities to develop and implement output-based emissions standards
for ICI facilities. Some commenters tied in the appropriateness of
output-based standards to the Agency's other pollution prevention
techniques included in the proposal, such as the energy assessments.
The commenter added that by providing an output-based regulatory
option, the user will have further incentive to implement energy
efficiency opportunities identified during the energy assessment.
    Response: With respect to the commenters' request for the
development of percent reduction standards, sufficient data were not
available to determine the percent reduction from the best performing
units. In order to determine such standards, we would need emissions
data from testing conducted at both the APCD inlet and outlet for the
best performing sources, or at least for a reasonable number of best
performing sources. However, we only have APCD inlet and outlet data
for one pollutant (PM) for two subcategories, and based on this
overwhelming lack of data available to calculate percent reduction
standards, EPA did not pursue this option. We do agree with the
commenters that output-based standards would provide incentives for
implementation of energy conservation measures identified in an energy
assessment. This final rule includes a compliance alternative that
allows owners and operators of existing affected sources to demonstrate
compliance on an output-basis. This alternate output-based limit will
promote energy efficiency in industrial, commercial, and institutional
steam-generating facilities, and are equivalent to the MACT emissions
limits that are in heat-input format. EPA has established pollution
prevention as one of its highest priorities. One of the opportunities
for pollution prevention lies in simply using energy efficient
technologies to minimize the generation of emissions. Therefore, as
part of EPA's general policy of encouraging the use of flexible
compliance approaches where they can be properly monitored and
enforced, we are including alternate output-based emission limits in
this final rule. The alternate output-based emission limits provide
sources the flexibility to comply in the least costly manner while
still maintaining regulation that is workable and enforceable. We
investigated ways to promote energy efficiency in boilers by changing
the manner in which we regulate flue gas emissions. The alternate
output-based emission limits further this goal without reducing the
stringency of the emissions standards.
    Traditionally, boiler emissions have been regulated on the basis of
boiler input energy (lb of pollutant/MMBtu heat input). However, input-
based limitations allow units with low operating efficiency to emit
more of each pollutant per output (steam or electricity) produced than
more efficient units. Considering two units of equal capacity, under
current regulations, the less efficient unit will emit more

pollutants because it uses more fuel to produce the same amount of
output (steam or electricity) than a more efficient unit. One way to
regulate mass emissions and encourage plant efficiency is to express
the emission standards in terms of output energy. Thus, output-based
emission standards provide a regulatory incentive to enhance unit
operating efficiency and reduce emissions. An example of such an
output-based standard is the NOX standard under the New
Source Performance Standards (subpart Da) for electric utility boilers.
    The criteria used for selecting a specific output-based format were
based on the following: (1) Provide flexibility in promotion of plant
efficiency; (2) permit measurement of parameters related to stack
emissions and plant efficiency, on a continuous basis; and (3) be
suitable for equitable application on a variety of facility
configurations. The output-based option of mass of pollutant emitted
per boiler energy output (lb/MMBtu energy output) meets all three
criteria. The majority of ICI boilers produce steam only for process
operation or heating and, in this case, the energy output of the boiler
is the energy content of the boiler steam output. For those ICI boilers
that supply steam to generate, or cogenerate, electricity, the boiler's
energy output can include both electrical and thermal (process steam)
outputs. There are also some industrial boilers that only generate
electricity. Technologies are readily available to measure these energy
outputs, and they currently are measured routinely in many industrial
plants. Therefore, emission limits based on this format can be applied
equitably on a variety of facility configurations. Based on this
analysis, an emission limit format based on mass of pollutant emissions
per energy output was selected for the alternate output-based
standards.
    In the case of a boiler that produces steam for process or heating
only (no power generation), the lb/MMBtu output-based emission limit is
based on the mass rate of emissions from the boiler and the energy
content in terms of MMBtu of the boiler steam output. At cogeneration
facilities (also known as combined heat and power (CHP)), energy output
includes both electricity and process steam. The steam from the boiler
is first used to generate electricity. The thermal energy (steam)
exiting the electricity generating equipment is then used for a variety
of useful purposes, such as manufacturing processes, space heating and
cooling, water heating, and drying. The electricity output and the
useful energy present in the steam exiting the turbine must both be
accounted for in determining the overall energy output from the boiler
and converted to a common basis of lb/MMBtu consistent with the output-
based standard for steam-only units.
    The efficiency and associated environmental benefits of CHP result
from avoiding emissions from the generation of electricity at a central
station power plant. The avoided emissions at most times are from a
less-efficient unit that consequently also has higher emissions.
Consequently, the electricity output of the CHP facility in kWh should
be valued at the equivalent heat rate of the avoided central station
power, nominally 10,000 Btu/kWh. Therefore, the lb/MMBtu output-based
emission limit used for compliance with a CHP boiler is based on the
mass rate of emissions from the boiler and a total energy output, which
is the sum of the energy content of the steam exiting the turbine and
sent to process in MMBtu and the energy of the electricity generated
converted to MMBtu at a rate of 10,000 Btu per kWh generated (10 MMBtu
per MWh).
    Compliance with the alternative output-based emission limits would
require continuous measurement of boiler operating parameters
associated with the mass rate of emissions and energy outputs. In the
case of boilers producing steam for process use or heating only (no
power generation), the boiler steam output flow conditions would have
to be measured to determine the energy content of the boiler steam
output. In the case of CHP plants, where process steam and electricity
are output products, methods would have to be provided to measure
electricity output and the flow conditions of the steam exiting the
electrical generating equipment and going to process uses. These
conditions will determine the energy content of the steam going to
process uses. Instrumentation already exists in many facilities to
conduct these measurements since the instrumentation is required to
support normal facility operation. Consequently, compliance with the
alternate output-based emission limits is not expected to require any
additional instrumentation in many facilities. However, additional
signal input wiring and programming is expected to be required to
convert the above measurements into the compliance format (lb/MMBtu
energy).
    Since the June 4, 2010, proposal, we obtained steam data (flow,
temperature, and pressure) from the best performing units that made up
the MACT floor at proposal. In determining alternate equivalent output-
based emission limits, we first determined for each of the best
performing units the Btu output of the steam and then calculated the
boiler efficiency for each of the boilers having available steam/heat
input data. Boiler efficiency is defined as steam Btu output divided by
fuel Btu input. Next, we determined the average boiler efficiency
factor for each subcategory from the best performing units in that
subcategory. We then applied the average boiler efficiency factor to
the final MACT limits that are in the current format of lb/MMBtu heat
input to develop the alternate output-based limits. The efficiency
factor approach was selected because the alternative of converting all
the reported data in the database to an output-basis would require
extensive data gathering and analyses. Applying an average boiler
efficiency factor, based on the individual boiler efficiency of the
best performing units, essentially converts the heat input-based limits
to output-based emission limits.
    The alternate output-based emission limits in this final rule do
not lessen the stringency of the MACT floor limits and would provide
flexibility in compliance and cost and energy savings to owners and
operators. We also have ensured that the alternate emission limits can
be implemented and enforced, will be clear to sources, and most
importantly, will be no less stringent than implementation of the MACT
floor limits.

B. Beyond the Floor

1. Energy Assessment Requirement
    Comment: In the proposal preamble, we solicited comments on various
aspects of the energy assessment requirement. The proposed standards
included the requirement to perform an energy assessment to identify
cost-effective energy conservation measures. Since there was
insufficient information to determine if also making the implementation
of cost-effective measures a requirement was economically feasible, we
requested comment on this point. We also specifically requested comment
on: (1) Whether our estimates of the assessment costs are correct; (2)
is there adequate access to certified assessors; (3) are there
organizations other than for certifying energy engineers; (4) are
online tools adequate to inform the facility's decision to make
efficiency upgrades; (5) is the definition of ``cost-effective''
appropriate in this context since it refers to payback of energy saving
investments without regard to the impact on HAP reduction; (6) what
rate of return should

be used; and (7) are there other guidelines for energy management
beside ENERGY STAR's that would be appropriate. The energy assessment
requirement has been revised in this final rule and alternate
equivalent output-based emission limits have been incorporated into
this final rule as an alternative means of complying with the emission
limits in final rule. The alternate output-based emission limits allow
a facility implementing energy conservation measures that result in
decreased fuel use to comply with that emission limit by applying
emission credits earned from the implementation of the energy
conservation measure.
    Commenters stated that EPA should provide a clear, statutory-based
definition of ``Boiler,'' and the scope of the required energy
assessment. Commenters also stated that if EPA includes an energy
assessment requirement in this final rule, it should regulate only the
emission source over which it has Sec.  112 authority to regulate. The
``boiler'' logically includes the combustion unit (the emissions
source) and closely associated equipment, from flame to last heat
recovery. EPA should adopt this definition of ``boiler system,'' which
reflects the extent of its section 112 authority.
    Commenters also recommended that an energy assessment previously
conducted of a facility that has not had significant changes to the
boilers and associated equipment should be acceptable for initial
compliance. Energy performance of facilities strongly depends on
equipment configuration, equipment performance, and fuels fired. If
these do not change from the time an energy assessment was conducted to
the time the Initial Compliance energy assessment report is submitted,
the report would be representative of an accurate depiction of the
facility.
    Several commenters supported the use of energy assessments as a
``beyond the floor'' control measure and advocated for output-based
standards (noting that such an approach is critically important to
encourage CHP since input-based emissions regulations fail to credit
CHP systems for their greater efficiency, reducing the incentive for
CHP to be installed and used throughout U.S. industry). Moreover, since
this final boiler rule will apply to a wide variety of manufacturing
facilities in multiple sectors producing a variety of final products,
normalizing pollutant output per useful energy output is a good way to
ensure all affected facilities can be assessed on similar baselines.
Several commenters also applauded recognition of energy efficiency
measures to achieve pollution reductions and encouraged EPA to continue
to view energy efficiency investments favorably. Some commenters
criticized EPA's failure to require implementation of findings of the
energy assessments.
    Response: We agree that EPA should provide a clear definition of
what the energy assessment should encompass. However, we disagree that
the energy assessment should be limited to only the boiler and
associated equipment, and in fact the proposed rule included a broader
scope. EPA has properly exercised the authority granted to it pursuant
to CAA section 112(d)(2) which states that ``Emission standards
promulgated * * * and applicable to new or existing sources shall
require the maximum degree of reduction in [HAP] emissions that the
Administrator determines * * * is achievable * * * through application
of measures, processes, methods, systems or techniques including, but
not limited to measures which * * * reduce the volume of, or eliminate
emissions of, such pollutants through process changes, substitution of
materials or other modifications * * *.'' The energy assessment
requirement is squarely within the scope of this authority. 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 from the
affected boiler, which would result in reduced fuel use. Reduced fuel
use will result in a corresponding reduction in HAP, and non-HAP,
emissions from the affected boiler.
    We agree that the scope of the required energy assessment presented
in the proposed rule needs to be clarified and we have done this in
this final rule. In the proposed Boiler MACT, the intended scope of the
energy assessment did extend beyond the affected boiler. The energy
assessment included a requirement that a facility energy management
program be developed. The energy assessment was intended to be broader
than the affected boiler and process heater and included other systems
or processes that used the energy from the boiler and process heater.
We disagree that the scope of the energy assessment should be limited
to the boiler and directly associated components such as the feed water
system, combustion air system, fuel system (including burners), blow
down system, combustion control system, and heat recovery of the
combustion fuel gas. Including all of the energy using systems in the
energy assessment can result in decreased fuel use that results in
emission reductions, the result articulated in 112(d)(2). We have
included in this final rule a definition of what the energy assessment
should include for various size fuel consuming facilities. We also have
included a definition of the qualified assessors who must be used to
conduct those energy assessments. We have clarified the requirement
that the energy assessment include a review of the facility's energy
management program and identify recommendations for improvements that
are consistent with the definition of an energy management program. A
definition of an energy management program that is compatible with the
ENERGY STAR Guidelines for Energy Management and other similar
approaches was added.
    We also agree that a facility should be exempt from the requirement
to conduct an energy assessment if an energy assessment has recently
been conducted. We have revised the final rule to allow facilities to
comply with the requirement by submitting an energy assessment that has
been conducted within 3 years prior to the promulgation date of this
final rule.
    Comment: The principle arguments against an energy assessment
requirement are: (1) EPA lacks authority to impose requirements on
portions of the source that are not designated as part of the affected
source, such as non-emitting energy using systems at a facility; (2)
EPA has not quantified the reductions associated with the energy
assessment requirement, therefore it cannot be ``beyond the floor;''
and (3) the bare requirement to perform an audit without being required
to implement its findings is not a standard under CAA section 112(d).
    Response: With respect to the first argument, we have carefully
limited the requirement to perform an energy audit to specific portions
of the source that directly affect emissions from the affected source.
The emissions that are being controlled come from the affected source.
The process changes resulting from a change in an energy using system
will reduce the volume of emissions at the affected source by reducing
fuel consumption and the HAP released through combustion of fuel. The
requirement controls the emissions of the affected source and, as
explained above, is within the scope of EPA's authority under section
112(d)(2).
    With respect to the second argument, the energy assessment will
generate emission reductions through the reduction in fuel use beyond
those reductions required by the floor. While the precise quantity of
emission reductions will vary from source to

source and cannot be precisely estimated, the requirement is clearly
directionally sound and thus consistent with the requirement to examine
beyond the floor controls. By definition, any emission reduction would
be cost effective or else it would not be implemented.
    Finally, with respect to the third argument, the requirement to
perform the energy audit is, of course, a requirement that can be
enforced and thus a standard. As noted, while we do not know the
precise reductions that will occur at individual sources, the record
indicates that energy assessments reduce fuel consumption and that
parties will implement recommendations from an auditor that they
believe are prudent. Therefore, the requirement to perform an energy
assessment can both be enforced and will result in emission reductions.
    We agree that EPA should provide a clear definition of what the
energy assessment should encompass. However, we disagree that the
energy assessment should be limited to only the boiler and associated
equipment. EPA has properly exercised the authority granted to it
pursuant to CAA section 112(d)(2) which states that ``Emission
standards promulgated * * * and applicable to new or existing sources
shall require the maximum degree of reduction in [HAP] emissions that
the Administrator determines * * * is achievable * * * through
application of measures, processes, methods, systems or techniques
including, but not limited to measures which * * * reduce the volume
of, or eliminate emissions of, such pollutants through process changes,
substitution of materials or other modifications * * *.'' 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 from the
affected boiler which would result in reduced fuel use. Reduced fuel
use will result in a corresponding reduction in HAP, and non-HAP,
emissions from the affected boiler. Reducing the energy demand from the
plant's energy using systems can result in additional reductions in
fuel use and associated emissions from the affected boilers. We agree
that the scope of the required energy assessment needs to be clarified.
However, in the proposed Boiler MACT, the intended scope of the energy
assessment did extend beyond the affected boiler. The energy assessment
did include a requirement that a facility energy management program be
developed. The energy assessment was intended to be broader than the
affected boiler and process heater and included other systems or
processes that used the energy from the boiler and process heater. We
disagree that the scope of the energy assessment should be limited to
the boiler and directly associated components such as the feed water
system, combustion air system, fuel system (including burners), blow
down system, combustion control system, and heat recovery of the
combustion fuel gas. Including the facility's energy using systems and
energy management practices in the energy assessment can identify
measures that result in decreased fuel use and related emission
reductions. We have included in this final rule a definition of what
the energy assessment should include for various size fuel consuming
facilities. We also have included a definition of the qualified
assessors who must be used to conduct those energy assessments.
    We also agree that a facility should be exempt from the requirement
to conduct an energy assessment if an energy assessment had recently
been conducted. We have revised this final rule to allow facilities to
comply with the requirement by submitting an energy assessment that had
been conducted within 3 years prior to the promulgation date of this
final rule.

C. Rationale for Subcategories

    Many commenters stated that EPA should have proposed more
subcategories, while others believed that too many subcategories were
proposed. Many different issues were raised, and some of the key issues
that led to changes in the rule include: The need for a limited use
subcategory for boilers that operate for only a small percentage of
hours during a year; the unique suspension/grate design of units that
combust bagasse; the need for a non-continental liquid fuel subcategory
for island units that have limited fuel options and other unique
circumstances; and the appropriate subcategory for mixed fuel units.
The comments and EPA responses are provided below.
1. Limited Use Subcategory
    Comment: Industry representatives and State and local governments
argued that limited use units are significantly different from steady-
state units and requested that they have their own subcategory.
Commenters requested various thresholds for a limited-use subcategory
including 10 percent annual capacity factor or 1,000 hours of operation
per year. Several commenters stated that due to their function, limited
use boilers spend a larger percentage of time in startup, shutdown, or
other reduced-efficiency operating conditions than either base-loaded
or load-following (continuously operated) units. Operating more
frequently in these conditions makes emissions profiles of limited use
units very different from sources which operate in more efficient
steady-state modes. Based on this, commenters claimed it would be
technically infeasible for limited-use units to meet the proposed
emission limits.
    In addition to technical reasoning, commenters also submitted
requests for a limited-use subcategory on the basis of regulatory
precedent, citing the 2010 RICE MACT and 2004 vacated Boiler MACT.
Several commenters requested a subcategory and work practices similar
to those in the Stationary RICE NESHAP. Several other commenters also
stated that the subcategory was warranted because it was included in
the previous Boiler MACT rule. These commenters argued that EPA had not
provided any justification for eliminating the subcategory in the
proposed rule. Some of these commenters also stated that the
recordkeeping requirements that were proposed in Section 63.7555(d)(3)
for limited-use boilers and process heaters should be the only
requirement for these units.
    The majority of commenters that requested a limited use subcategory
also requested for EPA to adopt a work practice standard for limited
use units and not subject the subcategory to emissions testing or
monitoring. Commenters argued that EPA has acknowledged that there is
no proven control technology for organic HAP emissions from limited use
units. Limited use units, such as emergency and backup boilers, cannot
be tested effectively due to their limited operating schedules. Based
on existing test methods, which require a unit to operate in a steady
state, limited use units would have to operate for the sole purpose of
emissions testing. One commenter claimed that the proposed rule
performance testing would require, not including startup and
stabilization, operating at least 15 additional hours of per year, or
24 hours per year if testing for all pollutants is required. Commenters
also noted that because the operation of these units is neither
predictable nor routine over a 30 day period, back-up boilers would not
benefit from 30-day emissions averaging. Commenters argued that
establishing numerical standards for limited use units is contrary to
the goals of the CAA and will lead to creating

emissions for the sole purpose of demonstrating compliance.
    Many commenters also mentioned the economic impacts of a numerical
limit on limited-use units and requested work practice standards.
Commenters stated that it would not be cost effective to install
controls on units that operate at 10 percent capacity or less annually.
They claimed that the additional controls would produce minimal
emission reductions and would result in the shutdown of limited-use
units.
    Several commenters claimed that the current distinction between
natural gas and oil-fired limited-use units is unnecessary, and that
additional requirements for oil-fired units do not produce
environmental benefits. Commenters recommended that EPA create a
separate subcategory for limited use, oil-fired boilers and suggest
that the work practice standard proposed for gas-fired boilers be
applied in lieu of emissions standards for these units. Other
commenters stated that the limited use subcategory should include new/
reconstructed limited use units as well as existing units for all fuel
categories. One commenter recommended a tiered approach and stated that
for very limited use boilers, EPA should establish a standard with no
additional controls or requirements, other than monitoring annual hours
of operation. They defined very limited use as <500 hours of operation
per year.
    Response: EPA agrees that a subcategory for limited use units is
appropriate for many of the reasons stated by the commenters. The fact
that the nature of these units is such that they operate for
unpredictable periods of time, limited hours, and at less than full
load in many cases has lead EPA to determine that limited use units are
a unique class of unit based on the unique way in which they are used
and EPA is including a subcategory for these units in the final rule.
The unpredictable operation of this class of units makes emission
testing for the suite of pollutants being regulated impracticable. In
order to test the units, they would need to be operated specifically to
conduct the emissions testing because the nature and duration of their
use does not allow for the required emissions testing. As commenters
noted, such testing and operation of the unit when it is not needed is
also economically impracticable, and would lead to increased emissions
and combustion of fuel that would not otherwise be combusted.
Therefore, we are regulating these units with a work practice standard
that requires a biennial tune-up, which will limit HAP by ensuring that
these units operate at peak efficiency during the limited hours that
they do operate.
2. Combination Grate/Suspension Firing
    Comment: Several commenters requested EPA further subcategorize
boilers and process heaters according to combustor design. Three
industry and collective trade group representatives requested EPA
consider adding a bagasse boiler subcategory. These commenters claimed
that bagasse boilers are different from other biomass boilers based on
both fuel type and boiler design. The commenter suggested four factors
EPA should consider when establishing similar sources or subcategories:
(1) Do the units in the category have comparable emissions; (2) are the
units structurally similar in design; (3) are the units structurally
similar in size; and, (4) are the units capable of installing the same
control technology. The commenter elaborated on the fuel density and
moisture of bagasse fuel and highlights the unique combustor design
needed to heat and evaporate the moisture from the fuel using a
combination of suspension and grate firing. Several commenters
requested that EPA set separate subcategories for organic HAP (or CO)
and for metal HAP and PM for bagasse boilers (between 48 to 55 percent
moisture), suspension burners designed to burn dry biomass (defined as
less than 30 percent moisture), suspension burners designed to burn wet
biomass (greater than 30 percent moisture), and Dutch ovens.
    One commenter also requested that the regulatory definition of
bagasse boiler be altered to take into account that bagasse boilers are
hybrid suspension and grate/floor-fired boilers uniquely designed to
dry and burn bagasse. The commenter goes on to explain that the
majority of drying and combustion take place in suspension and the
combustion is completed on the grate or floor. The boilers are designed
to have high heat release rates and high excess air rates which are to
evaporate high fuel moisture content and this design impacts CO, PM,
and organic HAP formation. Under the proposal, most bagasse-fired
boilers would be categorized as ``suspension burners/dutch ovens
designed to burn biomass.'' However, the commenter claimed that the CO
limit for this subcategory was driven largely by emissions data from
units which fire dry biomass (i.e., less than 20 to 30 percent moisture
fuel) that do not need to undergo this initial drying process, since
the fuel is already dry enough to combust. The commenter elaborated
that emissions of organic HAP and PM from these dry biomass suspension
boilers are much different than boilers that must use a combination of
suspension firing and grate firing in order to achieve complete
combustion of a wet fuel such as bagasse.
    One commenter went on the say that EPA has inappropriately
subcategorized suspension burners/dutch ovens designed to burn biomass
as a single subcategory. Hybrid suspension/grate-floor burners are
designed such that the wet fuel first undergoes drying and then
combustion in suspension within the furnace, with any remaining
unburned fuel falling onto the grate to complete combustion. Another
commenter also provided technical design elements to highlight the
differences between dutch ovens, suspension burners, and the above
mentioned hybrid suspension grate burners. This commenter indicated
that dutch ovens have two chambers. Solid fuel is dropped down into a
refractory lined chamber where drying and gasification take place in
the fuel pile. Gases pass over a wall into the second chamber where
combustion is completed. Dutch ovens are capable of burning high
moisture fuels such as bark, but have low thermal efficiency and are
unable to respond rapidly to changes in steam demand. On the contrary,
suspension burners combust fine, dry fuels such as sawdust and sander
dust in suspension. Rapid changes in combustion rate are possible with
this firing method. This commenter added that some dutch oven units
located at particleboard, hardboard, and medium density fiberboard
plants were misclassified and there are less than 30 true dry-fired
suspension burners in operation, and only a small handful of true dutch
oven boilers.
    Response: EPA agrees that for combustion-related pollutants (used
as a surrogate for organic HAP emissions), the design differences for
hybrid suspension grate boilers (also referred to as comination
suspension/grate boilers) are significant, and that combustion
conditions in these types of units are not similar to those in dutch
ovens or true suspension burners that combust fine, dry fuels.
Therefore, EPA has added a hybrid suspension grate boiler subcategory
for CO and dioxin/furan emissions. However, the differences discussed
by the commenters with respect to PM are less indicative of the design
of the boiler and more indicative of the types of air pollution
controls that are used. In keeping with the subcategorization approach
being used for this final rule, these units, and all other solid fuel
units, will be included

in a subcategory for units combusting solid fuels for PM, Hg, and HCl.
3. Non-Continental Units
    Comment: Commenters from affected island refineries and trade
groups representing the petroleum and refining sectors requested
additional fuel oil burning flexibility in this final rule and stated
that work practice standards are more appropriate for fuel oil burning
at refineries and other remote locations without access to natural gas.
    Commenters also submitted technical issues justifying the creation
of a non-continental or remote location subcategory. One commenter
stated that most oil combustion in the petroleum sector is in locations
that are islands or in more remote parts of the United States. Island
and remote facilities cannot physically access natural gas pipelines,
making burning liquid fuels unavoidable. The option of crude oil
shipments would be impractical because the ships are limited by size
and what is manageable by load/discharge ports. The commenter also
claims that in the time it would take a crude ship to arrive, the
refinery would have produced the amount of crude in the shipment.
Further, while some units at a facility are designed to burn refinery
fuel gas, the fuel gas produced at a refinery is less than the energy
required to operate the refinery. These non-continental facilities are
also limited to the fuel quality provided by their nearby crude slate
used in the refining process. That commenter goes on to say that these
refineries produce their fuel, the HAP metals content of the fuel used
(particularly residual fuel oil) is a direct result of the crude slate
used on site. The commenter submitted trace metals from various crudes
to show that the content varies substantially between crude oils being
used on site.
    Another commenter provided the following distinctions for non-
continental units: A striking example of fuel system differences for
non-continental units is daily variation in fuel gas production due to
ambient temperature fluctuations between night and mid-day or resulting
from tropical rainfall events, coupled with fin fan cooling systems
that are used because of the lack of fresh water available in an island
without freshwater lakes or streams. The fuel system experiences a
large daily variation in refinery fuel gas due to changes in ambient
air temperature. These changes occur as a day-night swing in the
refinery or any time there is a significant rain storm. As the ambient
air temperature decreases, the amount of propane, butane and heavier
molecules in the fuel gas decreases, as those compounds condense out.
This results in a change in volume and composition (energy content) of
the refinery fuel gas produced which, in the case of rainfall events,
occurs very quickly and unpredictably. This temperature variation
occurs more frequently than at a mainland refinery because: The method
of cooling on gas compressors and distillation column overheads systems
is ambient air fin fan coolers (water with cooling towers is not used
like a stateside refinery because fresh water is not available other
than by desalination); the refinery fuel gas system contains miles of
aboveground piping (long lines are affected by rain and weather
conditions); refinery fuel gas contains more propane and butane than
would natural gas from a pipeline (which condense at closer to ambient
temperatures than methane or ethane); the make-up fuel system for the
refinery is not a natural gas pipeline as at a stateside refinery. A
natural gas pipeline can handle changes in refinery fuel gas produced
because natural gas delivery systems are usually large enough to handle
changes. A temperature change of 10 to 15 degrees or a rain storm that
quickly wets the air fin fans/piping will change the volume and
composition (energy content) of the refinery fuel gas produced and also
impacts CO emissions.
    In addition to the technical limitations described above, one
commenter cited other EPA air regulations that have provided separate
standards or subcategories for non-continental units. For example, 40
CFR part 60 subparts Db and KKKK include separate standards for ``non-
continental'' units and the 2010 CISWI proposal had a subcategory for
smaller remote facilities because of inherent design and operating
constraints.
    Another commenter mentions that the inability to obtain natural gas
removes the option of being able to burn only gaseous fuels as a
compliance strategy and burning fuel oil as a supplemental fuel makes
complying with this proposed MACT unfairly onerous.
    Response: EPA agrees that the unique considerations faced by non-
continental refineries warrant a separate subcategory for these units.
However, data were only provided for CO and Hg, and, in the absence of
data for the other pollutants, EPA is adopting the same limits that
were developed for liquid units, because liquid units are the most
similar units for which data are available. EPA assumed that while the
commenter focused on changes in refinery gas, that the commenters
concern was with liquid fuel-fired units whose performance is impacted
by the co-firing of refinery gas. Regardless, it is clear that the
unique design of this type of unit warrants a separate subcategory
because design constraints would not enable the sources to meet the
same standards, particularly for CO, as stateside units.
4. Combination Fuel Units
    Comment: Several industries and industry representatives in
addition to some State and local governments argued that combination
fuel units are significantly different from units in single fuel
subcategories. These commenters focused on three types of combination
fuel units. The first, which the majority of comments focused on, was
biomass and coal co-fired units. Commenters stated that classifying
units that burned 90 percent biomass in the coal subcategory if it
fired at least 10 percent heat input coal penalizes and discourages the
use of biomass. One commenter claimed that they were unaware of any
available control technology with the capability of reducing emissions
from its biomass-fired boilers from their current levels to the level
proposed for the coal stoker subcategory. Commenters stated that in
order to meet the organic HAP limits for coal, they would have to
switch from biomass to more coal or abandon co-firing projects.
According to the commenter this result was contrary to state Renewable
Portfolio Standards and general national renewable energy policy.
    The second type of combination unit commenters discussed was units
that co-fire gas and liquid fuels. Many commenters argued that
combination oil and gas fired units are of a completely different
design than EPA contemplated in setting its standards and cannot be
fairly included in the same subcategory with other dedicated gas or oil
fired units. Commenters elaborated that the main design difference was
due to combustion techniques which require the heater/boiler firebox
configuration to compromise between the needs of oil fuel and gas fuel,
making it impossible to maximize combustion efficiency or minimize
NOX emissions. Commenters also noted that these units were
not considered in development of the MACT standards, and claimed that
they are well known in the burner industry and referenced in standard
literature.
    The third type of combination unit, one commenter mentioned, was a
subcategory for units co-firing biomass with any solid fuel. Commenters
claimed that by failing to recognize the wide verity of fuel inputs and
thus the variation in fuel quality (i.e., BTU and

moisture content) and emissions, EPA was penalizing facilities that use
multiple fuel streams. The commenter went on to request that EPA
establish emission limits that reflect the variation in fuels and fuel
quality in these combination units.
    Several commenters disagreed with the EPA statement that boilers
are designed to burn only one fuel and that unit will encounter
operational problems if another fuel type is fired at more than 10
percent heat input. Commenters stated that some boilers are
specifically designed to burn a combination of fuels, and to burn them
in varying quantities. Commenters elaborated that such boilers are not
able to reach full load on any single fuel and that EPA has incorrectly
presumed that all boilers are designed based on a primary fuel. Some
commenters identified that many of the boilers used as the basis of the
proposed MACT floor emission limits co-fire different fuel types. One
commenter stated that if most units are designed to burn a primary fuel
and will encounter problems if the 10 percent threshold is exceeded,
then EPA has proposed MACT standards that will apply to boilers that by
their nature are ``encountering problems'' due to their fuel mix. The
commenter requested that EPA addresses this inconsistency.
    Many commenters noted that emissions profiles vary with the fuel
which made it very difficult to establish a typical emissions profile.
Commenters also explained that combination fuel boilers must often
adapt to process steam demands and thus experience frequent load swings
and fuel input adjustments that cause significant variation in CO
emission levels. Commenters also mentioned that control compatibility
should be considered for multi-fuel boilers because they have
inherently different control needs depending on the fuels being fired.
Commenters went on to say that current limits are based on control
equipment that is optimized for one HAP or fuel but the affect of other
HAP and fuels or even another control would result in unknown
performance and compatibility with other fuel types.
    Several commenters also had concerns regarding enforcement and
compliance of combination fuel units. One commenter requested that EPA
more specifically address the ``enforceability'' of the ``designed to
burn'' classification and more clearly consider the implications of the
multi-fuel boiler operation on testing considerations. Another
commenter stated that expressing limits as applicable to units
``designed to burn'' certain fuels was problematic and should be
changed to ``permitted to burn'' because a State permit could limit the
type of fuels combusted at a unit that may have originally been
designed to burn other fuel types. Other commenters claimed that the
fuel subcategory should be determined by the actual quantity of fuel
burned not what the unit is designed to burn. Some questions that
commenters requested clarification on were: If compliance tests would
be required under different fuel firing conditions, can units with CEMS
switch limits depending on what fuel is being combusted, if ``designed
to combust'' is not maintained would actual fuel burned or fuel the
unit is permitted to burn determine the subcategory, what would the
annual performance test be if in the middle of the year a unit goes
from having burned only one type of fuel to only another type the rest
of the year.
    Several solutions were suggested for addressing combination
boilers. Some commenters requested that combination boilers have their
own subcategory. Several other industry commenters suggested that EPA
modify the subcategory definitions and applicability so that
combination fuel units burning more than 10 percent coal with biomass
would be regulated under the coal subcategory for fuel-based HAP and
units burning more than 10 percent biomass with coal would be regulated
under the biomass subcategory for combustion-based HAP. A more general
solution proposed, for all types of combination fuel units, was that if
a facility combusts more than one fuel type, it must meet the lowest
applicable emission limit for all of the fuel types actually burned.
Some commenters also requested the development of a formula based
approach similar to that of the boiler NSPS SO2 limits that
considers the mix of fuel fired rather than assuming one fuel dictates
the emission limitations.
    Some commenters were concerned that determination of MACT floor
limits should be based only on data obtained while firing 100 percent
of the affected fuel category and recommended that EPA either exclude
all test runs where a unit was co-firing or adjust the data accordingly
to remove the co-firing bias.
    Response: In response to the variety of comments regarding
combination fuel boilers, EPA has revised the subcategories in order to
simplify implementation, improve the flexibility of units in
establishing and changing fuel mixtures, promote combustion of cleaner
fuels, and provide MACT standards that are enforceable and consistent
with the requirements of section 112. For the combination liquid and
gas-fired units, while the commenters provided some insights on these
units, the data available to EPA regarding any distinctions between
these units and units designed to burn liquid only were insufficient to
provide a justification for changing the approach for these units. For
combined fuel units that combust solid fuels, due to the many potential
combinations and percentages of solid fuels that are or can be
combusted, for the fuel-based pollutants, EPA selected the option of
combining the subcategories for solid fuels into a single solid fuel
subcategory. For the fuel-based pollutants, this alleviates the
concerns regarding changes in fuel mixtures, promotion of combustion of
dirtier fuels, and the implementation and compliance concerns. For
combustion-based pollutants (CO and dioxin/furan), we maintained the
proposed subcategories and added a few additional subcategories, as
discussed elsewhere in this preamble, based on public comment. One
change we are finalizing is that to determine the appropriate
subcategory, instead of considering whether the unit 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 unit.
    The subcategories for the combustion-based pollutants are now
determined in the following manner. If your new or existing boiler or
process heater burns at least 10 percent biomass on an annual average
heat input basis, the unit is in one of the biomass subcategories. If
your new or existing boiler or process heater burns at least 10 percent
coal and less than 10 percent biomass, on an annual average heat input
basis, the unit is in one of the coal subcategories. If your facility
is located in the continental United States and your new or existing
boiler or process heater burns at least 10 percent liquid fuel (such as
distillate oil, residual oil) and less than 10 percent coal and less
than 10 percent biomass, on an annual average heat input basis, your
unit is in the liquid subcategory. If your non-continental new or
existing boiler or process heater burns at least 10 percent liquid fuel
(such as distillate oil, residual oil) and less than 10 percent coal
and less than 10 percent biomass, on an annual average heat input
basis, your unit is in the non-continental liquid subcategory. Finally,
for the combustion-based pollutants, if your unit combusts gaseous fuel
that does not

qualify as a ``Gas 1'' fuel, your unit is in the Gas 2 subcategory.

D. Work Practices

1. Gas 1 Work Practices
    Comment: Several industry and industry trade group commenters
expressed general support for the adoption of work practice standards
for natural gas and refinery gas (Gas 1) fired boilers and process
heaters. Many of these commenters stated that work practice standards
will minimize HAP emissions in a cost effective manner.
    Commenters, including industry representatives and one government
agency, submitted several technical justifications that supported the
proposed work practice standards for natural gas and refinery gas
units. Many of these commenters stated that Gas 1 units contribute a
negligible amount of the total emissions from the source category. One
commenter stated that based on a review of air permits issued for
natural gas-fired units over the last 10 years no HAP emissions were
identified at rates which required the State to set emission limits.
Further, many commenters indicated that no currently-available control
technology or technique has been indentified to achieve numeric limits
for natural gas units. Others went on to argue that tune-ups actually
represent the only ``floor'' technology currently in use at boilers and
process heaters in the Gas 1 subcategory. One commenter stated that
design characteristics of these units, and hence the emissions-
reduction potentials of annual tune-ups, vary widely and no single
emission rate or even percentage of emission reduction could be
translated into a numerical limit.
    Several commenters argued that work practice standards were
justified based on the technical infeasibility of emissions testing and
the accuracy of testing results from gas units. These commenters stated
that most of the emission test data were close to detection limits or
in some cases indistinguishable from ambient air near the lowest detect
levels, thus preventing the limits from being enforced or reliably
measured. Others argued that the application of EPA test methods to
measure emissions from natural gas units results in unreliable data
given that the emissions are low and below what the test methods can
detect, causing repeat tests or significantly lengthening the periods
for the tests, which in turn increase the cost of testing.
    On the contrary, one of the environmental advocacy group commenters
stated that EPA exempted natural gas-fired units from CO limits without
any discussion or analysis. This commenter argued that nothing in the
rulemaking docket showed that measurement would be technically
infeasible and identified CO emission test results from over 160
natural gas-fired units in the NACAA database. Further, the commenter
suggested that federal, State and local authorities have routinely
required CO to be measured at gas fired units since CO is a criteria
pollutant under the CAA.
    In addition to technical reasoning, many industry and industry
representative commenters also supported the adoption of work practice
standards on the basis of legal precedent and authority under the CAA.
Commenters stated that EPA derives its authority to use work practices
in lieu of numeric emission limitations from two different statutory
provisions: The narrowly construed provisions of 112(h) and the broad
authority under 112(d) as defined in section 302(k). Additionally, one
commenter stated that work practice standards for Gas 1 units are
consistent with the D.C. Circuit's opinion in Sierra Club v. EPA on the
Brick MACT standard, which provided guidance on the criteria EPA must
meet to justify the application of section 112(h) work practices, only
if measuring emission levels is technologically or economically
impracticable.
    Many commenters also cited economic justifications supporting the
proposed work practices for Gas 1 units. These comments included claims
that work practice standards avoid economic harm to the manufacturing
sector, and they added that the cost to control each unit would be
extremely burdensome with minimal benefits to the environment. These
commenters suggested that any type of control beyond a tune-up would be
a beyond-the-floor option and the complex controls needed to achieve
such low emission levels would fail the cost-benefit determination
needed to justify a beyond-the-floor option.
    On the contrary, two environmental advocacy groups submitted
comments opposing EPA's rationale for exempting Gas 1 units from CO
limits on the basis of cost. The commenters argued that the only
economic defense of work practice standards that would be justified was
if economic limitations rendered the measurement of emissions
``impracticable.'' Further, the commenters suggested that many of these
Gas 1 units would require more than a tune-up to achieve comparable
reductions to those estimated if a numeric MACT floor standard was
required.
    Another commenter representing the coal industry also disagreed
with EPA's use of a public policy rationale to justify a work practice
for Gas 1 units instead of demonstrating that a work practice meets the
requirements under section 112(h). The commenter argued that cost
considerations were not relevant in a MACT floor analysis and they
noted that the per unit costs of complying with MACT standards for gas
units are lower than the cost for coal units.
    Many commenters from industry, industry trade groups, universities,
and State agencies agreed that emission limits would provide a
disincentive to operate or switch to natural gas and refinery gas fired
units. Commenters claimed that if limits for Gas 1 were adopted, units
would switch from natural gas to electric systems powered by coal.
Commenters stated that EPA correctly concluded that imposing emission
limitations on gas-fired boilers would create a disincentive for
switching to gas from oil, coal, or biomass as a control technique and
would create an incentive for facilities to switch away from gas to
other fuels.
    A commenter from a private coal company indicated that EPA's
concerns that establishing a MACT floor limit for Gas 1 units would
incentivize fuel switching to coal or other fuels contradict EPA's
rejection of fuel switching as a MACT floor alternative. The commenter
added that if EPA rejected fuel switching because of its costliness and
lack of a net emissions benefit, EPA should want to discourage coal
units from converting to natural gas rather than promoting fuel
switching to natural gas. This commenter also claimed that establishing
a work practice standard for only Gas 1 units discriminated in favor of
the use of natural gas and against the use of coal. The commenter
argued that such a policy rationale invokes considerations that are not
relevant in setting MACT floor standards and suggested that such a
rationale is in violation of both CAA and the Equal Protection Clause
of the Constitution. This commenter added that the only relevant
statutory factor under 112(h) to help EPA determine where to apply a
work practice standard was whether the hazardous air pollutant cannot
be emitted through a conveyance designed and constructed to emit or
capture that pollutant, whether the use of such a conveyance would be
inconsistent with law, or whether the application of measurement
methodology is not practicable due to technological and economic
limitations.

    Response: EPA has determined that it is not feasible to prescribe
numerical emissions standards for Gas 1 units because the application
of measurement methodology is not practicable due to technological and
economic limitations. Therefore, EPA is finalizing the work practice
standards for Gas 1 units. The commenters correctly point out that the
measured emissions from these units are routinely below the detection
limits of EPA test methods, and, as such, EPA considers it
impracticable to reliably measure emissions from these units. Even CO,
which commenters correctly point out was tested at many natural gas and
refinery gas-fired units, was below the level EPA considers to be a
reliable measurement for more than 80 percent of the test runs that
were conducted on Gas 1 units. The case for other pollutants is even
more compelling as the majority of measurements are so low as to cast
doubt on the true levels of emissions that were measured during the
tests. Of the 48 test runs for HCl, 98 percent were below three times
the maximum reported measurement detection level; similarly, 100
percent of the Hg runs, and 45 percent of the PM data were below three
times the maximum reported measurement detection level. It is unusual
to see numbers near the detection limit for PM since the ``detection''
involves a comparatively simple (compared to other test methods)
weighing procedure, and the overall result indicates that the emissions
are very close to zero. All of the dioxin tests had multiple non-detect
isomers. Overall, the available test methods are greatly challenged, to
the point of providing results that are questionable for all of the
pollutants, when testing natural gas units. Because of these
technological limitations that render it impracticable to measure
emissions from Gas 1 units, EPA is also unable to establish the actual
performance of the best performers as well as sources outside of the
top performing 12 percent. The inability to accurately measure
emissions from Gas 1 units and the related economic impracticability
associated with measuring levels that are so low that even carefully
conducted tests do not accurately measure emissions warrant setting a
work practice standard under CAA section 112(h). EPA is establishing a
requirement to implement a tune-up program as described in Section
III.D of this preamble. As noted by many commenters, the tune-up
program is an effective HAP emissions limitation technology. The
requirement of an annual tune-up will allow these units to continue to
combust the cleanest fuels available for boilers while minimizing
emissions to the same degree that is consistent with the operating
practices of the best performing units in the subcategory.
2. Combining Gas 1 and Gas 2 Subcategories
    Comment: Several commenters requested consolidation of the Gas 1
and Gas 2 subcategories into a single gas-fired subcategory. The
majority of commenters supported this concept by suggesting that there
is very little difference between emissions from the top performing
sources in each of the two gas subcategories. One commenter
specifically argued that in most cases the mean emission levels for Gas
2 fuels are within range and confidence intervals for individual Gas 1
fuels and that the differences in fuel characteristics do not have a
first order impact on HAP emissions. The commenter reported on
communications with a facility in the database firing a heavy recycle
liquid and natural gas fuel combination, which indicated that this unit
is a liquid fuel boiler and they provided an analysis of the dataset
without this heavy recycle data where the confidence intervals for the
remaining landfill gas, biogas/natural gas, and coke oven gas all
overlap that for Gas 1 fuels. The commenter also claimed that if 12
outliers from two process gas facilities are eliminated, the remaining
232 of 244 CO data points within Gas 2 fuel group compare favorably
with, even lower than, CO levels from Gas 1 fuels. Another commenter
stated that pilot scale and field data studies have concluded that
emissions of organic HAP from gaseous fuels are not significantly
affected by fuel type.
    In lieu of a single gas subcategory, several of the commenters
requested that the Gas 1 subcategory be expanded to include gases
similar to natural gas and refinery gas. These commenters argued, much
like the commenters advocating for a single gas-fired subcategory, that
units fired with process gases generated in chemical plants, pulp and
paper plants, iron and steel plants, and similar operations should be
included in the Gas 1 subcategory because the emissions data show very
little difference in performance. One commenter stated that most of the
Gas 2 fuels, including all 9 of the data points used in the proposed
floor calculations, are from chemical plants. The commenter added that
at a minimum, chemical plant process gas should be grouped with
refinery gas in Gas 1 and a new floor made for Gas 2. One commenter
noted that EPA did not gather information on composition or heating
value in the Phase 1 ICR survey to justify placing chemical process
gases in a separate subcategory from natural gas and refinery gas.
Another commenter submitted combustion properties of refinery gas and
petrochemical gas in order to argue that they are very similar in
composition and should be categorized with natural gas in the Gas 1
category.
    In order to accomplish this expansion of the Gas 1 subcategory,
many commenters also addressed the definition of natural gas and
refinery gas. One commenter simply stated that all gases derived from
hydrocarbon sources should be classified under the Gas 1 subcategory.
Another commenter suggested the definition of refinery gas in 40 CFR
part 63 subpart CC for the Petroleum Refineries NESHAP should be used
in this final rule. The commenter went on to say that such gases from
petrochemical processes have similar compositions to those stated in
the Subpart CC definition (e.g. methane, hydrogen, light hydrocarbons,
and other components) that are used as fuel in boilers and process
heaters and thus should be subcategorized as Gas 1. One commenter
stated that the definition of natural gas should be consistent across
federal air regulations and suggested that the definition of natural
gas should be edited to be consistent with the definition provided in
40 CFR Part 60 Subpart Db. Another commenter requested that the
definition of Gas 1 include any boiler or process heater burning at
least 90 percent natural gas, refinery gas, or process off-gases with
metals and sulfur content equal or less than those in natural gas.
    Many other commenters argued that in general the definition of
natural gas needs to be broadened to account for non-geological origins
of natural gas such as landfill gas, biogas, and synthetic gas in order
to promote the use of these renewable fuels. This commenter went on to
state that the Gas 1 subcategory excludes biogas and process off gases
that have no metals and very comparable combustion characteristics to
that of natural gas or refinery gas. One commenter argued that landfill
gas (LFG) should be included in Gas 1 with the work practice approach
because placing it in the Gas 2 subcategory conflicts with EPA Landfill
Methane Outreach Program goals. The commenter goes on to say that there
is no assurance that all limits can be achieved with control
technologies and installation of controls will be prohibitively
expensive and thus LFG projects will be stopped or replaced

with natural gas. A few commenters suggested that EPA did not have
enough data on combustion of anaerobic digester gas to differentiate it
from natural gas. One commenter requested confirmation that biogas
under the proposed rule would be subject to Gas 2 emission limits.
Another commenter requested that EPA separate and clearly define
gaseous fuels derived from biomass and noted that depending on the
source these fuels can contain chlorine or Hg and constituents that
lead to the formation of dioxins and furans. With respect to syngas,
one commenter suggested that EPA adopt a definition similar to that
used in the 40 CFR part 60 subpart YYYY standards for stationary
combustion turbines. The commenter noted that if the purity of syngas
was a concern, a solution would be to require the syngas to meet
minimum specifications in part 261 of the hazardous waste regulations.
Another commenter requested that Integrated Gas Combined Cycle units
that use a gasifier to convert coal to gas and remove impurities before
combustion be classified under the Gas 1 subcategory.
    Three commenters specifically argued for the inclusion of propane
fired boilers within the Gas 1 subcategory. One commenter stated that
if propane meets the specifications of ASTM D1835-03a or other
specification types like the Gas Processors Association Standard 2140-
92 it should be included within the Gas 1 definition. Another commenter
requested clarification that boilers firing liquefied petroleum gas
(LPG) or propane-derived synthetic natural gas (SNG) as a backup fuel
are still classified as Gas 1 boilers. The commenter argued that
propane or LPG is mixed with air to make SNG and should be considered
natural gas for the purposes of this final rule.
    Several commenters specifically requested that hydrogen plant tail
gas or similar process gases that are derived from natural gas be
included in the Gas 1 subcategory. Commenters argued that hydrogen
fuels do not contain HAP and subcategorizing the fuel as Gas 2 subjects
the units to limits that would achieve no further reduction of HAP but
require extensive performance testing, recordkeeping, fuel analysis and
monitoring requirements. One commenter submitted historical facility
data from a unit firing byproduct hydrogen and the commenter claimed
that the fuel is cleaner burning than natural gas. One commenter
suggested an 8 percent by volume minimum hydrogen content in hydrogen-
fueled process gases as a criterion for consideration as a Gas 1 fuel.
The commenter mentioned that this percentage is based on a 1998 EPA
document that established a minimum hydrogen content by volume for non-
assisted flare combustion efficiency.
    If a separate Gas 2 subcategory remains in the rule, many other
commenters requested that work practices be extended to the Gas 2
subcategory based on the claim that gas-fired units, relative to units
firing other fuels, have the lowest emissions and pose the lowest risk
of all the subcategories. Thus, the use of gas should be encouraged
rather than discouraged. Some commenters argued that as a consequence
of establishing limits for Gas 2 fuels, some plant sites currently
designed to use Gas 2 streams for energy efficient operations will be
forced to dispose of process off-gases in other types of combustion
sources such as flares. The commenters added that such disposal would
result in essentially the same emissions from combustion of the Gas 2
stream using a flare (as opposed to combusting the fuel in a boiler)
and additional emissions from consumption of natural gas that would be
used in lieu of the Gas 2 fuel. Overall, the standard as proposed for
Gas 2 units would result in increased emissions of all pollutants and
lower fuel efficiency.
    Response: EPA has determined that to the extent that process gases
are comparable to natural gas and refinery gas, combustion of those
gases in boilers and process heaters should be subject to the same
standards as combustion of natural gas and refinery gas. Boilers that
combust other gaseous fuels that have comparable emissions levels to
Gas 1 units are similar in class and type to Gas 1 units because they
share common design, operation, and emissions characteristics.
Therefore, we are providing a mechanism by which units that combust
gaseous fuels other than natural gas and refinery gas can demonstrate
that they are similar to Gas 1 units and will therefore be subject to
the standards for Gas 1 units. EPA originally examined the possibility
of basing such a demonstration on levels of mercury and chlorine
content in the gases, but no information was available regarding the
chlorine content of natural gas or refinery gas, and no proven test
methods were identified to quantify chlorine content of natural gas.
Therefore, EPA is requiring a demonstration that other gases have
levels of H2S and Hg that are no higher than those found in
Gas 1 units. Natural gas purity is commonly defined considering the
sulfur content of the gas, in the form of H2S. Sweet natural
gas, which is considered pipeline quality gas, contains no more than 4
ppmv H2S. Information on Hg levels typical of natural gas
was available through literature, and domestic natural gas Hg
concentrations range up to about 40 micrograms per cubic meter. Using
H2S and Hg concentration as parameters for establishing
equivalent contamination levels to natural gas, EPA is providing a fuel
specification that can be used by facilities to qualify Gas 2 units for
the Gas 1 standards. The fuel specification would also allow facilities
to perform pre-combustion gas cleanup in order to qualify Gas 2 units
for the Gas 1 standards. Boilers using process gases that do not meet
the fuel specification and are not processed to meet the contaminant
levels must meet the emissions limits for Gas 2 units.
3. Dioxin/Furan Emission Limits or Work Practices
    Comment: Many commenters disagreed with the proposed dioxin/furan
emission limits. Some commenters noted that a large majority of the
dioxin/furan test data are non-detect values. As such, under section
112(h)(2)(b) of the CAA, the commenters noted that EPA has the
authority to establish work practice standards when ``the application
of measurement methodology to a particular class of sources is not
practicable due to technological and economic limitations.'' Other
commenters stated that dioxin/furan formation in industrial boilers is
not well understood and it would not be possible to duplicate the
emissions from the facilities tested during the Phase II ICR that were
used as the basis of the limit. One commenter indicated they will
undergo preliminary research on the dioxin/furan removal efficiency of
ESP and scrubbers, but much additional research is needed. Several
commenters also added that there are no demonstrated technologies that
would allow the units to reduce their emissions below the limit.
Furthermore, control device vendors commented that they would not be
able to guarantee their equipment will be able to control dioxin/furan
for the affected boilers and process heaters due to lack of practical
experience on boilers and process heaters. They also noted that most
industry experience in controlling dioxin/furan is for waste-to-energy
plants where concentrations of these pollutants are much higher than
the reported Phase II ICR testing results.
    Many commenters believe EPA is not authorized to regulate the
entire dioxin/furan class as is currently proposed. They noted that in
the section 112 HAP list only two compounds are specifically named,
dibenzofuran and 1,3,7,8 TCDD,

and the MACT floor must be limited to those two and not all 17
congeners. Furthermore, some commenters stated that neither the initial
EPA source category list (EPA-450/3-91-030) or the 2004 Boiler MACT
rule identified dioxin/furan as a pollutant to be regulated.
    Some commenters stated that regulating dioxin/furan emissions from
these boilers and process heaters is not necessary because they are not
a significant source of emissions. They noted that dioxin/furan
emissions are significantly higher in units that burn chlorinated
wastes and only those applicable rules (e.g. CISWI and Municipal Waste
Combustors) should focus on regulating dioxin/furan. Having a limit in
this Boiler MACT would only cause undue burden with minimal
environmental impact. Given the uncertainties surrounding dioxin/furan
emissions, a few commenters suggested EPA should do a thorough review
prior to finalizing limits for this final rule to determine how this
source category affects public health. It is suggested that EPA review
the following questions: What portions of the annual total dioxin/furan
emissions are contributed by this source category; what are the other
major sources of dioxin/furan throughout the country; what are the
current conditions for dioxin/furan exposure throughout the U.S.; have
levels been going down or changing and if so by how much; and, could
reductions be achieved more effectively by examining other sources of
dioxin/furan?
    In lieu of a specific dioxin/furan limit, many commenters suggested
that CO should be used as a surrogate and meeting the CO limit would
reduce dioxin/furan. While EPA stated in the preamble to the proposed
rule that it is not appropriate to use CO as a surrogate, these
commenters stated that the precursors to dioxin/furan formation are
produced by incomplete combustion and thus dioxin/furan formation
itself is indirectly related to the combustion process similar to the
other organic HAP CO is currently used as a surrogate for. Another
commenter suggested that control of other HAP such as Hg will provide
adequate incidental control and reduction of dioxin/furan and the cost
of separately monitoring dioxin/furan is not warranted taking into
consideration the cost of achieving such emission reductions, energy
requirements, and environmental impacts as required by Section
112(d)(2) of the CAA.
    On the contrary, another commenter suggested that EPA correctly
recognized that dioxin/furan can be formed outside of the combustion
unit, not as part of the combustion process, and so sets separate
standards for these carcinogens.
    Several commenters provided specific comments on a lack of data
available for boilers burning bagasse in a combined suspension and
grate firing design.
    As an alternative to the limits, many commenters offered
suggestions for a work practice standard to minimize dioxin/furan
emissions. These comments focused on creating boiler-specific plans for
implementing good combustion practices along with an operations and
maintenance plan. Additionally, boiler operators could maintain a
minimum temperature at the outlet of PM control devices to minimize
dioxin/furan formation.
    Response: In response to the comments that EPA is not authorized to
regulate the dioxin/furan class as proposed, the commenters are
incorrect. While dibenzofuran and 2,3,7,8 TCDD are two of the HAP
listed in section 112, all dioxin and furan compounds are considered to
be POM and, as such, EPA has the authority to regulate these compounds
under section 112. The risk-related questions suggested by commenters
are not applicable to establishment of the MACT floor standards under
section 112(d), which are to be based on the average emissions
performance of the best performing units for which the Administrator
has emissions information. EPA received a number of comments on dioxin
and furan emission limits regarding the ability of the test method to
measure the typically low levels of emissions that are emitted from
boilers and process heaters.
    Commenters stated that the emissions were so low that they could
not be measured, and therefore work practice standards, rather than
emission limits, should be finalized for dioxin/furan for all
subcategories. EPA disagrees. While emissions were below detectable
levels in many tests for a large portion of the dioxin/furan isomers,
virtually every test detected some level of dioxin/furan. Furthermore,
some of the emission tests detected most or all isomers at some level.
Dioxin/furan emissions can be precisely measured for at least some
units in each subcategory except for Gas 1. Therefore, except for the
Gas 1 subcategory, which is addressed elsewhere in this preamble, the
statutory test for establishment of work practice standards--i.e., that
measurement of emissions is impracticable due to technological and
economic limitations--is not met.
    In order to make sure that the emission limits are set at a level
that can be measured, EPA used the ``three times MDL'' approach
(discussed elsewhere in this preamble) as a minimum level at which a
dioxin/furan emission limit is set. Rather than finalizing work
practice standards, but recognizing that emissions tend to be very low
compared to more significant sources of dioxin such as incinerators,
EPA's approach to dioxin requires an initial compliance test to
demonstrate that the units meet the dioxin/furan standard, and no
additional compliance testing. Following a test demonstrating
compliance with the emission limit, provided that the unit's design is
not modified in a manner inconsistent with good combustion practices,
the oxygen level must be monitored, and the 12-hour block average must
be maintained at or above 90 percent of the level established during
the initial compliance test in order to provide an assurance of good
combustion. Another important point to mention is that the dioxin/furan
test method, EPA Method 23, requires that for compliance purposes, non-
detect values should be counted as zero. Therefore, for purposes of
compliance, the concern about not being able to meet the standards
because of the contribution of non-detect values is moot.
4. Work Practices for Small Units
    Comment: Many commenters stated EPA should treat new small units in
the same manner as existing small units; for boilers and process
heaters with a design capacity less than 10 MMBtu/hr, a work practice
standard should be implemented instead of numerical limits. These
commenters stated that the same technical and economic conditions under
section 112(h) for existing units still held true for new units. New
small boilers and process heaters (less than 10 mmBtu/hr) are typically
designed like comparable existing units with small diameter stacks, or
wall vents and no stack. These vents and small stacks do not allow for
accurate application of standard EPA test methods required to
demonstrate compliance with emission limits, and larger stacks would
decrease the efficiencies of the units. They continued that while there
are some savings in adding the controls and monitoring equipment during
original construction, those savings were minor in comparison to the
cost of the control and monitoring equipment itself. One commenter
noted that the annual performance tests are over three times the cost
of the boiler. In addition, other commenters stated that the D.C.
Circuit has upheld EPA's discretion to have insignificant emission
sources exempt from regulations, and small units meet this condition.

    Several of the commenters who supported work practice standards for
small units also believed the size threshold should change. A few
commenters suggested the size should be lowered to 5 MMBtu/hr, while
most contended that the size threshold should be raised to 20, 25, or
30 MMBtu/hr. Those commenters who wanted the threshold raised noted
that even boilers as large as 30 MMBtu/hr experience the same economic
implications on their facilities. Some commenters also noted that 40
CFR part 60 subpart Dc New Source Performance Standards have work
practice standards for units less than 30 MMBtu/hr. One State agency
commented that the proposed rule established stringent emission limits
for new small units. The commenter argued that a tiered approach should
be used which required higher emission limits for new small units.
    Conversely, some commenters agreed with EPA's proposed method of
making the limits applicable to new small units. They noted that new
boilers can be built with stacks appropriate for testing, or can have
temporary stack extensions built for testing. One commenter added that
it is not uncommon for new small boilers to vent exhaust into existing
larger stacks that would allow for testing.
    Response: We agree that the design of new and existing small units
precludes the use of the suite of test methods required by this final
rule. As pointed out by commenters, new small boilers and process
heaters (less than 10 mmBtu/hr) are typically designed like comparable
existing units with small diameter stacks, or wall vents and no stack.
These vents and small stacks do not allow for accurate measurement of
emissions using the standard EPA test methods required to demonstrate
compliance with emission limits, and larger stacks would decrease the
efficiencies of the units. Changes in stack diameters or addition of
stacks in lieu of wall vents can impact efficiencies of boilers and can
require significant redesign of boiler systems, which imposes
significant economic limitations. Therefore, EPA has concluded that
work practice standards are appropriate for new and existing small
units because the measurement of emissions is impracticable due to
technological and economic limitations.

E. New Data/Technical Corrections to Old Data

    Comment: Many commenters identified shortcomings in EPA's emissions
database, and multiple corrections were submitted to EPA both through
the public comment process and through e-mail communication with the
ICR Combustion Survey team. Commenters also submitted new data directly
to the ICR Combustion Survey Team and through the public comment
process.
    Response: EPA has incorporated all technical corrections and new
data submitted since proposal. The corrections and new data are
described in detail in a memorandum in the docket entitled ``Handling
and Processing of Corrections and New Data in the EPA ICR Databases.''

F. Startup, Shutdown, and Malfunction Requirements

    Comment: Numerous commenters raised concerns that insufficient data
are currently available to establish emission standards for SSM events.
Due to inherent limitations with measurement methods/technologies,
which often require steady state conditions, emissions testing data and
CEMS provide limited insight into SSM events, therefore combustor
variability during these periods has been underestimated.
    To address these data limitations, several commenters suggested
that EPA should collect additional data that represent SSM events
within each subcategory. One commenter had specific ideas for data
collection including collecting SSM data from CEMS installed at the
facilities previously included in the ICR survey and using portable
analyzers to evaluate SSM emissions during future compliance testing.