source. By incorporating an affirmative defense, the EPA has formalized
its approach to upset events. In a Clean Water Act setting, the Ninth
Circuit required this type of formalized approach when regulating
``upsets beyond the control of the permit holder.'' Marathon Oil Co. v.
EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977). But see, Weyerhaeuser Co.
v. Costle, 590 F.2d 1011, 1057-58 (D.C. Cir. 1978) (holding that an
informal approach is adequate). The affirmative defense provisions give
the EPA the flexibility to ensure both that its emission limitations
are ``continuous'' as required by 42 U.S.C. 7602(k), and account for
unplanned upsets and thus support the reasonableness of the standard as
a whole.

F. Testing and Initial Compliance

    We have carefully evaluated the wide-ranging comments on testing,
continuous monitoring, and other provisions regarding initial
compliance demonstrations, and we have made adjustments intended to
help streamline implementation while still ensuring adequate
demonstration of compliance with the emission limits and other
standards established under this final rule. The significant changes
include:
1. No Fuel Analysis Requirements
    Apart from an alternative that allows you to analyze fuel moisture
for liquid oil-fired EGUs rather than measuring HCl and HF, the final
rule does not include any of the fuel analysis requirements that were
in the proposed rule, either as part of initial compliance
demonstrations or ongoing compliance demonstrations. In reviewing the
results of the fuel analyses and the expected range of results that
would be received from laboratories conducting the proposed analyses,
we determined that too many results would be returned as ``below
detection level'' and, thus, provide little information to assist with
rule implementation and compliance oversight. Given the costs and
efforts involved, we determined that the proposed fuel analysis
requirements would not be an effective compliance monitoring tool for
this final rule.
2. Clarification of Testing
    We have clarified that where options for emission limits apply
(such as filterable PM versus non-mercury HAP metals, or SO2
versus HCl), you need only perform stack testing to demonstrate
compliance with the selected emission limit. For example, if you elect
to meet the individual non-

mercury HAP metals standards, you must conduct the Method 29 test for
the metals, and you do not have to conduct a Method 5 test for PM.
3. Low Emitting EGU Qualification
    We have significantly modified the proposed requirements to qualify
as a LEE unit for a pollutant other than Hg based on an initial
performance test. Under the proposed rule, the operating limit
monitoring provided additional assurance of compliance for a source
qualified for non-mercury LEE status based on an initial compliance
demonstration. Under the final rule, to qualify for LEE status for
pollutants other than Hg, a unit must meet the LEE criteria for a
series of performance tests over a 3-year period to demonstrate that
the unit continues to perform well below the standard for which the
source has obtained LEE status.

G. Continuous Compliance

    The most significant changes to the testing and monitoring
requirements involve the procedures for demonstrating continuous
compliance. The proposed rule contained different options involving
CEMS, periodic stack tests, fuel analysis, and various PM and control
device operating limits. The final rule greatly simplifies the
requirements and provides two basic approaches for most situations: use
of continuous monitoring (either CEMS or PM continuous parametric
monitoring system, CPMS) or periodic quarterly testing. The final rule
does not contain the proposed fuel analysis requirements. For periodic
testing, the proposed rule required testing every month or every 2
months. For those EGU owners or operators who choose to use emissions
testing to demonstrate compliance, the final rule requires quarterly
filterable PM or non-mercury metals HAP, whether individual or total
metals, testing for coal- and liquid oil-fired units. The rule requires
quarterly HCl testing for coal-fired units and quarterly HCl and HF
testing, along with site-specific monitoring for liquid oil-fired units
to ensure compliance with the HCl and HF standards. The final rule also
has a separate compliance demonstration for those liquid oil-fired EGUs
that have an annual capacity factor of less than 8 percent (emission
limits do not apply, just the tune-up work practice standard). For
those EGU owners or operators who choose to use emissions testing to
demonstrate compliance, the final rule requires quarterly filterable PM
or non-mercury metals HAP, whether individual or total metals, testing
for coal- and liquid oil- fired units; quarterly HCl testing for coal-
fired units and quarterly HCl and HF testing, along with site-specific
parameter monitoring for liquid oil-fired units to ensure compliance
with the HCl and HF standards.
    The continuous monitoring options remain generally intact from the
proposed rule, with relatively minor clarifications concerning
calculation of 30-boiler operating day averages and QA requirements.
    The final rule eliminates all operating limits for PM except for
the use of a PM CPMS. For the PM CPMS, the final rule clarifies
procedures for setting this operating limit and how it is distinct from
the PM emission limit. The PM CPMS will not be correlated as a PM CEMS
under PS 11 and will produce data in terms of a signal you define. That
signal could be milliamps, stack concentration, or other output signal
instead of PM emissions in units of the standard. The operating limit
will be set using the highest hourly average obtained from the PM CPMS
during the performance test. Compliance with the limit is based on a
30-boiler operating day rolling average basis. However, the final rule
also does provide for the use of a PM CEMS to determine compliance with
the filterable PM emission limit if the source elects to use this
approach. The EPA believes that some sources may be interested in
adopting this direct approach, and so has included that option in the
final rule. If this approach is selected, the PM CEMS is used as the
direct method of compliance and no additional testing is required other
than tests that are required as part of the QA requirements in PS 11
and Procedure 2. To use this option, the source must elect to meet the
filterable PM standard, and not one of the HAP metals standards.
    Apart from the operating limit for site-specific monitoring
associated with liquid oil-fired EGUs, we removed the other operating
limits for control devices based on a review of the comments, after
considering other programs in place to ensure proper operations of
controls at EGUs. Those other programs include compliance assurance
monitoring under part 64, part 70, and New Source Review permit
conditions, and other SIP and NSPS requirements for operating and
maintaining equipment in accordance with good air pollution control
practices. Those requirements, in combination with the CEMS, PM CPMS,
and frequent periodic testing provisions under the final rule, will
enhance the monitoring of continuous compliance with the requirements
of this rule.
    Because the EPA is concerned that there will be little or no
monitoring in these underlying applicable requirements for acid gases
at liquid oil-fired EGUs, the final rule requires a site-specific
monitoring plan for those units in this subcategory that demonstrate
compliance with the HCl and HF standards through quarterly performance
tests. With the exception for limited-use liquid oil-fired EGUs and
other monitoring options available (such as fuel moisture monitoring or
HCl/HF CEMS), the EPA believes this provision will apply to few units.
The owner or operator will submit the site-specific plan to identify
appropriate parameters that ensure that the operations of the unit
critical to meeting the HCl/HF emission limits remain consistent with
conditions during performance testing. This will be approved similarly
to an alternative monitoring request. The plan should include the
parameters, monitoring approach, QA/QC elements, and data reduction
(including averaging period) elements. Like the PM CPMS operating
limit, the operating limit for acid gas control devices on liquid oil-
fired EGUs will be set using the highest hourly average obtained during
the HCl and HF performance tests. Compliance with the limit is based on
a 30-boiler operating day rolling average basis.
    Finally, we have changed the continuous compliance requirements for
the performance tune-up work practice standard since the proposal. Our
intent was that this work practice standard could be performed in
conjunction with routine maintenance operations at a facility and be a
logical extension of routine best practices for boiler inspection and
optimization. Based on the comments received, we have reduced the
required frequency for this inspection to every 3 years and provided
incentives for neural network combustion management and optimization
practices by providing a longer interval of 4 years between inspections
when such systems are in use at a given EGU.

H. Emissions Averaging

    We are finalizing that owners and operators of existing affected
sources may demonstrate compliance by emissions averaging for existing
EGUs that are located at the same facility that are within a single
subcategory and that rely on emissions testing as the compliance
demonstration method. In response to our request for comments on the
suitability of emissions averaging and need for a discount factor, we
received a range of suggestions, including requests for clarification
regarding eligibility, points for and against the need for a discount
factor, and suggestions to ease implementation.

    As we noted at proposal, part of the EPA's general policy of
encouraging the use of flexible compliance approaches where they can be
properly monitored and enforced is to include emissions averaging.
Emissions averaging can provide sources the flexibility to comply in
the least costly manner while still maintaining a regulation that is
workable and enforceable. Emissions averaging would not be applicable
to new affected sources and could only be used between EGUs in the same
subcategory at a particular facility. Also, owners or operators of
existing sources subject to the EGU NSPS (40 CFR part 60, subparts D
and Da) would be required to continue to meet the PM emission standard
of that NSPS regardless of whether or not they are using emissions
averaging (i.e., an EGU subject to 40 CFR part 60, subpart D or Da must
meet its applicable NSPS filterable PM emission limit even if it is
included in a 40 CFR part 63, subpart UUUUU, emissions averaging group
for filterable PM).
    Emissions averaging allows owners and operators of a facility that
includes existing EGUs within a subcategory to demonstrate that the
source complies with the proposed emission limits by averaging the
emissions from an individual affected EGU that is emitting above the
proposed emission limits with other affected EGUs at the same facility
that are emitting below the proposed emission limits and that are
within the same subcategory. Although some commenters note that the
MACT limits are low, based on the data available to the Agency, we
believe that dozens of existing EGUs are achieving all of the limits
and, thus, emissions averaging is a possible approach.
    The final rule includes an emissions averaging compliance
alternative because emissions averaging \315\ represents an equivalent,
more flexible, and less costly alternative to controlling certain
emission points to MACT levels. We have concluded that averaging in the
proposed rule could be implemented and that it would not lessen the
stringency of the MACT floor limits and would provide flexibility in
compliance, cost and energy savings to owners and operators. We also
recognize that we must ensure that any emissions averaging option can
be implemented and enforced, will be clear to sources, and most
importantly, will be no less stringent than unit-by-unit implementation
of the MACT floor limits.
---------------------------------------------------------------------------

    \315\ As long as required emission rates are designed to account
for factors such as changes in averaging times.
---------------------------------------------------------------------------

    In the final rule, the EPA is providing that sources may average
emissions from existing EGUs at the same facility and within the same
subcategory. Further, for Hg emissions only from existing EGUs within
the same subcategory, such EGUs in an emissions averaging plan may use
an alternate compliance approach consisting of a 90-boiler operating
day rolling average emission limit of 1.0 lb/TBtu or 1.1E-2 lb/GWh.
    In the memo entitled ``The Impact of Emission Averaging Time on the
Stringency of an Emission Standard'' in the docket, we have illustrated
why a longer-term average results in a lower limit. In essence, longer-
term averages allow particularly high (or low) measurements to be
averaged with many more measurements closer to the mean. This results
in the highest averages from a longer-term averaging period (e.g., 90
days) being lower than the highest averages in a shorter term averaging
period (e.g., 30 days).
    We have illustrated this concept by taking Hg CEMS data and
calculating rolling 30-day averages and rolling 90-day averages. The
30-day averages have greater variability and, thus, higher peaks and
valleys. The 90-day average has less variability; therefore, the same
unit is able to meet a tighter 90-day limit.
    The EPA is providing this alternate 90-day rolling average
compliance approach for Hg only. A 90-day rolling average is
appropriate for Hg, and only for Hg, because the health and
environmental impacts associated with Hg are related to environmental
loading rather than shorter term inhalation or other acute exposure, as
is the case with HCl and PM. We believe that this alternative
compliance approach will provide at least the same level of
environmental protection while allowing companies greater flexibility
to use emissions averaging. For example, such an approach would allow
for the averaging of an infrequently operated unit that is operating
slightly above the standard with a more frequently operated unit that
is operating below the standard in the instances when the more
frequently operated unit is in a multi-day or multi-week maintenance
outage.
    The EPA has concluded that it is permissible to establish within a
NESHAP a unified compliance regimen that permits averaging within the
same facility across individual existing EGUs subject to the same
standards under certain conditions. As mentioned earlier, individual
EGUs within an emissions averaging group would be allowed to have
emissions greater than, less than, or equivalent with the emissions
limit for their subcategory, provided that the average emissions
comprised from individual EGU emissions do not exceed the emissions
limit for their subcategory. Averaging across affected units is
permitted only if it can be demonstrated that the total quantity of any
particular HAP that may be emitted by that portion of a contiguous
major source that is subject to the same standards in the NESHAP will
not be greater under the averaging mechanism than it could be if each
individual affected EGU in the subcategory complied separately with the
applicable standard. Under this test, the practical outcome of
averaging is equivalent to compliance with the MACT floor limits by
each discrete EGU, and the statutory requirement that the MACT standard
reflect the maximum achievable emissions reductions is, therefore,
fully effectuated.
    As noted in the proposal preamble, in past rulemakings, the EPA has
generally imposed certain limits on the scope and nature of emissions
averaging programs. These limits include: (1) No averaging between
different types of pollutants; (2) No averaging between sources that
are not part of the same affected source; (3) No averaging between
individual sources within a single major source if the individual
sources are not subject to the same NESHAP; and (4) No averaging
between existing sources and new sources.
    The final rule fully satisfies each of these criteria. First,
emissions averaging would only be permitted between individual existing
sources at a single stationary source (i.e., the facility), and would
only be permitted between individual sources in the same subcategory in
the final EGU NESHAP. Further, emissions averaging would not be
permitted between two or more different affected sources. Finally, new
affected sources could not use emissions averaging. Accordingly, we
have concluded that the averaging of emissions across affected units in
the same existing source subcategory is consistent with the CAA. In
addition, the final rule requires each facility that intends to utilize
emissions averaging to develop an emissions averaging plan, which
provides additional assurance that the necessary criteria will be
followed. In this emissions averaging plan, the facility must include
the identification of: (1) All units in the averaging group; (2) the
control technology installed; (3) the process parameter that will be
monitored; (4) the specific control technology or pollution

prevention measure to be used; (5) the test plan for the measurement of
the HAP being averaged; and (6) the operating parameters to be
monitored for each control device. A state, local, or tribal regulatory
agency that is delegated authority for this rule could require the
emissions averaging plan to be submitted or even approved before
emissions averaging could be used. Upon receipt, the regulatory
authority would not be able to approve an emissions averaging plan
differing from the eligibility criteria contained in the rule.
    The final rule excludes new affected sources from the emissions
averaging provision. The EPA does not believe the statute authorizes
emissions averaging for new affected sources. One reason we allow
emissions averaging is to give existing sources flexibility to achieve
compliance at diverse points with varying degrees of add-on control
already in place in the most cost-effective and technically reasonable
fashion.
    With the monitoring and compliance provisions that are being
finalized, there is additional assurance that the environmental benefit
will be realized. Further, the emissions averaging provision would not
apply to individual EGUs if the EGU shares a common stack with units in
other subcategories, because in that circumstance it is not possible to
distinguish the emissions from each individual unit.\316\
---------------------------------------------------------------------------

    \316\ The EPA has reviewed monitoring data submitted to the
Agency under the Title IV Acid Rain Program. Based on that review,
the EPA is unaware of any coal- and oil-fired units that share a
common stack.
---------------------------------------------------------------------------

    The rule allows EGUs that rely on CEMS for compliance
demonstrations to be able to participate in emissions averaging and the
emissions limits are not subject to a discount. The EPA believes that
the data certainty provided by units that use CEMS would be ideal for
emissions averaging and the flexibility and cost-effectiveness it
offers. Given the homogeneity of fuels within the rules subcategories,
along with other emissions averaging criteria, the Agency believes use
of a discount factor to be unwarranted for this rule.
    The emissions averaging provisions in this final rule are based in
part on the emissions averaging provisions in the Hazardous Organic
NESHAP (HON). The legal basis and rationale for the HON emissions
averaging provisions were provided in the preamble to the final
HON.\317\ We do not believe that we have the authority to provide for
emissions averaging among EGUs in different subcategories or among EGUs
not physically located at the same affected facility.
---------------------------------------------------------------------------

    \317\ Hazardous Organic NESHAP (59 FR 19,425; April 22, 1994).
---------------------------------------------------------------------------

I. Notification, Recordkeeping, and Reporting

    Compared to the proposed rule, the reduced continuous compliance
requirements in the final rule--primarily reduced testing frequencies
and removal of fuel analyses and control device or fuel operating
parameter monitoring--considerably reduces the overall burden
associated with recordkeeping and reporting. Based on evaluation of the
comments received, we have established a provision in the final rule
for submission of most CEMS data (including monitoring plan, emissions
data, and QA data) through ECMPS, so that the affected industry uses a
common reporting tool for submitting CEMS data.
    For data other than most CEMS data, the final rule requires
electronic reporting of certain data, including performance test
reports, PM CPMS data, PM CEMS data, and, if approved as part of an
alternative monitoring request, HAP metals CEMS data. Other reports,
such as notifications, must be submitted in hard copy format or in
accordance with the procedures established by state and local agencies
that receive delegation for implementing this rule. In the proposed
rule, we took comment on these approaches and stated our anticipation
of adopting these approaches. In the final rule, we have extended the
ECMPS reporting to most CEMS data to promote harmonization for CEMS
data from the industry, while leaving reporting of non-CEMS data in a
separate reporting system.

J. Technical/Editorial Corrections

    In this final action, we are making a number of technical
corrections and clarifications to 40 CFR part 63, subpart UUUUU. These
changes clarify procedures for implementing the emission limitations
for affected sources. We are also clarifying several definitions to
help affected sources determine applicability of this rule. We have
modified some proposed regulatory language based on public comments. In
addition, in response to comments received (including the May 2010
notice from the Utility Air Regulatory Group (UARG) of calculation
errors in the proposed Hg MACT floor limits), we have checked all
calculations and made corrections where necessary.
    In several places throughout the subpart, including the associated
tables, we have corrected the cross-references to other sections and
paragraphs of the subpart.

VII. Public Comments and Responses to the Proposed NESHAP

A. MACT Floor Analysis

1. New Data/Technical Corrections to Old Data
    Comment: Many commenters identified errors in the emissions
database compiled through information provided by industry in response
to the 2010 information collection request (ICR) that supported
development of this rule. Commenters submitted corrections to the EPA
during the public comment period.
    Response: The EPA has incorporated technical corrections and new
data submitted prior to the end of the comment period. The corrections
and new data are described in detail in a memorandum in the docket. The
EPA re-ranked the sources in the MACT floor pools to the extent
necessary based on the new or corrected data, and we recalculated the
MACT floors as necessary based on the re-ranking of sources. The
revised MACT floors were established using the same methodology set
forth in the proposed rule.
2. Pollutant-by-Pollutant Approach
    Comment: Many commenters raised concerns about the way the EPA
determined the MACT floors using a pollutant-by-pollutant approach.
Commenters contended that such a methodology produced limits that are
not achievable in combination, and as such, the limits do not comport
with the intent of the statute or the recent court decision (NRDC v.
EPA, 2007). Commenters further added that the CAA directs the EPA to
set standards based on the overall performance of ``sources'' and CAA
sections 112(d)(1), (2), and (3) specify that emissions standards be
established on the ``in practice'' performance of a ``source'' in the
category or subcategory. Commenters stated that if Congress had
intended for the EPA to establish MACT floor levels considering the
achievable emission limits of individual HAP, it could have worded CAA
section 112(d)(3) to refer to the best-performing sources ``for each
pollutant.'' Many commenters added that the EPA's discretion in setting
standards is limited to distinguishing among classes, types, and sizes
of sources. Commenters contend that although Congress limited the EPA's
authority to parse units and sources with similar design and types, it
does not allow the EPA to ``distinguish'' units and sources by
individual pollutant as proposed in this rule (Sierra Club v. EPA, 551
F.3d 1019, 1028 (D.C. Cir. 2008)). By calculating each MACT floor

independently of the other pollutants, commenters contend that the
combination of HAP limits results in a set of standards that only a
hypothetical ``best performing'' unit could achieve.
    Response: We disagree with the commenters who believe MACT floors
cannot be set on a pollutant-by pollutant basis. Contrary to the
commenters' suggestion, CAA section 112(d)(3) does not mandate a total
facility approach. A reasonable interpretation of CAA section 112(d)(3)
is that MACT floors may be established on a HAP-by-HAP basis, so that
there can be different pools of best performers for each HAP. Indeed,
as illustrated below, the total facility approach not only is not
compelled by the statutory language but can lead to results so
arbitrary that the approach may simply not be legally permissible.
    Clean Air Act section 112(d)(3) is not explicit as to whether the
MACT floor is to be based on the performance of an entire source or on
the performance achieved in controlling particular HAP. Congress
specified in CAA section 112(d)(3) the minimum level of emission
reduction that could satisfy the requirement to adopt MACT. For new
sources, this floor level is to be ``the emission control that is
achieved in practice by the best controlled similar source.'' For
existing sources, the floor level is to be ``the average emission
limitation achieved by the best performing 12 percent of the existing
sources'' for categories and subcategories with 30 or more sources, or
``the average emission limitation achieved by the best performing 5
sources'' for categories and subcategories with fewer than 30 sources.
Commenters point to the statute's reference to the best performing
``sources,'' and claim that Congress would have specifically referred
to the best performing sources ``for each pollutant'' if it intended
for the EPA to establish MACT floors separately for each HAP.
    The EPA disagrees. The language of the Act does not address whether
floor levels can be established HAP-by-HAP or by any other means. The
reference to ``sources'' does not lead to the assumption the commenters
make that the best performing sources can only be the best-performing
sources for the entire suite of regulated HAP. Instead, the language
can be reasonably interpreted as referring to the source as a whole or
to performance as to a particular HAP. Similarly, the reference in the
new source MACT floor provision to ``emission control achieved by the
best controlled similar source'' can mean emission control as to a
particular HAP or emission control achieved by a source as a whole.
    Commenters also stressed that CAA section 112(d) requires that
floors be based on actual performance from real facilities. The EPA
agrees that this language refers to sources' actual operation, but
again the language says nothing about whether it is referring to
performance as to individual HAP or to single facility's performance
for all HAP. Industry commenters also said that Congress could have
mandated a HAP-by-HAP result by using the phrase ``for each HAP'' at
appropriate points in CAA section 112(d). The fact that Congress did
not do so does not compel any inference that Congress was sub-silentio
mandating a different result when it left the provision ambiguous on
this issue. The argument that MACT floors set HAP-by-HAP are based on
the performance of a hypothetical facility, so that the limitations are
not based on those achieved in practice, just reiterates the question
of whether CAA section 112(d)(3) refers to whole facilities or
individual HAP. All of the limitations in the floors in this rule
reflect sources' actual performance and were achieved in practice. As
to commenters' claims that standards set in this manner cannot be met
by any actual sources, we have determined that there are approximately
69 existing coal-fired EGUs that meet all of the final existing source
MACT emission limits (out of 252 EGUs that reported data for Hg, PM,
and HCl in the 2010 ICR) and at least one EGU that meets all of the
final new source MACT emission limits.
    Commenters also point to the EPA's subcategorization authority, and
claim that because Congress authorized the EPA to distinguish among
classes, types, and sizes of units, the EPA cannot distinguish units by
individual pollutant, as they allege the EPA did in the proposed rule.
However, that statutory language addresses the EPA's authority to
subcategorize sources within a source category prior to setting
standards, which the EPA has done for certain EGUs. The EPA is not
distinguishing within each subcategory based on HAP emitted. Rather, it
is establishing emissions standards based on the emissions limits
achieved by units in each subcategory. Therefore, the EPA's
subcategorization authority is irrelevant to the question of how the
EPA establishes MACT floor standards once it has made the decision to
distinguish among sources and create subcategories.
    The EPA's long-standing interpretation of the Act is that the
existing and new source MACT floors are to be established on a HAP-by-
HAP basis. One reason for this interpretation is that a whole plant
approach could yield least common denominator floors--that is, floors
reflecting limited or no control, rather than performance which is the
average of what best performers have achieved. See 61 FR 173687 (April
19, 1996); 62 FR 48363-64 (September 15, 1997) (same approach adopted
under the very similar language of CAA section 129(a)(2)). Such an
approach would allow the performance of sources that are outside of the
best-performing 12 percent for certain pollutants to be included in the
floor calculations for those same pollutants, and it is even
conceivable that the worst performing source for a pollutant could be
considered a best performer overall, a result Congress could not have
intended. Inclusion of units that are outside of the best performing 12
percent for particular pollutants would lead to emission limits that do
not meet the requirements of the statute.
    For example, if the best performing 12 percent of facilities for
HAP metals were also the worst performing units for acid gas HAP and
the best performers for acid gas HAP were the worst performers for HAP
metals, the floor for acid gases or metals would end up not reflecting
best performance. In such a situation, the EPA would have to make a
value judgment as to which pollutant reductions were most critical to
decide which sources are best controlled.\318\ Such value judgments are
antithetical to the direction of the statute at the MACT floor-setting
stage.
---------------------------------------------------------------------------

    \318\ See Petitioners Brief in Medical Waste Institute et al. v.
EPA, No. 09-1297 (D.C. Cir.) pointing out, in this context, that
``the best performers for some pollutants are the worst performers
for others'' (p. 34) and ``[s]ome of the best performers for certain
pollutants are among the worst performers for others.''
---------------------------------------------------------------------------

    Commenters suggested that a multi-pollutant approach could be
implemented by weighting pollutants according to relative toxicity and
calculating weighted emissions totals to use as a basis for identifying
and ranking best performers. This suggested approach would require the
EPA to essentially prioritize the regulated HAP based on relative risk
to human health of each pollutant, where risk is a criterion that has
no place in the establishment of MACT floors, which are required by
statute to be based on technology.
    The central purpose of the amended air toxics provisions was to
apply strict technology-based emission controls on HAP. See, e.g., H.
Rep. No. 952, 101st Cong. 2d sess. 338. An interpretation that the
floor level of control must be limited by the performance of devices

that only control some of these pollutants effectively guts the
standards by including worse performers in the averaging process,
whereas the EPA's interpretation promotes the evident Congressional
objective of having the floor reflect the average performance of best
performing sources. Because Congress has not spoken to the precise
question at issue, and the Agency's interpretation effectuates
statutory goals and policies in a reasonable manner, its interpretation
must be upheld. See Chevron v. NRDC, 467 U.S. 837 (1984).\319\
---------------------------------------------------------------------------

    \319\ Because industry commenters argued that the statute can
only be read to allow floors to be determined on a single source
basis, commenters offered no view of why their reading could be
viewed as reasonable in light of the statute's goals and objectives.
It is not evident how any statutory goal is promoted by an
interpretation that allows floors to be determined in a manner
likely to result in floors reflecting emissions from worst or
mediocre performers.
---------------------------------------------------------------------------

    The EPA notes, however, that if optimized performance for different
HAP is not technologically possible due to mutually inconsistent
control technologies (for example, if metals performance decreased as
organics reduction is optimized), then this would have to be taken into
account by the EPA in establishing a floor (or floors). The Senate
Report indicates that if certain types of otherwise needed controls are
mutually exclusive, the EPA is to optimize the part of the standard
providing the most environmental protection. S. Rep. No. 228, 101st
Cong. 1st sess. 168 (although, as noted, the bill accompanying this
Report contained no floor provisions). It should be emphasized,
however, that the D.C. Circuit has stated that ``the fact that no plant
has been shown to be able to meet all of the limitations does not
demonstrate that all the limitations are not achievable.'' Chemical
Manufacturers Association v. EPA, 885 F. 2d at 264 (upholding
technology-based standards based on best performance for each pollutant
by different plants, where at least one plant met each of the
limitations but no single plant met all of them).
    All available data for EGUs indicate that there is no technical
problem achieving the floor levels contained in this final rule for
each HAP simultaneously, using the MACT floor technology. Data
demonstrating a technical conflict in meeting all of the limits have
not been provided, and, as stated above, based on the available data,
there are approximately 64 EGUs that meet all of the final existing
source emission limits and at least one EGU that meets all of the final
new source emission limits.
3. Minimum Number of EGUs To Set Floors
    Comment: Many commenters indicated that CAA section 112 requires
that data from a minimum of 5 units are required to set MACT floors for
existing sources. Commenters noted that the EPA's use of less than 5
units for subcategories with greater than 30 units is a legalistic
reading of CAA section 112 that could result in such absurd results as
using 5 units to set MACT floors for a subcategory with 29 units and
data for only 10 units, but using a single unit to set MACT floors for
a subcategory with 31 units and data for only 10 units.
    Response: The EPA does not agree that CAA section 112(d)(3)
mandates a minimum of 5 sources in all instances, notwithstanding the
incongruity of having less data to establish floors for larger source
categories than is mandated for smaller ones. The literal language of
the provision appears to compel this result. CAA section 112(d)(3)
states that for categories and subcategories with at least 30 sources,
the MACT floor for existing sources shall be no less stringent than the
average emission limitation achieved by the best-performing 12 percent
of the sources for which the Administrator has emissions information.
The plain language of this provision requires the use of fewer data
points for large source categories than for small source categories
where the Administrator only has emissions information on a small
number of units for categories and subcategories with 30 or more
sources. Furthermore, commenters contend that Congress could not have
intended the floors for a subcategory with 29 sources to be based on 5
sources and a subcategory with 31 sources to be based on less than that
number; but we maintain this contention is without merit because 12
percent of 31 is 3.72 (rounded to 4) so the EPA would not base
standards for a subcategory with 31 sources on 5 sources even if we had
data on all 31 sources in the subcategory. For these reasons, we
decline to adopt commenters' position and continue to adhere to the
clear statutory directive.
4. Treatment of Detection Levels
    Comment: Commenters stated that when setting the MACT floors, non-
detect values are present in many of the datasets from best performing
units. Commenters provided input on how these non-detect values should
be treated in the MACT floor analysis. Some commenters agreed that it
is appropriate to keep the detection levels as reported, while certain
commenters suggested that the detection levels should be replaced using
a value of half the method detection limit (MDL). Many other commenters
stated that data that are below the detection limit should not be used
in setting the floors, and these data should be replaced with a higher
value including either the MDL, limit of quantitation (LOQ), practical
quantitation limit (PQL), or reporting limit (RL) for the purposes of
the MACT floor calculations. Other commenters stated all non-detect
values should be excluded from the floor analysis, or all values should
be treated as zero.
    Some commenters stated it is necessary to keep the data as reported
because changing values would lead to an upward bias. Additional
commenters agreed with this basic premise, but suggested that replacing
non-detect data with a value of half the MDL is appropriate while still
minimizing the bias. They noted that treating measurements below the
MDL as occurring at the MDL is statistically incorrect and violates the
statute's ``shall not be less stringent than'' requirement for MACT
floors. One commenter also provided a reference for a statistical
method based on a log-normal distribution of the data which estimated
the ``maximum likelihood'' of data values; this result is slightly
higher than half the MDL.
    Some commenters stated that it is necessary to substitute the MDL
value when performing the MACT floor calculations. With MDL defined as
the lowest concentration that can be distinguished from the blank at a
defined level of statistical significance, this is an appropriate
value. If MDL values are not reported, one commenter suggested an
approach for estimating an MDL equivalent value, but recognized that
the background laboratory and test report files may not be available to
the EPA in order to derive these estimates.
    Most commenters representing industry and industry trade groups
argued that either LOQ or PQL values should replace non-detects. The
LOQ is defined as the smallest concentration of the analyte which can
be measured. These commenters contended that the LOQ leads to a
quantifiable amount of the substance with an acceptable level of
uncertainty. A few commenters provided calculations showing some of the
proposed MACT floors were below the LOQ. Additionally, some of these
commenters stated that using LOQ or PQL values also incorporates
additional sources of random and inherent sampling error throughout the
testing process, which is necessary. These errors occur during sample
collection, sample recovery, and sample analysis;

MDL values only account for method specific (e.g., instrument) errors.
These commenters contended that the three times the MDL approach
discussed in the proposal accounts for some measurement errors but does
not account for these unavoidable sampling errors. The commenters also
noted that an LOQ is calculated as 3.18 times the MDL, and PQL is
calculated as 5 to 10 times the MDL. Many of the commenters in support
of using either an LOQ or PQL value ultimately believed a work practice
is more appropriate where a MACT floor limit is below either of these
two values. They cited CAA section 112(h)(1) which allows work
practices under CAA section 112(h)(2) if ``the application of
measurement methodology to a particular class of sources is not
practicable due to technological and economic limitations''. These
commenters stated that the inability of sources to accurately measure a
pollutant at the level of the MACT floor qualifies as such a
technological limitation that warrants a work practice standard.
    Commenters stated that where the proposed MACT floor is below the
LOQ or PQL then that source category has a technological measurement
limitation. A few commenters suggested RL values should be used when
developing the floor limits. They stated that the RL is the lowest
level at which the entire analytical system gives reliable signals and
includes an acceptable calibration point. They added that use of an
acceptable calibration point is critical in showing that numbers are
real versus multiplying the MDL by various factors.
    Several commenters stated that all non-detect values should be
excluded from MACT floor calculations. They believed that excluding all
non-detect values would eliminate any potential errors or accuracy
issues related to testing for compliance. Due to inconsistencies of the
MDL value reported for non-detect data, one commenter suggested
treating all such values as zero. This would provide a consistent
approach for setting the floor as well as determining compliance.
    Several commenters provided input on the EPA's proposed method of
three times the MDL as an option for setting limits. A few commenters
in support noted that this approach provided a reasonable method to
account for data variability as it took into account more than just
analytical instrument precision. Many other commenters argued that this
method results in limits which are too low, namely that it is still
lower than the LOQ value which they are in favor of as a substitute for
any reported non-detect data. Other commenters disagreed with this
method and claimed that it would lead to results which introduce a high
bias in the floor setting process. A few contended that multiplying by
3 would introduce a 300 percent error into the floor, resulting in a
floor that is less stringent than required by the Act. Others suggested
that the MDL values are antiquated and already too high and thus it is
not appropriate to multiply them by three. Also, a few commenters
suggested multiplying the MDL by three would not reflect the actual
lower emissions achieved by any source and as such is unlawful under
CAA section 112(d).
    Response: We agree with many of the comments related to treatment
of data reported as detection limit values in the development of MACT
floors and emissions limits. As we noted at proposal, the statistical
probability procedures applied in calculating the floor or an emissions
limit inherently and reasonably account for emissions data variability
including measurement imprecision when the database represents multiple
tests from multiple emissions units for which all of the data are
measured significantly above the method detection level. That is less
true when the database includes emissions occurring below method
detection capabilities regardless of how those data are reported.
    The EPA's guidance to respondents for reporting pollutant emissions
used to support the data collection specified the criteria for
determining test-specific method detection levels. Those criteria
ensure that there is only about a 1 percent probability of an error in
deciding that the pollutant measured at the method detection level is
present when in fact it was absent. (Reference: ReMAP: PHASE 1,
Precision of Manual Stack Emission Measurements; American Society of
Mechanical Engineers, Research Committee on Industrial and Municipal
Waste, February 2001.) Such a probability is also called a false
positive or the alpha, Type I, error. This means specifically that for
a normally distributed set of measurement data, 99 out of 100 single
measurements will fall within 2.54 x standard deviation of
the true concentration. The anticipated range for the average of
repeated measurements comes progressively closer to the true
concentration. More precisely, the anticipated range varies inversely
with the square root of the number of measurements. Thus, for a known
standard deviation (SD) of anticipated single measurements, the
anticipated range for 99 out of 100 future triplicate measurements will
fall within 2.54 SD/[radic]3 of the true concentration.
This relationship translates to an expected measurement imprecision for
an emissions value occurring at or near the method detection level of
about 40 to 50 percent.
    By assuming a similar distribution of measurements across a range
of values and increasing the mean value to a representative higher
value (e.g., 3 times minimum detection level or 3xMDL), we can estimate
measurement imprecision at other levels. For an assumed 3xMDL, the
estimated measurement imprecision for a three test run average value
would be on the order 10 to 20 percent. This is about the same
measurement imprecision as found for Methods 23 and 29 indicated in the
ASME ReMAP study for the sample volumes prescribed in the final rule
(e.g., 4 to 6 dscm) for multiple tests.
    Analytical laboratories often report a value above the method
detection limit that represents the laboratory's perceived confidence
in the quality of the value. This independently adjusted value is
expressed differently by various laboratories and is called LOQ, PQL,
or RL. In many cases, the LOQ, PQL, or RL is simply a multiplication of
the method detection limit. Commonly used multipliers range from 3 to
10. Because these values reflect individual laboratories' perceived
confidence, and, therefore, could be viewed as arbitrary, we decline to
adopt the LOQ, PQL, or RL because such approaches in our view would
inappropriately inflate the MACT floor standards. Our alternative to
those inconsistent approaches is discussed below.
    Consistent with findings expressed in reports of emissions
measurement imprecision and the practices of analytical laboratories,
we believe that using a measurement value of 3 times a representative
method detection limit established in a manner that assures 99 percent
confidence of a measurement above zero will produce a representative
method reporting limit suitable for establishing regulatory floor
values.
    On the other hand, we also agree with commenters that an emissions
limit set from a small subset of data or data from a single source may
be significantly different than the actual method detection levels
achieved by the best performing units in practice. This fact, combined
with the low levels of emissions measured from many of the best
performing units, led the EPA since proposal to review and revise the
procedure intended to account for the contribution of measurement
imprecision to data variability in establishing effective emissions
limits. In response to the comments about the

quality of measurements at very low emissions limits especially for new
sources, we revised the procedure for identifying a representative
method detection level (RDL).
    The revised procedure for determining an RDL starts with
identifying all of the available reported pollutant-specific method
detection levels for the best performing units regardless of any
subcategory (e.g., existing or new, fuel type, etc.). From that
combined pool of data, we calculate the arithmetic mean value. By
limiting the data set to those tests used to establish the floor or
emissions limit (i.e., best performers), which in this case is a larger
data set than normally available for establishing NESHAP, we believe
that the result is representative of the best performing testing
companies and laboratories using the most sensitive analytical
procedures. We believe that the outcome should minimize 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 minimum
value for reporting was other than the detection level). We then call
the resulting mean of the method detection levels the representative
detection level (RDL) because it is characteristic of accepted source
emissions measurement performance.
    The second step in the process is to calculate 3xRDL to compare
with the calculated floor or emissions limit. This step is similar to
what we have used for other NESHAP including the Portland Cement rule.
As outlined above, we use the multiplication factor of 3 to reduce the
imprecision of the analytical method until the imprecision in the field
sampling reflects the relative method precision as estimated by the
ASME ReMAP study. That study indicates that such relative imprecision
remains a constant 10 to 20 percent over the range of the method. For
assessing the calculated floor results relative to measurement method
capabilities, if 3xRDL were less than the calculated floor or emissions
limit (e.g., calculated from the upper predictive limit, UPL), we would
conclude that measurement variability was adequately addressed with the
initial floor calculation. The calculated floor or emissions limit
would need no adjustment. If, on the other hand, the value equal to
3xRDL were greater than the UPL, we would conclude that the calculated
floor or emissions limit did not account entirely for measurement
variability. Where such was the case, we substituted the value equal to
3xRDL for the calculated floor or emissions limit (UPL) which results
in a concentration where the method would produce measurement accuracy
on the order of 10 to 20 percent similar to other EPA test methods and
the results found in the ASME ReMAP study.
    We determined the RDL for each pollutant using data from tests of
all the best performers for all of the final regulatory subcategories
(i.e., pooled test data). We applied the same pollutant-specific RDL
and emissions limit assessment and adjustment procedures to all
subcategories for which we established emissions limits. We believe
that adjusting emissions limits in this manner, which ensures that
measurement variability is adequately addressed relative to compliance
determinations, is a better procedure than the one applied at proposal,
which was based on more limited data. We also believe that currently
available emissions testing procedures and technologies provide the
measurement certainty sufficient for sources to demonstrate compliance
at the levels of the revised emissions limits.
5. Basis for New Source MACT
    Comment: Several commenters stated that the proposed limits set for
new EGUs do not represent the best performing EGU. The commenters state
that the EPA has chosen the strictest limit irrespective of the EGU and
that limits for new EGUs should be achievable. According to the
commenters, no existing EGU is currently meeting the proposed limits,
which will result in a moratorium on the construction of new coal-fired
EGUs. Further, commenters state that another result of the EPA's flawed
approach is that the proposed standards for new EGUs are so low that
adequate test methodologies to demonstrate compliance do not exist.
Without accurate testing methodologies, commenters assert that
contractors will not guarantee that potential emission control
technologies will meet the proposed standards. Without accurate test
methodologies and vendor guarantees, commenters believe that financing
of new facilities will be virtually impossible to secure which will, in
turn, effectively preclude the construction of any new coal-based EGUs.
    Commenters also stated that the EPA failed to address cumulative
effects of using multiple pollution control devices in determining MACT
levels applicable to PM levels. In proposing total PM as a surrogate,
commenters believe that the EPA failed to consider or address the
antagonistic effects that adding multiple pollution control devices can
have on an EGU's HAP emissions. Commenters indicated that EGUs would
not be able to comply with the proposed new source HCl limit without
adding a scrubber or some type of sorbent injection to control HCl
emissions. Adding these HCl control technologies will increase the
total PM emissions of these units. According to commenters, because a
fabric filter-alone configuration (the basis for the new source PM
limit) would not meet all MACT limits, these units may not be the best-
performing units.
    Response: The EPA disagrees with the commenters' statements that no
existing unit is currently meeting the new source limits. The EPA
established the new source limits based on data from existing EGUs and
there is at least one EGU, based on the data available, that is meeting
all three final HAP limits and at least eight EGUs that are meeting one
or more of the new source limits. As a result of comments received on
the full body of data, the EPA has re-ranked the best performing EGUs
and reviewed the new source limits based on the re-ranking where
appropriate. Based on the revised ranking, the best performing source
for PM has changed and that source now forms the basis for the new
source filterable PM limit in the final rule. The source is a coal-
fired EGU that includes the entire suite of controls that would likely
be required on a new coal-fired source constructed prospectively (i.e.,
it is a unit with SCR, dry FGD, and FF). Thus, the commenters' concerns
are no longer relevant as they relate to PM emissions from coal-fired
EGUs.
    The EPA also believes that the EGUs serving as the basis for the
new source Hg and HCl limits in the final rule are representative of
what a new coal-fired EGU would look like to meet all of the requisite
regulations applicable to EGUs (e.g., NSPS and the CSAPR) as they also
include the entire suite of controls that would likely be required on a
new coal-fired source constructed prospectively. The EPA has also taken
into account the ability of the various test methods to accurately
measure emissions at the levels being demonstrated by the EGUs in the
top performing 12 percent in establishing the final limits, and we have
determined that there are adequate test methods to measure the
regulated HAP at the new source levels.
6. Achievability of Limits
    Comment: A number of commenters state that the EPA has chosen the
strictest limit irrespective of the unit and that limits for new EGUs
should be achievable. According to the

commenters, no existing unit is currently meeting the proposed new
source limits, which will result in a moratorium on the construction of
new coal-fired units. The commenters state that this regulation goes
beyond protecting public health and will impact the country's choice of
fuel for energy production. Other commenters state that another result
of the EPA's flawed approach is that the proposed standards for new
units are so low that adequate test methodologies to demonstrate
compliance do not exist. Without accurate testing methodologies,
commenters allege that contractors will not guarantee that potential
emission control technologies will meet the proposed standards. Without
accurate test methodologies and vendor guarantees, commenters believe
that financing of new facilities will be virtually impossible to
secure, and that this in turn will effectively preclude the
construction of any new coal-based units. Commenters maintain that
adopting standards effectively banning new coal units amounts to a
momentous change in national energy policy without discussion or
analysis and far exceeds the EPA's authority.
    Some commenters add that the proposed new source MACT standards do
not represent rates that have been achieved in practice and are orders
of magnitude lower than any of the CAA section 112(g) case-by-case MACT
limits established for the most advanced units in the U.S. coal fleet
by multiple state agencies.
    Other commenters stated that the synergistic impact of multiple
controls has not been taken into account in the proposed rules.
Commenters argue that circumstances exist with respect to the control
of acid gases, which will require scrubbers or other SO2
controls that add particulate to the flue gas stream, and that added
particulate must be removed by PM control devices along with the
particulate added to the flue gas for EGUs that need to install ACI for
Hg control. Because particulate devices provide a fixed percent
reduction of particulate, commenters assert that it is mathematically
certain that PM performance will decrease because control of both acid
gases and Hg would add PM to the flue gas stream which would in turn
decrease performance of the PM control on the relevant mass metric. As
a consequence, commenters allege that there is no assurance that
sources can meet the EPA's ``cherry-picked'' floors for acid gases and
for Hg by ``optimizing'' these systems to meet the performance of the
floor units because to do so would impact their ability to meet the
EPA's similarly ``cherry-picked'' total PM floor standard.
    The commenters state that, for existing sources as with the new
source standard-setting approach, a pollutant-by-pollutant approach
does not consider what the top performing 12 percent achieve in
practice for all pollutants and does not consider the antagonistic
effects of the concurrent use of various control technologies. For
example, one commenter states that 47 of the 131 sources used to
calculate the existing source total PM limit only had PM control but no
acid gas or Hg controls that could emit additional PM. According to the
commenter, the CAA is clear that standards must be based on actual
sources and not the product of a pollutant-by-pollutant determination
resulting in a set of composite standards that do not necessarily
reflect the overall performance of any actual source. To address these
issues, the commenter recommends that the EPA use an approach that more
accurately reflects what actual best performing sources achieve.
    Response: The EPA disagrees with the commenters' contention that
the pollutant-by-pollutant approach to establishing MACT floors is
inconsistent with the CAA for the reasons set forth in the response to
comments on the EPA's MACT floor setting process. In addition, the EPA
established the proposed new source limits based on data from existing
EGUs, and there are EGUs that are able to meet the new source limits.
To the extent the commenters are concerned that no existing source is
simultaneously meeting all of the new sources limits, we note that the
EPA has revised the new source standards based on comments and data
corrections that industry made to data it incorrectly provided in
response to the utility ICR. We have identified at least one source
that is meeting all of the new source MACT limits in the final rule.
    We disagree with commenters that suggest the proposed new source
standards are invalid because they are more stringent than CAA section
112(g) case-by-case MACT limits established by state agencies. As
commenters note, states, not the EPA, established the CAA section
112(g) standards, and they did so based on the information available to
them. The EPA likewise must establish CAA section 112(d) standards
based on the available data. We have considered the available data and
information, including the 2010 ICR data, and complied with the
requirements of CAA section 112(d) in establishing the standards in
this final rule. That the final standards are more stringent than CAA
section 112(g) standards issued by certain state agencies has no
bearing on the legitimacy of the standards at issue here.
    The EPA agrees with commenters that the SO2 and some Hg
controls may add to the PM loading and that it is reasonable to
establish the new source standard based on an EGU that has a suite of
controls that will be required of any new source. For example, new
coal-fired EGUs will be required to comply with the utility NSPS and
may have to comply with the CSAPR and other requirements (e.g., SIP or
state-only requirements). Commenters are also correct that the proposed
new source PM surrogate standard was based on a source that is not like
a coal-fired EGU that would be constructed today (i.e., an EGU with
only PM control and no SO2 controls).
    The final standard is not based on the source used to establish the
proposed limit. As stated above, industry commenters provided data
corrections and new data and the EPA considered that new and revised
data in establishing the final standards. We re-ranked all the coal-
fired EGUs based on the new data. The new ranking of coal-fired EGUs
resulted in a change of the source we used to establish the new source
PM surrogate standard for non-mercury metal HAP. The basis for the new
source limit in the final rule is a unit that has a full suite of
controls similar to what would be required for any new coal-fired EGUs
(i.e., it is a unit with SCR, dry FGD, and FF). The EPA has identified
at least one EGU meeting all of the final new source limits; thus, the
EPA does not believe that it is finalizing standards that ``ban'' new
coal-fired generation as indicated by the commenter.
    The EPA also disagrees that the final new source standards are so
stringent that there are not adequate test methods available to
determine compliance with the standards. The EPA has taken into account
the ability of the various test methods to accurately measure emissions
at the levels being demonstrated by the best performing EGUs in
establishing the final limits. This has been done through use of the
3XRDL (discussed elsewhere in this preamble and the Response to
Comments document) and through adjustments to the sampling time
requirements for certain of the HAP.
7. Comments on Technical Approaches
    Comment: Commenters disagreed with the EPA's use of data from
multiple units exhausting through a common stack and argued that the
EPA unreasonably treated data from multiple

units exhausting through a single stack as multiple data points in
establishing the MACT floors. The commenters believe it is improper to
count a single data point from a multiple-unit common stack as multiple
data points. The commenters state that where two units exhaust through
a common stack, the performance is not that of two sources, but only
one. The commenters indicate that emissions performance that is
actually achieved reflects combined operation, which cannot rationally
be split into two parts (data points) because this emissions
performance was not achieved by two separate sources. Commenters assert
that although it may be acceptable for the EPA to surmise that the
combined performance of multiple EGUs and pollution control devices
represents an emissions control strategy that could be a best
performer, thereby entitling the Agency to use the data at all, the
fact is there is only one performer not two. Commenters contend that
apart from being inconsistent with applicable MACT case law, counting
combined stack emissions as two or more data points is unreasonable
because it dampens variability and over-represents the emissions data
by creating multiple ``performers'' or sources when there is in fact
only one. Commenters note that in the major-source Industrial Boiler
NESHAP, the EPA argued its approach of creating two data points from a
single combined stack data point is reasonable because it cannot
separate the comingled fraction of the emissions from the different
emission points. Commenters state that this is irrelevant, believing
that there is no basis to separate these emissions because the MACT
floor is based on best performing sources and there is only a single
source.
    According to commenters, the EPA cannot determine what amount of
the overall performance of a combined stack data point is the specific
result of the combination. Commenters assert that the EPA also argues
that applying the emissions equally to multiple units exhausting
through a single stack ``accurately represents the emissions of those
units on average.'' Commenters believe that is simply not correct and
there is no plausible factual basis for that statement, believing that
there is no unit that ``achieved'' those emissions. Rather, the data
represent the combined weighted average of two units, without knowing
how either unit actually performed. One commenter also stated that in
several instances when a facility operated tandem or multiple EGUs but
only submitted a single stack measurement, the EPA used the single
stack measurement to represent Hg emissions from the facility's other
stacks.
    Response: The EPA disagrees with commenters. As in the major-source
Industrial Boiler NESHAP, the EPA continues to believe that the
emissions from the common stack represent the average emissions of the
EGUs exhausting to the common stack and are representative of both
EGUs. Commenters have provided no data to support the contention that
this assumption is false. In addition, commenters' contention that
distinct EGUs (i.e., boilers) are one source if they emit out of a
common stack is not consistent with the CAA section 112(a)(8)
definition, which clearly applies to the individual boiler units with a
capacity of more than 25 MW. It would not be reasonable in light of
that definition to consider the emissions from two boilers to a common
stack as the emissions of one EGU. The EPA only used data from combined
stacks where both EGUs were operating or where the owner/operator
certified that no air leakage could occur. The EPA expects that
companies will comply with the final rule by conducting testing at the
common stack as that is usually where the sampling locations are
(rather than in the intermediate ductwork) and will report the results
as being for each EGU.
    The EPA has reviewed the data based on comments received and does
not believe that there are any inconsistencies in the data set used for
the final rule. In the MACT floor analysis, the EPA only used data from
stacks that were tested or for which test data were provided. These
stack measurements were not used to represent emissions from other,
non-tested, stacks in the MACT analysis.
8. Alternative Units for Emission Limits
    Comment: Several commenters submitted a variety of alternatives to
the input- or output-based MACT floor limits as means of establishing
the MACT floors. Some commenters suggested emission reductions or
removal efficiencies. These commenters suggest that a percent reduction
MACT metric be considered as an alternative, and not a substitute, to
some of the proposed MACT numerical limits, particularly those that
appear too problematic to meet in reality. A necessary data format and
protocol could be developed for some HAP, such as Hg, that would allow
an appropriate percent reduction alternative to be developed.
Commenters believe that the Brick MACT decision stands for the
proposition that a MACT level cannot be based on a specific technology;
commenters are advocating that a percent reduction format would specify
the level or reduction but would not dictate any specific control or
methodology.
    Comments were also received that some state programs contain Hg
emission limits that are more stringent than the EPA's proposed
emission limits. The programs of Connecticut, Massachusetts, New
Hampshire, New Jersey, and New York were noted. Commenters provided
information on these states' Hg emission limits, which often are in the
form of either a lb/TBtu format or a percent reduction. Commenters
noted that EGUs in these states were in compliance with the state
regulations and, therefore, the EPA's emission limits should be more
stringent.
    Response: The EPA disagrees with the commenters' suggestion that a
percent reduction standard should be included in the final rule. The
EPA notes that the inability to account for Hg removed from the coal
prior to combustion was not the only reason provided for not using a
percent reduction format. As noted in the proposal preamble (76 FR
25040), we did consider using a percent reduction format for Hg. We
determined not to propose a percent reduction standard for several
reasons. The percent reduction format for Hg and other HAP emissions
would not have addressed the EPA's desire to promote, and give credit
for, coal preparation practices that remove Hg and other HAP before
firing because we did not have the data to account for those practices.
Specifically, to account for the coal preparation practices, sources
would be required to track the HAP concentrations in coal from the mine
to the stack, and not just before and after the control device(s). Such
an approach would be difficult to implement and enforce. Moreover, we
do not have the data necessary to establish percent reduction standards
for HAP at this time. Depending on what was considered to be the
``inlet'' and the degree to which precombustion removal of HAP was
desired to be included in the calculation, the EPA would need (e.g.)
the HAP content of the coal as it left the mine face, as it entered the
coal preparation facility, as it left the coal preparation facility, as
it entered the EGU, as it entered the control devices, and as it left
the stack to be able to establish percent reduction standards. We do
not have this type of information.
    The EPA believes that an emission rate format allows for, and
promotes, the use of pre-combustion HAP removal processes because such
practices will

help sources assure they will comply with the proposed standard. A
percent reduction requirement would likely limit the flexibility of the
regulated community by requiring the use of a control device. In
addition, as discussed in the Portland Cement NESHAP (75 FR 55002;
September 9, 2010), the EPA believes that a percent reduction format
negates the contribution of HAP inputs to EGU performance and, thus,
may be inconsistent with the D.C. Circuit's rulings as restated in the
Brick case (479 F.3d at 880) which say, in effect, that it is the
emissions achieved in practice (i.e., emissions to the atmosphere) that
matter, not how one achieves those emissions.
    The 2010 ICR data confirm that plant inputs likely play a role in
emissions to the atmosphere. These data indicate that some EGUs are
achieving lower Hg emissions to the atmosphere at a lower Hg percent
reduction (e.g., 75 to 85 percent) than are other EGUs with higher
percent reductions (e.g., 90 percent or greater). However, we are not
sure whether these data accurately reflect the total percent reduction
mine-to-stack because we do not have all the data necessary to make
that determination. Thus, we proposed to establish numerical emission
standards for Hg HAP emissions from EGUs and we are finalizing
numerical emission standards. The same issues prevent us from
considering percent reduction standards for the other HAP emitted from
EGUs.
    With regard to the comments relating to some state programs being
more stringent than the EPA's proposed limits, the EPA would note that
many of the programs identified by one commenter have an ``either/or''
format for their Hg standards. That is, an EGU can either meet an
emission limit (e.g., lb/TBtu) or achieve a percent reduction. The
commenter did not note which form of the standard the EGUs were meeting
so it is unclear whether the standards are in fact more stringent. In
any case, CAA section 112(d) does not mandate that federal standards be
more stringent than state requirements for HAP emissions. Furthermore,
states are authorized to establish standards more stringent than this
final NESHAP so promulgation of this rule will in no way affect a
source's responsibility to comply with an otherwise applicable state Hg
or other HAP standard.
9. Beyond-the-Floor
    Comment: Several commenters stated that the proposed beyond-the-
floor Hg limit for low rank coal EGUs is based on too little data and
is technically and economically unattainable, noting that the EPA's
proposed beyond-the-floor limit is based on only three samples from a
single test held at only one EGU, which is not enough data to develop
such a limit, especially as more data were available for this EGU in
the database. Commenters noted that although this one EGU may have been
able to achieve the proposed limit during this one test, the three
samples are not adequate to demonstrate the long-term ability of this
EGU to meet that limit consistently, let alone the long-term abilities
of the top 12 percent of all low rank coal EGUs to meet that limit
consistently. Given Texas lignite's particularly high rates of
variability of Hg concentration, and the inability to minimize this
variability, the commenters believe that the EPA is obliged to have
more, not less, data to support the proposed beyond-the-floor Hg limit
for low rank coal EGUs. One commenter added that the EPA's decision to
require a beyond-the-floor limit for the low rank virgin coal
subcategory does not comply with CAA section 112(d)(2). Some commenters
also contended that the EPA failed to include the cost of a baghouse in
its beyond-the-floor analysis. They note that, according to the EPA, in
order to comply with the proposed EGU MACT rule, units will either fuel
switch to a lower Hg fuel or retrofit air pollution controls.
    Response: The EPA notes that all of the low rank virgin coal-fired
EGUs for which data were submitted in response to the 2010 ICR were
meeting the Hg floor limit (11 lb/TBtu). Four of the EGUs have ACI
systems installed and three of the four EGUs tested were also meeting
the beyond-the-floor Hg emission limit of 4.0 lb/TBtu. Those three
units were achieving control levels of greater than 95 percent (fuel to
stack). The other low rank virgin coal-fired EGUs that are not
currently meeting the beyond-the-floor emission limit do not have
installed Hg-specific controls. An analysis of the Hg content of the
fuel used during the 2010 ICR testing suggests that control in the
range of 80 to 90 percent (fuel to stack) would be needed to meet the
beyond-the-floor limit of 4.0 lb/TBtu. One low rank virgin coal-fired
EGU achieved 75 percent control with no Hg-specific control technology
(e.g., ACI).
    The EPA believes that its beyond-the-floor analysis is appropriate,
including the costs analyzed. The EPA's cost analysis is meant to serve
as an average for all sources in the subcategory recognizing that some
EGU's costs will be more and some less; EGUs whose costs are higher are
not exempted from the regulation. Further, five EGUs in the subcategory
are meeting the final beyond-the-floor limit based on available data
(see the MACT Floor analyses in the docket), and, in any case, CAA
section 112(d) does not require that a specified percentage of sources
in a category or subcategory be able to meet the MACT standard that is
established. This is even truer for beyond-the-floor standards which
are set at levels beyond what the average of the best performing
sources are achieving in practice and instead based on what is
achievable. Commenters have failed to provide any data that supports
the contention that some EGUs in the subcategory will not be able to
achieve the standards with additional controls.
    Comment: Commenters indicated that the EPA has not justified a
beyond-the-floor limit for Hg for new IGCC units. The EPA's choice of
the beyond-the-floor Hg limit for new IGCCs is not derived from IGCC
test data from the 2010 ICR and commenters allege that the EPA has not
provided adequate justification for its decision from a technology
capability assessment. Commenters note that ACI for Hg treatment of
coal-derived syngas is not in use in any operating IGCC plant today,
nor can it be used in the same fashion as it is used at conventional
coal-fired EGUs. Commenters assert that the EPA also lacks data with
respect to new IGCC units, yet the EPA proposed beyond-the-floor MACT
limits for new IGCC sources. The commenters assert that the EPA's
limits for new IGCC sources are based on beliefs, predictions,
projections and design target assumptions. The limits from the 2007 DOE
Report referenced in the preamble are based on environmental target
assumptions. These IGCC environmental targets were chosen to match
Electric Power Research Institute (EPRI) design basis from their Coal
Fleet for Tomorrow Initiative. Commenter states that EPRI notes that
these were design targets and were not to be used for permitting
values. Commenters assert that the EPA has simply not justified its
process for going beyond-the-floor for new IGCC units and that, without
sufficient justification, the EPA actions are unsupported.
    Two commenters provided permit information, based on IGCC units
currently under construction, for PM and Hg emissions. One commenter
requested that the proposed new MACT floor limit for PM be modified to
address the two scenarios for duct burners at IGCC plants, syngas-fired
and natural-gas-fired. The commenter requested the 0.050 lb/MWh limit
be increased to at least 0.068 lb/MWh

based on gross energy output from the combined cycle generating unit
when operated with duct burners fired with syngas. The 0.068 lb/MWh
value is consistent with the calculated emission ceiling for its permit
to construct for this operating scenario. According to the commenter,
there is not sufficient experience with syngas turbines for
manufacturers to guarantee performance in the 0.050 lb/MWh range. The
0.0681b/MWh performance basis proposed by the commenter was calculated
based on the emission guarantees that the commenter was able to obtain
for a turbine fired on the syngas. The commenter also requested that
the 0.050 lb/MWh limit be increased to 0.083 lb/MWh based on gross
energy output from the combined cycle unit when operated with duct
burners fired by natural gas. The commenter indicated that, depending
on market conditions, the syngas produced at an IGCC may have more
value as a raw material for producing co-products than it would have as
duct burner fuel. Where that is the case, the economic viability of an
IGCC would be enhanced by firing the duct burners on natural gas and
diverting that syngas to manufacture of a co-product. The commenter's
air permits are currently based on the use of syngas as duct burner
fuel; however, the commenter is currently examining an alternative
operating scenario that may result in amendments to the air permits to
authorize firing natural gas in the duct burners. Commenter states that
preliminary calculations indicate that the PM limit would need to be
set at 0.083 lb/MWh gross energy output when operated with duct burners
fired with natural gas.
    The commenter also noted that there is not sufficient test data to
precisely predict the Hg emissions performance of even the best-
controlled IGCC units, other than that IGCC Hg emissions are expected
to be much less than those for EGUs that directly burn coal. In its
permit application, the commenter proposed to establish a new standard
for Hg removal in IGCC units by treating the syngas in catalytic
reactors. The catalytic reactor system is expected to achieve greater
than 95 percent Hg removal using either sulfur-impregnated activated
carbon or alumina catalyst. In the absence of actual stack test data,
the commenter has had to estimate expected emissions based on
engineering estimates of how much Hg may arrive in the syngas routed to
the catalytic reactors. Based on these engineering estimates and 95
percent Hg removal in the catalytic reactors, the commenter believes
that the resulting Hg emission limit for a state-or-the-art IGCC unit
would be 0.003 lb/GWh, which is much less than the Hg emissions for
EGUs that directly burn coal.
    The commenter notes that IGCC units are still in their infancy.
Funding for them will be very difficult or unavailable if there is a
regulatory limit below the level that can be supported by vendor
guarantees. Given the important role that IGCC units may have in
meeting global energy and climate stability goals, the commenter
believes it would be a mistake to erect barriers to the implementation
of this technology. The commenter stated that the EPA can reevaluate
the appropriate levels for future IGCC units after demonstration units
which incorporate effective controls have been built and tested.
    Response: The EPA is not finalizing the proposed new source
standards for IGCC units. As commenters noted, EPA proposed beyond-the-
floor limits for IGCC units based on the performance of PC-fired EGUs
and solicited data from IGCC units that would represent what a new IGCC
could achieve. We received information that there are new IGCC units
permitted and under construction. The EPA believes one IGCC unit under
construction for which permit data were provided is representative of
both current technologies and of IGCC units that will be built in the
near-term future. Therefore, the EPA believes these permit levels
should be the basis of the new source IGCC emission limits and the
Agency is finalizing the PM and Hg limits on that basis, as that source
will be required to comply with its permitted limits once constructed
and it is a similar source. However, permit limits were only provided
for PM and Hg; therefore, the EPA is finalizing the new source limits
for acid gas HAP based on data from the best-performing of the existing
IGCC units for the respective HAP.

B. Rationale for Subcategories

    Many commenters stated that the EPA should have proposed more
subcategories, while others believed that too many subcategories were
proposed. Many different issues were raised by commenters, and some of
the key issues that were considered in the final rule (some of which
led to changes in the final rule) include: the technical deficiencies
in the definition for the low-Btu coal subcategory; additional
subcategorization of the coal-fired EGU population; the need for
subcategorization of distillate vs. residual oil-fired EGUS; the need
for a limited-use subcategory for EGUs that operate for only a small
percentage of hours during a year; and the need for a non-continental
liquid oil subcategory for island units that have limited fuel options
and other unique circumstances. The comments and the EPA responses are
provided below.
    In general, the EPA has reviewed the data provided and continues to
believe that the coal-fired EGU subcategories proposed are the only
ones supported by the data, though we have revised the basis for EGUs
designed to burn low rank virgin coal as discussed above. The EPA may
not subcategorize by air pollution control technology type as requested
by a few commenters. Further, the EPA has reviewed the other suggested
coal-fired subcategories and finds no basis for further
subcategorization (e.g., based on boiler design, boiler size, or duty
cycle).
1. Coal Subcategories
    Comment: Commenters noted that although other subcategories had
been evaluated, including subcategorization of other coal ranks, no
other coal rank subcategorization was proposed. Commenters submit there
should be subcategories for the coal ranks of bituminous,
subbituminous, and lignite. The commenters noted that such treatment
would be consistent with past practice (e.g., CAMR where the
differences in the type of emissions of Hg due to the different
chemical properties of coal within differing fuel ranks was discussed).
Commenters note that activated carbon has been shown to be very
effective when used in combination with low chlorine coals (such as
western subbituminous coals); however, activated carbons can suffer
from poor performance when used with high sulfur coals. Commenters
indicate that firing high sulfur coals (especially when an SCR is also
used) can result in sulfur trioxide (SO3) vapor in the flue
gas stream. The SO3 competes with Hg for binding sites on
the surface of the activated carbon (or unburned carbon) and limits the
effectiveness of the injected activated carbon. But another commenter
noted that an SO3 mitigation technology, such as dry sorbent
injection (DSI, e.g., trona or hydrated lime), applied upstream of the
ACI can minimize this effect.
    Commenters also stated that without further subcategorization the
economic impacts on individual Midwestern states will be particularly
acute as huge segments of the U.S. coal reserve will be disenfranchised
by this rule. According to the commenters, the EPA did not even attempt
to legitimately analyze this issue and, thus, in their opinion the
Agency's proffered rationale for

declining to further subcategorize based on the acid gas standard is
belied by the record. The commenters believe that the EPA needs to
better align this rule with its previous position in CAMR and further
subcategorize based on coal type.
    Other commenters are opposed to any further subcategorization based
on coal rank. Because many sources blend several ranks of coal on a
regular basis, commenters believe that establishing coal rank
subcategories would create numerous opportunities for sources to game
the regulations and substantially increase emissions. Commenters stated
that there is no need for such an approach since modern pollution
controls can accommodate a wide range of coals. These commenters
believe that EGUs firing different ranks of coal are not fundamentally
different in size, class, or type in a way that impacts emissions or
that limits the availability of controls. The commenters believe that
emissions of fuel-dependent HAP can be controlled by either changing
the fuel prior to combustion or by removing the HAP from the flue gas
after combustion. Commenters state that ACI systems, DSI controls, and
PM controls are available for installation at units firing sub-
bituminous coal and are equally available for units firing bituminous,
anthracite, or lignite coal. These commenters also believe that as long
as a control option is commercially available, the cost for a
particular EGU is irrelevant to the EPA's development of emission
standards based on MACT. Commenters stated that subcategories based on
coal rank would make a meaningful consideration of fuel switching
impossible, contrary to the judicial mandate to consider substitution
of materials in setting the floor and the statutory mandate to consider
substitution of materials in the beyond-the-floor analysis.
    One commenter stated that although they previously supported the
subcategorization of coal-fired units on the basis of coal rank, they
no longer object to grouping units that burn bituminous and
subbituminous coals in a single category because the prior basis for
subcategorization no longer exists. The commenter indicated that at the
time of CAMR, it was widely recognized that although coal-fired units
combusting bituminous coal, with its higher concentration of chlorine
and, therefore, ionic Hg, could effectively limit Hg emissions by
utilizing existing control technologies such as scrubbers, units
burning subbituminous coal could not do so with the same controls
because of the coal's higher levels of elemental Hg. The commenter
stated that activated carbon was only a fledgling and unproven
technology at the time; today, however, activated carbon has been
proven, and units burning bituminous and subbituminous coal can achieve
the same levels of emissions for Hg and other HAP. Consequently, the
commenter believes the prior basis for subcategorization no longer
exists and the commenter, therefore, agrees that coal-fired EGUs
burning bituminous and subbituminous coals ought to be grouped in a
single category.
    Response: The EPA disagrees with commenters that additional coal-
fired subcategories are warranted and has not provided any in the final
rule. Commenters are correct that additional subcategorization was
proposed in January 2004. Whether or not such subcategorization was
warranted at that time, the EPA believes that the current conditions
are such that, even if appropriate at that time, such further
subcategorization is not appropriate at this time.
    When all of the factors noted by commenters have been reviewed,
with the exception of Hg for certain units, as discussed above, the EPA
does not believe that the HAP emissions to the atmosphere are
sufficiently different from coal-fired EGUs to warrant further
subcategorization. There are EGUs firing bituminous, subbituminous, and
coal refuse among the top performing units for Hg and EGUs firing
bituminous, subbituminous, lignite, and coal refuse are all among the
top performers for the acid gas HAP and non-mercury metallic HAP
indicating that the MACT floor limits established based on these units
are achievable by units burning all ranks of coal.
    As noted by commenters, ACI, not fully developed in 2004, is now
able to effect Hg control levels on subbituminous coals such that
similar emissions to the atmosphere may be achieved as those achieved
by higher-chlorine bituminous coals when FGD systems are used or by
coal refuse EGU with less controls. Thus, in looking at the total
system, similar emissions to the atmosphere are achieved by all of
these coal ranks. The EPA has addressed elsewhere in this document its
rationale for not subcategorizing by coal chlorine content. The EPA
does not believe that any fundamental discrimination between coal ranks
will occur as a result of the final rule, though clearly some sources
will be required to install greater controls to comply with the final
standard. We maintain that such result is consistent with the intent of
CAA section 112 standards, which are not intended to have an outcome
whereby all sources can comply with final standards without any action.
    The EPA agrees, in theory, that EGUs are designed around a basic
set of coal characteristics. However, the 1999 ICR demonstrated that
numerous EGUs have conducted trial burns and gained sufficient
experience such that co-firing blends of various coal ranks is now
common practice. In fact, the EPA believes that such blends may be
modified daily, depending on the characteristics of the coal being
burned and on the level of generation needed. The extent of blending,
and the ability to switch the blends on short notice, does not lend
itself (or, in fact, argue for) additional subcategorization.
    The EPA disagrees with any assertion that the EPA ignored possible
subcategorization approaches or that it has insufficient data upon
which to base or evaluate various subcategories. The EPA fully examined
the record, which demonstrates that coal-fired EGUs, with the exception
of certain units for Hg, have similar HAP emissions profiles and that
similar control approaches are available to such EGUs. Although
commenters suggested additional subcategories were warranted, they
failed to provide sufficient data to support their proposed alternative
subcategories. As noted elsewhere, the EPA does not disagree with
commenters that there are some differences in EGUs. However, the EPA
does disagree with commenters that those differences result in
differences in emissions to the atmosphere such that additional
subcategorization is justified.
    Failing to demonstrate that coal-fired EGUs are different based on
emissions, the commenters turn to economic arguments, asserting that
failing to subcategorize will impose an economic hardship on certain
sources. Congress precluded consideration of costs in setting MACT
floors, and it is not appropriate to premise subcategorization on costs
either. See S. Rep No. 101-228 at 166-67 (5 Legislative History at
8506-07) (rejecting the implication that separate categories could be
based on ``assertions of extraordinary economic effects''); see also
NRDC v. EPA 489 F.3d 1364 (D.C. Cir. 2007) (holding that EPA properly
declined to create a subcategory for a particular source and rejecting
the argument that the source may have to incur more costs to comply
with the rule without such subcategory).
    The final limits are based on EGUs currently operating with
available controls. As noted above, the record shows that the various
types of EGUs are represented in the floors, with the exception of
certain units for Hg, which

indicates that the levels are achievable by such units. Thus, the data
actually show that the MACT standards are achievable for a wide variety
of EGUs.
    In addition, the EPA believes it has fulfilled the CAA section
112(c)(l) directive that ``[t]o the extent practicable, the categories
and subcategories listed under this subsection shall be consistent * *
*'' with those of CAA section 111, notwithstanding commenters assertion
to the contrary. The decision on whether to directly align CAA sections
112 and 111 subcategories is discretionary and EPA has reasonably
exercised its discretion in declining to create additional
subcategories for coal-fired EGUs based on the record, with the
exception of certain sources for Hg.
    Finally, the EPA disagrees with the commenters that suggest that
EPA lacks the legal authority to consider material inputs when
considering subcategories. We agree, however, that material inputs must
be considered when establishing MACT standards for the subcategories
that are established. We also believe a meaningful consideration of
fuel switching can occur even if sources are subcategorized based on
fuel inputs because EPA considers fuels switching in evaluating
potential beyond-the-floor alternatives.
    Comment: One commenter stated that the EPA should establish an
existing source acid-gas subcategory for high sulfur or high chlorine
coals because the same factors that the EPA relied on to support a low
rank virgin coal subcategory for Hg are also present in the high sulfur
or high chlorine coal context. The commenter stated that the data
indicate that even well-controlled units burning high sulfur coals
would not be in the top performers for acid gases even at removal rates
of 95 or 96 percent. The commenter added that absent such a
subcategory, about 12 percent of coal deliveries (2005 data), and the
vast majority of coal shipped from the states of Indiana, Ohio, and
Illinois (2008 data), would become unusable. The commenter expressed
support for the alternative SO2 standard for units unable to
meet the HCl standard; however, the commenter also believed that it is
appropriate to establish a coal chlorine or sulfur content-based
subcategory for the alternative SO2 standard. The commenter
stated that coal testing data indicate a clear break in chlorine
concentrations in the coals burned by EGUs, as well as in sulfur
content. The commenter indicated that there are factors supporting a
high sulfur or high chlorine coal subcategory that are similar to those
that the EPA relied upon to support a Hg subcategory for low rank
virgin coal. According to the commenter, the EPA's key rationale for a
Hg subcategory for low rank virgin coal was that no low rank virgin
coal-fired unit appeared in the ``top performing 12 percent of sources,
indicating a difference in the emissions for this HAP from these types
of units.'' The EPA did not establish other subcategories because ``the
data did not show any difference in the level of HAP emissions and,
therefore, we have determined that it is not reasonable to establish
separate emissions limits for other HAP.'' The commenter indicated that
the EPA does not need emissions data to know that even well-controlled
units burning higher sulfur coals would be unable to meet the
alternative SO2 emissions rate, and would therefore also not
appear in the top 12 percent of performing units.
    Response: The EPA disagrees with commenters that subcategories
should be established for high sulfur and high chlorine coals. It
appears from the comments that it is not in fact the chlorine content
that is at issue but the sulfur content of the coal. Commenters state
that they are unable to meet the HCl limit, but they only provide
information indicating it would be difficult to meet the alternative
equivalent SO2 limit. In fact, our data show that coals with
chloride contents as high as 2,100 ppm (0.16 lb/MMBtu) were burned by
EGUs making up the MACT floor pool of sources for the final HCl
emission limit and that the best-performing unit was burning coal with
a maximum chloride content of 1,200 ppm. The median chloride level for
bituminous coals identified from data submitted through the 1999 ICR
was 1,030 ppm so we believe that the coals represented in the MACT
floor pool indicate that the final limits are achievable with high-
chlorine coals. We have determined that HCl removal is very effective
using a number of different types of FGD systems. Absent information
demonstrating that sources are unable to meet the proposed HCl limit
due to the chlorine content of the coal, we believe it is unnecessary
and inappropriate to consider subcategorizing based on chlorine content
in the coal.
    In addition, as noted above, the SO2 limit is an
alternative equivalent standard that is available to sources that have
an SO2 control and CEMS and operate the controls at all
times. The EPA did not provide the alternative equivalent standard for
sources that could not meet the HCl limit as one commenter suggests;
instead, we provided the standard as a convenience and cost saving
measure to EGUs with installed FGD systems because we recognize that
many EGUs have SO2 CEMS. Sources are required to comply with
the HCl limit as a surrogate for all the acid gas HAP or the
SO2 limit as an alternate equivalent standard. Commenters
have not demonstrated that they are unable to meet the HCl standard and
our data show that the standard is achievable even for high chlorine
coals.
    Comment: Several commenters supported the development of a separate
subcategory for fluidized bed combustors (FBC) or circulating fluidized
bed (CFB) EGUs. The commenters encouraged the Agency to consider
subcategorization of FBC EGUs for Hg emissions noting that the industry
has long contended that the design, construction, and operation of FBCs
are different than conventional boilers and that FBCs employ
fundamentally different processes than conventional PC-fired EGUs. The
selection of an FBC unit over a conventional PC boiler is driven in
large part by fuel characteristics. The commenters assert that, as a
result, the emissions profile of FBC units generally differ from
conventional PC boilers because FBC units more advantageously combust
waste coals, as well as coal blends with other carbonaceous material.
The commenters stated that the EPA did not discuss the design
differences between FBC units and PC units in the preamble to this
proposed rule unlike what the Agency did when it previously proposed Hg
MACT limits in January 2004. Commenters state that, for these reasons,
FBC units can be considered a distinct type of boiler.
    The commenters noted that an examination of the 40 ``best
performing'' units for Hg emissions in the proposed MACT floor
spreadsheet showed that 14 of those units are FBC units. The commenters
maintained that had FBC units performed as well as conventional PC
boilers, 2 units would have been expected to be in the top 40. The
commenters allege that the far higher percentage of FBCs in the top 40
leads to the conclusion that these units are different from
conventional PCs with regard to Hg emissions and, as a result, should
have been placed in their own subcategory. Further, commenters noted
that the largest FBC has a nameplate capacity of about 300 MW while the
largest conventional boilers have nameplate capacities of around 1,300
MW.
    The commenters stated that FBCs combust relatively large coal
particles in a bed of sorbent or inert material at a lower degree of
combustion efficiency.

Fluidized bed units operate at less than half of the temperature of a
conventional boiler and have much longer fuel residence times.
Conventional boilers pulverize coal to a very fine particle size to
maximize combustion efficiency and minimize unburned carbon. As a
result, the commenters noted that FBCs typically have higher levels of
unburned carbon present in the ash, which behaves much like activated
carbon and helps promote more efficient Hg removal. Accordingly,
commenters maintain that Hg emissions of FBC boilers and PC boilers are
statistically different, with emissions from FBCs significantly lower
than those from PC boilers. According to commenters, this statistically
significant difference in the Hg emissions profiles for these two
distinct boiler technologies argues in favor of the creation of a
separate subcategory for FBCs, as there is no control technology that
PCs could install that would result in emissions reductions similar to
those achieved by FBCs. The active quantity of calcium oxide (lime-CaO)
available in a FBC boiler is also orders-of-magnitude greater than
compared to a PC boiler, whose alkalinity is derived solely from the
coal's mineral content. Significantly higher CaO can alter the process
chemistry in the boiler, including the oxidation levels of Hg.
    One commenter stated that the EPA properly declined to
subcategorize units based on design type where there is no indication
that any physical distinctions among unit designs have a meaningful and
substantial impact on HAP emissions. The commenter indicated that it
would be inappropriate to subcategorize FBCs because there is no
evidence to support a determination that FBC design is responsible for
a unit falling in or out of the top 12 percent for a particular HAP.
    Response: The EPA acknowledges that there are design and operation
differences between conventional PC-fired EGUs and FBC/CFB EGUS;
however, the commenters are incorrect in asserting that the HAP
emissions levels and characteristics are sufficiently distinct from
other coal-fired EGUs to support subcategorization. Further, commenters
fail to note that FBC EGUs were not subcategorized in CAMR even though,
as commenters note, such design and operation differences were cited
there. The fact that FBC units operate at lower temperatures is of no
consequence as they still operate at temperatures high enough to
vaporize Hg.
    Commenters assert that FBC units are disproportionately represented
among the best performers, with the inference being that they were
selected to test in the 2010 ICR because of their boiler design.
However, FBC EGUs were not specifically selected as best performers for
Hg, as EPA did not select any EGUs based on a determination that they
were best performers for Hg (as noted elsewhere, we had no basis for
selecting EGUs as being best performers for Hg), and to the extent CFB
units were selected in the 2010 ICR, they were selected because we
determined they were best performers for non-mercury metallic HAP, acid
gas HAP, or organic HAP or because they were randomly selected among
the non-best performers for those three HAP groupings. Thus, the CFBs
were selected for testing under the 2010 ICR based not on their boiler
design but, rather, based on the age and on their PM and FGD control
systems (as noted in the Supporting Statement for the 2010 ICR). As
many FBC EGUs, including CFB EGUs, are relatively new, they were
included in the non-mercury metallic HAP group selected for testing
(because their PM controls were among the 175 newest), the acid gas HAP
group selected for testing (because FBC was considered to be an FGD
system and the units were among the 175 newest), and organic HAP
testing (because they were among the newest and, thus, determined to be
among the most efficient).
    The effect on Hg emissions is not what commenters suggest because,
although, as noted by commenters, FBC units may be found among the
better performers (among the top 10 EGUs) on the Hg MACT floor
spreadsheet, they are also found in the range of 221 to 226 EGUs (of
393 data points). The fact that FBC units have ``vastly dissimilar ash
properties'' that may contain higher levels of lime or unburned carbon
in the fly ash than conventional PC EGUs does not indicate that the
overall system behaves any differently with regard to emissions to the
atmosphere (the key metric) than a conventional PC EGU with add-on
controls. The asserted higher levels of unburned carbon result in a
range of effectiveness of Hg control that is similar to that of ACI
found on PC EGUs; such ACI control may be found on EGUs that are among
the better performers as well as on EGUs as low as 369 on the list of
data points. Thus, the EPA disagrees that FBC units are
disproportionately represented in the Hg floor and that their inclusion
is somehow inappropriate or leads to skewing of the analysis.
    All types of coal-fired EGUs other than those we subcategorized are
represented in the MACT floors for Hg and all types of EGUs are
represented in the floors for the non-mercury HAP. Fluidized bed
combustion EGUs are not an exception and such EGUs are found across the
range of top performing EGUs for all of the HAP categories: Acid gas,
non-mercury metallic, and Hg. In addition, any assertion that non-FBC
EGUs are unable to meet the final standards because FBC EGUs are
included in the same subcategory (or vice versa) is plainly refuted by
the fact that EGUs of all types are currently meeting one or more of
the final standards. Thus, the EPA finds no basis for subcategorizing
FBC EGUs.
    Further, as noted below, the EPA does not believe there is a basis
for subcategorizing small EGUs, either FBC or PC. In addition, the data
have been re-evaluated based on comments received and an FBC unit is
not the basis for the new source Hg MACT floor.
    Comment: Many commenters stated that the EPA should have considered
additional subcategorization schemes, including one based on EGU size.
Commenters noted that one of the factors that the Administrator can
consider under CAA section 112(d)(1) in making subcategorization
decisions is unit size. Commenters stated that an analysis of the 2010
ICR data showed a statistical difference between EGUs with a capacity
of 100 MW or less and EGUs above 100 MW; other commenters suggested
that the cut-off range should be 125 MW. Although large in number
(about 27 percent) of all EGUs, these small EGUs only comprise about 5
percent of the coal-fired capacity in the U.S. Thus, commenters assert
that if different MACT limits are set for this subcategory of EGUs, it
will not have a significant impact on the health effects of HAP
emissions. Commenters noted that although emission rates from such
small EGUs are greater than those found in the large unit fleet, their
contribution to the total EGU emissions is not significant. The costs
associated with coming into compliance with the proposed rule by
installing new controls would be proportionally much higher for these
small EGUs than larger EGUs according to the commenters. The commenters
allege that this would force the retirement of generation capacity and
threaten electrical reliability without appreciable benefit to the
environment.
    One commenter stated that in general, the nature of many public
power facilities differs from the general population of coal-fired
power plants. Public power units tend to be smaller in size, and are
often space-constrained by growth in the community surrounding the
generating unit since its initial construction. These limitations
restrict the ability of these EGUs to achieve the same performance
levels of larger,

unconstrained EGUs; and, for those EGUs that can comply with the
proposed standards, the installation of controls sharply increases the
cost of compliance. The commenter stated that the EPA did not
adequately subcategorize to accommodate many small- and medium-sized
public power utilities. In particular, the EPA did not avail itself of
the opportunity to use a public power electric utility subcategory,
rural subcategory, or fuel type subcategories. Other commenters
endorsed the establishment of a less than 100 MW subcategory that would
reduce the costs of the proposed rule significantly, but only affect 5
percent of the total electric utility sector, and help minimize
retirement of uneconomical plants.
    One commenter stated that the EPA properly recognized that
subcategories based on unit size would be inappropriate because the
proposed emission limits are in terms of lb/MMBtu or lb/TBtu and noting
that an EGU's total nameplate capacity is wholly unrelated to its
ability to achieve the proposed limits. Another commenter opposed any
proposal to subcategorize units below 100 MW. The proposed rule does
not apply to units less than or equal to 25 MW, and this commenter
believed that this is a sufficient threshold for applicability.
    One commenter stated that the EPA could establish subcategories for
the purpose of temporarily exempting, for example, a subcategory of
utilities that meet the definition of small entity for purposes of the
proposed rule. The temporary exemption would sunset on a date certain
(e.g., 3 years from the effective date of the rule) at which point the
sources in the subcategory would become subject to the rule, and a
compliance timetable would start to run. The commenter believed that
this time-staged promulgation and compliance proposal would greatly
increase the chance that the control measures could be added in an
orderly and efficient manner with minimal disruption to power markets
and grid reliability.
    Response: The EPA agrees with commenters who stated that an EGU's
size is totally unrelated to its ability to comply with the final
concentration-based limits. The EPA examined the size of units within
the respective MACT floor pools of sources and found units ranging in
size from 25 to 1,320 MW in the HCl floor pool, from 25 to 869 MW in
the non-mercury metallic floor pool, and from 47 to 544 MW in the Hg
floor pool. Thus, we find no more difference between a 25 MW EGU and
(e.g.) a 500 MW EGU than we do between a 500 MW EGU and a 1,300 MW EGU
and reaffirm our position that the MW capacity of the EGU is not a
determining factor in its emissions. Further, the EPA believes that
units of all sizes are owned by both large and small entities.
    The EPA examined the effect if EGUs less than 125 MW were
subcategorized for Hg. The resultant MACT floor for these EGUs would be
1.0 lb/TBtu on a 30-boiler operating day rolling average, a level more
stringent than that developed for the >8,300 Btu subcategory as a
whole. We do not believe that this is what commenters envisioned when
suggesting such a subcategory but we believe it confirms our analysis
of the data that indicates, as noted, these units are controlled in the
same manner as other, larger EGUs, such that additional
subcategorization is not necessary or reasonable. Further, based on the
number of EGUs less than 125 MW in the HCl and PM MACT floor pools, we
believe that a similar analysis for HCl and PM would lead to similar or
more stringent standards than without the additional subcategory. Thus,
units of all sizes are capable of achieving the proposed limits and the
EPA is not finalizing a subcategory based on unit size in the final
rule.
    The CAA authorizes EPA to subcategorize based on ``classes, types,
and sizes of sources.'' The EPA does not believe that this provision
permits subcategorizing sources based solely on their status as small
entities for several reasons. As a threshold matter, commenters
provided no information to suggest that EGUs at small entities are
different from EGUs owned by other entities. Instead, the commenters'
justification for such a subcategory was that the costs to comply with
the standards make it more difficult for small entities; thus, the
basis is essentially a cost basis and we do not think that is
consistent with the statute. Moreover, the legislative history of CAA
section 112(d) supports EPA's interpretation that subcategories cannot
be based on the cost of compliance. See S. Rep No. 101-228 at 166-67 (5
Legislative History at 8506-07) (rejecting the implication that
separate categories could be based on ``assertions of extraordinary
economic effects'').
    In addition, the EGUs owned by small entities use the same type of
fuel as other units, have the same type of combustor designs, and can
use the same types of controls, and so there is no difference in the
HAP emissions from such units. So, even if we believed a subcategory
based on small entities was consistent with the statute, we would
decline to include such a subcategory.
    Therefore, given the language of CAA section 112(d), the
legislative history, and the available information, EPA is not creating
a separate subcategory for EGUs owned by small entities.
    In addition, the D.C. Circuit has clearly stated that the EPA does
not have the statutory authority under CAA section 112 to extend
compliance dates past the 3-year maximum compliance time authorized in
CAA section 112(i)(3)(A) except consistent with CAA sections
112(i)(3)(B) and 112(i)(4). See NRDC v. EPA, 489 F.3d 1364, 1374 (D.C.
Cir. 2007) (finding that ``Congress enumerated specific exceptions to
the 3-year maximum, which indicates that Congress has spoken on the
question and has not provided the EPA with authority under subsection
112(i)(3)(B) to extend the compliance date * * *'') (citing also CAA
section 112(i)(4)). The EPA may not alter the compliance date based on
size or ownership considerations and, thus, we are not providing a
separate compliance date for different groups of EGUs in the final
rule.
    Comment: One commenter stated that the EPA should establish a
subcategory consisting of EGUs that had received air construction
permits but had not yet commenced construction as of the date of the
EPA's proposed rule. The commenter believed that such a category would
be justified because a substantial amount of time, money, and effort
has been invested in these units. The commenter asserted that imposing
new source standards on these EGUs for which the EPA's proposed rule
had not been anticipated during their permit consideration would
unreasonably and arbitrarily impose additional costs and burdens on
these projects and would likely threaten the viability of many of them.
The standards for this subcategory would be based on the anticipated
performance of these units (as reflected by the permitted case-by-case
emission levels), ensuring a reasonable and appropriate level of HAP
control without unreasonably and arbitrarily interfering with the
development of these units.
    Response: Clean Air Act section 112(a)(4) defines a new source as
``a stationary source the construction or reconstruction of which is
commenced after the Administrator first proposes regulations under this
section establishing an emission standard applicable to such source.''
The EPA's regulations implementing the CAA section 112 General
Provisions define ``commenced'' to mean ``with respect to construction
or reconstruction of an

affected source, that an owner or operator has undertaken a continuous
program of construction or reconstruction or that an owner or operator
has entered into a contractual obligation to undertake and complete,
within a reasonable time, a continuous program of construction or
reconstruction.'' See 40 CFR 63.2.
    The EPA is constrained by the definition of ``new source'' such
that any source that ``commenced'' construction after the May 3, 2011,
proposal date is considered a new source under the statute and the
source must comply with the new source standards even if the source
received a final and legally effective CAA section 112(g) permit before
proposal. It is unclear from the comments whether the sources
identified in the comments have commenced construction as defined in
the regulations; however, the identified sources are existing sources,
not new sources, under the final rule if construction was commenced
prior to the proposal date.
    Under the final rule, new sources must comply with the standards on
the date of promulgation or at startup, whichever is earlier, and
existing sources have 3 years to come into compliance with the final
standards. Pursuant to the EPA's regulations at 40 CFR 63.44(b)(1),
however, we may provide in a final CAA section 112(d) standard a
specific compliance date for those sources that obtained a final and
legally effective CAA section 112(g) case-by-case MACT standard and
submitted the information required by 40 CFR 63.43 to the Agency before
the close of the comment period. The EPA does not believe it has
received such information during the comment period and we are not
establishing a separate specific compliance period for sources that
obtained final and legally effective CAA section 112(g) standards prior
to promulgation of the final rule. In the absence of EPA action on this
issue, state Title V permitting authorities are required to ``establish
a compliance date in the [title V] permit that assures that the owner
or operator shall comply with the promulgated standard [ ] as
expeditiously as practicable, but not longer than 8 years after such
standard is promulgated * * *'' 40 CFR 63.44(b)(2). Sources with final
and legally effective section 112(g) standards should work with their
permitting authorities to determine the appropriate compliance date
consistent with the EPA regulations.
    Comment: One commenter stated that in accordance with CAA section
112(d)(l), based on the government-to-government relationship of the
Navajo Nation and the U.S. government, and consistent with the right of
sovereignty and self-determination of the Navajo Nation, it may be
appropriate to classify EGUs on tribal lands in a different subcategory
from those on non-Indian lands. The commenter stated that in accordance
with the distinctive status of Indian lands, based on principles of
tribal sovereignty and self-determination, the government-to-government
relationship, and the flexibility of federal agencies mandated under
E.O. 13175, the EPA should classify sources on tribal lands as a unique
subcategory of EGUs for which emission standards for NESHAP should be
set pursuant to CAA section 112(d)(3).
    Response: Pursuant to CAA section 112(d)(1), the EPA may
subcategorize sources based on differences in class, type, or size. In
the preamble to the proposed rule, the EPA further explains that any
basis for subcategorizing (e.g., class) must be related to an effect on
emissions, rather than some difference which does not affect emissions
performance. The EPA does not agree that a subcategory based on
location on Tribal lands is consistent with the statutory authority to
subcategorize, and commenters do not explain why emissions would be
different for EGUs located on Tribal lands. Absent that showing, EPA
believes it would not be appropriate to subcategorize units even if we
believed such a subcategory is consistent with the statute. CAA section
112 imposes specific requirements with respect to the methodology that
the EPA must use in establishing emission standards for HAP, including
Hg emissions from EGUs. Pursuant to CAA section 112(d)(1), the EPA may
subcategorize sources based on differences in class, type, or size. The
EPA believes, that any basis for subcategorizing (e.g., class) must be
related to an effect on emissions, rather than some difference which
does not affect emissions performance.
    However, the EPA is sensitive to the commenters' concerns and
particularly recognizes the significance of Navajo Generating Station
to the Central Arizona Project and the water delivery to tribes. As a
result, EPA has been consulting with affected Indian tribes and working
closely with other federal agencies, including the Department of the
Interior, on these issues and intends to work with tribal and other
authorities to ensure a smooth transition and address specific issues
as they arise.
2. Oil Subcategories
    Comment: Several commenters stated that distillate oil, and in
particular ultra-low sulfur diesel (ULSD) oil, has fuel characteristics
closer to that of pipeline gas than to residual oils. The metals, as
well as the ash and nitrogen content, of distillate oils are very low,
and the sulfur content of ULSD is approximately the same as that of
pipeline natural gas. The commenters state that distillate oil is a
more refined product than residual oil and, thus, burns cleaner.
According to commenters, separating liquid oil-fired EGUs into two
subcategories (distillate and residual oil) would be consistent with
the discussion of subcategory differentiation in the rule's preamble
which indicates that the division of a category into subcategories is
justified if the two subcategories have very different emissions, which
is true for distillate vs. residual oils. Distillate and residual oils
are also differentiated by their operating requirements. Some
commenters stated that as a consequence of the mechanical differences
between boilers designed for residual oil vs. distillate oils, and
between the fuel-handling requirements for the different fuels, it is
not possible to interchange oil types without significant modifications
to the oil storage tanks, transfer pumps, piping and valves, flow
control systems, burners, and burner control systems. Commenters also
noted that some of the EGUs in the EPA's liquid oil-fired database were
mischaracterized with regard to the type of oil burned during the 2010
ICR testing.
    Some commenters alleged that by combining distillate and residual
oil into a single MACT category, the resultant MACT standards cannot be
satisfied by a boiler firing residual oil without substantial add-on
controls. The commenters asserted that creation of separate
subcategories for liquid oil-fired units that distinguish between
residual and distilled oil would render the standards more achievable
for distinct subcategories of EGUs and reduce the number of potential
plant closures while still advancing the goal of reducing overall
emissions. These commenters contend that MACT floors should not be used
to eliminate whole classes of existing EGUs through mathematical floor
calculations based on data from uncontrolled units and combining boiler
subcategories that are not capable of accommodating a different fuel.
    One commenter stated that the EPA should not subcategorize liquid
oil-fired EGUs based upon different grades of liquid oil. Although
different grades of liquid oil may vary in their heat contents or
viscosities, the commenter maintained that there is no indication in
the rulemaking record that any physical

distinction among units burning different grades of liquid oil affects
the nature or characteristics of emissions in a way that impacts the
availability of controls. According to the commenter, both distillate
and residual oil-fired units can apply similar control technologies to
reduce HAP emissions, and EGUs firing these fuels do not have physical
distinctions that prevent controls from operating effectively. The
commenter believes that fuel switching is an appropriate control
technology and is available for liquid oil-fired sources. Residual fuel
oil contains higher levels of contaminants, including HAP, than
distillate oil, and because a regulated entity can readily burn cleaner
distillate oil in lieu of residual oil, it is inappropriate to
subcategorize based on the distillation fraction of the liquid oil.
Thus, according to the commenter, the grade of liquid-oil fuel does not
provide a reasonable basis for subcategorizing various groups of liquid
oil-fired EGUs. Another commenter alleges that the EPA did not list
distillate oil-fired EGUs in the 2000 Finding.
    Response: The EPA has reviewed the data and determined that it is
not necessary to subcategorize distillate vs. residual oil. Commenters
had noted that the EPA's MACT Floor Analysis spreadsheet at proposal
had erroneously assigned the oil type used during testing for some
boilers. The EPA reviewed the data and determined that the submitting
companies had entered the data incorrectly, or had indicated that two
types of oil were fired in different parts of the 2010 ICR responses.
The EPA contacted all of the companies with oil-fired EGUs in the 2010
ICR to confirm the oil used during testing. Upon review of these data,
it became apparent that units using residual oil with ESPs or
distillate oil without control were the best-performing oil-fired EGUs
for PM and the HAP metals. Further, although emissions of HAP from
distillate oil-fired EGUs are generally lower than those from residual
oil-fired EGUs, EGUs burning distillate oil appeared to have higher
emissions of some HAP but lower emissions of others.
    In addition, the EPA does not agree that distillate oil-fired EGUs
were not listed in the 2000 Finding. We believe it is inappropriate to
exclude distillate oil-fired EGUs from regulation under the final rule
because the Agency did not make a distinction when listing the oil-
fired units.