similarly caused event. Multiple events from the same flare in a given
time period would be a deviation of the work practice standard. Force
majeure events would not be included in the event count for this
requirement.
    Based on industry claims that there is a hydraulic load flaring
event, on average, every 4.4 years, we assumed the best performers
would have no more than one event every 6 years, or a probability of
16.7-percent of having an event in any given year. We found that, over
a long period of time such as 20 years, half of these best performers
would have 2 events in a 3 year period, which would still result in
over half the ``best performing'' flares having a deviation of the work
practice standard if it was limited to 2 events in 3 years. Conversely,
only 6 percent would have 3 events in 3 years over this same time
horizon. Based on this analysis, 3 events in 3 years would appear to be
``achievable'' for the average of the best performing flares.
    Pursuant to CAA section 112(d)(2) and (3), we are finalizing a work
practice standard for flares that is based on the best practices of the
industry, and considers the rare hydraulic load events that inevitably
occur at even the best performing facilities.
    The best performing facilities have flare management plans that
include measures to minimize flaring during events that may cause a
significant release of material to a flare. Therefore, we are requiring
owners or operators of affected flares to develop a flare management
plan specifically to identify procedures that will be followed to limit
discharges to the flare as a result of process upsets or malfunctions
that cause the flare to exceed its smokeless capacity. We are
specifically requiring refinery owners or operators to implement
appropriate prevention measures applicable to these

emergency flaring events (similar to the prevention measures we are
requiring in this final rule to minimize the likelihood of a PRD
release). Refiners will be required to develop a flare minimization
plan that describes these proactive measures and reports smokeless
capacity. Refiners will need to conduct a specific root cause analysis
and take corrective action for any flare event above smokeless design
capacity that also exceeds the velocity and/or visible emissions limit.
If the root cause analysis indicates that the exceedance is caused by
operator error or poor maintenance, the exceedance is a deviation from
the work practice standard. A second event within a rolling 3-year
period from the same root cause on the same equipment is a deviation
from the standard. Events caused by force majeure, which is defined in
this subpart, would be excluded from a determination of whether there
has been a second event. Finally, and again excluding force majeure
events, a third opacity or velocity limit exceedance occurring from the
same flare in a rolling 3-year period is a deviation of the work
practice standard, regardless of the cause.
    Comment: Several commenters suggested that the EPA should revise
the combustion efficiency requirements to apply only to steam-assisted
flares used as Refinery MACT control devices during periods of time
that the flares are controlling Refinery MACT regulated streams. One
commenter suggested that the EPA misused the TCEQ data in proposing the
NHVcz metric and that the proposed limits are overly
conservative. The commenter requested that the EPA work with
stakeholders to conduct additional testing to determine what, if any,
operating parameters are appropriate and necessary to achieve an
adequate destruction efficiency for non-steam-assisted flares.
    Response: We disagree with the commenters that the combustion
efficiency requirements should apply only to steam-assisted flares. The
available data (for runs where steam assist is turned off) as well as
the available combustion theories suggest that the combustion zone net
heating value minimum limit, which is the vent gas net heating value
for unassisted or perimeter air-assisted flares, is necessary to ensure
proper flare performance. While we agree that additional data on air-
assisted flares would allow for a more robust analysis, the data we do
have strongly indicate that air-assisted flares can be over-assisted
and that the combustion efficiency of air-assisted flares that are
over-assisted is below 98-percent control efficiency.
    Comment: A few commenters suggested that the proposed flare
regulations should not apply to part 63, subpart R (gasoline loading)
and subpart Y (marine vessel loading) facilities, and to part 61,
subpart FF (benzene waste) facilities. The commenters recommended that
flares associated with gasoline loading, marine vessel loading and
wastewater treatment emissions need to comply only with the General
Provisions for flares. Some of these commenters argued that these
sources are more consistent in flow and composition than other refinery
sources, so the new requirements are not necessary to ensure good
combustion for these ``dedicated'' flares. Some commenters suggested
that operators of flares with consistent flow and composition be
allowed to use process knowledge or engineering judgment rather than be
required to install continuous monitors or be subject to ongoing grab
sampling requirements.
    Some commenters noted that the required control efficiency for some
refinery emissions sources subject to subpart CC sources is 95-percent.
One commenter also requested that the EPA provide overlap provisions so
flares used to control sources from different MACT sources would not
have duplicative requirements.
    Response: The regulatory revisions that we are finalizing apply to
petroleum refinery sources subject to part 63, subparts CC and UUU.
Gasoline loading, marine vessel loading and wastewater treatment
operations that are part of the refinery affected source as defined at
40 CFR 63.640 are subject to subpart CC. Gasoline loading, marine
vessel loading and wastewater treatment operations located at non-
refinery source categories are not subject to part 63, subpart CC and,
thus, would not be subject to the revisions to subpart CC being
finalized in this action. To the extent that the commenters are
requesting that the EPA establish flare requirements that would apply
to flares that are not part of the refinery affected source, that
request is beyond the scope of this rulemaking, which only addresses
revisions to Refinery MACT 1 and 2. When we issue rules addressing
requirements for other sources with flares, we will consider issues
similar to those we considered in this action and determine at that
time whether revisions to those other flare requirements are necessary.
    The commenters note that some subpart CC emissions sources have
only a control efficiency requirement of 95-percent. While this may be
true, where the owner or operator chooses to control these sources
through the use of a flare, operation of that flare was subject to
operational requirements in the General Provisions at 40 CFR 63.11 and
the best performing flares were achieving 98-percent control at the
time the General Provisions were promulgated. At the time the General
Provisions were promulgated, we received no comments that the EPA
should set different operational limits for flares that are controlling
emissions from sources where the standard may vary by level of control
efficiency and we see no basis to do so now. The purpose of the
revisions to the flare operating requirements is to ensure that flares
are operating consistent with the MACT floor requirements for any and
all sources that may use flares as a control device (79 FR 36905, June
30, 2014). As the MACT floor control requirements of certain refinery
sources that allow the use of a flare as a control device is 98-
percent, we established operational limits to ensure flares used as
control devices meet this MACT requirement.
    To the extent that the commenters are requesting that the EPA
establish an alternative monitoring approach for flares in dedicated
service that have consistent composition and flow, we agree that these
types of flares, which have limited flare vent gas streams, do not need
to have the same type of on-going monitoring requirements as those with
more variable waste streams. Thus, we are establishing an option that
refinery owners or operators can use to demonstrate compliance with the
operating requirements for flares that are in dedicated service to a
specific emission source, such as a wastewater treatment operation.
Refinery owners or operators will need to submit an application for the
use of this alternative. The application must include a description of
the system, characterization of the vent gases that could be routed to
the flare based on a minimum of 7 grab samples (14 daily grab samples
for continuously operated flares) and specification of the net heating
value that will be used for all flaring events (based on the minimum
net heating value of the grab samples). We are also allowing
engineering estimates to characterize the amount of gas flared and the
amount of assist gas introduced into the system. For example, the use
of fan curves to estimate air assist rates is acceptable. Flare owners
or operators would use the net heating value determined from the
initial sampling phase and measured or estimated flare vent gas and
assist gas

flow rates, if applicable, to demonstrate compliance with the
standards.
    Comment: A few commenters suggested that the EPA's proposed work
practice and monitoring standards for flares are CAA section 112(d)
``developments'' required by law and supported by the evidence, and
reflect best practices at many refineries today. One commenter
suggested that the EPA must allow companies with consent decrees to
meet their consent decree requirements as an alternative compliance
approach and in lieu of the proposed requirements.
    Response: We proposed the enhanced monitoring requirements and
operating limits under authority of CAA sections 112(d)(2) and (d)(3)
to ensure that flares used to control regulated Refinery MACT 1 or 2
gas streams are meeting the prescribed control efficiencies established
at the time the MACT standard was promulgated. And, we continue to
believe that these revisions are appropriate under CAA sections
112(d)(2) and (d)(3). The commenter has not suggested, and we do not
believe, that the revisions promulgated would differ in substance if
they were instead promulgated under CAA section 112(d)(6).
    In general, we expect that the NHVcz monitoring
requirements that we are finalizing for flares will be consistent with
the requirements in various consent decrees. However, we have not
conducted a rigorous evaluation of equivalency between various
requirements and therefore we are not at this time providing an
allowance for flare owners or operators to comply with the
NHVcz operating limits and any provisions for necessary
monitoring needed in the consent decree in lieu of the NHVcz
limits and monitoring requirements established in this rule. In the
event that an owner or operator wishes to continue complying only with
the requirements of a consent decree, the rule contains provisions by
which owner or operator can seek approval for alternative limits that
are at least equivalent to the performance achieved from complying with
the operating limits included in the final rule.
iii. Pressure Relief Devices
    Comment: Several commenters suggested that the EPA develop a work
practice approach for atmospheric PRD rather than a prohibition on
releases. One commenter recommended that the EPA establish a work
practice standard for atmospheric PRDs that requires refiners to
implement a base level of preventative measures including: Basic
process controls, instrumented alarms, documented and verified routine
inspection and maintenance programs, safety-instrumented systems,
disposal systems, provide redundant equipment, increase vessel design
pressure and systems that reduce fire exposure on equipment.
Additionally, the commenter recommended that the EPA require refiners
to perform root cause analysis and implement corrective action in the
event of a release. The commenter stated these requirements would be
similar to the root cause analysis/corrective action requirements
recently promulgated for flares under NSPS subpart Ja and provided
specific regulatory language for a proposed work practice approach.
(See section <IP_ADDRESS> in Docket item EPA-HQ-OAR-2010-0682-0583.) One
commenter requested that the EPA allow a process for companies to
submit an application for case-by-case limits to be approved by the
agency, either the EPA or a delegated state similar to the alternate
NOX limits for process heaters provided in NSPS subpart Ja.
This commenter recommended that the EPA establish reasonable work
practice standards, specifically suggesting that the EPA develop work
practice standards consistent with API 521. The commenter stated that
the EPA should provide an implementation period for compliance that
goes beyond the timeframe provided under CAA section 112(d). The
commenter added that the EPA should adopt specified changes to the
definition of an atmospheric pressure relief safety valve and provided
suggested regulatory language for a proposed work practice standard for
PRDs in EPA-HQ-OAR-2010-0682-0549.
    Another commenter stated that the EPA should require, as the Bay
Area Air Quality Management District (BAAQMD) does, that any refinery
that has a reportable PRD event must take certain steps to prevent such
releases in the future (BAAQMD Rule 8-28-304). In particular, such a
refinery must create a Process Hazard Analysis, meet the Prevention
Measures Procedures specified in section 8-28-405, and conduct a
failure analysis of the incident, to prevent recurrence of similar
incidents (Id. Reg. section 8-28-304.1). If a second release occurs,
then, within one year, the facility must vent its PRDs to a vapor
recovery or disposal system that meets certain requirements (Id. Reg.
section 8-28-304.2). The commenter asserted that the EPA's prohibition
on releases to the atmosphere from PRD will ensure that refineries take
the necessary steps to prevent such releases, or install control
devices so that any releases from PRDs that must occur are vented
through a control device to reduce the amount of toxic air pollution
they emit. At a minimum, the commenter stated, the EPA must prohibit
these uncontrolled emissions and require monitoring and reporting to
assure compliance and ensure that the emission standards apply at all
times, as required by the Act. The commenter argued that the EPA must
also, however, consider requiring the additional developments that have
been put into place in the BAAQMD and also require control devices to
be used for all PRD, as some local air districts require. In addition,
the commenter supported the EPA's monitoring and reporting requirements
for PRD releases and the proposed electronic reporting requirements,
which the EPA recognized are needed to assure compliance and assist
with future rulemakings and as that provision requires, the EPA also
must make all information reported publicly available online promptly
and in an accessible and understandable format.
    Response: We agree that, under the proposal, refineries would
consider installing add-on controls to comply with the prohibition on
atmospheric releases from PRDs. In addition, they would consider
venting these control devices to existing control devices, including
flares. However, it may not be feasible to vent some or all of the PRDs
to existing flares if the flares are near their hydraulic load capacity
based on the processes already connected to the flares. Flares have
negative secondary impacts when operated at idle conditions for the
vast majority of time, which could be the case if they were installed
solely to address PRD releases. These secondary impacts result from
GHG, CO and NOX emissions. Some PRDs may vent materials that
are not compatible with flare control and would need to be vented to
other controls.
    To estimate the impact of the proposed prohibition on venting PRDs
to the atmosphere, we estimated that at least one new flare per
facility would be required to handle releases from PRDs, based on the
number of atmospheric PRDs reported at refineries; that 60-percent of
the PRDs could be piped to existing controls at minimal costs and the
other 40-percent would have to be piped to new flares; and that, on
average, each new flare would service 40 PRDs. Based on these
assumptions, 151 new flares would be needed or approximately one new
flare per refinery. At a capital cost of $2 million for each new flare,
which would not include long pipe runs, if needed, to PRD that are
dispersed across the plant, we estimate that the capital cost of the

prohibition on venting to the atmosphere would exceed $300 million.
Considering the fuel needed (approximately 50,000 scf/day per flare)
and a natural gas price of $4.50 per 1,000 scf, we estimate the annual
operating cost for these new flares to be $12 million.
    PRDs are unique in that they are designed for the purpose of
releasing or ``popping'' as a safety measure to address pressure build-
up in various systems--pipes, tanks, reactors--at a facility. These
pressure build-ups are typically a sign of a malfunction of the
underlying equipment. While it would be difficult to regulate most
malfunction events because they are unpredictable and can vary widely,
in the case of PRDs, they are equipment installed specifically to
release during malfunctions and as such, we have information on PRDs in
our 2011 Refinery ICR and through the SCAAMD and BAAQ rules to
establish standards for them. After reviewing these comments, we thus
examined whether it would be feasible to regulate these devices under
CAA section 112(d)(2) and (3).
    After reviewing the comments, we agree with the commenters who
suggest that the BAAQMD rule, as well as a similar South Coast Air
Quality Management District (SCAQMD) rule that address PRD releases
(SCAQMD Rule 1173), provide work practice standards that reflect the
level of control that applies to the best performers. Consequently, we
developed a work practice standard for PRD based on a detailed MACT
analysis considering the requirements in these rules. Our rationale for
the selected MACT requirements is provided in section IV.C.4 of this
preamble. The work practice standards that we are finalizing for PRDs
require refiners to establish proactive measures for each affected PRD
to prevent direct release of HAP to the atmosphere as a result of
pressure release events. In the event of an atmospheric release, we are
requiring refinery owners or operators to conduct root cause analysis
to determine the cause of a PRD release event. If the root cause was
due to operator error or negligence, then the release would be a
deviation of the standard. For any other release (not including those
caused by force majeure events), the owner or operator would have to
implement corrective action. A second release due to the same root
cause for the same equipment in a 3-year period would be a deviation of
the work practice standard. Finally, a third release in a 3-year period
would be a deviation of the work practice standard, regardless of the
root cause. Force majeure events would not count in determining whether
there has been a second or third event.
    With respect to defining ``atmospheric pressure relief safety
valve'' as suggested by the commenter, we note that the June 30, 2014,
proposed amendments in 40 CFR 63.648(j) used the term ``relief valve''
because this was a defined term in Refinery MACT 1. However, the
proposed amendments included clauses such as ``if the relief valve does
not consist of or include a rupture disk.'' Thus, we specifically
intended to apply the pressure relief management requirements broadly
to ``pressure relief devices'' and not just ``valves.'' To clarify
this, we have revised the regulatory language to use the term
``pressure relief device'' rather than ``relief valve'' to clearly
include rupture disks or similar types of equipment that may be used
for pressure relief.
4. What is the rationale for our final approach and final decisions for
the revisions pursuant to CAA section 112(d)(2) and (3)?
    We revised the MACT floor determination for DCU sources. CAA
section 112(d)(3)(A) requires the MACT floor for existing sources to
exclude ``. . . 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.'' Because we have
determined that a 2 psig emissions limitation is equivalent with a LAER
emission limit for DCU, we revised the MACT floor analysis in order to
exclude sources that first met the 2 psig limit on or after December
30, 2012. For existing sources, based on the revised MACT analysis, we
concluded that the MACT floor is still 2 psig. However, because the
information on which we relied was submitted in response to the 2011
Petroleum Refinery ICR which requested ``typical'' venting pressures
and because providing an allowance to average across venting periods
does not reduce the emissions reductions achieved, we are providing a
60-event averaging period for existing sources in response to public
comments received.
    For new DCU sources, our revised analysis identified one DCU
subject to permit emission limitations of 2.0 psig pressure limit prior
to venting on a per event basis. Under CAA section 112(d)(3), the MACT
standard for new sources cannot be less stringent than the emission
control achieved in practice by the best-controlled similar source.
Thus, we are finalizing a limit of 2.0 for new DCU sources. We note
that as 2.0 psig limit is more stringent than a 2 psig limit because of
the rounding convention of rounding to the number of significant digits
for which the standard is expressed. For example, a 2.4 psig venting
pressure is compliant with a 2 psig limit, while it is not compliant
with a 2.0 psig limit.
    We evaluated the costs of requiring existing sources to meet a 2.0
psig limit as a beyond-the-MACT-floor option. We determined the
incremental cost of going from a 2 psig limit with an allowance to
average over 60 events to a 2.0 psig limit on a per event basis was
approximately $70,000 per ton of HAP reduced considering VOC credits.
Based on this high incremental cost-effectiveness, we concluded that
the MACT floor requirement for existing DCU sources was MACT. As
discussed in detail in the proposal, we do not consider it technically
feasible to meet a 1 psig pressure limit (effectively a 1.4 psig limit)
on a not-to-be-exceeded basis. Thus, we rejected this beyond the floor
control option for both existing and new DCU sources. See the
memorandum titled ``Reanalysis of MACT for Delayed Coking Unit Decoking
Operations'' in Docket ID No. EPA-HQ-OAR-2010-0682 for additional
details regarding our re-analysis of MACT for DCU decoking operations.
    In response to comments received on the prohibition of draining
prior to achieving the proposed pressure limit (see Section 7.2.1 in
the ``National Emission Standards for Hazardous Air Pollutants from
Petroleum Refineries--Background Information for Final Amendments:
Summary of Public Comments and Responses'' in Docket ID No. EPA-HQ-OAR-
2010-0682), we are providing specific provisions to allow for draining
under special conditions. The specific provision and our rationale for
providing them are provided below.
    First, we learned that certain DCU are designed to completely fill
the drum with water and allow the water to overflow in the overhead
line and drain to a receiving tank in order to more effectively cool
the coke bed. Owners or operators of this DCU design were concerned
that the water overflow may be considered a drain and also stated that
overhead temperature rather than pressure would be a better indicator
of effective bed cooling. In reviewing this

type of DCU design, we find that this design has some unique advantages
to traditional DCU to effect better cooling of the coke drum, and
therefore we do not want to preclude its use. Based on saturated steam
properties, we determined that an overhead temperature of 220 [deg]F
would achieve equivalent or greater emissions reductions than a 2 psig
pressure limitation and an overhead temperature of 218 [deg]F would
achieve equivalent or greater emissions reductions than a 2.0 psig
pressure limitation. Therefore, we are including these temperature
limits as alternatives to the 2 or 2.0 psig pressure limitations for
existing and new DCU affected sources, respectively. With respect to
the overflow ``drain,'' we remain concerned with emissions from
draining superheated water. However, if submerged fill is used in the
atmospheric tank receiving the overflow water, the superheated water
will be cooled by the water within the tank and emissions that occur
during the conventional draining of water (from the flashing of
superheated water into steam) can be prevented. Therefore, we are
allowing the use of water overflow provided the overflow ``drain''
water is hard-piped to the receiving tank via a submerged fill pipe
(pipe below the existing liquid level) whenever the overflow water
exceeds 220 [deg]F.
    Second, we received comments that, for conventional DCU (those not
designed to allow water overflow), there is a limit to the maximum
water level in the drum, which limits to some extent how much cooling
water can be added to the coke drum. In rare cases, the coke drum does
not cool sufficiently using the typical cooling steps. In this case,
the common industry practice is to partially drain the coke drum and
refill it with additional cooling water. This ``double-quench'' process
is needed for safety reasons to sufficiently cool the coke drum
contents prior to the decoking operations. Therefore, commenters
requested provisions to allow double-quenching of the coke drum. We
recognize the safety issues associated with coke blow-out during coke
cutting if there is a portion of the coke bed that is not sufficiently
cooled and we agree that double-quenching is an effective means to cool
the coke drum in those rare instances that the typical cooling cycle
does not sufficiently cool the coke drum contents, so we considered
granting the commenters' request. As noted previously, the primary
concern with early draining of the coke drum is the emissions that are
expected to occur as a result of draining superheated water. We
recognize, however, that the water temperature near the bottom of the
coke drum is typically much lower than at the top of the coke drum. If
the temperature of the water drained from the bottom of the coke drum
remains below 210 [deg]F, this would minimize steam flashing and
associated HAP emissions since the water drained would not be
superheated. We conclude that the use of double quenching is
appropriate for cases when the coke drum is not sufficiently cooled
using the normal cooling procedures provided the temperature of the
water drained remains below 210 [deg]F, and it is consistent with the
practices of the best performing sources. Consequently, we are
finalizing provisions to allow the use of double-quenching for DCU
provided the temperature of the water drained remains below 210 [deg]F.
    For the CRU, we are finalizing the proposed revisions to require
CRU that employ active purging to meet the MACT emissions limitations
in Tables 15 and 16 in subpart UUU at all times regardless of vessel
pressure. We received limited comments regarding our proposal; these
comments generally concerned the costs associated with the proposed
emissions limitations. As discussed in our proposal, and based on data
submitted in response to the ICR, emissions using active purging are
much higher than those not using active purging. In the original rule,
we based the MACT floor on the best performing facilities that used
sequential pressurizations and depressurizations rather than active
purging. Thus, in the proposal, we concluded that allowing owners or
operators to actively purge while at low pressures was inconsistent
with the MACT floor emissions limitations achieved by the best
performing 12-percent of sources when the MACT floor was originally
established. As we are simply requiring these facilities to meet the
same emission levels determined to be MACT, we do not consider costs of
potential additional controls to be a viable rationale to allow these
units to emit several times more HAP than the units upon which the MACT
requirements were based and the emissions levels achieved in practice
by the vast majority of other CRU sources.
    For flares, we are finalizing proposed revisions to include
detailed flare monitoring and operating requirements. We are including
the flaring provisions for refineries in the Refinery MACT rules and
removing the cross-references to the flaring requirements in the
General Provisions. The final regulatory requirements differ from the
proposed requirements in several respects. First, we are not finalizing
the ban on halogenated vent streams because we did not include
sufficient justification or include cost estimates for this proposed
provision and we did not include any monitoring requirements to ensure
compliance with this ban on halogenated vent streams.
    We are finalizing the proposed no visible emissions limit and the
flare tip velocity limit but they will apply only when the flare vent
gas flow rate is below the smokeless capacity of the flare. We received
a number of comments stating that the no visible emissions limit and
the flare tip velocity limit cannot be met during large malfunctions
and emergency shutdown events. In response to comments, we are
finalizing work practice standards for emergency flaring events using
the proposed no visible emission limit and flare tip velocity limit as
thresholds in the final rule to trigger root cause analysis when the
flare vent gas flow rate is above the smokeless capacity of the flare.
The final work practice standard includes requirements to develop a
flare management plan, to implement prevention measures, and to perform
root cause analysis and implement corrective action following each
flaring event that exceeds the smokeless capacity of the flare. There
is also a limit on the number of these flaring events that a given
flare may have in the 3-year period. We are establishing these
provisions because we now recognize that flares have two different
design capacities: A smokeless design capacity and a hydraulic load
capacity. We determined that the proposed visible emissions limit and
the flare tip velocity limit for very large flow events are not the
MACT floor for such events. The final work practice standards for
flaring events are based on the best performing facilities and will
result in emission reductions in a technically feasible manner without
any negative secondary impacts.
    We consider it appropriate to establish a work practice standard
for flares as provided in CAA section 112(h). While it is possible to
monitor gaseous streams going into the flare (as we have required for
the flare operating requirements) it is not possible to design and
construct a conveyance to capture the emissions from a flare. While
knowledge of the composition and flow of gases entering the flare
provides a reasonable basis for establishing operating requirements for
normal operations, we have no data on flare performance under
conditions in the hydraulic load range. While smoke in the flare
exhaust is an indication of incomplete combustion, it is uncertain

how much deterioration of HAP destruction efficiency occurs during a
smoking event. We also consider that the application of a measurement
methodology for flare exhaust is not practicable due to technological
and economic limitations. Passive FTIR has been used to determine
combustion efficiency in flare exhaust, but these are essentially
manual tests, and the measurement accuracy is dependent on how well the
monitor is aligned with the flare exhaust plume. Changes in wind
direction require manual movement of the monitoring system. It is also
unclear if these systems can accurately measure combustion efficiency
during high smoking events. These systems also require very specialized
expertise, and we consider that it is both technologically and
economically infeasible to measure flare exhaust emissions,
particularly during high load events. Consequently, for emergency flare
releases, we conclude that it is appropriate to establish a work
practice standard as provided in CAA section 112(h).
    We also received comments that the daily visible emissions
observations were burdensome and unnecessary and some commenters
suggested that facilities be allowed to use video surveillance cameras.
We concluded that video surveillance cameras would be at least as
effective as the proposed daily 5-minute visible emissions observations
using Method 22. We are finalizing the proposed visible emissions
monitoring requirements Method 22 and the alternative of using video
surveillance cameras.
    We are simplifying the combustion zone gas property operating
limits in response to public comments received. Specifically, we are
finalizing requirements that all flares meet a minimum operating limit
of 270 BTU/scf NHVcz on a 15-minute average, and we are
providing that refiners use a corrected heat content of 1,212 BTU/scf
for hydrogen to demonstrate compliance with this operating limit. We
determined that a corrected heat content of 1212 BTU/scf for hydrogen
provided a better indication of flare performance than without the
correction. We also determined that the other combustion zone
parameters, which were primarily proposed to provide suitable methods
for flares that had high hydrogen concentrations, were no longer
necessary when a 1,212 Btu/scf net heating value is used for hydrogen.
Therefore, we are not finalizing the alternative combustion zone
operating limits based on lower flammability limit or combustibles
concentration. We are also not finalizing separate combustion zone
operating limits for gases meeting the proposed hydrogen-olefin
interaction criteria. In our revised analysis of the data, we analyzed
all of the data together and determined the 270 Btu/scf
NHVcz operating limit provided in the final rule would
adequately ensure that flares achieve the desired 98-percent control
efficiency regardless of the composition of gas sent to the flare.
    For air-assisted flares, we are finalizing the additional
``dilution parameter'' operating limit only for the net heating value
dilution parameter, NHVdil. 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, and we are
providing that refiners use a corrected heat content of 1,212 BTU/scf
for hydrogen to demonstrate compliance with this operating limit. For
the reasons explained above, we are not finalizing the proposed
alternative dilution parameter operating limits based on lower
flammability limit or combustibles concentration, and we are not
finalizing separate dilution parameter operating limits for gases
meeting the proposed hydrogen-olefin interaction criteria.
    For flares in dedicated service, we are establishing an alternative
to continuous or on-going grab sample requirements for determining
waste gas net heating content to reduce the burden of sampling for
flare waste gases that have consistent compositions. Flares in
dedicated service can use initial sampling period and process knowledge
to determine a fixed net heating value of the flare vent gas to be used
in the calculations of NHVcz and, if applicable,
NHVdil.
    We are revising the definition of MPV to remove the exemption for
in situ sampling systems for the reasons provided in the proposed rule.
    We received comments recommending that a work practice standard be
adopted for PRD rather than the proposed prohibition of atmospheric PRD
releases. Commenters stated that the prohibition was infeasible due to
the proposed immediate timing of the requirement and impractical due to
cost considerations. After reviewing these comments as well as the
BAAQMD rule (Regulation 8, Rule 8-28-304) and the SCAQMD rule (Rule
1173), we have determined that the work practice standards in these
rules reflect the level of control that applies to the best performers.
Therefore, we proceeded to evaluate appropriate MACT requirements based
on the provisions in these rules.
    The BAAQMD rule requires sources to implement a minimum of three
prevention measures to limit the possibility of a release. The BAAQMD
uses a ``release event'' threshold of 10 lbs/day of organic or
inorganic pollutants; the SCAQMD rule effectively uses a release event
threshold of 500 lbs VOC/day. When a release event occurs, both rules
require that the refiner perform a root cause analysis and take
corrective action (including additional prevention measures). In
addition, both rules require piping the PRD to a flare if there are
more than two release events (releases above a certain release size
threshold) in a 5-year period. Both rules include a number of
exemptions for certain types of PRD that are not expected to release
significant amounts of pollutants to the air or that are not feasible
to control because of pressure considerations. These include PRD
associated with storage tanks, vacuum systems and equipment in heavy
liquid service as well as liquid thermal relief valves that are vented
to process drains.
    There are five refineries subject to the BAAQMD rule and seven
refineries subject to the SCAQMD rule, accounting for 8-percent of
refineries nationwide and representing the industry's best performers.
We consider the BAAQMD rule to be the more stringent of the two because
this rule requires sources to implement a minimum of three prevention
measures to limit the possibility of a release (the SCAQMD rule has no
similar requirement) and uses a lower mass threshold for what is
considered a ``release event'' (10 lbs/day of organic or inorganic
pollutants versus the 500 lbs VOC release threshold in the SCAQMD
rule). Therefore, the BAAQMD rule is considered to be the MACT floor
requirement for PRDs associated with new affected sources and the
SCAQMD rule is considered to be the MACT floor for PRDs associated with
existing affected sources.
    In general, an open PRD is essentially the same as a miscellaneous
process vent that is vented directly to the atmosphere. Consistent with
our treatment of miscellaneous process vents and consistent with the
two California rules, we believe that it is appropriate to exclude
certain types of PRD that have very low potential to emit based on
their type of service, size and/or pressure. For example, PRD that have
a potential to emit less than 72 pounds per day of VOC, considering the
size of the valve opening, design release pressure, and equipment
contents, would be considered in a similar manner as Group 2
miscellaneous

process vents and would not require additional control. The two
California rule requirements do not apply to PRD on storage tanks and
vacuum systems. Most of these PRD have a design release pressure of 2.5
psig and thus have a very limited potential to emit. It is technically
infeasible to pipe these sources to a flare (or other similar control
system) because the back pressure in the flare header system generally
exceeds 2.5 psig. We note that some storage tanks can operate at
elevated pressure (i.e., pressure tanks). Therefore, rather than follow
exactly the requirements in the California rules, we determined it more
practical to exclude PRD with design release pressure of less than 2.5
psig.
    Any release from a PRD in heavy liquid service would have a visual
indication of a leak and any repairs to the valve would have to be
further inspected and, if necessary, repaired under the existing
equipment leak provisions. Therefore, consistent with the BAAQMD rule,
we are exempting PRD in heavy liquid service from the work practice
standards we are establishing in this final rule.
    Both the BAAQMD and SCAQMD rules exempt thermal expansion valves
that are ``vented to process drains or back to the pipeline.'' We are
unclear what is meant by ``vented to process drains''; however, if a
liquid is released from a PRD via hard-piping to a drain system that
meets the control requirements specified in Refinery MACT 1, we
consider that these PRD are controlled and they would not be subject to
the work practice standard established in this final rule. Similarly,
all PRD in light liquid service that are hard-piped to a controlled
drain system (or back to the process or pipeline) are otherwise subject
to a MACT requirement and would not be subject to the work practice
standard.
    In considering thermal relief valves not vented to process drains
or back to the pipeline, we expect that releases from these thermal
relief valves will be small and generally under the release event
thresholds specified in the California rules. Therefore, the work
practice standards do not apply to PRD that are designed solely to
release due to liquid thermal expansion.
    The primary goal of the PRD work practice standard is to reduce the
size and frequency of releases. The SCAQMD rule is targeted towards
fairly large releases (compared to the direct PRD releases reported in
response to the Refinery ICR), so it will reduce the frequency of large
releases, but it does little to reduce the frequency of smaller
releases. To more effectively reduce the size and frequency of all
releases, we consider it important to require the implementation of
prevention measures (as required in the BAAQMD rule) and require root
cause analysis and corrective action for PRD releases from all PRD
subject to the work practice standard. While we recognize that if a PRD
opens for a short period of time, the release might be below the
release thresholds in the SCAQMD rules, we believe the release may be
indicative of an important issue or design flaw. Because the potential
for large emissions exist from the PRD subject to the work practice
standard, we think it is reasonable to require a root cause analysis be
conducted and appropriate corrective action implemented to potentially
identify this issue and prevent a second release which, if the issue
remains uncorrected, could be significant.
    Requiring that prevention measures be implemented on all PRD
subject to the work practice standard and not establishing a release
threshold for release events is a variation from the SCAQMD rule.
However, we also considered the allowable release frequency. We believe
that our adoption of this approach is balanced by our not adopting the
SCAQMD provisions requiring that PRD be vented to a flare or other
control system or that refiners pay a fee if there are multiple
releases of a certain size within a specified timeframe.\12\ In place
of this system, we are limiting the number of events from each PRD that
can occur in a 3 year time period (2, if root causes are different),
and in place of a fine, or routing to control, stating that the 3rd
release in 3 years for any root cause is a deviation of the standard.
---------------------------------------------------------------------------

    \12\ The SCAQMD rule requires PRD to be vented to a flare or
other control device if there is a single release in excess of 2,000
pounds of VOC in a 24-hour period or three releases in excess of 500
pounds of VOC in a 5-year period or, alternatively, pay a $350,000
fee. Thus, the SCAQMD rule would allow, for example, two releases of
over 500 pounds of VOC each within a 5-year period without any
penalty provided a third event did not occur. If a third event did
occur, the refinery owner or operator would then have to vent the
PRD to a flare or other control system or pay a fee ($350,000) for
the third release over 500 pounds of VOC.
---------------------------------------------------------------------------

    Because we are not including a size threshold for release events as
in the SCAQMD rule, it is natural to assume release events would occur
more frequently than release events subject to the SCAQMD rules. Also,
based on our Monte Carlo analysis of random rare events, we note that
it is quite likely to have two or three events in a 5-year period when
a long time horizon (e.g., 20 years) is considered. Therefore,
considering our analysis of emergency flaring events and the lack of a
500 lb/day release threshold, we considered it reasonable to use a 3-
year period rather than a 5-year period as the basis of a deviation of
the work practice standard.
    The SCAQMD work practice standards do not apply to releases that
are demonstrated to ``result from natural disasters, acts of war or
terrorism, or external power curtailment beyond the refinery's control,
excluding power curtailment due to an interruptible service
agreement.'' These types of events, which we are referring to as
``force majeure'' events, are beyond the control of the refinery owner
or operator. We are providing that these events should not be included
in the event count, but that they would be subject to the root cause
analysis in order to confirm whether the release was caused by a force
majeure event.
    Consistent with the requirements in the SCAQMD rule, we are
requiring refinery owners or operators to conduct a root cause analysis
for a PRD release event. If the root cause was due to operator error or
negligence, then the release would be a deviation of the standard. For
any other release (not including those caused by force majeure events),
the owner or operator would have to implement corrective action. We
consider that a second release due to the same root cause for the same
equipment in a 3-year period would be a deviation of the work practice
standard. This provision will help ensure that root cause/corrective
action are conducted effectively. Finally, a third release in a 3-year
period (not including those caused by force majeure events) would be a
deviation of the work practice standard, regardless of the root cause.
While we are using a 3-year interval rather than the 5-year interval
provided in the SCAQMD, we consider that the requirements as included
in this final rule (i.e., the inclusion of prevention measure
requirements and no thresholds for release events) will achieve
equivalent if not greater emissions reductions than the SCAQMD rule. We
also consider that, given the prevention measure requirements and a 3-
year period, there is less likelihood of unusual random events that
happen over a short period of time that may cause refinery owners or
operators to feel compelled to vent the PRD to a flare to eliminate
concerns regarding potential non-compliance. Thus, we project that the
requirements that we have included in the final rule will achieve
emissions reductions commensurate to or exceeding the requirements in
the SCAQMD rule (that serves as the MACT floor for existing sources)
but will achieve those

reductions in a more cost-effective manner.
    We also considered requiring all PRD to be vented through a closed
vent system to a control device as an alternative beyond-the-MACT floor
requirement. While this requirement would provide additional emission
reductions beyond those we are establishing as the MACT floor, these
reduction come at significant costs. Capital costs for requiring
control of all atmospheric PRD is estimated to be approximately $300
million compared to $11 million for the requirements described above.
The total annualized cost for requiring control of all atmospheric PRD
is estimated to be approximately $41 million/year compared to $3.3
million/year for the requirements described above. We estimate that the
incremental cost-effectiveness of requiring control of all atmospheric
PRD compared to the requirements described above exceeds $1 million per
ton of HAP reduced. Consequently, we conclude that this is not a cost-
effective option for existing sources.
    The final requirements that we have developed for PRD achieve equal
or greater emission reductions than those achieved by the SCAQMD rule
(MACT floor). To the extent those requirements are more stringent that
the SCAQMD, they are cost-effective. We could not identify an
alternative requirement that provided further emission reductions in a
cost-effective manner. Thus, we conclude that the work practice
standards described above represent MACT for existing sources.
    The BAAQMD rule, which represents the requirements applicable to
the best performing sources, is the basis for new source MACT for PRD.
Based on the specific provisions for PRD in the BAAQMD rule, we
conclude that the MACT floor requirement is to have all PRD in HAP
service associated with a new affected source vented through a closed
vent system to a control device. As with existing sources, the PRD WPS
would also contain the same exclusions (e.g., heavy liquid service
PRDs, thermal expansion valves, liquid PRDs that are hard-piped to
controlled drains, PRD with release pressures of less than 2.5 psig,
PRD with emission potential of less than 72 lbs/day, and PRD on mobile
equipment). These provisions are similar to the applicability
provisions of the BAAQMD rule. Thus, we retain the same applicability
of the work practice standard for PRDs on new or existing equipment,
but all affected PRD on a new source would be required to be
controlled. This is essentially equivalent to the proposed requirement
of no atmospheric releases. We could not identify a control option more
stringent than the BAAQMD rule as applied to new sources. Therefore, we
conclude that venting all PRD in HAP service through a closed vent
system to a flare or similar control system is MACT for PRD associated
with new affected sources.
    We consider it appropriate to establish a work practice standard
for PRD as provided in CAA section 112(h). While it may be possible to
design and construct a conveyance for PRD releases, we consider that
the application of a measurement methodology for PRDs is not
practicable due to technological and economic limitations. First, it is
not practicable to use a measurement methodology for PRD releases. The
venting time can be very short and may vary widely in composition and
flow rate. The often-short duration of an event makes it infeasible to
collect a grab sample of the gases when a release occurs, and a single
grab sample would not account for potential variation in vent gas
composition. It would be economically prohibitive to construct an
appropriate conveyance and install and operate continuous monitoring
systems for each individual PRD in order to attempt to quantitatively
measure a release event that may occur only a few times in a 3-year
period. Additionally, we have not identified an available, technically
feasible continuous emission monitoring systems that can determine a
mass VOC or HAP release quantity accurately given the flow, composition
and composition variability of potential PRD releases from refineries.
Consequently, we conclude that it is appropriate to establish a work
practice standard for PRD releases as provided in CAA section 112(h).

D. NESHAP Amendments Addressing Emissions During Periods of SSM

1. What amendments did we propose to address emissions during periods
of SSM?
    We proposed to eliminate the SSM exemption in 40 CFR part 63,
subparts CC and UUU. Consistent with Sierra Club v. EPA, we proposed
standards in these rules that apply at all times. We also proposed
several revisions to Table 6 of subpart CC of 40 CFR part 63 and to
Table 44 to subpart UUU of 40 CFR part 63 (the General Provisions
Applicability tables for each subpart), including eliminating the
incorporation of the General Provisions' requirement that the source
develop an SSM plan, and eliminating and revising certain recordkeeping
and reporting requirements related to the SSM exemption.
    For Refinery MACT 1, we proposed that the use of a bypass at any
time to divert a Group 1 miscellaneous process vent to the atmosphere
is a deviation of the emission standard, and specified that refiners
install, maintain and operate a continuous parameter monitoring system
(CPMS) for flow that is capable of recording the volume of gas that
bypasses the APCD.
    We also proposed to revise the definition of MPV to remove the
exclusion for ``Episodic or non-routine releases such as those
associated with startup, shutdown, malfunction, maintenance,
depressuring and catalyst transfer operations.'' We also proposed that
the control requirements for Group 1 MPV apply at all times, including
startup and shutdowns.
    For Refinery MACT 2, we proposed alternate standards for three
emission sources for periods of startup or shutdown. We proposed PM
standards for startup of FCCU controlled with an ESP under Refinery
MACT 2 because of safety concerns associated with operating an ESP
during an FCCU startup. For FCCU controlled by an ESP, we proposed a
30-percent opacity limit (on a 6-minute rolling average basis) during
the period that torch oil is used during FCCU startup. For startup of
FCCU without a post-combustion device under Refinery MACT 2, we
proposed a CO standard based on an excess oxygen concentration of 1
volume percent (dry basis) based on a 1-hour average. For periods of
SRU shutdown, we proposed to allow diverting the SRU purge gases to a
flare meeting the design and operating requirements in 40 CFR 63.670
(or, for a limited transitional time period, 40 CFR 63.11) or to a
thermal oxidizer operated at a minimum temperature of
1,200[emsp14][deg]F and a minimum outlet oxygen concentration of 2
volume percent (dry basis). For other emission sources in Refinery MACT
2, we proposed that the requirements that apply during normal
operations should apply during startup and shutdown.
2. How did the SSM provisions change since proposal?
a. Refinery MACT 1
    We proposed that when process equipment is opened to the atmosphere
(e.g., for maintenance), the existing MPV emissions limits apply. In
this final rule, we are instead finalizing startup and shutdown
provisions that apply to these venting events. These startup and
shutdown provisions are work practice standards that allow refinery
owners or operators to open process equipment

during startup and shutdown provided that the equipment is drained and
purged to a closed system until the hydrocarbon content is less than or
equal to 10-percent of the LEL. For those situations where 10-percent
LEL cannot be demonstrated (no direct measurement location), the
equipment may be opened and vented to the atmosphere if the pressure is
less than or equal to 5 psig. Active purging of the equipment is only
allowed after the 10-percent LEL level is achieved, regardless of the
pressure of the equipment/vessel. We are establishing a separate
requirement for very small process equipment, defined as equipment
where it is physically impossible to release more than 72 lbs VOC per
equipment opening based on the size and contents of the equipment. This
definition is consistent with the Group 1 applicability cutoff for
control of miscellaneous process vents. We also developed requirements
specific to catalyst changeout activities where pyrophoric catalyst
(e.g., hydrotreater or hydrocracker catalysts) must be purged using
recovered hydrogen. These provisions include: Documenting the
procedures for equipment openings and procedures for verifying that
events meet the specific conditions above using site procedures used to
de-inventory equipment for safety purposes (i.e., hot work or vessel
entry procedures) and documenting any deviations from the work practice
standard requirements.
b. Refinery MACT 2
    We are expanding the proposed 1-percent minimum oxygen operating
limit alternative for organic HAP to apply for all FCCU startup and
shutdown events (rather than only partial burn FCCU with CO boilers
during startup). We are replacing the proposed opacity limit
alternative to the metal HAP standard with a minimum cyclone face
velocity limit and we are extending that alternative limit to all FCCU
(regardless of control device) for both startup and shutdown in this
final rule.
    We are extending the proposed alternative for SRU to monitor
incinerator temperature and excess oxygen limits during SRU shutdowns
to also apply during periods of startup.
3. What key comments did we receive on the SSM revisions and what are
our responses?
a. Refinery MACT 1
    Comment: Many commenters stated that the proposed extension of the
MPV definition to episodic maintenance startup and shutdown vents and
elimination of the SSM exception for storage tanks would create
hundreds or thousands of new vents per refinery per year and generate
massive on-going burdens. The commenters argued that the EPA has not
included in the record any analysis of the potential environmental
benefits, costs or operational and compliance feasibility and impacts
associated with this requirement and that many of these requirements
will result in delayed and extended equipment and process outages. One
commenter asserted that the EPA has articulated no justification for
applying emission standards to these events, nor any analysis
consistent with CAA section 112 for a determination that MACT standards
are appropriately applied to these emission events under the criteria
in CAA section 112(d).
    Many commenters stated that every time a vessel is opened for
inspection or maintenance each vent point will have to be evaluated as
a potential MPV or storage tank vent. If a particular vent point (e.g.,
bleeder) used for maintenance, startup or shutdown handles material
that is initially greater than 20 ppm HAP, then it is a MPV. If there
is a potential to emit greater than or equal 72 lbs/day of VOC, then it
is a Group 1 MPV and must be controlled. If there is a potential of
less than 72 lb/day VOC release, then it is a Group 2 MPV and subject
to recordkeeping requirements. Commenters stated that in a refinery
there would be tens or more such activities per day associated with
normal maintenance and inspection; during turnarounds, there could be
hundreds of such MPVs. Commenters added that these MPVs may then need
to be individually accounted for and permitted creating an unnecessary
permitting and recordkeeping burden for these periodic emissions.
    Commenters recommended a general set of work practice requirements
for maintenance, startup and shutdown of vents, based on state
requirements, that do not impose the permitting, notice and evaluation
requirements associated with identifying these vents individually.
Commenters explained that states have dealt with these episodic vents
by establishing them as a special class of process vent with limited
recordkeeping requirements and subject to a work practice standard,
rather than the normal MPV requirements. A key element of these work
practices is clear identification of the criteria for releasing these
vents to the atmosphere and for routing these vents to control after
hydrocarbon is reintroduced, which the commenters asserted the current
rule does not provide. Commenters proposed that a work practice
standard could include removing process liquids to the extent practical
and depressuring smaller volume equipment until a pressure of <5 psig
is achieved and/or purging and depressuring to a control device until
the vent has a hydrocarbon concentration of less than 10-percent of the
LEL. The commenters suggested that these standards should provide clear
easily monitored criteria for when this equipment can be vented to the
atmosphere, and should not impose the permitting, notice and evaluation
requirements associated with identifying these vents as individual
MPVs. One commenter provided draft regulatory language for a work
practice requirement.
    Response: We proposed to eliminate the episodic and non-routine
emission exclusion in order to ensure that the MACT includes emission
limits that apply at all times consistent with the holding in Sierra
Club. At the time of the proposal, we expected that essentially all SSM
event emissions would be routed to flares that are subject to the MACT
standards and, thus, would serve to control these emissions. However,
we recognize that maintenance activities that require equipment
openings are a separate class of startup/shutdown emissions because
there must be a point in time when the vessel can be opened and any
emissions vented to the atmosphere. We acknowledge that it would
require a significant effort to identify and characterize each of these
potential release points for permitting purposes.
    In considering these comments and whether we should establish a
separate limit that would apply to these equipment openings, we
reviewed state permit requirements and the practices employed by the
best performing sources. We found that some state or local agencies
required depressuring to 5 psig prior to atmospheric releases while
others required the gases to have organic concentrations at or below
10-percent of LEL prior to atmospheric venting. In the final rule, we
are establishing a requirement that prior to opening process equipment
to the atmosphere, the equipment must first be drained and purged to a
closed system so that the hydrocarbon content is less than or equal to
10-percent of the LEL. For those situations where 10-percent LEL cannot
be demonstrated, the equipment may be opened and vented to the
atmosphere if the pressure is less than or equal to 5 psig, provided
there is no active purging of the equipment to the atmosphere until the
LEL criterion is met. For equipment where it is not technically
possible to depressurize to a

control system, we allow venting to the atmosphere where there is no
more than 72 lbs VOC per day potential, consistent with our Group 1
applicability cutoff for control of process vents. For catalyst
changeout activities where hydrotreater pyrophoric catalyst must be
purged we have provided limited allowances for direct venting.
Provisions to demonstrate compliance with this work practice include
documenting the procedures for equipment openings and procedures for
verifying that events meet the specific conditions above using site
procedures used to de-inventory equipment for safety purposes (i.e.,
hot work or vessel entry procedures).
b. Refinery MACT 2
    Comment: Several commenters noted that there was a proposed
specific alternative metal HAP/PM standard for startup of an FCCU
controlled with an ESP, but took issue with the fact that no
alternative PM limits were proposed for startup of FCCU equipped with
other types of PM controls, or for any FCCU during periods of shutdown
or hot standby. Regarding the proposed alternative for startup, which
would provide an alternative in the form of an opacity limit when torch
oil is in use, commenters stated that there are serious process safety
concerns which prevent most FCCU ESPs from being operated when torch
oil is in the regenerator, that is, during periods of startup, shutdown
and hot standby. To avoid the possibility of a fire and explosion, the
commenters claimed ESPs are usually de-energized and bypassed during
these periods and, consequently, these FCCUs are generally unable to
meet the proposed 30-percent opacity limit.
    Several commenters stated that the EPA's limits on FCCU opacity
during SSM are unreasonable and ignore the technical requirements for
transitional operations of those units. The commenters indicated that
they have ESPs located downstream of the CO boiler and claimed that for
safety reasons the CO boiler cannot operate during startup, shutdown or
hot standby. Further, a commenter indicated that the ESP cannot operate
if the CO boiler is not operating and thus both the CO boiler and the
ESP must be bypassed during startup, shutdown, and hot standby
operations.
    Another commenter stated that the EPA offers no data to support the
achievability of this requirement in practice and discusses information
for 26 startup/shutdown events that found that none complied with a 30-
percent opacity requirement. Several commenters also noted that
experience has shown that the 30-percent opacity limit is unachievable
during these periods for FCCUs controlled with tertiary cyclones, when
regenerator gas flow is below cyclone minimum design flow.
    Several commenters suggested that the EPA establish a standard
based on the operation of FCCU catalyst regenerators' internal cyclones
that function to retain the catalyst in the regenerators and thereby
minimize catalyst and metal HAP emissions from the regenerators.
Additional control to meet the Refinery MACT 2 emission limit of not
more than 1.0 lb PM/1,000 lbs coke burn-off is provided by a bag house,
wet gas scrubber (WGS), ESP or tertiary (external) cyclone. The
efficiency of a cyclone is a function of the inlet gas velocity.
Assuring adequate velocity to the internal cyclones ensures that the
catalyst sent to these additional controls is minimized and ensures
that they are operating as effectively as possible. Similarly, even if
the FCCU cannot meet the normal opacity limits during startup, shutdown
or hot standby (e.g. due to the ESP being off-line for safety reasons
or the tertiary cyclones or WGS operating at non-routine conditions),
assuring adequate velocity to the internal regenerator cyclones will
control and minimize particulate emissions. Several commenters stated
support for another commenter's position that all FCCUs should be
allowed the option of complying with a 20 feet/second minimum inlet
velocity to the primary regenerator cyclones during periods of startup
and shutdown, including hot standby, and these commenters provided
additional technical explanations in their comments.
    On the other hand, some commenters seemed to support the proposed
opacity limits, but suggested minor revisions. One commenter noted that
the SCAQMD has granted Valero's request for variances from visible
emission standards during startup of the FCCU of up to 65-percent
opacity for up to five minutes, in aggregate, during any 1-hour period,
and 30-percent as an hourly average for the remaining period, during
startup events. The application of this variance reflects the
unavailability and/or ineffectiveness of the ESP during the startup
condition. Another commenter recommended that either the opacity
standard should be raised or the time period for averaging should be
extended so FCCUs can be operated safely during SSM events and still
remain in compliance.
    Response: We have reviewed the data submitted by the commenters to
support their assertion that the 30-percent opacity limit (determined
on a 6-minute average basis) is not achievable during startup and
shutdown events. While the data are limited, and it is unclear if the
data provided are indicative of the performance achieved by the best
performing sources, we do not have adequate data to refute the
assertion that the 30-percent opacity limit (determined on a 6-minute
average basis) is not achievable during startup and shutdown events. We
considered the two options suggested by the commenters, the minimum
velocity for the internal FCCU regenerator cyclones and the 30-percent
hourly average opacity limit excluding 5 minutes not exceeding 65-
percent opacity. Again, due to the limited data available during
startup and shutdown events, we are not able to determine which
requirement would provide greater HAP emissions reduction. However, we
note that some facilities may not be required to have an opacity
monitoring system in place and opacity monitoring is not applicable for
FCCU controlled with wet scrubbers. Therefore, we find that the minimum
internal cyclone inlet velocity requirement is more broadly applicable
than the opacity limit. Also, based on the data provided by the
commenters, the minimum internal cyclone inlet velocity requirement
will provide PM (and therefore metal HAP) emissions reductions during
startup and shutdown periods. Therefore, considering the available
data, we conclude that MACT for FCCU startup and shutdown events is
maintaining the minimum internal cyclone inlet velocity of 20 feet/
second.
    Comment: Several commenters stated that the EPA should provide
alternate standards for startups of FCCU equipped with CO boilers and
for any FCCU during periods of shutdown and hot standby. The commenters
stated that the EPA incorrectly assumes that refiners are able to
safely and reliably start up their FCCU with flue gas boilers in
service and meet the normal operating limit of 500 ppm CO. They claimed
that most refiners are unable to reliably start up their FCCU with flue
gas boilers in service due to the design of the boiler and the fact
that many boilers are not able to safely and reliably handle the
transient FCCU operations that can occur during startup, shutdown, and
hot standby. One commenter stated that FCCU built with CO boilers
experience issues with flame stability due to fluctuating flue gas
compositions and rates when starting up and shutting down. Accordingly,
the commenter stated, startup and shutdown activities at FCCU using a
boiler as an APCD are not currently meeting the Refinery MACT 2
standard

of 500 ppm CO on a 1-hour basis, and this level of control does not
qualify as the MACT floor. The commenter gave examples of facilities
where FCCU, including those equipped with post-combustion control
systems, do not consistently demonstrate compliance with a 500 ppm CO
concentration standard during all startup and shutdown events.
    Commenters stated that reliable boiler operation is critical to the
overall refinery steam system and refineries must avoid jeopardizing
boiler operation to prevent major upsets of process operations. A major
upset or site-wide shutdown could result in flaring and emissions of
HAP far in excess of that emitted while bypassing the CO boiler.
    Commenters stated that combustion of torch oil in the FCCU
regenerator during startup is one of the primary reasons the CO limit
cannot be met during these operations. Torch oil is also used during
shutdown to control the cooling rate (and potential equipment damage)
and during hot standby and, thus, the normal CO standard cannot be met
at these times either. Hot standby is used to hold an FCCU regenerator
at operating temperature for outages where a regenerator shutdown is
not needed and to avoid full FCCU shutdowns. Full cold shutdown also
increases personnel exposures associated with removing catalyst and
securing equipment. Additionally, this can produce additional emissions
over maintaining the unit in hot standby. Commenters claimed that
because of the variability of CO during torch oil operations, it is not
possible for the EPA to establish a CAA section 112(d) standard for
startup and shutdown activities at FCCU because refineries cannot
measure a constant level of emissions reductions.
    The commenters recommended expansion of the proposed standard of
greater than 1-percent hourly average excess regenerator oxygen to all
FCCU, including units with fired boilers. These commenters suggested
that maintaining an adequate level of excess oxygen for the combustion
of fuel in the regenerator is the best way to minimize CO and organic
HAP emissions from FCCU during these periods.
    Response: After reviewing the comments and discussing CO boiler
operations with facility operators, we agree that the 1-percent minimum
oxygen limit should be more broadly applicable to FCCU startup and
shutdown regardless of the control device configuration and have
revised the final rule accordingly.
    Comment: Several commenters stated that the proposed alternative
standards for SRP shutdowns should be extended to startups as well
since the normal SRP emission limitation cannot always be achieved
during SRP startups. Several commenters gave examples of startup
activities where this relief is needed, and noted there may be other
startup activities that also need this relief.
    Response: For the control of sulfur HAP, we determined that
incineration effectively controls these HAP. We were not aware that
there would be unusual sulfur loads in the SRU tail gas during startup.
We agree that the alternative standard we proposed for periods of
shutdown is also the MACT floor for periods of startup because
incineration meeting the limits proposed will achieve the MACT control
requirements for sulfur HAP during periods of either startup or
shutdown even though sulfur loadings during these periods may be
elevated. For many SRU configurations, compliance during normal
operations is demonstrated by monitoring SO2 emissions.
However, during startup and shutdown, high sulfur loadings in the SRU
tail gas entering the incinerator will cause high SO2
emissions even though sulfur HAP emissions are well controlled.
Consequently, the proposed incinerator operating limits provide a
better indication of sulfur HAP control during startup and shutdown
than SO2 emissions. Owners or operators that use
incinerators or thermal oxidizers during normal operations may meet the
site-specific temperature and excess oxygen operating limits that were
determined based on their performance test during periods of startup
and shutdown.
4. What is the rationale for our final approach and final decisions to
address emissions during periods of SSM?
a. Refinery MACT 1
    We did not receive comments regarding the proposed amendments to
Table 6 of subpart CC of 40 CFR part 63; therefore, for the reasons
provided in the preamble to the proposed rule, we finalizing these
amendments as proposed.
    We determined that it was overly burdensome and in most cases
technically infeasible to consider every potential equipment or vessel
opening and classify these ``openings'' (newly classified as MPV in the
proposal) as either Group 1 or Group 2 MPV. We also determined that it
is not always technically feasible, depending on the opening, to
demonstrate compliance with the MPV emissions limitations. After
considering the public comments, we determined it was appropriate to
establish separate startup and shutdown provisions for MPV associated
with process equipment openings. We reviewed state and local
requirements and based the final rule requirements on the emissions
limitations required to be followed by the best performing sources.
Therefore, we are finalizing requirements for refinery owners or
operators to open process equipment during these startup and shutdown
events without directly permitting these ``vents'' as Group 1 or Group
2 MPV provided that the equipment is drained and purged to a closed
system until the hydrocarbon content is less than or equal to 10-
percent of the LEL. As described in further detail previously in this
section, we have provided provisions for special cases where the 10-
percent LEL limit cannot be demonstrated and provisions for less
significant equipment openings, consistent with the practices used by
the best performing facilities.
b. Refinery MACT 2
    We did not receive significant comments regarding the proposed
amendments to Table 44 to subpart UUU of 40 CFR part 63; therefore, we
finalizing these amendments as proposed.
    In response to comments, we determined that the limited provisions
that were provided for startup only or for shutdown only were too
limited and we have expanded the proposed provisions to both startup
and shutdown regardless of control device used. For the FCCU organic
HAP emissions limit, we are finalizing an alternative limit for periods
of startup of no less than 1-percent oxygen in the exhaust gas as
proposed, but we are extending that alternative limit to shutdown and
to all FCCU in this final rule.
    For the FCCU metal HAP emissions limit, we proposed a specific
startup limit for FCCU controlled be an ESP of 30-percent opacity. We
received comments along with limited data suggesting that this limit
was not achievable. Commenters suggested that the best performing units
maintain a minimum face velocity of at least 20 feet/second to minimize
catalyst PM losses during startup and shutdowns. Operators of wet
scrubbers also noted that they cannot maintain pressure drops and that
one cannot meet the PM emissions limit normalized by coke burn-off rate
when the coke burn-off rate approaches zero. Consequently, commenters
stated that the alternative limits should be provided for startup and
shutdown regardless of control device. Upon consideration of the
comments, we determined that it was necessary to revise the proposed

alternative to be based on minimum inlet face velocity to the FCCU
regenerator internal cyclones and provide the alternative for both
startup and shutdown. We also expanded this limit to all FCCU; however,
we also required FCCU with wet scrubbers to meet only the liquid to gas
ratio operating limit during periods of startup and shutdown to allow
wet scrubbers to use a consistent compliance method at all times.
    For SRU, we are finalizing an alternative standard during periods
of startup and shutdown to use a flare that meets the operating limits
included in the final rule or a thermal oxidizer or incinerator
operated at a minimum hourly average temperature of 1,200 [deg]F and a
minimum hourly average outlet oxygen concentration of 2 volume percent
(dry basis). We proposed these alternatives for periods of shutdown
only, but based on comments received regarding startup issues, we
determined that high sulfur loadings can occur during periods of
startup and that the alternative limit proposed was appropriate for
both startup and shutdown.

E. Technical Amendments to Refinery MACT 1 and 2

1. What other amendments did we propose for Refinery MACT 1 and 2?
    We proposed a number of amendments to Refinery MACT 1 and 2 to
address technical issues such as rule language clarifications and
reference corrections. First, we proposed to amend Refinery MACT 1 to
clarify what is meant by ``seal'' for open-ended valves and lines that
are ``sealed'' by the cap, blind flange, plug, or second valve by
stating that sealed means when there are no detectable emissions from
the open-ended valve or line at or above an instrument reading of 500
ppm. Second, we also proposed electronic reporting requirements where
owners or operators of petroleum refineries must submit electronic
copies of required performance test and performance evaluation reports
for compliance with Refinery MACT 1 and 2 by direct computer-to-
computer electronic transfer using EPA-provided software. Third, we
proposed to update the General Provisions Tables 6 (for Refinery MACT
1) and 44 (for Refinery MACT 2) to correct cross references and to
incorporate additional sections of the General Provisions that are
necessary to implement these rules.
2. How did the other amendments for Refinery MACT 1 and 2 change since
proposal?
    We are not finalizing the definition of ``seal'' for open-ended
lines as proposed. We are finalizing changes to update the General
Provisions cross-reference tables as proposed, with one minor change to
provide an option for the administrator to issue guidance on
performance test reporting timeframes in order to address issues
relating to submittal of data to the ERT.
3. What key comments did we receive on the other amendments for
Refinery MACT 1 and 2 and what are our responses?
    Comment: Numerous commenters objected to the proposal to clarify
the meaning of ``seal'' as it relates to open-ended line (OEL)
standards. Commenters contend that there is no basis for the EPA to
assert that the proposed definition merely ``clarifies'' an established
interpretation of the term ``seal'' and stated that the proposed
revision constitutes an illegal change in the requirements for OELs,
and the clarification should not be finalized.
    One commenter stated that none of the MACT standards in place
before this proposal have stated or suggested that a ``sealed'' OEL is
one with detectable emissions below 500 ppm. This commenter added this
unique interpretation of the requirement to ``seal'' an OEL with a cap
or plug is incompatible with the historical interpretation of this
requirement by affected facilities and by the EPA, and the EPA has not
issued any sort of definitive guidance or interpretation setting out
this position. The commenter detailed numerous references to
considerations the EPA has made relative to OEL requirements in LDAR
programs. In addition to the examples cited, the commenter noted that
in 2006, the EPA proposed to add a ``no detectible emissions'' limit
and monitoring requirement for OELs to NSPS VV (71 FR 65317, November
7, 2006). Two commenters noted that the proposed monitoring was not
finalized in either NSPS VV or VVa (72 FR 64860, November 16, 2007)
because it was not considered BDT due to the low emission reductions
and the cost effectiveness of the requirement. Another commenter agreed
that there is no explanation provided for why this information could
now support the need for a new OEL seal standard that requires
monitoring to ensure compliance when it was deemed to be unjustified
previously.
    In addition, the commenter collected OEL monitoring data and
submitted it to the EPA (see Docket Item No. EPA-HQ-OAR-2010-0869-
0058). Based on these data, the commenter asserted that the existence
of leaks from OELs that are not properly sealed is extremely low.
    The commenter noted that the EPA is claiming this change is only a
clarification of current requirements, allowing the EPA to bypass the
need to cite a CAA authorization for this change to the existing CAA
section 112(d)(2) standard or meet the process requirements associated
with such a change, including providing emission reduction, cost and
burden estimates in the record and the associated PRA Information
Collection Request (ICR).
    Several commenters claimed that this clarification would result in
retroactive impact and also addressed the implication of the proposed
change on other fugitive emissions standards. One commenter stated that
the EPA cannot retroactively reinterpret the OEL requirements or define
the word ``seal'' and added that the EPA should account for the
thousands of additional monitoring events per year per refinery that
this new requirement would add to LDAR programs and provide proper cost
justification under CAA sections 112(d)(6) or 112(f)(2).
    Several commenters also stated that the proposed definition will
effectively change all equipment leak rules in parts 40 CFR parts 60,
61 and 63 and the change should not be finalized. One commenter added
that by claiming this change is only a clarification of current
requirements, the EPA would set a precedent applicable to all OELs in
all industries subject to any similar OEL equipment leak requirement.
    Response: We have decided not to finalize the proposed
clarification of the term ``seal'' for OELs at this time. The fenceline
monitoring requirements we are finalizing will detect any significant
leaks from a cap, blind flange, plug or second valve that does not
properly seal an OEL, as well as significant leaks from numerous other
types of fugitive emission sources.
    Comment: A few commenters stated that the proposed use of the ERT
is not appropriate because the costs and burdens imposed are additive
to the costs of producing and submitting the written report, and there
is no benefit that justifies the additional cost. One commenter also
stated that the EPA has not developed or articulated a reasonable
approach to using information that would be uploaded to the ERT. The
commenters recommended that the EPA remove this portion of the proposal
until the ERT is demonstrated to handle all the information from
refinery performance

tests (rather than only portions), thereby eliminating the need for
both written and electronic reporting and until the Agency demonstrates
that it is using the electronic data to develop improved air quality
emission factors.
    Other commenters stated that the ERT requirement does not supersede
or replace any state reporting requirements and thus the regulated
industry will be subject to dual reporting requirements. These
commenters disagreed with the preamble claim that eliminating the
recordkeeping requirements for performance test reports is a burden
savings, and stated that it may duplicate burdens already borne by the
regulated community.
    The commenters expressed further concern that duplicative reporting
requirements will strain the regulated industry to comply with
deadlines established by rule for report submittals. One commenter
stated that there is no mechanism for obtaining extensions for special
circumstances. Under proposed 40 CFR 63.655(h)(9)(i), all reports are
due in 60 days. The commenter claimed that by not referencing reporting
requirements to the General Provisions in 40 CFR 63.10(d)(2), there is
no allowance for obtaining additional time due to unforeseen
circumstances or due to the difficulties involved with completing
particularly complex reports.
    One commenter stated that the primary performance test method
(Method 18) required for determining compliance is not currently
included in the list of methods supported by the ERT. The commenter
stated that the regulated community's experience with Method 18 is that
it is a very broad methodology and can be exceptionally complex to
execute and to report. The commenter stated that the EPA is aware that
Method 18 reporting is complex, that it may be difficult to incorporate
into the ERT, and that no time schedule has been defined for
development or implementation for this method.
    The commenter also stated that without formal notice of changes to
the ERT, the regulated community is at risk of non-compliance. The only
way for the regulated community to know that changes have occurred in
the ERT is to monitor the Web site directly because the EPA does not
formally announce changes to the ERT in the Federal Register. As such,
it would be possible for a regulated entity to be unaware of changes
made such as the incorporation of Method 18. The commenter expressed
concern that the proposal language is an open-ended commitment subject
to change without notice. The commenter stated that the EPA should
clearly indicate when facilities would be required to use the ERT when
new test methods are included in the ERT.
    Response: We disagree that use of the ERT for completing stack test
reports is an added cost and burden. While the requirement to report
the results of stack tests with the ERT does not supersede state
reporting requirements, we are aware of several states that already
require the use of the ERT, and we are aware of more states that are
considering requiring its use. We note that where states will not
accept an electronic ERT submittal, the ERT provides an option to print
the report, and the printed report can be mailed to the state agency.
We have no reason to believe that the time savings in the ability to
reuse data elements within reports does not, at a minimum, offset the
cost incurred by printing out and mailing a copy of the report and the
commenters have provided no support for their cost claims.
    Furthermore, based on the analysis performed for the Electronic
Reporting and Recordkeeping Requirements for the New Source Performance
Standards Rulemaking (ERRRNSPS) (80 FR 15100), electronic reporting
results in an overall cost savings to industry when annualized over a
20-year period. The cost savings is achieved through means such as
standardization of data, embedded quality assurance checks, automatic
calculation routines and reduced data entry through the ability to
reuse data in files instead of starting from scratch with each test. As
outlined in the ERRRNSPS, there are many benefits to electronic
reporting. These benefits span all users of the data--the EPA, state
and local regulators, the regulated entities and the public. We note
that in the preamble to this proposed rule we provided a number of
reasons why the use of the ERT will provide benefit going forward and
that most of the benefits we outlined were longer-term benefits (e.g.,
reducing burden of future information collection requests).
Additionally, we note that in 2011, in response to Executive Order
13563, the EPA developed a plan \13\ to periodically review its
regulations to determine if they should be modified, streamlined,
expanded or repealed in an effort to make regulations more effective
and less burdensome. The plan includes replacing outdated paper
reporting with electronic reporting. In keeping with this plan and the
White House's Digital Government Strategy, \14\ in 2013 the EPA issued
an agency-wide policy specifying that new regulations will require
reports to be electronic to the maximum extent possible. By requiring
electronic submission of stack test reports in this rule, we are taking
steps to implement this policy. We also disagree that we have not
developed or articulated a reasonable approach to using information
that would be uploaded to the ERT. To the contrary, we have discussed
at length our plans for the use of stack test data collected via the
ERT. In 2009, we published an advanced notice of proposed rulemaking
(74 FR 52723) for the Emissions Factors Program Improvements. In that
notice, we first outlined our intended approach for revising our
emissions factors development procedures. This approach included using
stack test data collected with the ERT. We reiterated this position in
our ``Recommended Procedures for the Development of Emissions Factors
and Use of the WebFIRE Database'' (http://www.epa.gov/ttn/chief/efpac/procedures/procedures81213.pdf), which was subject to public notice and
comment before being finalized in 2013. Finally, we discussed uses of
these data in the preamble to the proposed rule and at length in the
preamble to the ERRRNSPS.
---------------------------------------------------------------------------

    \13\ EPA's ``Final Plan for Periodic Retrospective Reviews,''
August 2011. Available at: http://www.epa.gov/regdarrt/retrospective/documents/eparetroreviewplan-aug2011.pdf.
    \14\ Digital Government: Building a 21st Century Platform to
Better Serve the American People, May 2012. Available at: https://www.whitehouse.gov/sites/default/files/omb/egov/digital-government/digital-government-strategy.pdf.
---------------------------------------------------------------------------

    We think that it is a circular argument to say that the agency
should eliminate the use of the ERT until it demonstrates that it is
using the electronic data. It would be impossible for the agency to use
data that it does not have. We can only use electronic data once we
have electronic data. We do note that we are nearing completion of
programming the WebFIRE database with our new emissions factor
development procedures and anticipate running the routines on existing
data sets in the near future.
    We continue to improve and upgrade the ERT on an ongoing basis. The
current version of the ERT supports 41 methods, including EPA Methods
1-4, 5, 5B, 5F, 25A 26, and 26A. We note that the ERT does not
currently support EPA Method 18, and for performance tests using Method
18, the source will still have to produce a paper report. However, we
are aware of the need to add Method 18 to the ERT, and we are currently
looking at developing this capability. As noted in the ERRRNSPS, when
new methods are added to the

ERT, we will not only post them to the Web site; we will also send out
a listserv notice to the Clearinghouse for Inventories and Emissions
Factors (CHIEF) listserv. Information on joining the CHIEF listserv can
be found at http://www.epa.gov/ttn/chief/listserv.html#chief. We are
requiring the use of the ERT if the method is supported by the ERT, as
listed on the ERT Web site (http://www.epa.gov/ttn/chief/ert/ert_info.html) at the time of the test. We do not agree that it is
overly burdensome to check a Web site for updates prior to conducting a
performance test.
    We did revise the MACT 1 and 2 tables referencing reporting
requirements to the general provisions (Table 6 for Refinery MACT 1 and
Table 44 for Refinery MACT 2) to provide flexibility in the 60-day
reporting timeline to accommodate unforeseen circumstances or
difficulties involved with completing particularly complex reports.
4. What is the rationale for our final approach and final decisions for
the other amendments for Refinery MACT 1 and 2?
    We are not finalizing the definition of seal, as proposed. The
fenceline monitoring work practice standard will detect any significant
leaks from a cap, blind flange, plug or second valve that does not
properly seal an OEL, as well as significant leaks from numerous other
types of fugitive emission sources.
    We are finalizing requirements for electronic reporting, as
proposed, with a minor clarification. Specifically, we are revising
Tables 6 in subpart CC and 44 in subpart UUU, which cross-reference the
applicable provisions in the General Provisions to provide flexibility
in the ERT 60-day reporting timeline. Refiners can seek approval from
the EPA or a delegated state additional time for submittal of data due
to unforeseen circumstances or due to the difficulties involved with
completing particularly complex reports.

F. Technical Amendments to Refinery NSPS Subparts J and Ja

1. What amendments did we propose for Refinery NSPS Subparts J and Ja?
    We proposed a number of amendments to Refinery NSPS subparts J and
Ja to address reconsideration issues and minor technical
clarifications. First, we proposed revisions to 40 CFR 60.100a(b) to
include a provision that sources subject to Refinery NSPS subpart J
could elect to comply instead with the provisions of Refinery NSPS
subpart Ja.
    Second, we proposed a series of amendments to the requirements for
SRP in 40 CFR 60.102a, to clarify the applicable emission limits for
different types of SRP based on whether oxygen enrichment is used. The
amendments proposed also clarified that emissions averaging across a
group of emission points within a given SRP is allowed for each of the
different types of SRP, and that emissions averaging is specific to the
SO2 or reduced sulfur standards (and not to the 10 ppmv
hydrogen sulfide (H2S) limit). We also proposed a series of
corresponding amendments in 40 CFR 60.106a to clarify the monitoring
requirements, particularly when oxygen enrichment or emissions
averaging is used. We also proposed clarifications in 40 CFR 60.106a to
consistently use the term ``reduced sulfur compounds'' when referring
to the emission limits and monitoring devices needed to comply with the
reduced sulfur compound emission limits for sulfur recovery plants with
reduction control systems not followed by incineration.
    Third, we proposed amendments to 40 CFR 60.102a(g)(1) to clarify
that CO boilers, while part of the FCCU affected facility, can also be
FGCD.
    Fourth, we proposed several revisions to 40 CFR 60.104a to clarify
the performance testing requirements. We proposed revision to 40 CFR
60.104a(a) to clarify that an initial compliance demonstration is
needed for the H2S concentration limit in 40 CFR 60.103a(h).
We proposed revisions to the annual PM testing requirement in 40 CFR
60.104a(b) to clarify that annually means once per calendar year, with
an interval of at least 8 months but no more than 16 months between
annual tests. We also proposed to amend 40 CFR 60.104a(f) to clarify
that the provisions of that paragraph are specific to owners or
operators of an FCCU or FCU that use a cyclone to comply with the PM
emissions limit in 40 CFR 60.102a(b)(1) and not to facilities electing
to comply with the PM emissions limit using a PM CEMS. We also proposed
to amend 40 CFR 60.104a(j) to delete the requirements to measure flow
for the H2S concentration limit for fuel gas.
    Fifth, we proposed several amendments to clarify the requirements
for control device operating parameters in 40 CFR 60.105a.
Specifically, we proposed amendments to 40 CFR 60.105a(b)(1)(ii)(A) to
require corrective action be completed to repair faulty (leaking or
plugged) air or water lines within 12 hours of identification of an
abnormal pressure reading during the daily checks. We also proposed
revisions to 40 CFR 60.105a(i) to specify that periods when abnormal
pressure readings for a jet ejector-type wet scrubber (or other type of
wet scrubber equipped with atomizing spray nozzles) are not corrected
within 12 hours of identification and periods when a bag leak detection
system alarm (for a fabric filter) is not alleviated within the time
period specified in the rule are considered to be periods of excess
emissions.
    We also proposed amendments to 40 CFR 60.105(b)(1)(iv) and
60.107a(b)(1)(iv) to provide flexibility in span range to accommodate
different manufacturers of the length-of-stain tubes. We also proposed
to delete the last sentence in 40 CFR 60.105(b)(3)(iii).
    Finally, we proposed clarification to the performance test
requirements for the H2S concentration limit for affected
flares in 40 CFR 60.107a(e)(1)(ii) and (e)(2)(ii) to remove the
distinction between flares with or without routine flow.
2. How did the amendments to Refinery NSPS Subparts J and Ja change
since proposal?
    We are making very few changes to the amendments proposed for
Refinery NSPS subparts J and Ja. In response to comments, we are
revising the NSPS requirements to replace the ``measurement
sensitivity'' requirements with accuracy requirements consistent with
those used in Refinery MACT 1 and 2. Specifically, we are revising 40
CFR 60.106a(a)(6)(i)(B) and (7)(i)(B) to require use of a flow sensor
meeting an accuracy requirement of 5-percent over the
normal range of flow measured or 10-cubic-feet-per-minute, whichever is
greater. We are also revising the flare accuracy requirements in 40 CFR
60.107a(f)(1)(ii) to require use of a flow sensor meeting an accuracy
requirement of 20-percent of the flow rate at velocities
ranging from 0.1 to 1 feet per second and an accuracy of 5-
percent of the flow rate for velocities greater than 1-feet-per-second.
    Finally, we are revising 40 CFR 60.101a(b) to correct an
inadvertent error where the phrase ``and delayed coking units'' was not
included in the proposed sentence revision.
3. What key comments did we receive on the amendments to Refinery NSPS
Subparts J and Ja and what are our responses?
    Comment: Two commenters noted concern with the term ``measurement
sensitivity'' in proposed 40 CFR 60.106a(a)(6)(i)(B) and (a)(7)(i)(B)
for sulfur recovery unit monitoring alternatives and in existing
regulations 40 CFR 60.107a(f)(1)(ii) for flares because ``sensitivity''
is not a term

found on typical monitoring system data sheets. Typical flow meter
characteristics include terms such as accuracy and resolution and the
commenters requested that the EPA revise the terminology to match the
wording found in 40 CFR part 63, subpart CC, Table 13 for flow meters
(i.e., accuracy requirements). Additionally, several commenters
suggested that the EPA flow monitor accuracy specifications are
inconsistent with those in the SCAQMD Flare Rule and many refinery
consent decrees. The commenters recommended revising both the flare
flow meter sensitivity specification and accuracy specification in
Refinery MACT 1 Table 13 and in Refinery NSPS subpart Ja to be
consistent with the accuracy specification from the Shell Deer Park
Consent Decree, Appendix 1.10, which specifies the required flare flow
meter accuracy as ``20% of reading over the velocity range
of 0.1-1 feet per second (ft/s) and 5% of reading over the
velocity range of 1-250 ft/s.''
    Response: We proposed the term ``measurement sensitivity'' in
proposed 40 CFR 60.106a(a)(6)(i)(B) and (a)(7)(i)(B) to be internally
consistent within Refinery NSPS subpart Ja [i.e., consistent with the
existing language in Sec.  60.107a(f)(1)(ii)]. However, we agree with
the commenters that this term may be unclear. This term is not defined
in Refinery NSPS subpart Ja and it is not commonly used in the flow
monitoring system's technical specification sheets. Therefore, to be
consistent with the terminology used by instrument vendors and used in
Refinery MACT 1 and 2, we are revising these sections to replace the
term ``measurement sensitivity'' with ``accuracy.'' We are also
revising the flow rate accuracy provisions specific for flares to
provide an accuracy requirement of 20-percent over the
velocity range of 0.1-1 ft/s and 5% for velocities
exceeding 1 ft/s in 40 CFR 60.107a(f)(1)(ii) and in Table 13 of subpart
CC. We are providing this provision specifically for flares because
they commonly operate at high turndown ratios. For other flow
measurements, we are retaining the 10-cubic-foot-per-minute accuracy
requirement. We are also clarifying that the 5-percent
accuracy requirement for the SRU alternatives apply to the ``the normal
range of flow measured'' consistent with the requirements in Refinery
MACT 1 and 2.
    Comment: One commenter stated that in the proposed revisions to 40
CFR 60.100a, (79 FR 36956), the EPA proposes to remove the phrase ``and
delayed coker units'' from 40 CFR 60.100a(b). However, we state the
compliance date for both flares and delayed coker units separately in
the same paragraph. The commenter believes the EPA should explain the
reason for and implications of the removal of this phrase.
    Response: The removal of the phrase ``and delayed coking units''
from the first sentence in 40 CFR 60.100a(b) was an inadvertent error.
The only revision that we intended to make in 40 CFR 60.100a was to
allow owners or operators subject to subpart J to elect to comply with
the requirements in subpart Ja. In the final amendments, we have
included the phrase ``and delayed coking units'' in the first sentence
in 40 CFR 60.100a(b).
4. What is the rationale for our final approach and final decisions for
the amendments to Refinery NSPS Subparts J and Ja?
    We are finalizing amendments for Refinery NSPS subparts J and Ja as
proposed with minor revisions. In response to comments, we are revising
the ``measurement sensitivity'' requirements to be an ``accuracy''
requirement. This change will make the requirements more clear and
consistent between the flow meter requirements in the NSPS and the MACT
standards since the same flow meter will be subject to each of these
requirements. We are also providing a dual accuracy requirement for
flare flow meters. This accuracy requirement is necessary because
flares, which can have large diameters to accommodate high flows, are
commonly operated at low flow rates. Together, this makes it
technically infeasible for many flares to meet the lower flow 10 cfm
accuracy requirement. Therefore, we are providing specific accuracy
requirements for flares of 20-percent over the velocity
range of 0.1-1 ft/s and 5-percent for velocities exceeding
1 ft/s, consistent with recent consent decrees and equipment vendor
specifications.
    Finally, we are revising the introductory phrase in the first
sentence in 40 CFR 60.101a(b) to read ``Except for flares and delayed
coking units . . .'' to correct an inadvertent error. We intended to
revise this sentence only to include the proposed provision to allow
sources subject to Refinery NSPS subpart J to comply with Refinery NSPS
subpart Ja. The redline text posted on our Web site showed no revisions
to this introductory phrase, but the amendatory text did not include
the words ``and delayed coking units'' in this phrase. This was an
inadvertent error, which we are correcting in the final rule.

V. Summary of Cost, Environmental and Economic Impacts and Additional
Analyses Conducted

A. What are the affected facilities, the air quality impacts and cost
impacts?

    The sources affected by significant amendments to the petroleum
refinery standards include flares, storage vessels, pressure relief
devices, fugitive emissions and DCU. The amendments for other sources
subject to one or more of the petroleum refinery standards are expected
to have minimal air quality and cost impacts.
    The total capital investment cost of the final amendments and
standards is estimated at $283 million, $112 million from the final
amendments for storage vessels, DCU and fenceline monitoring and $171
million from standards to ensure compliance. We estimate annualized
costs of the final amendments for storage vessels, DCU and fenceline
monitoring to be approximately $13.0 million, which includes an
estimated $11.0 million for recovery of lost product and the annualized
cost of capital. We also estimated annualized costs of the final
standards to ensure compliance to be approximately $50.2 million. The
final amendments for storage vessels, DCU and fenceline monitoring
would achieve a nationwide HAP emission reduction of 1,323 tpy, with a
concurrent reduction in VOC emissions of 16,660 tpy and a reduction in
methane emissions of 8,700 metric tonnes per year. Table 2 of this
preamble summarizes the cost and emission reduction impacts of the
final amendments, and Table 3 of this preamble summarizes the costs of
the final standards to ensure compliance.

                                                 Table 2--Nationwide Impacts of Final Amendments (2010$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                 Total
                                               annualized    Product       Total       Methane
                                    Total         cost       recovery    annualized    emission       VOC           Cost          HAP           Cost
        Affected source            capital      without       credit       costs      reductions    emission   effectiveness    emission   effectiveness
                                  investment     credit    (million $/  (million $/    (metric     reductions   ($/ton VOC)    reductions   ($/ton HAP)
                                 (million $)  (million $/      yr)          yr)          tpy)        (tpy)                       (tpy)
                                                  yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Storage Vessels................         18.5         3.13       (8.16)       (5.03)  ...........       14,600         (345)           910       (5,530)
Delayed Coking Units...........           81         14.5       (2.80)         11.7        8,700        2,060         5,680           413        28,330
Fugitive Emissions (Fenceline           12.5         6.36  ...........         6.36  ...........  ...........  .............  ...........  .............
 Monitoring)...................
                                ------------------------------------------------------------------------------------------------------------------------
    Total......................          112         24.0       (11.0)         13.0        8,700       16,660           780         1,323         9,830
--------------------------------------------------------------------------------------------------------------------------------------------------------

                   Table 3--Nationwide Costs of Final Amendments To Ensure Compliance (2010$)
----------------------------------------------------------------------------------------------------------------
                                                                       Total
                                                   Total capital    annualized        Product          Total
                 Affected Source                    investment     cost without      recovery       annualized
                                                    (million $)       credit          credit      costs (million
                                                                  (million $/yr)  (million $/yr)       $/yr)
----------------------------------------------------------------------------------------------------------------
Relief Device Monitoring........................            11.1             3.3  ..............             3.3
Flare Monitoring................................             160            46.5  ..............            46.5
FCCU Testing....................................  ..............             0.4  ..............             0.4
                                                 ---------------------------------------------------------------
    Total.......................................             171            50.2  ..............            50.2
----------------------------------------------------------------------------------------------------------------

    The impacts shown in Table 2 do not include costs, product recovery
credits, or emissions reductions associated with any root cause
analysis or corrective action taken in response to the final amendments
for fenceline monitoring. The impacts shown in Table 3 do not include
(i) the costs or emissions reductions associated with any root cause
analysis and corrective action taken in response to the final source
performance testing at the FCCUs, or (ii) emissions reductions
associated with corrective action taken in response to pressure relief
device or (iii) emissions reductions associated with the flare
operating and monitoring provisions. The operational and monitoring
requirements for flares at refineries have the potential to reduce
excess emissions from flares by up to approximately 3,900 tpy of HAP
and 33,000 tpy of VOC. The operational and monitoring requirements for
flares also have the potential to reduce methane emissions by 25,800
metric tonnes per year while increasing emissions of carbon dioxide
(CO2) and nitrous oxide by 267,000 metric tonnes per year and 2 metric
tonnes per year, respectively, yielding a net reduction in GHG
emissions of 377,000 metric tonnes per year of CO2 equivalents
(CO2e).

B. What are the economic impacts?

    We performed a national economic impact analysis for petroleum
product producers. All petroleum product refiners will incur annual
compliance costs of less than 1-percent of their sales. For all firms,
the minimum cost-to-sales ratio is <0.01-percent; the maximum cost-to-
sales ratio is 0.87-percent; and the mean cost-to-sales ratio is 0.03-
percent. Therefore, the overall economic impact of this proposed rule
should be minimal for the refining industry and its consumers.
    In addition, the EPA performed a screening analysis for impacts on
small businesses by comparing estimated annualized engineering
compliance costs at the firm-level to firm sales. The screening
analysis found that the ratio of compliance cost to firm revenue falls
below 1-percent for the 28 small companies likely to be affected by the
proposal. For small firms, the minimum cost-to-sales ratio is <0.01-
percent; the maximum cost-to-sales ratio is 0.62-percent; and the mean
cost-to-sales ratio is 0.07-percent.
    More information and details of this analysis is provided in the
technical document ``Economic Impact Analysis for Petroleum Refineries
Proposed Amendments to the National Emissions Standards for Hazardous
Air Pollutants'', which is available in the docket for this rule
(Docket ID No. EPA-HQ-OAR-2010-0682).

C. What are the benefits?

    The final rule is anticipated to result in a reduction of 1,323 tpy
of HAP (based on allowable emissions under the MACT standards) and
16,660 tpy of VOC, not including potential emission reductions that may
occur as a result of the operating and monitoring requirements for
flares and fugitive emission sources via fenceline monitoring. These
avoided emissions will result in improvements in air quality and
reduced negative health effects associated with exposure to air
pollution of these emissions; however, we have not quantified or
monetized the benefits of reducing these emissions for this rulemaking.

D. Impacts of This Rulemaking on Environmental Justice Populations

    To examine the potential impacts on vulnerable populations
(minority, low-income and indigenous communities) that might be
associated with the Petroleum Refinery source categories addressed in
this final rule, we evaluated the percentages of various social,
demographic and economic groups in the at-risk populations living near
the facilities where these sources are located and compared them to
national averages. Our analysis of the demographics of the population
with estimated risks greater than 1-in-1 million indicates potential
disparities in risks between demographic groups including the African
American, Other and Multiracial, Hispanic, Below the Poverty Level, and
Over 25 without a High School Diploma when compared to the nationwide
percentages of those groups. These groups will benefit the most from
the emission reductions achieved by this final rulemaking, which is
projected to result in 1 million fewer people exposed to risks greater
than 1-in-1 million.
    Additionally, these communities will benefit from this rulemaking,
as this rulemaking for the first time ever requires fenceline
monitoring, and reporting of fenceline data. The agency during the pre-
proposal period and

during the comment period received feedback from communities on the
importance of having fenceline monitoring in their communities and the
importance of communities having access to this data. The EPA believes
that vulnerable communities will benefit from this data and the
requirements that EPA has put in place in this rulemaking to manage
fugitive emissions.

E. Impacts of This Rulemaking on Children's Health

    Under Executive Order 13045 the EPA must evaluate the effects of
the planned regulation on children's health and safety. This action's
health and risk assessments are contained in section IV.A of this
preamble. We believe we have adequately estimated risk for children,
and we do not believe that the environmental health risks addressed by
this action present a disproportionate risk to children. When the EPA
derives exposure reference concentrations and unit risk estimates (URE)
for HAP, it also considers the most sensitive populations identified
(i.e., children) in the available literature, and importantly, these
are the values used in our risk assessments. With regard to children's
potentially greater susceptibility to non-cancer toxicants, the
assessments rely on the EPA (or comparable) hazard identification and
dose-response values which have been developed to be protective for all
subgroups of the general population, including children. With respect
to cancer, the EPA uses the age-dependent adjustment factor approach,
and applies these factors to carcinogenic pollutants that are known to
act via mutagenic mode of action. Further details are provided in the
``Final Residual Risk Assessment for the Petroleum Refining Source
Sector'', Docket ID No. EPA-HQ-OAR-2010-0682.

VI. Statutory and Executive Order Reviews

A. Executive Orders 12866: Regulatory Planning and Review and Executive
Order 13563: Improving Regulation and Regulatory Review

    This action is an economically significant regulatory action that
was submitted to the Office of Management and Budget (OMB) for review.
Any changes made in response to OMB recommendations have been
documented in the docket. The EPA prepared an analysis of the potential
costs and benefits associated with this action. This analysis,
``Economic Impact Analysis: Petroleum Refineries--Final Amendments to
the National Emissions Standards for Hazardous Air Pollutants and New
Source Performance Standards'' is available in Docket ID Number EPA-HQ-
OAR-2010-0682.

B. Paperwork Reduction Act (PRA)

    The information collection requirements in this rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act, 44 U.S.C. 3501 et se. The
information collection requirements are not enforceable until OMB
approves them.
    Adequate recordkeeping and reporting are necessary to ensure
compliance with these standards as required by the CAA. The ICR
information collected from recordkeeping and reporting requirements is
also used for prioritizing inspections and is of sufficient quality to
be used as evidence in court.
    The ICR document prepared by the EPA for the amendments to the
Petroleum Refinery MACT standards for 40 CFR part 63, subpart CC has
been assigned the EPA ICR number 1692.08. Burden changes associated
with these amendments would result from new monitoring, recordkeeping
and reporting requirements. The estimated annual increase in
recordkeeping and reporting burden hours is 99,722 hours; the frequency
of response is quarterly and semiannual for reports for all respondents
that must comply with the rule's reporting requirements; and the
estimated average number of likely respondents per year is 95 (this is
the average in the second year). The cost burden to respondents
resulting from the collection of information includes the total capital
cost annualized over the equipment's expected useful life (about $18
million, which includes monitoring equipment for fenceline monitoring,
pressure relief devices, and flares), a total operation and maintenance
component (about $21 million per year for fenceline and flare
monitoring), and a labor cost component (about $8.3 million per year,
the cost of the additional 99,722 labor hours). Burden is defined at 5
CFR 1320.3(b).
    The ICR document prepared by the EPA for the amendments to the
Petroleum Refinery MACT standards for 40 CFR part 63, subpart UUU has
been assigned the EPA ICR number 1844.06. Burden changes associated
with these amendments would result from new testing, recordkeeping and
reporting requirements being finalized with this action. The estimated
average burden per response is 25 hours; the frequency of response
ranges from annually up to every 5 years for respondents that have
FCCU, and the estimated average number of likely respondents per year
is 67. The cost burden to respondents resulting from the collection of
information includes the performance testing costs (approximately
$778,000 per year over the first 3 years for the initial PM and one-
time HCN performance tests and $235,000 per year starting in the fourth
year), and a labor cost component (approximately $410,000 per year for
4,940 additional labor hours). Burden is defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9. When this ICR is
approved by OMB, the Agency will publish a technical amendment to 40
CFR part 9 in the Federal Register to display the OMB control number
for the approved information collection requirements contained in this
final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic
impact on a substantial number of small entities (SISNOSE) under the
RFA. The small entities subject to the requirements of this action are
small businesses, small organizations and small governmental
jurisdictions. For purposes of assessing the impacts of this rule on
small entities, a small entity is defined as: (1) A small business in
the petroleum refining industry having 1,500 or fewer employees (Small
Business Administration (SBA), 2011); (2) a small governmental
jurisdiction that is a government of a city, county, town, school
district or special district with a population of less than 50,000; and
(3) a small organization that is any not-for-profit enterprise which is
independently owned and operated and is not dominant in its field.
Details of this analysis are presented in the economic impact analysis
which can be found in the docket for this rule (Docket ID No. EPA-HQ-
OAR-2010-0682).

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. As discussed
earlier in this preamble, these amendments result in nationwide costs
of $63.2 million per year for the private sector. Additionally, the
rule contains no requirements that apply to small

governments and does not impose obligations upon them.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    This action does not have tribal implications, as specified in
Executive Order 13175. The final amendments impose no requirements on
tribal governments. Thus, Executive Order 13175 does not apply to this
action. Consistent with the EPA Policy on Consultation and Coordination
with Indian Tribes, the EPA consulted with tribal officials during the
development of the proposed rule and specifically solicited comment on
the proposed amendments from tribal officials.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 because the EPA
does not believe the environmental health or safety risks addressed by
this action present a disproportionate risk to children. This action's
health and risk assessments are contained in section IV.A of this
preamble.

H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution or Use

    This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution or use of energy. The overall economic impact of this
final rule should be minimal for the refining industry and its
consumers.

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR
Part 51

    This rulemaking involves technical standards. Therefore, the EPA
conducted searches for the Petroleum Refinery Sector Risk and
Technology Review and New Source Performance Standards through the
Enhanced National Standards Systems Network (NSSN) Database managed by
the American National Standards Institute (ANSI). We also contacted
voluntary consensus standards (VCS) organizations and accessed and
searched their databases. We conducted searches for EPA Methods 18, 22,
320, 325A, and 325B of 40 CFR parts 60 and 63, appendix A. No
applicable VCS were identified for EPA Method 22.
    The following voluntary consensus standards were identified as
acceptable alternatives to the EPA test methods for the purpose of this
rule.
    The voluntary consensus standard ISO 16017-2:2003(E) ``Air
quality--Sampling and analysis of volatile organic compounds in ambient
air, indoor air and workplace air by sorbent tube/thermal desorption/
capillary gas chromatography. Part 2: Diffusive sampling'' is an
acceptable alternative to Method 325A, Sections 1.2, 6.1 and 6.5 and
Method 325B Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 12.2.4, 13.0, A.1.1, and
A.2. This voluntary consensus standard gives general guidance for the
sampling and analysis of volatile organic compounds in air. It is
applicable to indoor, ambient and workplace air. This standard is
available at International Organization for Standardization, ISO
Central Secretariat, Chemin de Blandonnet 8, CP 401, 1214 Vernier,
Geneva, Switzerland. See https://www.iso.org.
    The voluntary consensus standard BS EN 14662-4:2005 ``Ambient Air
Quality: Standard Method for the Measurement of Benzene
Concentrations--Part 4: Diffusive Sampling Followed By Thermal
Desorption and Gas Chromatography'' is an acceptable alternative to
Method 325A, Section 1.2 and Method 325B, Sections 1.3, 7.1.3, 7.1.4,
12.2.4, 13.0, A.1.1, and A.2. This voluntary consensus standard gives
general guidance for the sampling and analysis of benzene in air by
diffusive sampling, thermal desorption and capillary gas
chromatography. This standard is available the European Committee for
Standardization, Avenue Marnix 17--B-1000 Brussels. See https://www.cen.eu.
    The voluntary consensus standard ASTM D6420-99 (2010) ``Test Method
for Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography/Mass Spectrometry'' is an acceptable alternative to EPA
Method 18. This voluntary consensus standard employs a direct interface
gas chromatography/mass spectrometer (GCMS) to identify and quantify a
list of 36 volatile organic compounds (the compounds are listed in the
method).
    The voluntary consensus standard ASTM D6196-03 (Reapproved 2009)
``Standard Practice for Selection of Sorbents, Sampling, and Thermal
Desorption Analysis Procedures for Volatile Organic Compounds in Air''
is an acceptable alternative to Method 325A, Sections 1.2 and 6.1, and
Method 325B, Sections 1.3, 7.1.2, 7.1.3, 7.1.4, 13.0, A.1.1, and A.2.
This voluntary consensus standard is intended to assist in the
selection of sorbents and procedures for the sampling and analysis of
ambient, indoor, and workplace atmospheres for a variety of common
volatile organic compounds.