ii. Rule Should Require Real-Time Monitoring Technology for Fenceline
Monitoring.
    Comment: Numerous commenters stated that the proposed fenceline
standards, which require monitoring using 2-week integrated passive
samplers, are flawed and weak for a number of reasons, including that
the monitoring method does not provide real-time data, does not provide
adequate spatial coverage of the fenceline, and does not provide a
mechanism to identify the specific emission source impacting the
fenceline to manage fugitive emissions. Several commenters suggested
that this monitoring technology is not state of the art. They claimed
that there are superior systems in place at refineries that are
technically and economically feasible, including at Shell Deer Park,
Texas; BP Whiting, Indiana; and Chevron Richmond, California. Further,
they claimed that these systems more effectively achieve the objective
of reducing fugitive emissions. They claimed several systems are
superior to the proposed system, including open-path systems such as
ultraviolet differential optical absorption (UV DOAS) and Fourier
transform infrared spectroscopy (FTIR), as well as point monitors such
as gas chromatographs. A number of commenters suggested that open-path
monitors should be required, stating that this technology is capable of
providing real-time analysis and data on air pollution, is able to
analyze multiple pollutants simultaneously at low, near-ambient
concentrations, and is capable of providing more complete geographic
coverage.
    The commenters also stated that the benefits of real-time monitors
are particularly important in communities close to refineries, where
they believe refinery emissions are a major source of toxic pollutants
and short-term upset events that can have significant public health
impacts. In particular, the commenters stated that open-path monitors
promote an individual's right-to-know, in real-time, about harmful
pollution events affecting their communities, and will allow refinery
owners or operators to immediately identify fugitive emissions and
undertake swift corrective action to reduce these emissions. Some
commenters suggested that, if the EPA rejects these open-path real-time
monitors, then at a minimum the EPA should require the use of active
daily monitoring, such as auto-gas chromatograph (GC) systems.
    Finally, a number of commenters recommended that the EPA provide
sufficient flexibility in its regulations to allow state and local
jurisdictions to develop, demonstrate, and subsequently require the use
of alternative monitoring programs, provided these monitoring programs
are at least equivalent to those in the final rule.
    Response: We understand that many commenters believe real-time
monitoring would not only help refinery owners or operators in
identifying emission sources, but also would warn the community of
releases in real time.
    Both open-path systems and active sampling systems (such as auto-
GCs) mentioned by the commenters, are monitoring systems capable of
yielding monitoring data quickly--ranging from a few minutes to about a
day. However, these ``real-time'' systems have not been demonstrated to
be able to achieve all of the goals stated by the commenters--
specifically, able to provide real-time analysis and data on multiple
pollutants simultaneously at low-, near-ambient concentrations, with
more complete geographic (or spatial) coverage of the fenceline.
    The real-time open-path systems suggested by the commenters are all
limited in that they are not sensitive enough to detect benzene at the
levels needed to ensure that fenceline monitoring achieves its intended
goal. The fenceline monitoring system needs to be capable of measuring
at sub-ppbv levels--well below the 9 [mu]g/m\3\ fenceline benzene
concentration action level in the final rule, in order to determine the
[Delta]C. In the proposal, we discussed two open-path monitoring
technologies, FTIR and UV-DOAS. For the proposed rule, we analyzed the
feasibility of employing UV-DOAS over FTIR because the UV-DOAS is more
sensitive to detection of benzene than FTIR, as we described in the
proposal. We reviewed performance data on several UV-DOAS systems in
support of the proposed rule, and for this final rule, we considered
information submitted during the comment period. We found that the
lowest detection limit reported for any commercially-available UV-DOAS
system is on the order of 3 ppbv over a 200-meter path length, whereas
the fenceline benzene concentration action level is 2.8 ppbv
(equivalent concentration to 9 [mu]g/m\3\). This system is being
installed at the Shell Deer Park refinery but has not been field
validated yet. Thus, we do not yet know the detection capabilities of
the system, as installed. Based on the lowest reported detection limit,
it cannot achieve the detection levels needed to demonstrate compliance
with the fenceline standard in this final rule. This system also will
only cover approximately 5 percent of the fenceline at Shell Deer Park,
instead of the full fenceline coverage of the passive diffusive tube
monitoring system we proposed. Facilities would have to deploy a
monitoring system consisting of many open-path monitors to achieve the
same spatial coverage as the passive diffusive tube monitoring system.
    For the final rule, we also reviewed other UV-DOAS systems in
operation at refineries that commenters identified. However, reported
detection limits for these systems are even higher than for the type of
system being installed at Shell Deer Park. For example, we reviewed the
open-path UV-DOAS system information from BP Whiting and found that
they were able to verify a detection limit of 8 ppbv path average
concentration for benzene over a 1,500-meter optical path. This is well
above the 2.8 ppbv fenceline benzene concentration action level, let
alone the sub-ppbv levels necessary to determine the [Delta]C.
Moreover, this system, though commercially available, was optimized by
developing alternative software to improve the detection limit (see
memorandum ``Meeting Minutes for April 21, 2015, Meeting Between the
U.S. EPA and BP Whiting'' in Docket ID No. EPA-HQ-OAR-2010-0682). Thus,
the system, as installed, would not be readily available to other
refineries. We reviewed data for the UV-DOAS system at the Chevron
Richmond refinery and found that this system, with optical path lengths
ranging from 500 to 1,000 meters, has a reported benzene detection
limit of 5 ppbv averaged over the path length. Again, this is above the
fenceline benzene concentration action level at the fenceline
established in this final rule. In addition, we could not find any
information to support the reported detection limit. We note that the
public Web site operated by the City of Richmond, California indicates
that information provided by the system is informational only, not
quality assured, and not to be used for emergency response or health
purposes.
    We also disagree with the commenter's claim that if the EPA does
not finalize requirements for real-time open-path monitors then, at a
minimum, the EPA should require active daily monitoring. There are two
methods of

active monitoring. One method, which we will refer to as the ``auto-GC
method,'' uses a dedicated gas chromatograph at each monitoring
location and can return ambient air concentration results multiple
times a day or even hourly. The other method, which we refer to as
``method 2,'' uses an active pump to collect gas in a sorbent tube or
in an evacuated canister over a 1-day period, for later analysis at a
central location. While active sampling monitoring networks are capable
of measuring multiple pollutants and would likely be able to detect
benzene at sub-ppbv levels as necessary to demonstrate compliance with
the fenceline requirements in this final rule, they consist of discreet
monitors and would not provide any better spatial coverage of the
refinery fenceline than a passive diffusive tube monitoring network.
Further, as shown in Table 9 of the proposed rule (see 79 FR 36923,
June 30, 2014), like open-path systems, an active sampling monitoring
network would cost many times that of a passive diffusive tube
monitoring network. At proposal, we estimated the costs of active daily
sampling based on ``method 2'' to be approximately 10 times higher than
for the proposed passive monitoring (see memorandum ``Fenceline
Monitoring Technical Support Document'', Docket ID No. EPA-HQ-OAR-2010-
0682-0210). We note that this type of active daily sampling based on
method 2 does not necessarily yield results within 24 hours as the
sample analysis would be conducted separately. We did not specifically
estimate the costs of an auto-GC alternative, but the capital costs
would be at least 20 to 30 times that for the passive diffusive tube
system, would require shelters and power supplies at all monitoring
locations and would have operating costs similar to the ``method 2''
active monitoring option we considered.
    To date, there are no commercially-available, real-time open-path
monitors capable of detecting benzene at the sub-ppbv levels necessary
to demonstrate compliance with the fenceline requirements in this final
rule. Only a system that can detect such levels will result in
effective action by facilities to identify and control fugitive
emissions in excess of those contemplated by the MACT standards.
Further, active monitoring systems, while potentially capable of
detecting benzene at sub-ppbv levels, like open-path systems, become
very costly when enough monitors are located around the facility to
approach the spatial coverage of the passive diffusive tubes. However,
we believe that the state of technology is advancing and that the
capabilities of these systems will continue to improve and that the
costs will likely decrease. If a refinery owner or operator can
demonstrate that a particular technology would be able to comply with
the fenceline standards, the owner or operator can request the use of
an alternative test method under the provisions of 40 CFR 63.7(f). A
discussion of the specific requirements for these requests can be found
in the first comment and response summary of Chapter 8.3 of the
``Response to Comment'' document.
    Comment: One commenter stated that the required monitoring should
include real-time monitoring of all chemicals released by refineries
that pose risks to human health. The commenter stated that the limited
scope of monitoring required by the proposed rule appears to be guided
by the EPA's judgment that fugitive, or ``unintended'' emissions pose
the greatest threat to public health. On the contrary, communities may
well suffer from the effects of chemicals released into the air under
normal, permitted emissions. A more expansive monitoring strategy would
account for both routine and fugitive emissions.
    Several commenters noted that monitoring is limited to benzene as
opposed to multiple HAP. One commenter noted that ill health
experienced by refinery neighbors is due in large part to the
synergistic effects of multiple chemicals. Therefore, the commenter
stated that it is essential that the rule require monitoring of the
full range of chemicals with health implications. Other commenters
recommended that the fenceline monitoring requirement be amended to
include additional contaminants, such as VOC, that may negatively
impact human health and the environment. Conversely, other commenters
stated that the EPA has appropriately selected benzene as a target
analyte and surrogate for HAP emissions from petroleum refineries, as
benzene is a common constituent in refinery feedstocks and numerous
refinery streams, and is present in most HAP-containing streams in a
refinery.
    Response: As part of the CAA section 112(d)(6) technology review,
the EPA identified the fenceline monitoring standard as a development
in practices, processes or control technologies that could improve
management of fugitive HAP emissions. Thus, to the extent the commenter
is suggesting that the EPA require the fenceline monitoring system to
monitor for emissions of non-HAP pollutants, such request goes beyond
the scope of our action. Furthermore, to the extent that the commenter
is raising health concerns, although we address residual risk remaining
after implementation of the MACT standards under CAA section 112(f)(2),
we note that the MACT standards themselves, including this requirement,
are aimed at protecting public health, especially in surrounding
communities. As we explained in the proposal, and as we determine for
this final rule, the MACT standards as modified by additional
requirements for storage vessels, provide an ample margin of safety to
protect public health. We did not propose and are not finalizing a
fenceline monitoring requirement as necessary to provide an ample
margin of safety under CAA section 112(f)(2).
    Petroleum refining emissions can contain hundreds of different
compounds, including many different HAP, and no single method can
detect every HAP potentially emitted from refineries. While several HAP
are amenable to quantification via passive diffusive tube monitoring
using the same adsorbent tubes used for benzene (e.g., toluene, xylenes
and ethyl benzene, which have uptake rates in Table 12.1 in Method
325B), we selected benzene as a surrogate because it is present in
nearly all refinery fugitive emissions. By selecting a single HAP as a
surrogate for all fugitive HAP, we are able to establish a clear action
level, which simplifies the determination of compliance for refinery
owners or operators and simplifies the ability of regulators and the
public to determine whether sources are complying with the work
practice standard. As described in the proposal preamble, benzene is
ubiquitous at refineries and present in nearly all refinery process
streams, including crude oil, gasoline and wastewater. Additionally,
benzene is primarily emitted from ground level, fugitive sources that
are the focus of the work practice standard. Thus, we conclude that
monitoring of benzene is appropriate and sufficient to identify
emission events for which the monitoring program is targeting.
Consequently, we are not requiring quantification of other pollutants
although refinery owners or operators could choose to analyze the
diffusive tube samples for additional HAP in conducting root cause
analysis and corrective action.
iii. Fenceline Monitoring Action Level
    Comment: Several commenters stated that the action level for
fenceline monitoring (i.e., 9 [mu]g/m\3\ or 2.8 ppbv), was set too
high. Some of these commenters noted that the EPA selected 9 [mu]g/m\3\
as the highest modeled benzene

concentration at any refinery fenceline. One commenter stated that this
was arbitrary and capricious and stated the action threshold level
makes little sense because only 2 of the 142 modeled facilities are
expected to have fenceline concentrations above 4 [mu]g/m\3\. Several
commenters noted that the average modeled benzene concentration is 0.8
[mu]g/m\3\, which is more than an order of magnitude less than the
proposed fenceline benzene concentration action level.
    Two commenters argued for a lower action level threshold, citing
the proposed California OEHHA rule, which finalized new and revised
benzene reference exposure levels (REL) that are more stringent than
the ones the EPA used in the residual risk assessment supporting the
proposed rule.
    Two commenters stated that while the fenceline benzene
concentration action level of 9 [mu]g/m\3\ is relatively protective
compared to standards adopted by many states, including Louisiana and
Texas, it is still 80-percent higher than the European Union's standard
of 5 [mu]g/m\3\. The commenter urged the agency to consider adopting a
stricter standard comparable to what other industrialized nations use.
    Several commenters stated that the EPA's 9 [mu]g/m\3\ action level
is inconsistent with the statutory text and objectives of CAA sections
112(d) and (f), which direct the EPA to focus on the best-performing,
lowest-emitting sources, in order to require the ``maximum achievable''
emission reductions. The commenters stated that the EPA promulgated the
9 [mu]g/m\3\ limit without properly following the statutory
requirements for establishing MACT floor limits, pointing out that the
EPA made no determination of whether or not these general models were
representative of the emissions levels actually achieved by the
submitting refinery, and no connection was drawn between the best
performing sources and the eventual 9 [mu]g/m\3\ limit.
    On the other hand, several commenters opposed the 9 [mu]g/m\3\
action level suggesting that it was not achievable and that it is
arbitrary. Some commenters noted that emission/dispersion models are
always very site-specific and do not necessarily yield a result that is
reliable or reproducible. Several commenters stated that additional
studies are necessary to allow the agency to account for these
variables and set a more appropriate concentration corrective action
level. Commenters suggested a 2-year data gathering effort at all
refineries and data evaluation before determining a specific threshold
to use.
    Several commenters recommended action levels ranging from 15 [mu]g/
m\3\ to 20 [mu]g/m\3\ of benzene to account for the variability
expected in monitoring data. The commenters stated that modeling biases
have underestimated the necessary action level to achieve the stated
goals of the program.
    Response: First, it is important to note that the purpose of the
standard has not changed between proposal and promulgation, namely that
it is a technology-based standard that is an advancement in practices
to manage fugitive emissions. It is not intended to be a separate or
new MACT standard promulgated pursuant to CAA sections 112(d)(2) and
(3) for which a ``floor'' analysis would be required.\7\ Nor is it a
standard that we are promulgating pursuant to CAA section 112(f)(2) as
necessary to provide an ample margin of safety to protect public health
or prevent an adverse environmental effect.\8\ Thus, claims that a
standard should reflect European Union health-based standards or the
California OEHHA rule are misplaced. We also disagree with the
suggestion that the proposed monitoring requirement will allow for
higher emissions. As noted elsewhere, we are retaining all of the
source-specific requirements for fugitive emissions sources that exist
in Refinery MACT 1.
---------------------------------------------------------------------------

    \7\ To the extent that the commenters are suggesting that EPA
must re-perform the MACT floor analysis for purposes of setting a
standard pursuant to section 112(d)(6), we note that the D.C.
Circuit has rejected this argument numerous times, most recently in
National Association for Surface Finishing et al. v. EPA No. 12-1459
in the U.S. Court of Appeals for the District of Columbia.
    \8\ Although we did not establish this limit to address residual
risk under CAA section 112(f)(2), the limit was derived from the
same inventory used for our risk modelling. Thus, based on our
current reference concentration for benzene, the 9 [mu]g/m\3\ action
level will also ensure that people living near the refinery will not
be exposed to cancer risks exceeding 100-in-1 million.
---------------------------------------------------------------------------

    We disagree with the commenters that suggest that the proposed
action level of 9 [mu]g/m\3\ is too low and may not be achievable even
for well-performing facilities. As discussed in the preamble for the
proposed rule, we selected the 9 [mu]g/m\3\ benzene action level
because it is the highest value on the fenceline predicted by the
dispersion modeling and, thus, is a level that we estimate that no
refinery should exceed when in full compliance with the MACT standards,
as amended by this final rule. All of the results of our pilot study,
the API study, and the other ambient monitoring data near refineries
clearly indicate that this level is achievable. Furthermore, we expect
the fenceline concentration difference measured following the
procedures in the final rule to be indicative of refinery source
contributions and we have provided procedures to isolate these
concentrations from outside sources, as well as background.
    We expect that the fenceline monitoring standard will result in
improved fugitive HAP emissions management as it will alert the
refinery owners or operators of fugitive sources releasing high levels
of HAPs, such as large leaks, faulty tank seals, etc.
iv. Fenceline Monitoring Root Cause Analysis and Corrective Action
Provisions
    Comment: A number of commenters objected to the proposal's ``open-
ended'' provisions allowing the EPA to direct refinery owners or
operators to change their operations in order to achieve the fenceline
limit, with no regulatory limits on costs and without consideration of
the impact to safe operations or operability of the plant. Another
commenter stated that the EPA must properly assess the costs associated
with the root cause analysis/corrective action requirements and should
establish a cost effectiveness threshold for any required root cause
analysis/corrective action to ensure that limited resources are
effectively and efficiently applied for the control of emissions.
    One commenter stated the proposed fenceline benzene concentration
action level is effectively an ambient air standard, because corrective
action to achieve that level is required and that if a facility's
initial corrective action is unsuccessful, the rule provides that
further action is required and the EPA must approve that further
corrective action plan. Thus, the commenter argued, the EPA would
essentially be able to dictate corrective actions, with no bounds on
what could be required and no consideration of whether any cost-
effective actions are available to assure the action level is met. The
commenter continued that such a requirement converts a work practice
program to an emission limitation and such ambient air limits are not
authorized by CAA section 112. Several commenters noted that LDAR and
current work practice programs have no similar requirement for the EPA
approval, and the commenters suggested that the requirement for the EPA
approval of any second corrective action should not be included in 40
CFR 63.658(h).
    Another commenter recommended that, if after corrective action, a
facility still has an exceedance for the next sampling episode, then
the facility should be required to do more than it

did after the first root cause analysis, as the prior corrective action
clearly did not correct the problem. The commenter stated that one
corrective action measure the EPA should include in all such instances
is higher-quality monitoring such as UV-DOAS for at least 1 year to
monitor, identify, correct and assure ongoing compliance after the
exceedance problem is fixed.
    Response: The ``on-going'' requirement to achieve the fenceline
benzene concentration action level is no different in concept from the
LDAR requirements for equipment or heat exchange systems in the
Refinery MACT 1 rule, which requires the refinery owner or operator to
repair the source of the emissions regardless of what it takes until
compliance with the standard is achieved.
    We disagree with the claim that the EPA must assess the costs
associated with the root cause analysis/corrective action requirements
and establish a cost effectiveness threshold for any required root
cause analysis/corrective action to ensure that limited resources are
effectively and efficiently applied for the control of emissions. We
did not attempt to project the costs of the root cause analysis/
corrective action for at least two reasons. First, based on the
dispersion modeling of the benzene emissions reported in response to
the inventory section of the 2011 ICR, we project that no refinery
should exceed that fenceline benzene concentration action level if in
full compliance with the MACT standards, as amended by this action.
Thus, assuming compliance with the MACT standards, we would expect that
there are no costs for root cause analysis/corrective action. To the
extent that there are exceedances of the action level, the premise of
the fenceline monitoring is to provide the refinery owners or operators
with the flexibility to identify the most efficient approaches to
reduce the emissions that are impacting the fenceline level. Since the
choice of control is a very site-specific decision, we would have no
way to know how to estimate the costs. Thus, the source is in the best
position to ensure that resources are effectively and efficiently spent
to address any exceedance.
    We intended the proposed requirement for refinery owners or
operators to submit a corrective action plan for the EPA approval to
provide the Administrator with information that they were making a
good-faith effort to reduce emissions below the fenceline benzene
concentration action level, as expeditiously as practicable. However,
we understand the importance for refinery owners or operators to begin
corrective action as soon as possible, without having to wait for the
EPA approval. Therefore, we are finalizing the requirement for refinery
owners or operators to submit such plans but we are not finalizing the
requirement that the EPA must approve the plan prior to the corrective
action being taken.
    We previously responded to comments regarding UV-DOAS or other
open-path monitoring systems in this section, explaining that the
current detection limits for these systems exceeds the action level
threshold and, thus, these systems would not provide usable data to
inform corrective action. Thus, we disagree that the EPA should require
these systems for all facilities whose first attempt at corrective
action is ineffective.
v. Fenceline Monitor Siting Requirements
    Comment: Numerous commenters provided suggestions on, or requested
clarification of, the monitor siting requirements. Several commenters
stated that proposed Method 325A uses the terms ``fenceline or property
boundary,'' while it should consistently use the term ``property
boundary'' or even ``property line'' as the fenceline location. Several
commenters stated that Sections <IP_ADDRESS>.4 and <IP_ADDRESS> of Draft Method
325A specify that samplers be placed just beyond the intersection where
the measured angle intersects the property boundary and this could
require placing monitors on other people's property, in a road, in a
water body or in a railroad right-of-way. The commenters suggested that
facilities should be allowed to place monitors at any vector location
that meets other requirements between the property boundary and the
source nearest the property boundary. They stated that facilities need
this clarification to avoid obstructions (e.g., buildings or trees)
that may be at the property line.
    Numerous commenters requested that the rule clarify where monitors
need to be placed in special circumstance, such as refineries bisected
by a road, railroad or other public right-of-way or a boundary next to
a navigable waterway. Several commenters stated that refiners should
not need to place monitors on these property boundaries or other
property boundaries where there are no residences within 500 feet of
the property line. Commenters also asked if areas that had non-refinery
operations, but are still inside the property boundary, would be
included for purposes of determining where to site monitors.
    A few commenters expressed concern about the approach for
determining the number of required monitors at a site based on the
acreage, noting that it is unfair to small facilities and will leave
gaps in monitoring coverage for very large facilities. Some commenters
recommended amending the proposed rule to require the placement of
fenceline monitors at fixed distances along facilities' perimeters with
no maximum number of monitors. Some commenters stated that the rule
should specify an acceptable range on the 2,000-foot spacing
requirement or the radial placement requirement as it may be necessary
to address accessibility or safety concerns. Several commenters
suggested that a lower minimum number of sampling monitors should be
required for very small refineries or small ``subareas.'' These
commenters noted that refineries often include disconnected parcels
that can be very small (e.g., 10 acres or less). If each disconnected
parcel must be treated as a separate subarea, then both sampler siting
options in Draft Method 325A would result in unnecessarily large
numbers of samplers extremely close together. Some commenters
recommended that Method 325A specify that samplers need not be placed
closer than 500 feet (versus the normal 2,000-foot interval specified
in Option 2) along the fenceline from an adjoining sampler, regardless
of whether the radial or linear approach is used and should waive the
minimum number of samplers specified in Sections <IP_ADDRESS>.1, <IP_ADDRESS>.1,
and <IP_ADDRESS>. Another commenter added that the rule should waive the
requirement for additional samplers in Sections <IP_ADDRESS>.5 and <IP_ADDRESS>
if the 500-foot minimum spacing criterion is compromised.
    Response: We agree that the Method 325A should provide clear and
consistent language. We have revised the language to be consistent in
referring to the ``property boundary''. We have also revised the Method
to allow placement of monitors at any radial distance along either a
vector location or linear location (that meets the other placement
requirements) between the property boundary and the source nearest the
property boundary. That is, the monitors do not need to be placed
exactly on the property boundary or outside of the property boundary.
They may be placed within the property closer to the center of the
plant as long as the monitor is still external to all potential
emission sources. We do note that if the monitors are placed farther in
from the property boundary, the owner or operator should take care to
ensure, if possible, that the radial distance from the sources to the
monitors is at least 50

meters. If the perimeter line of the actual placement of the fenceline
monitors is closer than 50 meters to one or more sources, then the
additional monitor citing requirements will apply. We have revised
subparagraphs of Section 8.2.2 to provide this allowance. This
clarification should address issues related to obstructions such as
tall walls located at the facility boundary.
    We intended that the fenceline monitoring would create a monitoring
perimeter capable of detecting emissions from all fugitive emission
sources at the refinery facility. We have long established that a road
or other right of way that bisects a plant site does not make the plant
site two separate facilities, and, thus, would not be considered part
of the property boundary. As we agree that monitors need only be placed
around the property boundary of the facility, it would not be necessary
to place monitors along a road or other right-of-way that bisects a
facility. We have clarified this in the final rule and Method 325A.
    If the facility is bounded by a waterway on one or more sides, then
the shoreline is the facility boundary and monitors should be placed
along this boundary. If the waterway bisects the facility, the waterway
would be considered internal to the facility and monitors would only be
needed at the facility perimeter.
    Regarding the comment that monitors should not be required where
there is no residence within 500 feet of the property line, we
disagree. We proposed and are finalizing the fenceline monitoring
standards under CAA section 112(d)(6) as a means to improve fugitive
HAP emissions management, regardless of whether there are people living
near a given boundary of the facility.
    Regarding the clarification requested about monitor placement
considering non-refinery operations, the property boundary monitors
should be placed outside of all sources at the refinery. This is
because moving the monitoring line inward to exclude the non-refinery
source could lead to an underestimation of the [Delta]C compared to the
monitoring external of the entire site. If the non-refinery source is
suspected of contributing significantly to the maximum concentration
measured at the fenceline, a site-specific monitoring plan and
monitoring location specific near-field interfering source (NFS)
corrections will be needed to address this situation.
    Section 8.2.3 of Method 325A includes language to provide some
flexibility when using the linear placement (10% or 250 feet). We consider it reasonable to provide similar placement
allowance criteria for the radial placement option (1
degree). We are not providing requirements that would allow small area
refineries to use fewer than 12 monitoring sites. We do not consider
that any refinery would be so small as to warrant fewer than 12
monitors; however, we did not necessarily consider very small subareas
for irregularly shaped facilities or segregated operations. When
considering these subareas, we agree that fewer than 12 monitoring
sites should be appropriate. Therefore, we have provided that monitors
do not need to be placed closer than 152 meters (500 feet) (or 76
meters (250 feet) if known sources are within 50 meters (162 feet) of
the monitoring perimeter, which is likely for these subareas or
segregated areas) with a stipulation that a minimum of 3 monitoring
locations be used per subarea or segregated area. We note, however,
that this distance provision does not obviate the near source extra
monitoring siting requirements or the requirement to have a minimum of
three monitors per subarea or segregated area.
    If facility owners or operators have questions regarding the
required locations of monitors for a specific application, they should
contact the EPA (or designated authority) to resolve questions about
acceptable monitoring placement.
vi. Compliance Time for Fenceline Monitoring Requirements
    Comment: Some commenters supported EPA's proposal to provide 3
years to put a fenceline monitoring program in place, but the
commenters believe that timing is unclear in the proposed regulatory
language, which appears in Table 11 to subpart CC, and requested that
the EPA add the initial compliance date to 40 CFR 63.658(a). One
commenter stated that instituting this program for all 142 major source
U.S. refineries would require considerable time. Based on their
experience with their pilot study, one commenter noted that
commercially available weather guards meeting the specifications of
proposed Method 325A are not available and would need to be fabricated.
Additionally, a commenter stated that only a limited number of
laboratories in the U.S. are able to perform the necessary analyses.
According to the commenter, considerable time and effort will be needed
to qualify additional laboratories and to expand the capacity of
existing laboratories to handle the samples from 142 refineries.
    Other commenters disagreed with the EPA's proposed compliance time
and suggested that the EPA shorten the timeline for implementation at
refineries so that possible corrective action occurs much sooner than
proposed. The commenters suggested that deployment of passive samplers
can proceed more promptly than proposed, especially since the EPA has
simultaneously proposed specific ``monitor siting and sample collection
requirements as EPA method 325A of 40 CFR part 63, Appendix A, and
specific methods analyzing the sorbent tube samples as EPA Method 325B
of 40 CFR part 63, Appendix A.'' Moreover, the commenter noted, a
principal reason that the EPA selected passive monitors over active
monitors was due to the relative ``ease of deployment.'' The commenter
claimed this ease of deployment rationale is undermined by a 3-year
grace period to deploy passive monitors when the EPA is providing very
specific criteria for their use. The commenter suggested that the EPA
require full compliance with the passive monitoring requirement within
1 year of the effective date of the rule.
    Response: While we realize that it will take some time for the
refinery owners or operators to understand the final rule and develop a
compliant monitoring program, we agree that in requiring the passive
sampler monitoring system, we recognized the ease of implementation and
deployment. Although industry commenters identified issues they faced
in the API pilot study while trying to implement the monitoring method,
we note that the 12 facilities that participated in the API pilot study
installed the fenceline monitors and began sampling in late 2013 with
relative ease and within months of obtaining the draft methods. Thus,
we disagree with the suggestion that 3 years is insufficient and agree
with other commenters that 3 years is in fact too long. However, we
also are aware that the API pilot facilities used the direct [Delta]C
approach proposed and did not attempt to develop site-specific
monitoring programs to correct for interfering near-field sources.
Although we expect that facilities could complete direct implementation
of the proposed fenceline monitoring requirement within 1 year after
the effective date of the rule, as suggested by some commenters,
facilities that choose to develop a site-specific monitoring plan would
need a longer period of time. Therefore, we are finalizing requirements
that specify that facilities must begin monitoring for the official

determination of [Delta]C values no later than 2 years after the
effective date of the rule.
vii. Fenceline Monitoring Recordkeeping and Reporting Requirements
    Comment: Some commenters suggested that facilities should be
required to submit the monitoring data via the ERT only if they exceed
the fenceline benzene concentration action level and that all remaining
data should be kept on-site and available for inspection or upon
request of the EPA, citing that this is consistent with EPA's
semiannual NESHAP reporting of only exceptions (i.e., deviations).
Other commenters requested that the EPA only post the rolling annual
average concentration values and not the 2-week monitoring data. These
commenters indicated concern that if errors are present in the raw data
that are submitted semiannually to the EPA, the data, errors and all,
will be released to the public and correcting them will not take place
or will not take place in a timely manner. One commenter added that
there is very little useful information that can be gleaned from the
raw data and posting it simply invites misunderstandings.
    Commenters also stated that the EPA should adopt reporting
requirements to ensure that facilities report the monitoring data
appropriately. Specifically, commenters recommended that 40 CFR
63.655(h)(8)(i) should be clarified to only require reporting of valid
data and cautioned that data should be processed to allow accurate
calculations of annual averages to be used for reporting and
evaluation. To accomplish this, commenters recommended that the rule
provide 75 days from the end of a 6-month sampling period to report to
the EPA, rather than the proposed 45-day period, in order to provide
adequate time to obtain quality-assured results for all 2-week sampling
periods.
    One commenter applauded the proposal's requirements for electronic
reporting of the fenceline concentration data and making the resulting
information publicly available. However, the commenter recommended that
the EPA consider a more truncated data reporting period that is more
consistent with the associated milestones of collecting a 14-day
sampling episode. As is, the commenter claimed, the proposed rule would
have a lag time of up to 7.5 months between data collection and
posting. The commenter indicated that data reporting on a more frequent
schedule will not only provide transparency, but will provide states
and local agencies with information about air quality at refineries at
a frequency that could allow informed activities to address leaks much
more quickly and protect public health.
    Response: We disagree with the commenters who suggest that
facilities only report the rolling annual average or only exceedances
of the fenceline benzene concentration action level because the
commenters believe there is little information to be gleaned from the
raw data. Monitoring data are useful in understanding emissions,
testing programs, and in determining and ensuring compliance. We
generally require reporting of all test data, not just values
calculated from test data and/or where a facility exceeds an emissions
or operating limit. For example, when we conduct risk and technology
reviews for source categories, we are adding requirements for
facilities to submit performance test data into the ERT, not just
performance test data that indicates an exceedance of an applicable
requirement. In the Mercury and Air Toxics Rule, we require facilities
to report direct measurements made with CEMS, such as gas
concentrations, and we require hourly reporting of all measured and
calculated emissions values (see discussion at 77 FR 9374, February 16,
2012). In particular, for the fenceline monitoring requirements in this
final rule, we offer facilities options for delineating background
benzene emissions and benzene emissions not attributable to the
refinery, and we offer options for reduced monitoring, making it even
more necessary that we have all of the data to review to ensure that
testing and analyses are being done correctly and in compliance with
the requirements set out in the regulations, and that root cause
analyses and corrective actions are being performed where necessary.
Therefore, as proposed, we are finalizing the requirements that
facilities report the individual 2-week sampling period results for
each monitor, in addition to the calculated [Delta]C values in their
quarterly reporting.
    Regarding commenters' concerns that facilities post accurate data
and have sufficient time to perform quality assurance on the data, in
the final rule, we have established provisions for how sources are to
address outliers and data corrections. Additionally, as proposed, we do
not require an initial report until facilities have collected 1 year of
data so that facilities do not report the data until a rolling annual
average value can be determined. This will allow refinery staff and
analytical laboratories to iron out any issues that might arise as they
implement these methods for the first time. Once this initial data
collection period is complete, we anticipate that data quality issues
should be infrequent. Therefore, we are providing a 45-day period
following each quarterly period before facilities must submit the
monitoring results, which should provide facilities adequate time to
correct any data errors prior to reporting the data.
    Regarding comments that suggest reporting each 2-week sample result
soon after its collection, we disagree. This frequency would put undue
burden on the refinery owners or operators in trying to collect, review
and quality assure the data prior to reporting. However, we agree with
commenters that more frequent reporting of the fenceline monitoring
data would be useful. Therefore, we have revised the reporting
frequency for the fenceline monitoring data to be quarterly in the
final rule rather than semiannually as proposed. Additionally, we
understand that there is a lot of interest in how these data will be
presented to the public, and we plan to reach out to all stakeholders
on appropriate approaches for presenting this information in ways that
are helpful and informative.
b. Refinery MACT 2
    This section provides comment and responses for the key comments
received regarding the technology review amendments proposed for
Refinery MACT 2. Comment summaries and the EPA's responses for
additional issues raised regarding the proposed requirements resulting
from our technology review are in the ``Response to Comment'' document
in the public docket (Docket ID No. EPA-HQ-OAR-2010-0682).
i. FCCU
    We received comments on the consideration of developments in
pollution controls, the averaging time for FCCU PM limits, and the FCCU
opacity limit, as discussed below.
    Comment: One commenter stated that the EPA failed to consider
developments in pollution controls for HAP from FCCUs for two reasons.
First, the commenter contended that cost is not a valid consideration
to evaluate if a ``development'' in pollution control is necessary
pursuant to section 7412(d)(2), (3), (6), unless the EPA is setting a
``beyond-the-floor'' requirement.
    Second, the commenter claimed that the EPA's review of developments
is nearly 10 years old and misses some important pollution control

improvements in the industry. For example, the commenter noted that
Valero Benicia installed a combination of controls in 2012 including a
scrubber, SCR and CO Boiler that combine exhaust streams from the FCCU
and coking and reportedly eliminate HAP emissions entirely from these
sources.
    The commenter also asserted that EPA consent decrees impose lower
effective limits on PM than the EPA considered under the technology
review. The commenter identified the BP Whiting facility as subject to
0.7 lb PM/1,000 lbs coke burn-off at one FCCU and 0.9 lb PM/1,000 lbs
coke burn-off at another and claimed these limits are lower than the
1.0 lb PM/1,000 lbs coke burn-off limit currently mandated by Refinery
MACT 2.
    Response: We disagree that we cannot consider costs when
determining if it is necessary to revise an existing MACT standard
based on developments in practices, processes and control technologies.
The commenter suggests that we cannot consider costs because of the
requirements in CAA section 112(d)(2) and (3) for establishing initial
MACT standards and which do not allow for consideration of costs until
the second, ``beyond the floor'' phase of the analysis. As discussed
previously in this preamble where we respond to comments on the
fenceline monitoring requirements, to the extent that the commenters
are suggesting that EPA must re-perform the MACT floor analysis for
purposes of setting a standard pursuant to section 112(d)(6), we note
that the D.C. Circuit has rejected this argument numerous times, most
recently in National Association for Surface Finishing et al. v. EPA
No. 12-1459 in the U.S. Court of Appeals for the District of Columbia.
    Regarding the claim that the EPA did not consider the types of
controls at the Valero and BP facilities, we disagree. The control
measures for both of those facilities are controls that existed at the
time of the development of the MACT standard. Thus, we did not identify
these technologies as developments in control technologies during the
technology review. However, we did identify developments in processes
or practices that reflect better control by the existing technology and
we reviewed modified emission limits that reflect that better level of
control. The commenter suggested that we failed to consider a level of
zero when the Valero facility was able to achieve zero emissions
through a combined SCR, boiler and scrubber. However, the commenter
provided no information to support such a claim and we are skeptical
that such a result could be achieved. We note that the SCR is designed
specifically to reduce NOX emissions, and would not be
capable of reducing significantly, much less eliminating completely,
HAP emissions. Similarly, based on our long-standing understanding of
the processes, neither a boiler nor a scrubber could achieve such a
result. Regarding the level of emissions achieved at the BP Whiting
facility, we note that we evaluated control systems that can meet 0.5
lb PM/1,000 lb coke burn-off, which is a lower limit than that at BP
Whiting. We determined that these were cost-effective to require for
new units that are installing a new control system. However, we
determined that retrofitting controls designed to meet a PM limit of
1.0 lb PM/1,000 lbs coke burn-off to now meet a limit of 0.5 lb PM/
1,000 lbs coke burn-off was not cost-effective when considering PM and
PM2.5 emissions reductions. We projected the cost of the 0.5
lb PM/1,000 lbs coke burn-off limit in retrofit cases to be $23,000 per
ton PM emissions reduced. To meet a limit of 0.7 lb PM/1,000 lbs coke
burn-off or 0.9 lb PM/1,000 lbs coke burn-off, as is the case for BP
Whiting, the retrofit costs would be similar to this 0.5 lb PM/1,000 lb
coke burn-off option, but the reductions would be even less, resulting
in costs over $23,000 per ton. As metal HAP content of FCCU PM is
approximately 0.1 to 0.2-percent of the total PM, the cost of requiring
this lower limit for existing FCCU is over $10 million per ton of metal
HAP reduced. Therefore, we determined that it is not necessary to
revise the PM standard for existing FCCU sources.
    Comment: Refinery MACT 2 requires the owner or operator to
demonstrate compliance with the PM FCCU limits by complying with the
operating limits established during the performance test on a daily
(i.e., 24-hour) average basis. Several commenters objected to the EPA's
proposal to revise this requirement to a 3-hour averaging time.
Commenters restated EPA's arguments for 3-hour averaging time as: (1)
Daily average could allow FCCUs to exceed limits for short periods
while still complying with the daily average, (2) consistency with NSPS
subpart Ja and (3) consistency with duration of testing. The commenters
stated that the EPA had not provided any data that show that the daily
average could allow FCCUs to exceed limits for short periods and,
therefore, the EPA is using a hypothetical compliance assurance
argument to change emission limits. The commenters stated that a change
in emission limits is not authorized by CAA section 112 because the
emission limitations in Refinery MACT 2 for FCCUs were established as
daily averages following the floor and ample margin of safety
requirements in section 112(d)(2) of the CAA.
    The commenters also state that the EPA's additional arguments for
the change to a 3-hour average are irrelevant and legally deficient.
The commenters stated that the combination of a numerical emission
limit and an averaging period frames the stringency of a limitation and
that a reduction in either of those factors results in a significant
lowering of the operating limit. The commenters conclude that the EPA
has proposed to change the stringency of the requirements without
justification, and the CAA requires that such a change in stringency be
justified pursuant to CAA section 112(d)(6) or (f)(2). The commenters
stated that increasing stringency for consistency with NSPS rules is
not a criterion for a CAA section 112(d)(6) action. Rather that section
requires a change to be due to ``developments.'' The only change in
technology since the 2002 promulgation of Refinery MACT 2 is the
availability of PM continuous emission monitoring system (CEMS), which
is unproven.
    One commenter noted that changing the averaging time is a very
significant modification considering that the compliance limits would
apply for periods of SSM. This commenter stated that it is unlikely
that existing operations can consistently be in compliance with a new
3-hour average since the current daily averaging was put in place to
recognize that there will be periods of operating variability that do
not represent the longer term performance of an FCCU. The commenters
recommended that the EPA retain the daily averaging requirement.
    Response: We disagree with the commenters' statement that reducing
the averaging time from a 24-hour basis to a 3-hour basis for
demonstrating compliance with the FCCU PM emission limit, using
operating limits established during the performance test, is a change
to the MACT floor. The emission limit of 1.0 lb PM/1,000 lbs coke burn-
off is the MACT floor, and we are not changing the PM emissions limit
(or alternate Ni limits) in Table 1 to subpart UUU (except to remove
the incremental PM limit that did not comport with the MACT floor
emissions limitation).
    However, whether or not it is a change from the MACT floor is not
relevant. Pursuant to CAA section 112(d)(6), the EPA must revise MACT
standards ``as necessary'' considering developments in practices,
processes and control technologies. For this

exercise, we considered any of the following to be a ``development'':
     Any add-on control technology or other equipment that was
not identified and considered during development of the original MACT
standards.
     Any improvements in add-on control technology or other
equipment (that were identified and considered during development of
the original MACT standards) that could result in additional emissions
reduction.
     Any work practice or operational procedure that was not
identified or considered during development of the original MACT
standards.
     Any process change or pollution prevention alternative
that could be broadly applied to the industry and that was not
identified or considered during development of the original MACT
standards.
     Any significant changes in the cost (including cost
effectiveness) of applying controls (including controls the EPA
considered during the development of the original MACT standards).
    In determining whether there are ``developments,'' we review, among
other things, EPA regulations promulgated after adoption of the MACT,
such as the NSPS we identified in this instance. We identified the
enhanced monitoring requirements for these operating limits as a
development in practices that will help ensure FCCU owners or operators
are properly operating control devices and, thus, are meeting the PM
emission limit at all times. We further determined that this enhanced
monitoring was cost effective and proposed that it was necessary to
revise the existing standard pursuant to CAA section 112(d)(6).
    While we do not have continuous PM emissions data that show actual
deviations of the PM limit, we do not need such data in order to
conclude that such deviations could occur when daily averages are used.
The Refinery MACT 2 (i.e., subpart UUU) rule requires owners or
operators to establish operating limits based on three 1-hour runs
during the performance test. As a matter of simple mathematics, a
source could demonstrate that it is meeting the operating limit based
on a 24-hour average but could be exceeding the 1.0 lb PM/1,000 lbs
coke burn-off emission limit based on a 24-hour average or for one or
more individual 3-hour periods during that 24-hour average. For
example, an owner or operator could operate with a power input 5-
percent higher than the operating limit for 23 hours, have the ESP off
(zero power) for one hour, and still comply with a 24-hour average
operating limit. However, it would be difficult for this same unit to
meet the 1.0 lb PM/1,000 lbs coke burn-off emissions limit over a 24-
hour period, and it certainly would not meet the limit for every 3-hour
period during that day. As the operating limit can be established to
correspond with 1.0 lb PM/1,000 lbs coke burn-off, the 5-percent higher
power input would likely correspond with a 0.95 lb PM/1,000 lbs coke
burn-off emissions rate (5-percent lower). Uncontrolled emissions are
typically 6 to 8 lbs/1,000 lbs coke burn-off. Thus, this unit would
have emissions averaging approximately 1.2 lbs PM/1,000 lbs coke burn-
off during this 24-hour period [i.e., (0.95*23+7)/24], but would be in
compliance with the 24-hour average operating limit. The unit would
obviously also be out of compliance with the 3-hour average over the
period when the power was turned off. We also have concerns that the
operating limits are not always linear with the emissions, so that the
longer averaging times do not effectively ensure compliance with the PM
emissions limit. Therefore, as proposed, we are finalizing the
requirement for owners or operators to comply with the operating limits
on a 3-hour basis, rather than the 24-hour basis currently in the rule.
    Comment: The technology review for FCCUs resulted in the EPA
proposing to remove the 30-percent opacity alternative limit for
demonstrating compliance with the PM emissions limit that is available
for refineries complying with the Refinery NSPS 40 CFR part 63, subpart
J. Two commenters supported the EPA's proposed removal of the 30-
percent opacity limit for FCCUs. Other commenters stated that current
technology is good enough for a 10- or 20-percent opacity limit. On the
other hand, several commenters stated that the proposed removal of the
30-percent opacity limit must meet the criteria specified in CAA
section 112(d)(6) and (f)(2), which requires analysis of the statutory
basis, environmental impacts, costs, operational and compliance
feasibility and impacts, that the EPA has not conducted. The commenters
claimed that had the EPA conducted a proper analysis, the EPA would
have determined that the proposed change to remove the 30-percent
opacity limit is not necessary or supportable. Additionally, these
commenters stated that since the underlying PM emissions limit is
unchanged, there is no emission reduction justification for this
proposed change, and the change would not meet the CAA section
112(d)(6) requirement of being cost effective. The commenters also
noted that processes or practices for existing FCCUs have not changed,
as required for a CAA section 112(d)(6) revision.
    Several commenters urged the EPA to maintain the 30-percent opacity
limit for these FCCUs. As a practicable and cost-effective alternative
to address the EPA's concern as to whether compliance with a 30-percent
opacity limit ensures compliance with the PM emissions limit,
commenters suggested annual performance tests to confirm that the FCCU
is meeting the PM emissions limit, rather than performance tests every
5 years, as proposed.
    One commenter stated that the EPA never intended for the opacity
limit in Refinery NSPS subpart J to be used to demonstrate compliance
with the PM emissions limit, but instead to assure the PM controls
operate properly. The commenter stated that the EPA's conclusion that
the 30-percent opacity limit may not be sufficiently stringent to
ensure compliance with the underlying PM emissions limit is based on a
false premise as to the purpose of the opacity standard because as the
EPA states, ``Opacity of emissions is indicative of whether control
equipment is properly maintained and operated.''
    Several commenters stated that the proposed elimination of the 30-
percent opacity limit currently in Refinery MACT 2 leaves existing
FCCUs that use cyclones with no viable alternative approach to
demonstrate compliance with the PM emissions limit without adding or
replacing controls. They stated the other approaches for demonstrating
compliance with the PM emissions limit in Refinery MACT 2 (such as
development of a site-specific opacity limit) do not work for them. The
commenters stated that although they believe that more frequent
performance tests would show that the FCCUs are in fact meeting the PM
emissions limit, the absence of the 30-percent opacity limit would
force FCCUs using cyclones for PM control to install additional, costly
PM controls (e.g., ESPs or wet gas scrubbers). They projected that
these additional controls would cost tens of millions of dollars per
FCCU and would require at least 3 years of compliance time.
Additionally, one commenter stated that even FCCUs with additional
downstream PM controls would not be able to achieve a site-specific
limit at all times and needed the availability of the alternative 30-
percent opacity limit. One commenter estimated that installing an ESP
to meet the proposed 10-percent opacity limit would cost approximately
$121,000/ton, assuming a 32 tpy PM emission reduction. The commenter
noted that the ESP would also increase GHG emissions and require more
energy

resources from the facility. The commenter concluded that installing an
ESP is neither cost effective nor appropriate considering non-air
quality environmental and health impacts and energy requirements, and
recommended that the EPA maintain the current NSPS subpart J
alternative limits and add additional alternative limits into Refinery
MACT 2 only as optional limits for demonstrating compliance with the PM
emissions limit.
    Response: In promulgating Refinery MACT 2, the EPA identified the
1.0 lb PM/1,000 lbs coke burn-off limit as the MACT floor but allowed a
compliance option for FCCUs subject to Refinery NSPS subpart J to
comply with an opacity limit up to 30 percent with one 6-minute
allowance to exceed the 30-percent opacity in any 1-hour period. As
stated in the proposal, compliance studies have shown that the 30-
percent opacity limit does not correlate well with the 1.0 lb PM/1,000
lbs coke burn-off limit, and that an FCCU can comply with the 30-
percent opacity limit while its emissions exceed the PM emissions
limit.\9\ Regardless of whether the 30-percent opacity limit in
Refinery NSPS subpart J was designed to ``ensure that the control
device was operated properly,'' Refinery MACT 2 allows sources subject
to NSPS subpart J to use the 30-percent opacity limit to demonstrate
continuous compliance with the PM emissions limit. We have determined
that the 30-percent opacity limit is inadequate for the purpose of
demonstrating continuous compliance with the PM emissions limits in
Refinery MACT 2. As such, we proposed to remove this opacity limit and
require the owner or operator to either demonstrate compliance with the
PM emissions limit by continuously monitoring the control device
parameters established during the performance test or establish and
monitor a site-specific opacity limit. For clarity, we note that we
proposed to allow a site-specific opacity limit, not a 10-percent
opacity limit as some commenters suggest. The site-specific opacity
limit can be significantly higher than 10 percent, but it cannot be
lower than 10 percent.
---------------------------------------------------------------------------

    \9\ Compliance Investigations and Enforcement of Existing Air
Emission Regulations at Region 5 Petroleum Refineries. U.S.
Environmental Protection Agency, Region 5--Air and Radiation,
Chicago, Illinois. March 9, 1998.
---------------------------------------------------------------------------

    While the compliance study indicates that a 30-percent opacity
limit does not correlate well with a 1.0 lb PM/1,000 lbs coke burn-off
emissions limit, further review of this same study indicates that a 20-
percent opacity limit provides a reasonable correlation with units
meeting the 1.0 lb PM/1,000 lbs coke burn-off emissions limit. We also
reviewed the data submitted by the commenters regarding PM emissions
and opacity correlation. While the data suggest that there is
variability and uncertainty in the PM/opacity correlation, the data do
not support that a 30-percent opacity limit would ensure compliance
even when considering the uncertainty associated with the PM/opacity
correlation. Based on the variability of the 3-run average opacity
limits, we determined that, if the 3-hour average opacity exceeded 20-
percent, then it was highly likely (98 to 99-percent confidence) that
the FCCU emissions from the unit tested would exceed the PM emissions
limit.
    After considering the public comments, reviewing the data submitted
with those comments, and further review of the compliance study, in
this final rule we are adding a 20-percent opacity limit, evaluated on
a 3-hour average basis for units subject to NSPS subpart J. As we noted
above, a 20-percent opacity limit provides a reasonable correlation
with the PM emissions limit, and an exceedance of this 20-percent
opacity limit will provide evidence that the PM emissions limit is
exceeded. However, it is possible that units could still exceed the PM
emissions limit while complying with the 20-percent opacity limit, if
those units operate close to the 1 lb PM/1,000 lbs coke burn-off
emissions limit. To address this concern, we considered the commenters'
suggestion to require a performance test annually rather than once
every 5 years. Some commenters suggested that this option specifically
apply to FCCUs with cyclones, but this option is applicable to any
control system operating very near the PM emissions limit and using an
opacity limit to demonstrate continuous compliance. We have determined
that the Refinery NSPS subpart J compliance procedures in Refinery MACT
2, in combination with a 20-percent opacity limit demonstrated on a 3-
hour average basis and with annual performance tests when a test
indicates PM emissions are greater than 80-percent of the limit (i.e.,
0.80 lb PM/1,000 lbs coke burn-off), will ensure continuous compliance
with the PM emissions limit. FCCUs with measured PM emissions during
the performance test at or below 0.80 lb PM/1000 lbs of coke burn-off
will remain subject to the requirement to conduct performance tests
once every 5 years, consistent with the requirements we proposed.
    We do not agree with commenters that the proposed opacity revision
would add significant cost or compliance burden. The control device-
specific monitoring parameters that were proposed rely on parameters
commonly used to control the operation of the control device, so the
monitoring systems should be already available. Further, since we are
merely changing the opacity limit, we expect these units will already
have opacity monitoring systems needed to demonstrate compliance with
the PM emissions limit and would not incur costs for new equipment.
    Comment: Several commenters stated that they agree with the EPA's
determination in the proposal that the current CO limits provide
adequate control of HCN. Two commenters stated that there are limited
HCN emissions data and that more data are needed before the Agency can
appropriately determine whether an HCN standard is necessary and
justified. One commenter noted that the process undertaken by the EPA
to estimate HCN emissions was flawed, and likely overestimates HCN
emissions significantly. Another commenter stated that they performed
HCN stack testing at three refineries and subsequent modeling at two
refineries and concluded that the ambient HCN emissions were well below
the applicable health limits.
    In contrast, some commenters expressed concerns about high HCN
levels. One commenter stated that the EPA should consider re-evaluating
the benefit of low NOX emissions from the FCCU, if that is
indeed the cause of higher HCN emissions, because exposing people to
HCN is not acceptable. The commenter also noted that the community now
also has the increased dangers of storing and transporting aqueous
ammonia, which is used in some cases to achieve low NOX
emissions from the FCCU.
    One commenter stated that the EPA must set stronger HCN standards
on FCCU emissions because of the high release amounts reported, the
fact that non-cancer risk is driven by emissions of HCN from FCCU, and
the fact that the EPA has never set standards for HCN emissions. The
commenter provided a report that they believe shows that the EPA has
not shown that CO is a reasonable or lawful surrogate to control HCN
and has not shown that the conditions necessary for a surrogate are met
with regard to CO and HCN, which is an inorganic nonmetallic HAP.
Further, the report indicates that SCR is a reasonable and cost
effective method for controlling HCN and that the EPA failed to review
and consider other viable methods to control HCN and must do so to
satisfy its legal obligations in this rulemaking.

    Response: At the time we promulgated the MACT, we determined that
the control strategy used by the best performing facilities to reduce
organic HAP emissions was the use of complete combustion, which occurs
when the CO concentration is reduced to 500 ppmv (see the proposal for
Refinery MACT 2 at 63 FR 48899, September 11, 1998). We rejected
arguments that some facilities operate at CO levels well below 500 ppmv
and, thus, the MACT floor should be set at a lower CO concentration
because once CO concentrations reached 500 ppmv, there was no longer a
correlation between reduced CO concentrations and reduced HAP
concentrations. And, in fact, emissions of certain HAP, such as
formaldehyde, tended to increase as CO concentrations were reduced
below 500 ppmv.\10\
---------------------------------------------------------------------------

    \10\ U.S. EPA, 2001. Petroleum Refineries: Catalytic Cracking
Units, Catalytic Reforming Units, and Sulfur Recovery Units--
Background Information for Promulgated Standards and Response to
Comments. Final Report.EPA-453/R-01-011. June. p. 1-19.
---------------------------------------------------------------------------

    In the current rulemaking action, we determined at the time of the
proposed rule that this also holds true for HCN emissions. That is,
once CO emissions are reduced to below 500 ppmv (i.e., complete
combustion is achieved), we no longer see a direct correlation between
CO concentrations and HCN emissions.
    All of the HCN emissions data we have were reported from units
operating at or below the 500 ppmv CO limit (i.e., in the complete
combustion range), so it is not surprising that there is not a strong
correlation between CO and HCN from the FCCU ICR source test data.
However, catalyst vendor data and combustion kinetic theory support the
fact that, in the partial burn mode (with CO concentrations of 2 to 6-
percent, which is 20,000 to 60,000 ppmv), HCN concentrations exiting
the FCCU regenerator are much greater than for units using complete
combustion FCCU regenerators or the concentration exiting a post-
combustion device used in conjunction with a partial burn FCCU
regenerator. Therefore, we maintain that complete combustion is the
primary control needed to achieve controlled levels of HCN emissions.
    We initially thought the higher levels of HCN emissions that were
reported by sources achieving complete combustion might be due to a
switch away from platinum-based combustion promoters to palladium-based
combustion promoters. However, many of the units that were tested and
that had some of the lowest HCN emissions used palladium-based oxygen
promoters. Therefore, it appears unlikely that palladium-based catalyst
promoters are linked to the higher HCN emissions. We also evaluated one
commenter's argument that CO is not a good surrogate for HCN emissions,
but that SCR are a reasonable and cost-effective control strategy. We
are not aware of any data that suggest that an SCR removes HCN and the
commenter did not provide any support for that premise. At proposal, we
evaluated HCN control on units using extra oxygen or converting back to
platinum-based promoters to oxidize any HCN formed. This would cause
more NOX formation, which would then require post-combustion
NOX control, such as an SCR. However, if HCN emissions are
not a function of CO concentration beyond that required to achieve
complete combustion (as noted by the commenter), then more aggressive
combustion conditions and the use of an SCR (to remove the
NOX formed) may not be a viable control strategy. Therefore,
considering all of the data currently available and the comments
received regarding HCN emissions and controls, we maintain that the
only proven control technique is the use of complete combustion as
defined by a CO level of 500 ppmv or less. We are not establishing a
more stringent CO level because, once complete combustion is achieved,
(i.e., CO concentrations drop below 500 ppmv), no further reduction in
HCN emissions are achieved.
    For the purposes of Refinery MACT 2, we consider the emission
limits and operating requirements for organic HAP in Tables 8 through
14 to subpart UUU of part 63 adequate to also limit HCN emissions.
    Finally, we understand concerns about the reported HCN emissions
being higher than anticipated and the need for more data to better
determine HCN emissions levels. To address these concerns, we are
finalizing a requirement that facility owners or operators conduct a
performance test for HCN from all FCCU at the same time they conduct
the first PM performance test on the FCCU following promulgation of
this rule. Facility owners or operators that conducted a performance
test for HCN from a FCCU in response to the refinery ICR or subsequent
to the 2011 Petroleum Refinery ICR following appropriate methods are
not required to retest that FCCU.
4. What is the rationale for our final approach for the technology
review?
a. Refinery MACT 1
    We did not receive substantive comments concerning our proposal
that it was not necessary to revise Refinery MACT 1 requirements for
MPV, gasoline loading racks and cooling towers/heat exchange systems.
Based on the rationale provided in the preamble to the proposed rule,
we are taking final action concluding that it is not necessary pursuant
to CAA section 112(d)(6) to revise the MACT requirements for MPV,
gasoline loading racks and cooling towers/heat exchange systems
emission sources at refineries.
    We proposed that the options for additional wastewater controls are
not cost effective and thus it was not necessary to revise the MACT for
these emission sources. We received public comments suggesting that
emissions from wastewater systems are higher than modeled and that we
should develop additional technology standards for wastewater treatment
systems regardless of cost. As we discussed in the proposal, emissions
from wastewater are difficult to measure and emission estimates rely on
process data and empirical correlations, which introduces uncertainty
into the estimates. Although we do not have evidence, based on the
process data we collected, that emissions are higher than modeled at
proposal, we note that the fenceline monitoring program effectively
ensures that wastewater emissions are not significantly greater than
those included in the emissions inventory and modeled in the risk
assessment. Furthermore, we believe that cost is a valid consideration
in determining whether it is necessary within the meaning of section
112(d)(6) to revise requirements and that we are not required to
establish additional controls regardless of cost. Consequently, we
conclude that it is not necessary to revise the Refinery MACT 1
requirements for wastewater systems pursuant to CAA section 112(d)(6).
    For storage vessels, we identified a number of options, including
requiring tank fitting controls for external and internal floating roof
tanks, controlling smaller tanks with lower vapor pressures and
requiring additional monitoring to prevent roof landings, liquid level
overfills and to identify leaking vents as developments in practices,
processes and control technology. We proposed to cross-reference the
storage vessel requirements in the Generic MACT (effectively requiring
additional control for tank roof fittings) and to revise the

definition of Group 1 storage vessels to include smaller tanks with
lower vapor pressures. We received comments that we could have required
additional controls on tanks and monitoring for landings, overfills and
leaking vents described above. We also received comments related to
clarifications of specific rule references and overlap provisions. We
addressed these comments in the ``Response to Comments'' document, and
we maintain that the additional control options described by the
commenters (tank roof landing/degassing requirements or use of geodesic
domes to retrofit external floating roofs) are not cost-effective.
Consequently, based on the rationale provided in the preamble to the
proposed rule and our consideration of public comments, we are
finalizing the requirements as proposed with minor clarifications of
the rule references. However, as with wastewater systems, we note that
the fenceline monitoring program will ensure that the owner or operator
is effectively managing fugitive emissions sources and should detect
landings, overfills, and leaking vents.
    For equipment leaks, we identified specific developments in
practices, processes and control technologies that included requiring
repair of leaking components at lower leak definitions, requiring
monitoring of connectors, and allowing the use of the optical imaging
camera as an alternative method of monitoring for leaks. We proposed to
establish an alternative method for refineries to meet LDAR
requirements in Refinery MACT 1. This alternative would allow
refineries to monitor for leaks via optical gas imaging in place of EPA
Method 21, using monitoring requirements to be specified in a not yet
proposed appendix K to 40 CFR part 60. However, the development of
appendix K is taking longer than anticipated. Therefore, we are not
finalizing this alternative monitoring method in Refinery MACT 1.
    We received comments suggesting that additional requirements be
imposed to further reduce emissions from leaking equipment components,
such as requiring ``leakless'' equipment, reducing the leak threshold,
and eliminating delay of repair provisions. As provided in the
``Response to Comments'' document, we do not agree that these
additional requirements are cost-effective. Based on the rationale
provided in the preamble to the proposed rule and our consideration of
public comments, we conclude that it is not necessary to revise the
Refinery MACT 1 requirements for equipment leaks. Again, however, the
fenceline monitoring program is intended to ensure that large leaks
from fugitive emissions sources, including equipment leaks, are more
quickly identified and repaired, thereby helping to reduce emissions
from leaking equipment components.
    For marine vessel loading, we identified control of marine vessel
loading operations with HAP emissions of less than 10/25 tpy and the
use of lean oil absorption systems as developments that we considered
in the technology review. We proposed to amend 40 CFR part 63, subpart
Y to require small marine vessel loading operations (i.e., operations
with HAP emissions less than 10/25 tpy) and offshore marine vessel
loading operations to use submerged filling based on the cargo filling
line requirements in 46 CFR 153.282. We received comments that other
options considered during the technology review of the standard were
cost-effective for small marine vessel loading operations and should be
required. As provided in the ``Response to Comments,'' we continue to
believe those other controls are not cost-effective because of the high
costs of controls for limited additional organic HAP emission
reduction. Therefore, we are finalizing these amendments as proposed.
    Finally, we proposed that it was necessary to revise the MACT to
require fenceline monitoring as a means to manage fugitive emissions
from the entire petroleum refinery, which includes sources such as
wastewater collection and treatment operations, equipment leaks and
storage vessels. We received numerous comments regarding the proposed
requirement to conduct fenceline monitoring, many of which we address
above and the remainder of which we respond to in the ``Response to
Comments'' document. After considering comments, we maintain that the
proposed work practice standard is authorized under section 112 of the
CAA and will improve fugitive management at the refinery. Therefore, we
are finalizing the key components of fenceline monitoring work practice
as proposed. These requirements include the use of passive diffusive
tube samplers (although we are providing a mechanism to request
approval for alternative monitoring systems provided certain criteria
are met), the 9 [mu]g/m3 on a rolling annual average basis
action level, and the need to perform corrective action to comply with
the action level.
    Based on public comments received, we are making numerous revisions
to clarify the fenceline monitor siting requirements. This includes
provisions to allow siting of monitors within the property boundary as
long as all emissions sources at the refinery are included within the
monitoring perimeter. We are also clarifying that we do not consider
public roads or public waterways that bisect a refinery to be property
boundaries, and owners or operators do not need to place monitors along
the internal public right-of-ways. We are also providing provisions to
allow fixed placement of monitors at 500 feet intervals (with a minimum
of 3 monitors) for subareas or segregated areas. If an emissions source
is near the monitoring perimeter, an additional monitor siting
requirement would still apply. The 500 feet provision is provided to
reduce burden for facilities with irregular shapes or noncontiguous
property areas that we did not fully consider at proposal.
    We also received comments on the compliance time and reporting
requirements associated with the fenceline monitoring provisions. Upon
consideration of public comments, we have revised the compliance period
to 2 years after the effective date of the final rule. Thus, beginning
no later than 2 years after the effective date of the rule, the source
must have a fenceline monitoring system that is collecting samples such
that the first rolling annual average [Delta]C value would be completed
no later than 3 years after the effective date of the final rule.
Facilities will have 45 days after the completion of the first year of
sampling, as proposed, to submit the initial data set. We are reducing
the proposed compliance period from 3 years to 2 years because the
passive diffusive tube monitors are easy to deploy and pilot study
demonstrations indicate that significant time is not needed to deploy
the monitors. However, the reduced compliance period still provides
time to resolve site-specific monitor placement issues and to provide
time to develop and implement a site-specific monitoring plan, if
needed. We are increasing the fenceline monitoring reporting frequency
(after the first year of data collection) from semiannually to
quarterly to provide more timely dissemination of the data collected
via this monitoring program.
b. Refinery MACT 2
    We proposed to revise Refinery MACT 2 to incorporate the
developments in monitoring practices and control technologies reflected
in the Refinery NSPS subpart Ja limits and monitoring provisions (73 FR
35838, June 24, 2008). We are finalizing most of these provisions as
proposed. Specifically, we are incorporating the

Refinery NSPS subpart Ja PM limit for new FCCU sources. We are also
finalizing compliance options for FCCU that are not subject to Refinery
NSPS subpart J or Ja. These options would allow such sources to elect
to comply with the Refinery NSPS subpart Ja monitoring provisions to
demonstrate compliance with the emissions PM limit. We are revising the
averaging period for the control device operating limits or site-
specific opacity limits to be on a 3-hour average basis in order to
more directly link the operating limit to the duration of the
performance test runs, on which they are based, as proposed. We are
incorporating additional control device-specific monitoring
alternatives for various control devices on FCCU, including BLD
monitoring as an option to COMS for owners or operators of FCCU using
fabric filter-type control systems and total power and secondary
current operating limits for owners or operators of ESPs. We are adding
an additional requirement to perform daily checks of the air or water
pressure to atomizing spray nozzles for owners or operators of FCCU wet
gas scrubbers not subject to the pressure drop operating limit, as
proposed. Finally, we finalizing requirements to conduct a performance
test at least once every 5 years for all FCCU, as proposed. These
requirements are being finalized to ensure that control devices are
continuously operated in a manner similar to the operating conditions
of the performance test and to ensure that the emissions limits, which
are assessed based on the results of three 1-hour test runs, are
achieved at all times.
    We also proposed to eliminate the Refinery NSPS subpart J
compliance option that allows refineries to meet the 30-percent opacity
emissions limit requirement and revise the MACT to include control
device operating limits or site-specific opacity limits identical to
those required in Refinery NSPS subpart Ja. We received numerous
comments, particularly from owners or operators of FCCU that employ
tertiary cyclones to control FCCU PM emissions. According to the
commenters, opacity is not a direct indicator of PM emissions because
finer particles will increase opacity readings without a corresponding
mass increase in PM emissions. Additionally, the commenters stated that
the site-specific opacity limit generally leads to a site-specific
operating limit of 10-percent opacity, which is too stringent and does
not adequately account for variability between PM emissions and opacity
readings. According to the commenters, FCCU with tertiary cyclones
would need to be retrofitted with expensive and costly controls in
order to meet the 10-percent opacity limit, even though they are
meeting the 1 lb/1000 lbs coke burn PM emissions limit. It was not our
intent to require units to retrofit their controls simply to meet the
site-specific opacity limit. However, the existing 30-percent opacity
limit in the subpart J compliance option is not adequate to ensure
compliance with the PM emissions limit at all times. After reviewing
the public comments and available data, we determined that, rather than
removing the subpart J compliance option altogether, it is sufficient
to add an opacity operating limit of 20-percent opacity determined on a
3-hour average basis to the existing subpart J compliance option and to
require units complying with this operating limit to conduct annual
performance tests (rather than one every 5 years) when the PM emissions
measured during the source test are greater than 0.80 lb PM/1,000 lbs
coke burn-off. These provisions improve assurance that these units are,
in fact, achieving the required PM emissions limitation without
requiring units to retrofit controls due to variability in the
correlation of PM emissions and opacity.
    We did not propose to revise the organic HAP emissions limits for
FCCU to further address HCN emissions. We received numerous comments on
this issue. We continue to believe that complete combustion is the
appropriate control needed to control HCN emissions. Consequently, for
the purposes of Refinery MACT 2, we are not changing the MACT standards
to further reduce emissions of HCN. However, we understand that there
are uncertainties and high variability in HCN emissions measured from
FCCU. In order to address the need for more data to better characterize
HCN emissions levels, we are finalizing a requirement for refinery
owners or operators to conduct a performance test for HCN from all FCCU
(except those units that were tested previously using acceptable
methods as outlined in the 2011 Refinery ICR) during the first PM test
required as part of the on-going compliance requirements for FCCU metal
HAP emissions. These data will be useful to the EPA in understanding
HCN emissions from FCU and may help to inform future regulatory reviews
for this source category.
    We proposed that there have been no developments in practices,
processes, and control technologies for CRU based on our technology
review and that therefore it is not necessary to revise these
standards. Based on the rationale provided in the preamble to the
proposed rule and our consideration of public comments, we are
finalizing our conclusion.
    For SRU, we identified the Refinery NSPS subpart Ja allowance for
oxygen-enriched air as a development in practice and we proposed that
it was necessary to revise the MACT to allow SRU to comply with
Refinery subpart Ja as a means of complying with Refinery MACT 2. The
key issue identified by commenters was that Refinery NSPS subpart Ja
includes a flow monitoring alternative for determining the average
oxygen concentration in the enriched air stream and that this was not
included in the proposed amendments to Refinery MACT 2. This was an
oversight on our part. We are, based on the rationale provided in the
preamble to the proposed rule and our consideration of public comments,
finalizing the SRU revisions as proposed but with inclusion of the flow
monitoring alternative provisions that are in Refinery NSPS subpart Ja
for this source.

C. Refinery MACT Amendments Pursuant to CAA Section 112(d)(2) and
(d)(3)

1. What did we propose pursuant to CAA section 112(d)(2) and (d)(3) for
the Petroleum Refinery source categories?
    We proposed the following revisions to the Refinery MACT 1 and 2
standards pursuant to CAA section 112(d)(2) and (3) \11\: (1) Adding
MACT standards for DCU decoking operations; (2) revising the CRU purge
vent pressure exemption; (3) adding operational requirements for flares
used as APCD in Refinery MACT 1 and 2; and (4) adding requirements and
clarifications for vent control bypasses in Refinery MACT 1.
---------------------------------------------------------------------------

    \11\ The EPA has authority under CAA section 112(d)(2) and
(d)(3) to set MACT standards for previously unregulated emission
points. EPA also retains the discretion to revise a MACT standard
under the authority of section 112(d)(2) and (3), see Portland
Cement Ass'n v. EPA, 665 F.3d 177, 189 (D.C. Cir. 2011), such as
when it identifies an error in the original standard. See also
Medical Waste Institute v. EPA, 645 F. 3d at 426 (upholding EPA
action establishing MACT floors, based on post-compliance data, when
originally-established floors were improperly established).
---------------------------------------------------------------------------

    For DCU, we proposed to require that prior to venting or draining,
each coke drum must be depressured to a closed blowdown system until
the coke drum vessel pressure is 2 psig or less. As proposed, the 2
psig limit would apply to each vessel opening/venting/draining event at
new or existing affected DCU facilities.
    For the CRU, we proposed to require that any emissions during the
active

purging or depressuring of CRU vessels meet the applicable organic HAP
emission limitations in Tables 15 and 16 to subpart UUU regardless of
the vessel pressure.
    For flares, we proposed to remove cross references to the General
Provisions requirements for flares used as control devices at 40 CFR
63.11(b) and to incorporate enhanced flare operational requirements
directly into the Refinery MACT rules. The proposed rule amendments
included:
     A ban on flaring of halogenated vent streams.
     A requirement to operate with continuously lit pilot
flames at all times and to equip the pilot system with an automated
device to relight the pilot if it is extinguished.
     A requirement to operate with no visible emissions except
for periods not to exceed a total of 5 minutes during any 2 consecutive
hours and to monitor for visible emissions daily.
     A requirement to operate with the flare tip velocity less
than 60-feet-per-second or the velocity limit calculated by an equation
provided in the proposed rule.
     A requirement to meet one of three combustion zone gas
properties operating limits based on the net heating value, lower
flammability limit, or combustion concentration. Owners or operators
could elect to comply with any one of the three limits at any time. Two
separate sets of operating limits were proposed: One for gas streams
not meeting all three ``hydrogen-olefin interaction criteria''
specified in the rule and a more stringent set of limits for gas
streams meeting all three hydrogen-olefin interaction criteria. The
combustion zone net heating value considered steam assist rates but not
``perimeter air'' assist rates.
     For air-assisted flares, a requirement to meet an
additional ``dilution parameter'' operating limit determined based on
the combustion zone net heating values above, the diameter of the flare
and the perimeter air assist rates.
    The proposed amendments for flares also included detailed
monitoring requirements to determine these operating parameters either
through continuous parameter monitoring systems or grab sampling,
detailed calculation instructions for determining these parameters on a
15-minute block average, and detailed recordkeeping and reporting
requirements. We also proposed provisions to allow owners or operators
to request alternative emissions limitations that would apply in place
of the proposed operating limits.
    We proposed to revise the definition of MPV to remove the current
exclusion for in situ sampling systems (onstream analyzers). We also
proposed to limit the exclusion for gaseous streams routed to a fuel
gas system to apply only to those systems for which any flares
receiving gas from the fuel gas system are in compliance with the
proposed flare monitoring and operating limits. We note that we also
proposed revisions related to monitoring of bypass lines, but these
revisions were proposed to address concerns related to SSM releases and
are described in further detail in section IV.D. of this preamble.
    We proposed that emissions of HAP may not be discharged to the
atmosphere from PRD in organic HAP service to address concerns related
to SSM releases. To ensure compliance with this proposed amendment, we
proposed to require that sources monitor PRD using a system that is
capable of identifying and recording the time and duration of each
pressure release and of notifying operators that a pressure release has
occurred. This proposed requirement was addressed in section IV.A.4. of
the preamble for the proposal.
2. How did the revisions pursuant to CAA section 112(d)(2) and (3)
change since proposal?
    We proposed identical standards for existing and new DCU decoking
operations, but we are finalizing standards for new and existing
sources that are not identical. We are finalizing provisions that will
require owners or operators of existing DCU sources to comply with a 2
psig limit averaged over 60 cycles (i.e., 60 venting events), rather
than meet the 2 psig limit on a per venting event basis, as proposed.
We are finalizing provisions that will require owners or operators of
new DCU sources to comply with a 2.0 psig limit on a per event, not-to-
exceed basis. We are adding one significant digit to the limit for new
DCU affected sources because our re-review of permit requirements
conducted in response to comments identified that the best performing
DCU source is required to comply with a 2.0 psig limit on a per event
basis. In response to comments regarding the proposed prohibition on
draining prior to achieving the pressure limit, we are finalizing
specific provisions for DCU with water overflow design and for double
quenching.
    For flares, we are not finalizing the ban that we proposed on
halogenated vent streams and we are not finalizing the proposed
requirement to equip the flare pilot system with an automated device to
relight an extinguished pilot.
    We are revising the MACT to include the proposed no visible
emissions limit and the flare tip velocity limit as direct emissions
limits only when the flare vent gas flow rate is below the smokeless
capacity of the flare. Under the revised standard, when the flare is
operating above the smokeless capacity, an exceedance of the no visible
emission limit and/or flare tip velocity limit is not a violation of
the standard but instead triggers a work practice standard. Flares
operate above the smokeless capacity only when there is an emergency
release event and thus the work practice standard is intended to
address emissions during such emergency release events. (See section
IV.D. of this preamble for more details regarding this work practice
standard). We are also adding provisions that would allow sources to
use video surveillance of the flare as an alternative to daily Method
22 visible emissions observations.
    For flares, we are also simplifying the combustion zone gas
property operating limits by finalizing a requirement only for the net
heating value of the combustion zone gas. We are finalizing
requirements that flares meet a minimum operating limit of 270 BTU/scf
NHVcz on a 15-minute average, as proposed, and we are allowing refinery
owners or operators to use a corrected heat content of 1212 BTU/scf for
hydrogen to demonstrate compliance with this operating limit. We are
not finalizing separate combustion zone operating limits for gases
meeting the hydrogen-olefin interaction criteria that were proposed. We
are also not finalizing the alternative combustion zone operating
limits based on lower flammability limit or combustibles concentration.
    We are finalizing ``dilution parameter'' requirements for air-
assisted flares, but we are providing a limit only for the net heating
value dilution parameter. Similar to the requirements we are finalizing
for the combustion zone parameters, we are finalizing requirements that
flares meet a minimum operating limit of 22 BTU/ft2
NHVdil on a 15-minute average, as proposed, and we are
allowing refinery owners or operators to use a corrected heat content
of 1,212 BTU/scf for hydrogen to demonstrate compliance with this
operating limit. We are not finalizing separate dilution parameter
operating limits for gases meeting the hydrogen-olefin interaction
criteria that were proposed. We are also not finalizing the alternative
dilution parameter operating limits based on lower flammability limit
or combustibles concentration.

    We are providing an alternative to use initial sampling period and
process knowledge for flares in dedicated service as an alternative to
continuous or on-going grab sample requirements for determining waste
gas net heat content.
    We are finalizing revisions to the definition of MPV, as proposed.
    We are establishing work practice standards that apply to PRD
releases in place of the proposed prohibition on PRD releases to the
atmosphere. The work practice standards that we are finalizing for PRD
require refiners to establish proactive, preventative measures for each
PRD to identify and correct direct releases of HAP to the atmosphere as
a result of pressure release events. Over time, these proactive
measures will reduce the occurrence of releases and the magnitude of
releases when they occur, while avoiding the environmental disbenefits
of having additional flare capacity on standby to control these
unpredictable and infrequent events. Refinery owners or operators will
be required to perform a root cause analysis/corrective action
following such pressure release events. In addition, a second release
event in a 3-year period from the same PRD with the same root cause on
the same equipment is a deviation of the work practice standard. A
third release event in a 3-year period from the same PRD is a deviation
of the work practice standard regardless of the root cause. PRD release
events related to force majeure events are not considered in these hard
limits.
3. What key comments did we receive on the proposed revisions pursuant
to CAA section 112(d)(2) and (3) and what are our responses?
i. DCU
    Comment: Several commenters argued that the EPA incorrectly set the
MACT floor emission limitation for DCU. Commenters noted that CAA
section 112(d)(3)(A) states that the MACT limit for existing sources
``shall not be less stringent, and may be more stringent than the
average emission limitation achieved by the best performing 12-percent
of the existing sources'' excluding those first achieving that level
within 18 months prior to proposal or 30 months prior to promulgation,
whichever is later. According to the commenters, the EPA failed to
follow this procedure in setting the 2 psig vent limit as a MACT floor
because the EPA incorrectly considered permit limits and other non-
performance based criteria instead of basing the MACT floor on the
actual performance of sources. Commenters stated that the EPA
improperly considered permit limits that should have been excluded from
consideration, as well as considering permit limits for closed
facilities instead of using more accurate data from operating DCUs at
sources that submitted actual emissions data. Specifically, commenters
stated that the DCU at the non-operational plant (Hovensa) should not
be included. One commenter noted that they operate one of the South
Coast DCU listed as subject to a 2 psig limit and asserted that it does
not currently meet that emission limitation. The commenter claimed that
significant capital investment would be required in order for the DCU
to comply with the 2 psig limit. According to one commenter, data for
six of the eight DCU they claim the EPA considered for the MACT floor
should not be counted in determining the limit that represents the
average emission limitation actually achieved 18 months prior to the
proposal.
    Response: CAA section 112(d)(3)(A) states that the existing source
standard shall not be less stringent than the average emission
limitation achieved by the best performing 12-percent of the existing
sources (for which the Administrator has emissions information),
excluding those sources that have, within 18 months before the emission
standard is proposed or within 30 months before such standard is
promulgated, whichever is later, first achieved a level of emission
rate or emission reduction which complies, or would comply if the
source is not subject to such standard, with the lowest achievable
emission rate (as defined by section 171) applicable to the source
category and prevailing at the time, in the category or subcategory for
categories and subcategories with 30 or more sources. We consider a 2
psig emissions limitation to be equivalent to the lowest achievable
emission rate (LAER) emission limits. Thus, we agree with the commenter
that sources that first meet the 2 psig limit on or after December 30,
2012, should be excluded from the MACT floor analysis. We also agree
that under CAA section 112(d)(3)(A), the MACT floor analysis focuses on
those sources that are achieving the emission limit (i.e., the emission
limitation ``achieved by . . . ''). The EPA has previously determined
that the 6th-percentile unit is a reasonable estimate of the average
emission limitation achieved by the best performing 12-percent of
sources especially when averaging across units with and without control
requirements. As noted in our DCU MACT floor analysis memorandum
(Docket ID No. EPA-HQ-OAR-2010-0682-0203), the 6th-percentile is
represented by the fifth-best performing DCU. If we exclude the two
South Coast refineries and the two Marathon Garyville DCU because these
sources were not implementing the 2 psig permit limit prior to December
30, 2012, the fifth-best performing DCU would be represented by the Bay
Area refineries (4.6 psig). However, based on the 2011 Petroleum
Refinery ICR responses, 25 out of 75 (33-percent) DCU have a ``typical
coke drum pressure when first vented to the atmosphere'' of 2 psig or
less and 10 out of 75 (13-percent) DCU have a ``typical coke drum
pressure when first vented to the atmosphere'' of 1 psig or less. While
we acknowledge that these data represent ``typical'' operations and not
necessarily a never-to-be-exceeded emissions limitation, we conclude
that this information is sufficient for us to conclude that the average
emission limitation achieved by the best performing 12-percent of
sources is consistent with a 2 psig emissions limitation. This is
because facility owners or operators commonly target to operate at
approximately half the allowable emissions limit to ensure that they
can comply with the emissions limit at all times. Therefore, we
maintain that an average venting pressure of 2 psig is the MACT floor
level for decoking operation at existing sources based on the ICR
responses and considering the average performance expected.
    Comment: Four commenters suggested that the 2 psig limit, if
finalized, should be based on a rolling 30-day average per DCU rather
than a never to be exceeded ``instantaneous'' standard. According to
the commenters, an instantaneous standard is unnecessary to address
HAPs with chronic health impacts and adds cost and compliance
challenges. According to the commenters, chronic health impacts are not
materially affected by short-term variability, but instead depend on
the average concentration of exposure over a 70-year lifetime;
therefore, there is no health based or environmental reason for
requiring an instantaneous limit. The commenters noted that there would
be additional capital costs to comply with a 2 psig not-to-be-exceeded
limit compared to a 30-day average 2 psig limit vent pressure. One
commenter specifically requested that the EPA also confirm that a
pressure of 2.4 psig is compliant with the 2 psig limit vent pressure.
Another commenter also requested clarification that the vent pressure
can be rounded to

one significant figure when determining compliance.
    Response: For new sources, the MACT floor emission limit for DCU is
based on the best-performing source. Based on this and other comments
received, we again reviewed existing permit conditions. Based on this
review, we found that one of the permit requirements specified the
pressure limit as 2.0 psig for each coke drum venting event. Therefore,
we are finalizing the new source MACT floor as 2.0 psig on a per coke
drum venting event basis.
    As discussed in response to the previous comment, we are basing the
MACT floor for existing source DCU on responses we received from the
2011 Petroleum Refinery ICR. Because the ICR requested the ``typical
coke drum pressure when first vented to the atmosphere,'' we do not
consider the information provided in ICR responses to reflect a
``never-to-be-exceeded'' limit. Therefore, we evaluated whether it is
reasonable to allow averaging, and if so, what averaging period should
be provided.
    Health risks are not considered in establishing MACT requirements,
so we do not consider the argument that chronic effects are evaluated
over a 70-year period to be relevant to a determination of the MACT
floor. However, a primary consideration regarding averaging periods is
how the averaging period was considered in setting the floor and
whether the intended reductions will occur under a different averaging
period. According to the heat balance method for estimating DCU
emissions, DCU decoking operations emissions are directly proportional
to the average bed temperature. While the relationship is not exactly
linear, the average bed temperature is expected to be a function of the
venting pressure. Moreover, the shape of the pressure-temperature
correlation curve is such that the emissions at 6 psig are almost
exactly but not quite three times the emissions at 2 psig. Given the
expected linearity of the emissions with venting pressures, we are not
concerned with an occasional venting event above 2 psig because the
average emissions from a facility meeting an average 2 psig pressure
limit would be identical to the emissions achieved by a facility that
vented each time at 2 psig. That is, given the expected linearity in
the projected DCU emissions to the venting pressure, we conclude that
it is reasonable to allow averaging across events and that the precise
averaging period is not a critical concern.
    Most industry commenters requested a 30-day average. However,
different facilities have different numbers of DCU, different numbers
of drums per DCU and different cycle times. Consequently, basing the
averaging period across a given time period would result in
significantly different number of venting events included in a 30-day
average for different facilities and generally provide more flexibility
to larger refineries and less flexibility to smaller refineries. Based
on the ICR responses, almost half of all DCU operate with two drums and
about 90-percent of DCU have two to four coke drums; however, a few DCU
have six or even eight drums. Also, based on the ICR responses, the
average complete coke drum cycle time is 32 hours, but can be as short
as 18 hours and as long as 48 hours. Reviewing the ICR responses, we
found that a 30-day average would include 30 events for some facilities
and more than 250 events at other facilities.
    Since the existing source MACT standards apply ``in combination''
to ``all releases associated with decoking operations'' at a given
facility, we determined that it was reasonable to consider an averaging
period that applies to the number of venting events from all coke drums
at the facility rather than to all coke drums for a specific DCU for a
specified period of time. This provides a more consistent basis for the
averaging period and allows the same operational flexibility for small
refineries as large refineries. Based on the ICR responses, the median
(typical) DCU has 60 venting events in a 30-day period. Providing an
averaging period of 60 venting events provides a more consistent
averaging basis for all facilities, regardless of the number of DCU at
the facility and the number of drums and cycle times for different DCU.
Additionally, it eliminates issues with respect to how to handle
operating days versus non-operating days, e.g., in the event of a turn-
around resulting in a limited number of venting events in a 30-calendar
day period. Therefore, we are establishing a 2 psig limit based on a
60-event average considering all coke drum venting events at an
existing source and we are finalizing a 2.0 psig limit on a per coke
drum venting event for DCU at new sources.
    We have consistently maintained our policy to round to the last
digit provided in the emission limit, a pressure of 2.4 psig would
round to 2 psig and would be compliant with a requirement to depressure
each coke drum to a closed blowdown system until the coke drum vessel
pressure is 2 psig or less, but it would not be compliant with the
revised new source provision to depressure until the coke drum vessel
pressure is 2.0 psig or less. A coke drum pressure of 2.04, however,
would be compliant with the revised new source requirement pressure
limit of 2.0 psig.
ii. Refinery Flares
    Comment: Several commenters suggested that the proposed flare
operating limits were too complex. The commenters recommended that the
EPA eliminate the dual flare combustion zone heat content limits
related to the proposed hydrogen-olefin interaction criteria and
instead finalize a single combustion zone net heating value of
approximately 200 BTU/scf, which would minimize the unnecessary burning
of supplemental gas but still ensure good combustion efficiency.
    A few commenters suggested that the EPA based the proposed
combustion zone limits on an invalid data analysis, that the 1 minute
PFTIR data should not be used to establish combustion efficiency
correlations, and that the emission limits should be set so as to
provide an equal chance of false positives and negatives. A few
commenters suggested that the EPA should assign hydrogen a heating
value of 1,212 BTU/scf to more accurately reflect its flammability in a
NHV basis and that doing so is consistent with some recent flare
consent decrees and would help reduce natural gas supplementation for
facilities complying only with the NHVcz metric.
    Several commenters suggested that neither scientific literature nor
the available flare test data support the EPA's claim of an adverse
hydrogen-olefin interaction on combustion efficiency and that the EPA
should not finalize the more restrictive combustion zone operating
limits for all flare types. These commenters suggested that the EPA did
not provide any evidence the assumed hydrogen-olefin effect actually
exists; that statistical analysis demonstrates the EPA developed their
limit based on random differences in data; that the PFTIR data analysis
method of using the individual minute-by-minute data instead of the
test average data is flawed and leads to invalid conclusions; and that
proper analysis of the data demonstrates the more stringent operating
limits for hydrogen-olefin conditions cannot be supported.
    Some commenters suggested that there is evidence to support more
stringent flare combustion zone limits for a narrowly defined high
concentration propylene-only condition as outlined in some of the
recent flare

consent decrees but that the flare test data do not support more
stringent operating limits for the proposed hydrogen-olefins criteria
by the EPA. Additionally, one commenter suggested that if the EPA
decides to proceed with the more restrictive combustion zone limits for
the hydrogen-olefins interaction cases then the final rule should not
expand beyond an interaction between hydrogen and propylene.
    Several commenters suggested that the proposed 15-minute feed
forward averaging time for flares (e.g., combustion zone parameters,
air-assist dilution parameters and associated flow rates) is arbitrary,
unrealistic and unworkable and that the feed forward compliance
determination should not be finalized and, if it is finalized, the
averaging time should be extended to 1-hour, 3-hour, or 24-hour. To
support these suggested averaging periods, commenters claimed that
typical standards for combustion devices are averaged over these
suggested timeframes, noting as an example, recent refinery flare
consent decrees that contain a 3-hour average. The commenters also
asserted that both a GC and calorimeter will be needed to obtain data
rapidly enough to try and maintain a 15-minute average; that the feed
forward approach requires calculation artifices to attempt to correct
for the fact that compliance cannot be determined until the averaging
period is over; and that a longer averaging time is needed for
instrument and control response time.
    Response: In addressing these comments, we further analyzed the
flare emissions test data. First, to address concerns that the minute-
by-minute analysis produced flawed results, we re-compiled the data
into approximate ``15-minute averages'' to the extent practical based
on the duration of a given test run (e.g., a 10-minute run was used as
1 run and a 32-minute run was divided into 2 runs of 16 minutes each).
We do not find significant differences in the data or that different
conclusions would be drawn from the data based on this approach as
compared with the minute-by-minute analysis used for the proposed rule.
    Next, we evaluated the 15-minute run data using the normal net
heating value for hydrogen of 274 Btu/scf, which is the value we used
in the analysis for the proposed rule and also evaluated the data using
the 1,212 Btu/scf, the value recommended by some commenters. The 1,212
Btu/scf value is based on a comparison between the lower flammability
limit and net heating value of hydrogen compared to light organic
compounds and has been used in several consent decrees to which the EPA
is a party. Based on our analysis, we determined that using a 1,212
Btu/scf value for hydrogen greatly improves the correlation between
combustion efficiency and the combustion zone net heating value over
the entire array of data. Using the net heating value of 1,212 Btu/scf
for hydrogen also greatly reduced the number of ``type 2 failures''
(instances when the combustion efficiency is high, but the gas does not
meet the NHVcz limit). One of the primary motivations for the proposed
approach to provide alternative limits based on lower flammability
limits and combustibles concentrations was to reduce these type 2
failures. Therefore, we proposed all three of these parameters (i.e.,
NHVcz, LFL and total combustibles) and allowed flare owners or
operators to comply with any of the parameter limits at any time. When
using the net heating value of 1,212 Btu/scf for hydrogen, the other
two alternatives no longer provide any improvement in the ability to
predict good flare performance. Consequently, we are simplifying the
operating limits to use only NHVcz.
    Next, we re-evaluated whether to finalize the proposed dual
combustion zone operating limits for refinery flares that met certain
hydrogen-olefins interactions or to finalize a single combustion zone
net heating value limit. The newly re-compiled PFTIR run average flare
dataset suggests that higher operating limits may be appropriate for
some olefin-hydrogen mixtures. However, the dataset using 15-minute
test average runs is much smaller than the set using 1-minute runs and
thus creates a greater level of uncertainty. In addition, we cannot
definitively conclude that a dual combustion zone limit for refinery
flares meeting certain hydrogen-olefins interactions is appropriate
given these uncertainties. Thus, in order to minimize these
uncertainties and streamline the compliance requirements, we used all
of the 15-minute test run average data together as a single dataset in
an effort to determine an appropriate, singular combustion zone net
heating value operational limit.
    Finally, we conducted a Monte Carlo analysis to help assess the
impacts of extending the averaging time on the test average flare
dataset of 15-minute runs to 1-hour or 3-hour averaging time
alternatives. While we consider it reasonable to provide a longer
averaging time for logistical reasons, the Monte Carlo analysis
demonstrated, consistent with concerns described in our proposal, that
short periods of poor performance can dramatically limit the ability of
a flare to achieve the desired control efficiency. Consequently, we
find it necessary to finalize the proposed 15-minute averaging period
to ensure that the 98-percent control efficiency for flares is achieved
at all times. However, we understand that flare vent gas flow and
composition are variable. While a short averaging time is needed to
ensure adequate control given this variability, we also understand the
complications that this variability places on flare process control in
efforts to meet the NHVcz limit. Therefore, we are clarifying that the
270 Btu/scf NHVcz value is an operational limit that must be calculated
according to the requirements in this rule. We also clarify that
compliance with this operational limit must be evaluated using the
equations and calculation methods provided in the rule. We proposed a
feed forward calculation method to allow refinery owners or operators a
means by which to adjust steam (or air) and, if necessary, supplemental
natural gas flow, in order to meet the limit. In other words, ``feed
forward'' refers to the fact that the rule requires the refinery owners
or operators to use the net heating value of the vent gas (NHVvg) going
into the flare in one 15-minute period to adjust the assist media
(i.e., steam or air) and/or the supplemental gas in the next 15-minute
period, as necessary for the equation in the rule to calculate an NHVcz
limit of 270 BTU/scf or greater. We recognize that when a subsequent
measurement value is determined, the instantaneous NHVcz based on that
compositional analysis and the flow rates that exist at the time may
not be above 270 Btu/scf. We clarify that this is not a deviation of
the operating limit. Rather, the owner or operator is only required to
make operational adjustments based on that information to achieve, at a
minimum, the net heating value limit for the subsequent 15-minute block
average. Failure to make adjustments to assist media or supplemental
natural gas using the equation provided for calculating an NHVcz limit
of 270 BTU/scf, using the NHVvg from the previous period, would be a
deviation of the operating limit.
    Alternatively, if the owner or operator is able to directly measure
the NHVvg on a more frequent basis, such as with a calorimeter (and
optional hydrogen analyzer), the process control system is able to
adjust more quickly, and the owner or operator can make adjustments to
assist media or supplemental natural gas more quickly. In this manner,
the owner or operator is not limited by

relying on NHVvg data that may not represent the current conditions.
Therefore, the owner or operator may opt to use the NHVvg from the same
period to comply with the operating limit.
    Based on the results of all of our analyses, the EPA is finalizing
a single minimum NHVcz operating limit for flares subject to the
Petroleum Refinery MACT standards of 270 BTU/scf during any 15-minute
period. The agency believes, given the results from the various data
analyses conducted, that this operating limit is appropriate,
reasonable and will ensure that refinery flares meet 98-percent
destruction efficiency at all times when operated in concert with the
other suite of requirements refinery flares need to achieve (e.g.,
flare tip velocity requirements, visible emissions requirements, and
continuously lit pilot flame requirements). For more detail regarding
our data re-analysis, please see the memorandum titled ``Flare Control
Option Impacts for Final Refinery Sector Rule'' in Docket ID No. EPA-
HQ-OAR-2010-0682.
    Comment: Numerous commenters objected to the proposed requirements
to have the velocity and visible emissions limits apply at all times
for flares. Commenters suggested that flares are not designed to meet
the visible emissions and flare tip velocity requirements when being
operated beyond their smokeless capacity and suggested several
alternative approaches: remove the visible emissions and flare tip
velocity requirements from the rule altogether; exempt flares from
these requirements during emergencies; or add a requirement to maintain
a visible flame present at all times or include a work practice
standard in the rule when flares are operated beyond their smokeless
capacity at full hydraulic load. The commenters identified full
hydraulic load as the maximum flow the flare can receive based on the
piping diameter of the flare header and operating pressure of processes
connected to the flare header system. They also specified that full
hydraulic load would only occur if all sources connected to the flare
header vented at the same time, which might result from an emergency
shutdown due to a plant-wide power failure. According to commenters,
flares are typically designed to operate in a smokeless manner at 20 to
30-percent of full hydraulic load. Thus, they claimed, flares have two
different design capacities: A ``smokeless capacity'' to handle normal
operations and typical process variations and a ``hydraulic load
capacity'' to handle very large volumes of gases discharged to the
flare as a result of an emergency shutdown. According to commenters,
this is inherent in all flare designs and it has not previously been an
issue because the flare operating limits did not apply during
malfunction events. However, if flares are required to operate in a
smokeless capacity during emergency releases, the commenters claimed
that refineries would have to quadruple the number of flares at each
refinery to control an event that may occur once every 2 to 5 years.
    To support their suggestions, commenters pointed out that flaring
during emergencies is the optimum way of handling very large releases
and that the flare test data clearly demonstrate that visible emissions
and/or high flare tip velocity do not suggest poor destruction
efficiency during such events. The commenters also argued that
operators should not have conflicting safety and environmental
considerations to deal with during these times. The commenters stated
that refiners are still subject to a civil suit even if the EPA uses
its enforcement discretion where such a release would violate the limit
and in order to avoid such liability, many new flares would have to be
built. Commenters estimated that 500 new large flare systems at a
capital cost in excess of $10-20 billion would need to be built because
of the amount of smokeless design capacity that would be needed and
that this significant investment would take the industry at least a
decade to install.
    Response: At the time of the proposed rule, we did not have any
information indicating that flares were commonly operated during
emergency releases at exit velocities greater than 400 ft/sec (which is
270 miles per hour (mph)). Similarly, we did not have information to
indicate that flares were commonly designed to have a smokeless
capacity that is only 20 to 30-percent of their ``hydraulic load
capacity.'' While we are uncertain that refineries actually would
install additional flares to the degree the commenters claim, based on
the possibility that there may be an event every 2 to 5 years that
would result in a deviation of the smokeless limit, we also recognize
that it would be environmentally detrimental to operate hundreds of
flares on hot standby in an effort to never have any releases to a
flare that exceed the smokeless capacity of that flare. This is because
operating hundreds of new flares to prevent smoking during these rare
events will generate more ongoing emissions from idling flares than the
no visible emissions limit might prevent during one of these events.
Therefore, we considered alternative operating limits or alternative
standards that could apply during these emergency release events.
    As an alternative to the proposed requirement that flares meet the
visible emissions and velocity limits at all times, we considered a
work practice standard for the limited times when the flow to the flare
exceeds the smokeless capacity of the flare. Owners or operators of
flares would establish the smokeless capacity of the flare based on
design specification of the flare. Below this smokeless capacity, the
velocity and visible emissions standards would apply as proposed. Above
the smokeless capacity, flares would be required to perform root cause
analysis and take corrective action to prevent the recurrence of a