differences between the monitoring approaches in Refinery MACT 2 for
these limits and Refinery NSPS Ja monitoring approaches for the NSPS PM
limit, so we evaluated whether it is necessary, pursuant to CAA section
112(d)(6), to revise the monitoring provisions in Refinery MACT 2
consistent with the requirements in Refinery NSPS Ja.
    The first significant difference is in the averaging times used for
the different operating limits. Refinery NSPS Ja requires a 3-hour
rolling average for the operating limits for parametric monitoring
systems; Refinery MACT 2 includes daily averaging of the operating
limits. Typically, the averaging time for operating limits is based on
the duration of the performance test used to establish those operating
limits. As the performance test duration is 3 hours (three 1-hour test
runs) and compliance with the PM (or Ni) emission limit is based on the
average emissions during this 3-hour period, the most appropriate
averaging period for these operating limits is 3 hours. Using a daily
average could allow poor performance (i.e., control equipment for
shorter periods (e.g., 3-hour averages that are higher than the PM
emissions limit in Refinery NSPS Ja). For example, assume an operating
limit developed from a performance test has a value of 1 and that
values exceeding this level would suggest that the control system is
not operating as well as during the performance test (i.e., potentially
exceeding the PM emission limit). If the control system is run for 18
hours operating at a level of 0.9 and 6 hours at a level of 1.2, the
unit would be in compliance with the daily operating limit even though
the unit may have 6 consecutive hours during which the operating limit
was exceeded.

Reducing the averaging time does not impact the types of monitors
required; it merely requires the owner or operator of the unit to pay
more careful attention to the APCD operating parameters. We are
proposing that it is necessary, pursuant to CAA section 112(d)(6), to
incorporate the use of 3-hour averages rather than daily averages for
parameter operating limits in Refinery MACT 2 for both the PM and Ni
limits, because this is a cost-effective development in monitoring
practice.
    The site-specific opacity operating limit for PM in Refinery MACT 2
(for units not electing to comply with Refinery NSPS J) has a 1-hour
averaging period, but the Ni operating limits (which use opacity
monitoring) have a 24-hour averaging period. These averaging periods
are inconsistent with the duration of the performance test, which is
over a 3-hour period. We are proposing, pursuant to CAA section
112(d)(6), to incorporate the use of 3-hour averages for the site-
specific opacity operating limit and the Ni operating limits rather
than daily averages because this is a cost-effective development in
monitoring practice.
    We also compared the APCD-specific operating parameters used in
Refinery MACT 2 to those that we promulgated for Refinery NSPS Ja. The
Refinery NSPS Ja rule includes monitoring approaches that are not
included in Refinery MACT 2. These include the option of using PM CEMS
and requiring BLD for fabric filter control systems. Adding a PM CEMS
as an option for demonstrating compliance with the Refinery MACT 2 PM
limit (similar to what is provided in Refinery NSPS Ja) would not
impact the costs of complying with Refinery MACT 2 because sources can
choose whether or not to adopt this monitoring method. With respect to
BLD, there is only one refinery that currently uses a baghouse (fabric
filter) to control emissions from its FCCU (although one additional
unit has indicated that it has plans to install a fabric filter control
within the next few years). Under the existing requirements in Refinery
MACT 2 (assuming that the FCCU currently operating with a fabric filter
has not elected to comply with the Refinery NSPS J PM emission limit
option), it is required to comply with a site-specific opacity
operating limit. For new, reconstructed, or modified FCCU, Refinery
NSPS Ja requires use of BLD. While we generally consider the BLD to be
superior to opacity monitors for ensuring fabric filter control systems
are operating efficiently, it is difficult to determine what, if any,
increment in assurance that the unit is properly controlled would be
achieved by requiring the one facility currently operating a fabric
filter control system and complying with a site-specific opacity
operating limit to switch from a COMS to BLD. Therefore, we are
proposing that it is not necessary to require the one existing FCCU
with a fabric filter control system to switch from COMS to a BLD system
because this would require additional monitoring equipment (with
additional costs) and little to no associated increase in assurance
that the unit is properly controlled. Although we are not proposing to
require existing sources using a fabric filter to use BLD, we are
proposing to include BLD as an option to COMS; owners or operators of
FCCU using fabric filter-type control systems at existing sources can
elect (but are not required) to use BLD in lieu of COMS and the site-
specific opacity operating limit.
    The Refinery NSPS Ja monitoring requirements for ESP include CPMS
for monitoring and recording the total power and the secondary current
to the entire system. The current MACT requires monitoring voltage and
secondary current or monitoring only the total power to the APCD. While
these monitoring requirements are similar, we consider that the
Refinery NSPS Ja requirements will provide improved operation of the
ESP. As the monitors required to measure these parameters are a routine
part of ESP installations, we project no additional costs for
monitoring equipment. We expect that a new performance test would be
needed to ensure that both total power and secondary current are
recorded during the source test. As discussed later in this section, we
are proposing to require ongoing performance tests regardless of the
monitoring option, so we are not projecting any additional costs
specific to revising the monitoring requirements for ESP. Because the
Refinery NSPS Ja monitoring and operating requirements for ESP are
expected to provide improved performance of the APCD with no
incremental costs, we propose that it is necessary, pursuant to CAA
section 112(d)(6), to incorporate the total power and the secondary
current operating limits into Refinery MACT 2.
    Refinery NSPS Ja provides a specific monitoring alternative to
pressure drop for jet ejector-type wet scrubbers or any other type of
wet scrubbers equipped with atomizing spray nozzles. Owners or
operators of FCCU controlled by these types of wet scrubbers can elect
to perform daily checks of the air or water pressure to the spray
nozzle rather than monitor pressure. Refinery MACT 2 currently excludes
these types of control systems from monitoring pressure drop but
includes no specific monitoring to ensure the jet ejectors or atomizing
spray nozzle systems are properly operating. Since proper functioning
of the jet ejectors or atomizing spray nozzles is critical to ensuring
these control systems operate at the level contemplated by the MACT,
some monitoring/inspection requirement of these components is necessary
to ensure compliance with the FCCU PM or Ni emission limit. The owner
or operator of a jet ejector-type wet scrubber or other type of wet
scrubber equipped with atomizing spray nozzles should be performing
routine checks of these systems, such as the daily checks of the air or
water pressure to the spray nozzles, as required in Refinery NSPS Ja.
These daily checks are consistent with good operational practices for
wet scrubbers and should not add significant burden to the FCCU wet
scrubber owner or operator. For these reasons, we propose it is
necessary to require owners or operators of a jet ejector-type wet
scrubber or other type of wet scrubber equipped with atomizing spray
nozzles to perform daily checks of the air or water pressure to the
spray nozzles pursuant to CAA section 112(d)(6).
    Finally, in our action promulgating Refinery NSPS Ja, we noted
that, even with improved monitoring methods, periodic source testing is
needed to verify the performance of the control system as it ages. In
Refinery NSPS Ja, annual performance demonstrations are required for
new sources. FCCU subject to Refinery MACT 2 as new sources would also
be subject to Refinery NSPS Ja and would have to comply with the annual
testing requirements in Refinery NSPS Ja. However, Refinery MACT 2 does
not include periodic performance tests for any FCCU. We considered
adding an annual testing requirement for FCCU subject to Refinery MACT
2. The annual nationwide cost burden exceeds $1 million per year and we
project only modest improvement in control performance resulting from
the performance demonstrations. We considered requiring FCCU
performance tests once every 5 years (i.e., once per title V permit
period). The nationwide annual cost of this additional testing
requirement for FCCU is projected to be, on average, $213,000 per year.
We consider this to be a reasonable minimum frequency for which
affected sources should demonstrate direct compliance with the FCCU
emission limits and that this cost is reasonable. Therefore, we propose
that it is

necessary, pursuant to CAA section 112(d)(6), to require a performance
test once every 5 years for all FCCU under to Refinery MACT 2.
    Organic HAP. Refinery MACT 2 uses CO as a surrogate for organic HAP
and establishes an emission limit of 500 ppmv CO (dry basis). Some
FCCU, referred to as complete-combustion FCCU, employ excess oxygen in
the FCCU regenerator and are able to meet this emission limit without
the need for a post-combustion device. Other FCCU, referred to as
partial-combustion FCCU, do not supply enough air/oxygen for complete
combustion of the coke to CO2 and, therefore, produce a
significant quantity of CO in the regenerator exhaust. Partial-
combustion FCCU are typically followed by a post-combustion unit,
commonly referred to as a CO boiler, to burn the CO in the regenerator
exhaust in order to meet the 500 ppmv CO limit (and to recover useful
heat from the exhaust stream).
    In our review of Refinery NSPS J, we conducted a review of state
and local regulations affecting refineries to identify control
strategies to reduce CO emissions or VOC emissions from refinery
sources (see Review of VOC Emission Sources at Refineries, December 14,
2005, Docket Item Number EPA-HQ-OAR-2007-0011-0043). We also conducted
a review of federal, state and local regulations affecting refineries
to identify control strategies to reduce CO emissions from refinery
sources (see Review of CO Emission Sources at Refineries, December 22,
2005, Docket Item Number EPA-HQ-OAR-2007-0011-0044). We did not
identify any developments in practices, processes and control
technologies to reduce CO or VOC emissions from FCCU as part of the
review of Refinery NSPS J, and we have not identified any developments
in practices, processes and control technologies for FCCU that would
reduce organic HAP since promulgation of Refinery MACT 2. We are
proposing that it is not necessary to revise the regulatory provisions
for organic HAP in the current MACT standards for FCCU, pursuant to CAA
section 112(d)(6).
    Inorganic HAP. As mentioned previously, Refinery MACT 2 includes a
CO emission limit of 500 ppmv. Although this limit is expressly
provided as a limit addressing organic HAP emissions, this emission
limit is also expected to limit the emissions of oxidizable inorganic
HAP, such as HCN. That is, the CO concentration limit was developed as
an indicator of complete combustion for all oxidizable pollutants
typically found in exhaust gas from the FCCU regenerator operated in
partial burn mode. We note that HCN concentrations in FCCU regenerator
exhaust with high CO levels also have high HCN concentrations and that
HCN concentrations in the regenerator exhaust from complete-combustion
FCCU (those meeting the 500 ppmv CO limit without the need for a post-
combustion device) are much lower than those from partial burn FCCU
prior to a post-combustion device. Thus, we consider that the CO
emission limit also acts as a surrogate for the control of oxidizable
inorganic HAP, such as HCN.
    The source test data from the ICR effort revealed that HCN
emissions from FCCU are greater than previous tests indicated,
particularly for complete-combustion FCCU. The increase in HCN
emissions was observed at units meeting lower NOX emission
limits, which have recently been required by consent decrees, state and
local requirements and Refinery NSPS Ja. The higher HCN emissions from
complete-combustion FCCU appear to be directly related to operational
changes made in efforts to meet these lower NOX emission
limits (e.g., reduced excess oxygen levels in the regenerator and
reduced regenerator bed temperatures). These higher HCN emissions were
only observed in complete-combustion FCCU; FCCU that operated in
partial burn mode followed by a CO boiler or similar post-combustion
device had significantly lower HCN emissions subsequent to the post-
combustion device.
    Based on our review of the available ICR data and the technologies
used in practice, we considered establishing specific emission limits
for HCN. In order to comply with emission limits for HCN, owners or
operators of complete-combustion FCCU would either have to operate
their FCCU regenerator at slightly higher temperatures and excess
oxygen concentrations (to limit the formation of HCN in the
regenerator) or employ a post-combustion device or thermal oxidizer to
destroy HCN exhausted from the FCCU regenerator. However, each of these
options comes with significant secondary energy and environmental
impacts. First, both of these control strategies would yield a
significant increase in NOX emissions. We anticipate that
most FCCU owners or operators would have to install a selective
catalytic reduction (SCR) system to meet their NOX emission
limits, if applicable. Operation of the SCR would have energy impacts
and may have additional secondary PM2.5 impacts (associated
with ammonia slip from the SCR). We expect that modifying the
regenerator operating characteristics is the most cost-effective
option, although installing and using a thermal oxidizer may be
necessary, depending on the operational characteristics of the
regenerator and the HCN control requirement. Using a thermal oxidizer
to treat FCCU regenerator exhaust, a gas stream that has limited
heating value (due to the already low CO concentrations) would be much
more expensive and would have additional energy and secondary impacts
associated with the auxiliary fuel needed for the device, as compared
to modifying regenerator operating conditions.
    We first performed a screening analysis of the impacts of making
only operational changes to the FCCU with the highest HCN
concentrations. If this control option is not cost effective for these
FCCU, it would not be cost effective for units that have lower HCN
concentrations and lower HCN emissions. Similarly, if operating changes
in the FCCU regenerator alone are not cost effective, then we can
assume that installing a thermal oxidizer to achieve this same level of
HCN emission reductions would also not be cost effective. We calculated
the cost of changing the regenerator parameters and adding an SCR for
the FCCU with the highest HCN emissions rate reported in the ICR, which
is an annual emissions rate of 460 tpy. This is also the largest FCCU
in operation in the United States and its territories. Based on the
size of this unit, we project that an SCR would be expected to cost
approximately $13-million and have annualized costs of approximately
$4.0-million/yr. Thus, if the HCN emissions can be reduced by 95
percent, the cost effectiveness would be approximately $9,000 per ton
of HCN. A smaller FCCU had similar HCN concentrations and annual HCN
emissions of 141 tpy. Based on the size of this unit, we project an SCR
would be expected to cost approximately $7-million and have annualized
costs of approximately $1.5-million/yr. Assuming a 95-percent reduction
in HCN emissions, the cost effectiveness would be approximately $11,000
per ton of HCN. The second-highest emitting FCCU was larger than this
unit, but had lower HCN concentrations. This third unit had emissions
of 184 tpy. Based on the size of this unit, we expect that an SCR would
cost approximately $9-million and have annualized costs of
approximately $2.2-million/yr. Assuming a 95-percent reduction in HCN
emissions, the cost effectiveness would be approximately $12,600 per
ton of HCN.
    These costs are for the FCCU with the largest HCN emissions and the
lowest control cost (assuming operational

changes alone are insufficient to significantly reduce HCN emissions),
and the average cost effectiveness for these units exceeds $10,000 per
ton HCN emissions reduced. Based on the economies of scale and
considering lower HCN concentrations for all other units, the costs per
ton of HCN removed for a nationwide standard would be higher. If a
post-combustion device is needed to achieve a specific HCN emissions
limit, the costs would be even higher.
    Based on the cost, secondary energy and secondary environmental
impacts of an HCN emission limit beyond that achieved by the CO
emission limit as a surrogate for HCN, we are proposing, at this time,
that it is not necessary, pursuant to CAA section 112(d)(6), to revise
the MACT standard to establish a separate HCN standard. As our
understanding of the mechanisms of HCN and NOX formation
improves and as catalyst additives evolve, it may be possible to
achieve both low NOX and low HCN emissions without the use
of an SCR and/or post-combustion controls. However, at this time our
test data indicate an inverse correlation between these two pollutants.
The three facilities with the highest HCN concentrations were the
facilities with the lowest NOX concentrations, all of which
were below 20 ppmv (dry basis, 0-percent excess air) during the
performance tests. While a 20 ppmv NOX limit may be
achievable, we anticipate that further reducing the NOX new
source performance limits for FCCU would either increase
PM2.5 secondary emissions (via the use of an SCR and its
associated ammonia slip) or further increase HCN emissions (if
combustion controls are used).
b. CRU Process Vents
    A CRU is designed to reform (i.e., change the chemical structure
of) naphtha into higher-octane aromatics. The reforming process uses a
platinum or bimetal (e.g., platinum and rhenium) catalyst material.
Small amounts of coke deposit on the catalyst during the catalytic
reaction and this coke is burned off the catalyst to regenerate
catalyst activity. There are three types of CRU classified by
differences in how the units are designed and operated to effect
reforming catalyst regeneration. Semi-regenerative reforming is
characterized by shutting down the reforming unit at specified
intervals, or at the operator's convenience, for in situ catalyst
regeneration. Semi-regenerative CRU typically regenerate catalyst once
every 8 to 18 months, with the regeneration cycle lasting approximately
2 weeks. Cyclic-regeneration reforming is characterized by continuous
or continual reforming operation with periodic (but frequent)
regeneration of catalyst in situ by isolating one of the reactors in
the series, regenerating the catalyst, then returning the reactor to
the reforming operation. The regeneration of the catalyst in a single
reactor may occur numerous times per year (e.g., once a month), and the
regeneration of each reactor may take 3 to 5 days to complete.
Continuous-regeneration reforming units use moving catalyst bed
reactors situated vertically (which is why they are often referred to
as platforming units). Catalyst flows down the series of reactors. At
the bottom of the last reactor, catalyst is continually isolated and
sent to a special regenerator. After regeneration, the regenerated
catalyst is continually fed to the first (top) reactor. Thus,
continuous-regeneration reforming units are characterized by
continuous-reforming operation along with continuous-regeneration
operation.
    The catalytic reforming reaction is performed in a closed reactor
system; there are no emissions associated with the processing portion
of the CRU. There is a series of emission points associated with the
CRU catalyst regenerator. Regardless of the type of CRU used, there is
a series of steps conducted to effect catalyst regeneration. These
steps are: (1) Initial depressurization/purge; (2) coke burn-off; (3)
catalyst rejuvenation; and (4) reduction/final purge. The primary
emissions during the depressurization/purge cycle are organic HAP.
Inorganic HAP, predominately HCl and chlorine, are emitted during the
coke burn-off and rejuvenation cycles. The reduction purge is mostly
inert materials (nitrogen and/or hydrogen). Refinery MACT 2 contains
organic HAP emission limits for the depressurization/purge cycle
(purging prior to coke-burn-off) and inorganic HAP emission limits for
the coke burn-off and catalyst rejuvenation cycles. Our technology
review, summarized below, considers each of these emission limits
separately. For additional details on the technology review for CRU,
see Technology Review Memorandum for Catalytic Reforming Units at
Petroleum Refineries in Docket ID Number EPA-HQ-OAR-2010-0682.
    Organic HAP. Refinery MACT 2 requires the owner or operator to
comply with either a 98-percent reduction of TOC or non-methane TOC, or
an outlet concentration of 20 ppmv or less (dry basis, as hexane,
corrected to 3-percent oxygen). The emission limits for organic HAP for
the CRU do not apply to emissions from process vents during
depressuring and purging operations when the reactor vent pressure is 5
psig or less. Control technologies used include directing the purge gas
directly to the CRU process heater to be burned, recovering the gas to
the facility's fuel gas system, or venting to a flare or other APCD.
The pressure limit exclusion was provided to allow atmospheric venting
of the emissions when the pressure of the vessel fell below that needed
to passively direct the purge gas to the APCD (most commonly the CRU
process heater or flare).
    We did not identify any developments in practices, processes and
control technologies for reducing organic HAP emissions from CRU.
However, as noted in section IV.A.2 of this preamble, we are proposing
to amend the pressure limit exclusion pursuant to CAA sections
112(d)(2) and (3) to clarify that this limit only applies during
passive vessel depressuring. Also, as described in section IV.A.3 of
this preamble, we are proposing revisions to Refinery MACT 1 and 2,
pursuant to CAA sections 112(d)(2) and (3), to ensure flares used as
APCD meet the required destruction efficiency, which includes flares
used to control the organic HAP emissions from the CRU
depressurization/purge vent streams.
    Inorganic HAP. Refinery MACT 2 uses HCl as a surrogate for
inorganic HAP during the coke burn-off and rejuvenation cycles.
Refinery MACT 2 requires owners or operators of existing semi-
regenerative CRU to reduce uncontrolled emissions of HCl by 92-percent
by weight or to a concentration of 30 ppmv (dry basis, corrected to 3-
percent oxygen) during the coke burn-off and rejuvenation cycles.
Owners or operators of new semi-regenerative CRU, new or existing
cyclic CRU, or new or existing continuous CRU are required to reduce
uncontrolled emissions of HCl by 97-percent by weight or to a
concentration of 10 ppmv (dry basis, corrected to 3-percent oxygen)
during the coke burn-off and rejuvenation cycles. Technologies used to
achieve these limits include caustic spray injection, wet scrubbers,
and solid adsorption systems. We conducted a technology review for CRU
by reviewing the ICR responses and scientific literature. We did not
identify any developments in practices, processes and control
technologies for reducing inorganic HAP emissions from CRU. We are
proposing that it is not necessary to revise the current inorganic HAP
MACT standards for CRU, pursuant to CAA section 112(d)(6).

c. SRU Process Vents
    Most sulfur recovery plants at petroleum refineries use the Claus
reaction to produce elemental sulfur. In the Claus reaction, two moles
of hydrogen sulfide (H2S) react with one mole of
SO2 in a catalytic reactor to form elemental sulfur and
water vapor. Prior to the Claus reactors, one-third of the
H2S in the sour gas feed to the sulfur plant must be
oxidized to SO2 to have the correct proportion of
H2S and SO2 for the Claus reaction. This
oxidation step is performed in the ``Claus burner.'' The remaining gas
stream, after the elemental sulfur is condensed, is referred to as
``tail gas.'' HAP emissions in tail gas from sulfur recovery plants are
predominately COS and CS2, which are primarily formed as
side reactions of the Claus process.
    Refinery MACT 2 contains HAP standards for SRU that were based on
the Refinery NSPS J SO2 and reduced sulfur compounds
emission limits. Refinery NSPS J includes an emission limit of 300 ppmv
reduced sulfur compounds for a reduction control system not followed by
an incinerator, and an emission limit of 250 ppmv SO2 (dry
basis, 0-percent excess air) for oxidative control systems or reductive
control systems followed by incineration. These Refinery NSPS J limits
apply only to Claus sulfur recovery plants with a sulfur recovery
capacity greater than 20 long tons per day (LTD). These emission limits
effectively required sulfur recovery plants to achieve 99.9-percent
sulfur recovery.
    Refinery MACT 2 defines SRU as a process unit that recovers
elemental sulfur from gases that contain reduced sulfur compounds and
other pollutants, usually by a vapor-phase catalytic reaction of sulfur
dioxide and hydrogen sulfide (see 40 CFR 63.1579). This definition
specifically excludes sulfur recovery processes that do not recover
elemental sulfur, such as the LO-CAT II process, but does not
necessarily limit applicability to Claus SRU. Refinery MACT 2 requires
owners or operators of an SRU that is subject to Refinery NSPS J to
meet the Refinery NSPS J limits. Owners or operators of an SRU that is
not subject to Refinery NSPS J can elect to meet the emission limits in
Refinery NSPS J or meet a reduced sulfur compound limit of 300 ppmv
(dry basis, 0-percent excess air) regardless of the type of control
system or the presence of an incinerator. Unlike Refinery NSPS J,
Refinery MACT 2 does not have a capacity applicability limit, so this
300 ppmv reduced sulfur compound limit is applicable to all SRU (as
that term is defined), regardless of size.
    Upon completion of our technology review for Refinery NSPS J, we
promulgated Refinery NSPS Ja, which includes new provisions for the
sulfur recovery plant. First, Refinery NSPS Ja limits are now
applicable to all sulfur recovery plants, not just Claus sulfur
recovery plants. Second, emission limits were added for sulfur recovery
plants with a capacity of 20 LTD or less, to require new, small sulfur
recovery plants to achieve a target sulfur recovery efficiency of 99-
percent. These limits are a factor of 10 higher than the emission
limits for larger sulfur recovery plants (i.e., 3,000 ppmv reduced
sulfur compounds for a reduction control system not followed by an
incinerator and 2,500 ppmv SO2 for oxidative control systems
or reductive control systems followed by incineration). Refinery NSPS J
did not include emission limits for these smaller sulfur recovery
plants. Third, new correlations were introduced to provide equivalent
emission limits for systems that use oxygen-enriched air in their Claus
burner.
    The technology review conducted for Refinery NSPS J focused on
SO2 emissions. Under our current technology review for
Refinery MACT 2, we considered the developments in practices, processes
or control technologies identified in the Refinery NSPS J technology
review as they pertain to HAP emissions and the existing Refinery MACT
2 requirements.
    We considered the new Refinery NSPS Ja limits for small sulfur
recovery plants. While Refinery NSPS Ja establishes criteria pollutant
emission limits for these smaller sulfur recovery plants that were
previously unregulated for such emissions, these sources are already
covered under Refinery MACT 2. Refinery MACT 2 requires these SRU to
meet a 300 ppmv reduced sulfur compound limit, which is more stringent
than the 3,000 ppmv limit established in Refinery NSPS Ja.
    We also considered the new correlations in Refinery NSPS Ja for SRU
that use oxygen-enriched air in their Claus burner. In the technology
review under Refinery NSPS J, we identified a change in practice in the
operation of certain Claus SRU. At the time we promulgated Refinery
MACT 2, we assumed that all units were using ambient air in the Claus
burner, and we established the same emission limits as in Refinery NSPS
J. Now, however, we understand that some facilities are using oxygen-
enriched air. This practice lowers the amount of inert gases introduced
into the SRU and improves operational performance and reliability of
the sulfur recovery plant. Air is approximately 20.9 percent by volume
oxygen and 79.1-percent inert gases (predominately nitrogen with 1-
percent argon and other inert gases). The inert gases introduced in the
Claus burner become a significant portion of the overall tail gas flow.
When oxygen enrichment is used in the Claus burner, there are fewer
inert gases in the tail gas and a lower overall tail gas flow rate. The
same molar flow rate of reduced sulfur compounds will be present in the
tail gas, but without the additional flow of inerts from the ambient
air, the concentration of the reduced sulfur compounds (or
SO2) in the tail gas is higher.
    In developing Refinery NSPS Ja, we included a correlation equation
that facilities can use to adjust the concentration limit based on the
enriched-oxygen concentration used in the Claus burner. This equation
is designed to allow the same mass of emissions for these units as is
allowed for units using only ambient air. That is, the emission
equation establishes a concentration limit for units using oxygen
enrichment so that the mass emissions from the unit do not exceed the
mass emissions allowed under the 250 ppmv SO2 (or 300 ppmv
reduced sulfur compounds) emissions limits in Refinery NSPS J and in
Refinery MACT 2. The new equation in Refinery NSPS Ja for large sulfur
recovery plants (those with sulfur recovery greater than 20 LTD)
provides an equivalent mass emissions rate of reduced sulfur HAP from
the SRU as is currently required in Refinery MACT 2 while allowing a
practice that improves the operational reliability of the unit. There
are no costs to providing this option for units using oxygen-enriched
air because: (1) It is an option that the owner or operator can elect
to meet instead of the xisting 250 ppmv SO2 emissions limit
and (2) owners or operators of SRU that use oxygen-enriched air are
expected to already routinely monitor the inlet air oxygen
concentration for operational purposes. Therefore, we are proposing
that it is necessary, pursuant to CAA section 112(d)(6), to amend
Refinery MACT 2 sulfur recovery requirements to include this equation
that addresses the use of oxygen-enriched air as a development in
practice in SRU process operations.
    The emission limits for large sulfur recovery plants (those with
sulfur recovery greater than 20 LTD) in Refinery NSPS Ja are equivalent
to those in Refinery MACT 2. We are proposing to allow owners or
operators subject to Refinery NSPS Ja limits for sulfur

recovery plants with a capacity greater than 20 LTD to comply with
Refinery NSPS Ja as a means of complying with Refinery MACT 2.
    We have not identified any additional developments in practices,
processes or control technologies for HAP from SRU since development of
Refinery NSPS Ja.

C. What are the results of the risk assessment and analyses?

1. Inhalation Risk Assessment Results
    Table 10 of this preamble provides an overall summary of the
results of the inhalation risk assessment.

                  Table 10--Petroleum Refining Source Sector Inhalation Risk Assessment Results
----------------------------------------------------------------------------------------------------------------
                                   Estimated population  Estimated annual   Maximum chronic   Maximum screening
Maximum individual cancer risk  (-   at increased risk   cancer incidence  non-cancer TOSHI  acute non-cancer HQ
        in-1 million) \a\            levels of cancer    (cases per year)         \b\                \c\
----------------------------------------------------------------------------------------------------------------
                                                Actual Emissions
----------------------------------------------------------------------------------------------------------------
60...............................  >= 1-in-1 million:                 0.3               0.9  HQREL = 5
                                    5,000,000.                                               (Nickel Compounds).
                                   >= 10-in-1 million:
                                    100,000.
                                   >= 100-in-1 million:
                                    0.
----------------------------------------------------------------------------------------------------------------
                                             Allowable Emissions \d\
----------------------------------------------------------------------------------------------------------------
100..............................  >= 1-in-1 million:                 0.6                 1  --
                                    7,000,000 \e\.
                                   >= 10-in-1 million:
                                    Greater than 90,000
                                    \e\.
                                   >= 100-in-1 million:
                                    0.
----------------------------------------------------------------------------------------------------------------
\a\ Estimated maximum individual excess lifetime cancer risk due to HAP emissions from the source category.
\b\ Maximum TOSHI. The target organ with the highest TOSHI for the Petroleum Refining source sector is the
  thyroid system for actual emissions and the neurological system for allowable emissions.
\c\ The maximum off-site HQ acute value of 5 is driven by emissions of nickel from CCU. See section III.A.3 of
  this preamble for explanation of acute dose-response values. Acute assessments are not performed on allowable
  emissions because of a lack of detailed hourly emissions data. However, because of the conservative nature of
  the actual annual to actual hourly emissions rate multiplier, allowable acute risk estimates will be
  comparable to actual acute estimates.
\d\ The development of allowable emission estimates can be found in the memo entitled Refinery Risk Estimates
  for Modeled ``Allowable'' Emissions, which can be found in Docket ID Number EPA-HQ-OAR-2010-0682.
\e\ Population risks from allowable emissions were only calculated for the model plant emissions (REM) approach.
  For the 138 facilities modeled using the modeled plant approach the population risks greater than 10-in-1
  million was estimated to be 90,000. If we consider the second approach to determining allowable emissions
  (combined the results of the actual and REM emissions estimates) we estimate that the allowable population
  risks greater than 10-in-1 million would be greater than 90,000 people. Further, the number of people above 1-
  in-1 million would also be higher than the 7,000,000 estimated using the REM model.

    The inhalation risk modeling performed to estimate risks based on
actual emissions relied primarily on emissions data from the ICR,
updated based on our quality assurance review as described in section
III.A.1 of this preamble.
    The results of the chronic baseline inhalation cancer risk
assessment indicate that, based on estimates of current actual
emissions, the maximum individual lifetime cancer risk (MIR) posed by
the refinery source category is 60-in-1 million, with benzene and
naphthalene emissions from equipment leaks and storage tanks accounting
for 98 percent of the MIR risk. The total estimated cancer incidence
from refinery emission sources based on actual emission levels is 0.3
excess cancer cases per year or one case in every 3.3 years, with
emissions of naphthalene, benzene, and 2-methylnaphthalene contributing
22 percent, 21 percent and 13 percent, respectively, to this cancer
incidence. In addition, we note that approximately 100,000 people are
estimated to have cancer risks greater than 10-in-1 million, and
approximately 5,000,000 people are estimated to have risks greater than
1-in-1 million as a result of actual emissions from these source
categories. When considering the MACT-allowable emissions, the maximum
individual lifetime cancer risk is estimated to be up to 100-in-1
million, driven by emissions of benzene and naphthalene from refinery
fugitives (e.g., storage tanks, equipment leaks and wastewater) and the
estimated cancer incidence is estimated to be 0.6 excess cancer cases
per year or one excess case in every 1.5 years. Greater than 90,000
people were estimated to have cancer risks above 10-in-1 million and
approximately 7,000,000 people were estimated to have cancer risks
above 1-in-1 million considering allowable emissions from all petroleum
refineries.
    The maximum modeled chronic non-cancer HI (TOSHI) value for the
source sector based on actual emissions was estimated to be less than
1. When considering MACT-allowable emissions, the maximum chronic non-
cancer TOSHI value was estimated to be about 1.
2. Acute Risk Results
    Our screening analysis for worst-case acute impacts based on actual
emissions indicates the potential for five pollutants--acetaldehyde,
acrolein, arsenic, benzene and nickel--to exceed an HQ value of 1, with
an estimated worst-case maximum HQ of 5 for nickel based on the REL
values. This REL occurred at a facility reporting nickel emissions from
the FCCU vent. One hundred thirty-six of the 142 petroleum refineries
had an estimated worst-case HQ less than or equal to 1 for all HAP;
except for the one facility that had an estimated REL of 5, the
remaining 5 refineries with an REL above 1 had an estimated worst-case
HQ less than or equal to 3.
    To better characterize the potential health risks associated with
estimated worst-case acute exposures to HAP, and in response to a key
recommendation from the SAB's peer review of EPA's RTR risk assessment
methodologies, we examine a wider range of available acute health
metrics than we do for our chronic risk assessments. This is in
acknowledgement that there are generally more data gaps and
inconsistencies in acute reference values than there are in chronic
reference values. By definition, the acute CalEPA REL represents a
health-

protective level of exposure, with no risk anticipated below those
levels, even for repeated exposures; however, the health risk from
higher-level exposures is unknown. Therefore, when a CalEPA REL is
exceeded and an AEGL-1 or ERPG-1 level is available (i.e., levels at
which mild effects are anticipated in the general public for a single
exposure), we have used them as a second comparative measure.
Historically, comparisons of the estimated maximum off-site 1-hour
exposure levels have not been typically made to occupational levels for
the purpose of characterizing public health risks in RTR assessments.
This is because occupational ceiling values are not generally
considered protective for the general public since they are designed to
protect the worker population (presumed healthy adults) for short-
duration increases in exposure (less than 15 minutes). As a result, for
most chemicals, the 15-minute occupational ceiling values are set at
levels higher than a 1-hour AEGL-1, making comparisons to them
irrelevant unless the AEGL-1 or ERPG-1 levels are also exceeded. Such
is not the case when comparing the available acute inhalation health
effect reference values for some of the pollutants considered in this
analysis.
    The worst-case maximum estimated 1-hour exposure to acetaldehyde
outside the facility fence line for the source categories is 1 mg/m\3\.
This estimated worst-case exposure exceeds the 1-hour REL by a factor
of 2 (HQREL=2) and is well below the 1-hour AEGL-1
(HQAEGL-1=0.01) and the ERPG-1 (HQERPG-1=0.05).
    The worst-case maximum estimated 1-hour exposure to acrolein
outside the facility fence line for the source categories is 0.005 mg/
m\3\. This estimated worst-case exposure exceeds the 1-hour REL by a
factor of 2 (HQREL=2) and is below the 1-hour AEGL-1
(HQAEGL-1=0.1) and the ERPG-1 (HQERPG-1=0.04).
    The worst-case maximum estimated 1-hour exposure to nickel
compounds outside the facility fence line for the source categories is
0.001 mg/m\3\. This estimated worst-case exposure exceeds the 1-hour
REL by a factor of 5 (HQREL=5). There are no AEGL, ERPG or
short-term occupational values for nickel to use as comparison to the
acute 1-hour REL value.
    The worst-case maximum estimated 1-hour exposure to arsenic
compounds outside the facility fence line for the source categories is
0.0004 mg/m\3\. This estimated worst-case exposure exceeds the 1-hour
REL by a factor of 2 (HQREL=2). There are no AEGL, ERPG or
short-term occupational values for arsenic to use as comparison to the
acute 1-hour REL value.
    The maximum estimated 1-hour exposure to benzene outside the
facility fence line is 2.7 mg/m\3\. This estimated exposure exceeds the
REL by a factor of 2 (HQREL=2), but is significantly below
both the 1-hour ERPG-1 and AEGL-1 value (HQ ERPG-1 (or AEGL-1) = 0.02).
This exposure estimate neither exceeds the AEGL-1/ERPG-1 values, nor
does it exceed workplace ceiling level guidelines designed to protect
the worker population for short-duration exposure (less than 15
minutes) to benzene, as discussed below. The occupational short-term
exposure limit (STEL) standard for benzene developed by the
Occupational Safety and Health Administration is 16 mg/m\3\, ``as
averaged over any 15-minute period.'' \33\ Occupational guideline STEL
for exposures to benzene have also been developed by the American
Conference of Governmental Industrial Hygienists (ACGIH) \34\ for less
than 15 minutes \35\ (ACGIH threshold limit value (TLV)-STEL value of
8.0 mg/m\3\), and by the National Institute for Occupational Safety and
Health (NIOSH) \36\ ``for any 15 minute period in a work day'' (NIOSH
REL-STEL of 3.2 mg/m\3\). These shorter duration occupational values
indicate potential concerns regarding health effects at exposure levels
below the 1-hour AEGL-1 value.
---------------------------------------------------------------------------

    \33\ 29 CFR 1910.1028, Benzene.
    \34\ ACGIH (2001) Benzene. In Documentation of the TLVs[supreg]
and BEIs[supreg] with Other Worldwide Occupational Exposure Values.
ACGIH, 1300 Kemper Meadow Drive, Cincinnati, OH 45240 (ISBN: 978-1-
882417-74-1) and available online at http://www.acgih.org.
    \35\ The ACGIH definition of a TLV-STEL states that ``Exposures
above the TLV-TWA up to the TLV-STEL should be less than 15 minutes,
should occur no more than four times per day, and there should be at
least 60 minutes between successive exposures in this range.''
    \36\ NIOSH. Occupational Safety and Health Guideline for
Benzene; http://www.cdc.gov/niosh/docs/81-123/pdfs/0049.pdf.
---------------------------------------------------------------------------

    All other HAP and facilities modeled had worst-case acute HQ values
less than 1, indicating that the HAP emissions are believed to be
without appreciable risk of acute health effects. In characterizing the
potential for acute non-cancer risks of concern, it is important to
remember the upward bias of these exposure estimates (e.g., worst-case
meteorology coinciding with a person located at the point of maximum
concentration during the hour) and to consider the results along with
the conservative estimates used to develop hourly emissions as
described earlier, as well as the screening methodology. Refer to the
memo in the docket for this rulemaking (Docket ID Number EPA-HQ-OAR-
2010-0682, Derivation of hourly emission rates for petroleum refinery
emission sources used in the acute risk analysis) for a detailed
description of how the hourly emissions were developed for this source
sector.
3. Multipathway Risk Screening Results
    Results of the worst-case Tier I screening analysis indicate that
PB-HAP emissions (based on estimates of actual emissions) from several
facilities in this source sector exceed the screening emission rates
for POM (PAH), CDDF, mercury compounds, and cadmium compounds. For the
compounds and facilities that did not screen out at Tier I, we
conducted a Tier II screen. The Tier II screen replaces some of the
assumptions used in Tier I with site-specific data, including the land
use around the facilities, the location of fishable lakes, and local
wind direction and speed. The Tier II screen continues to rely on high-
end assumptions about consumption of local fish and locally grown or
raised foods (adult female angler at 99th consumption for fish \37\ and
90th percentile for consumption of locally grown or raised foods \38\)
and uses an assumption that the same individual consumes each of these
foods in high end quantities (i.e., that an individual has high end
ingestion rates for each food). The result of this analysis was the
development of site-specific emission screening levels for POM, CDDF,
mercury compounds, and cadmium compounds. It is important to note that,
even with the inclusion of some site-specific information in the Tier
II analysis, the multi-pathway screening analysis is a still a very
conservative, health-protective assessment (e.g., upper-bound
consumption of local fish, locally grown, and/or raised foods) and in
all likelihood will yield results that serve as an upper-bound multi-
pathway risk associated with a facility.
---------------------------------------------------------------------------

    \37\ Burger, J. 2002. Daily consumption of wild fish and game:
Exposures of high end recreationists. International Journal of
Environmental Health Research 12:343-354.
    \38\ U.S. EPA. Exposure Factors Handbook 2011 Edition (Final).
U.S. Environmental Protection Agency, Washington, DC, EPA/600/R-09/
052F, 2011.
---------------------------------------------------------------------------

    While the screening analysis is not designed to produce a
quantitative risk result, the factor by which the emissions exceed the
screening value serves as a rough gauge of the ``upper-limit'' risks we
would expect from a facility. Thus, for example, if a facility emitted
a PB-HAP carcinogen at a level 2 times the screening value, we can say
with a high degree of confidence that the actual maximum cancer risks
will be less than

2-in-1 million. Likewise, if a facility emitted a noncancer PB-HAP at a
level 2 times the screening level, the maximum noncancer risks would
represent a HQ less than 2. The high degree of confidence comes from
the fact that the screens are developed using the very conservative
(health-protective) assumptions that we describe above.
    Based on the Tier II screening analysis, one facility emits cadmium
compounds above the Tier II screening level and exceeds that level by
about a factor of 2. Twenty-three facilities emit CDDF as 2,3,7,8-
tetrachlorodibenzo-p-dioxin toxicity equivalent (TEQ) above the Tier II
screening level, and the facility with the highest emissions of dioxins
exceeds the Tier II screening level by about a factor of 40. No
facilities emit mercury compounds above the Tier II screening levels.
Forty-four facilities emit POM as benzo(a)pyrene TEQ above the Tier II
screening level, and the facility with the highest emissions of POM as
benzo(a)pyrene TEQ exceeds its screening level by a factor of 30.
    Polychlorinated biphenyls (PCB) are PB-HAP that do not currently
have multi-pathway screening values and so are not evaluated for
potential non-inhalation risks. These HAP, however, are not emitted in
appreciable quantities (0.001 tpy) from refinery operations, and we do
not believe they contribute to multi-pathway risks for this source
category.
    Results of the analysis for lead indicate that the maximum annual
off-site ambient lead concentration was only 2 percent of the NAAQS for
lead, and even if the total annual emissions occurred during a 3-month
period, the maximum 3-month rolling average concentrations would still
be less than 8 percent of the NAAQS, indicating that there is no
concern for multi-pathway risks due to lead emissions.
4. Refined Multipathway Case Study
    To gain a better understanding of the uncertainty associated with
the multipathway Tier I and II screening analysis, a refined
multipathway case study using the TRIM.Fate model was conducted for a
single petroleum refinery. The site, a refinery in St. John the Baptist
Parish, Louisiana, was selected based upon its close proximity to
nearby lakes and farms as well as having one of the highest potential
multipathway risks for PAH based on the Tier II analysis. The refined
analysis for this facility showed that the Tier II screen for each
pollutant over-predicted the potential risk when compared to the
refined analysis results. For this site, the Tier II screen for mercury
indicated that mercury emissions were 3 times lower than the screening
value, indicating a potential maximum HQ for mercury of 0.3. In the
refined analysis, the potential HQ was 0.04 or about 7 times lower than
that predicted by the Tier II screen. For cadmium emissions, the Tier
II screen for this facility indicated that cadmium emissions were about
20 times lower than the screening value, indicating a potential maximum
HQ for mercury of 0.05. The results of the refined analysis for the
selected site in Louisiana show a maximum cadmium HQ of 0.02 or about 3
times lower than that predicted by the Tier II screen. For PAH
emissions, the site selected for the refined analysis had PAH emissions
20 times the PAH Tier II screening value, indicating a potential cancer
risk of 20-in-1 million. When the more refined analysis was conducted
for this site, the potential cancer risks were estimated to be 2-in-1
million or about 14 times lower than predicted by the Tier II analysis.
Finally, for the facility selected for the refined assessment, the
emissions of CDDF as 2,3,7,8-tetrachlorodibenzo-p-dioxin TEQ are 5
times higher than the dioxin Tier II screening value, indicating a
potential maximum cancer risk of 5-in-1 million. In the refined
assessment, the cancer risk from dioxins was estimated to be 2-in-1
million, about one-third of the estimate from the Tier II screen.
    Overall, the refined analysis predicts a potential lifetime cancer
risk of 4-in-1 million to the maximum most exposed individual (MIR).
The non-cancer HQ is predicted to be well below 1 for all target
organs. The chronic inhalation cancer risk assessment estimated
inhalation cancer risk around this same facility to be approximately
10-in-1 million, due in large part to emissions of naphthalene and 2-
methylnaphthalene (both non-persistent, bioaccumulative, and toxic
(PBT) HAP). Thus, although highly unlikely, if around this facility the
person with the highest chronic inhalation cancer risk is also the same
person with the highest individual multipathway cancer risk, then the
combined, worst-case MIR for that facility could theoretically be 10-
in-1 million (risk estimates are expressed as 1 significant figure).
    While this refined assessment was performed on only a single
facility, the results of this single refined analysis indicate that if
refined analyses were performed for other sites, the risk estimates
would consistently be lower than those estimated by the Tier II
analysis. In addition, the risks predicted by the multipathway analyses
at most facilities are considerably lower than the risk estimates
predicted by the inhalation assessment, indicating that the inhalation
risk results are in all likelihood the primary factor in our residual
risk determination for this source category.
    Further details on the site-specific case study can be found in
Appendix 10 of the Draft Residual Risk Assessment for the Petroleum
Refining Source Sector, which is available in Docket ID Number EPA-HQ-
OAR-2010-0682.
5. Environmental Risk Screening Results
    As described in the Draft Residual Risk Assessment for the
Petroleum Refining Source Sector, which is available in Docket ID
Number EPA-HQ-OAR-2010-0682, we conducted an environmental risk
screening assessment for the petroleum refineries source category. In
the Tier I screening analysis for PB-HAP (other than lead, which was
evaluated differently, as noted in section III.A.6 of this preamble),
the individual modeled Tier I concentrations for one facility in the
source category exceeded some of the ecological benchmarks for mercury.
In addition, Tier I modeled concentrations for four facilities exceeded
sediment and soil ecological benchmarks for PAH. Therefore, we
conducted a Tier II assessment.
    In the Tier II screening analysis for PB-HAP, none of the
individual modeled concentrations for any facility in the source
category exceeded any of the ecological benchmarks (either the LOAEL or
NOAEL).
    For lead compounds, we did not estimate any exceedances of the
secondary lead NAAQS. Therefore, we did not conduct further assessment
for lead compounds.
    For acid gases, the average modeled concentration around each
facility (i.e., the average concentration of all off-site data points
in the modeling domain) did not exceed any ecological benchmark. In
addition, for both HCL and HF, each individual concentration (i.e.,
each off-site data point in the modeling domain) was below the
ecological benchmarks for all facilities.
6. Facility-Wide Risk Results
    Table 11 of this preamble displays the results of the facility-wide
risk assessment.

   Table 11--Petroleum Refining Facility-Wide Risk Assessment Results
------------------------------------------------------------------------

------------------------------------------------------------------------
Number of facilities analyzed.........................               142
Cancer Risk:
    Estimated maximum facility-wide individual cancer                 70
     risk ([dash]in-1 million)........................
    Number of facilities with estimated facility-wide                 54
     individual cancer risk of 10-in-1 million or more
    Number of petroleum refining operations                           50
     contributing 50 percent or more to facility-wide
     individual cancer risk of 10-in-1 million or more
    Number of facilities with facility-wide individual               115
     cancer risk of 1-in-1 million or more............
    Number of petroleum refining operations                          107
     contributing 50 percent or more to facility-wide
     individual cancer risk of 1-in-1 million or more.
Chronic Non-cancer Risk:
Maximum facility-wide chronic non-cancer TOSHI........                 4
    Number of facilities with facility-wide maximum                    5
     non-cancer TOSHI greater than 1..................
    Number of petroleum refining operations                            0
     contributing 50 percent or more to facility-wide
     maximum non-cancer TOSHI of 1 or more............
------------------------------------------------------------------------

    The maximum individual cancer whole-facility risk from all HAP
emissions at any petroleum refinery is estimated to be 70-in-1 million,
based on actual emissions. Of the 142 facilities included in this
analysis, 54 have facility-wide maximum individual cancer risks of 10-
in-1 million or greater. At the majority of these facilities (50 of
54), the petroleum refinery operations account for over 50 percent of
the risk.
    There are 115 facilities with facility-wide maximum individual
cancer risks of 1-in-1 million or greater. At the majority of these
facilities (107 of 115), the petroleum refinery operations account for
over 50 percent of the risk. The facility-wide maximum individual
chronic non-cancer TOSHI is estimated to be 4, based on actual
emissions. Of the 142 refineries included in this analysis, five have a
TOSHI value greater than 1. The highest non-cancer TOSHI results from
emissions of chlorine from cooling towers. In each case, the petroleum
refinery operations account for less than 20 percent of the TOSHI
values greater than 1.
    Additional detail regarding the methodology and the results of the
facility-wide analyses are included in the risk assessment
documentation (Draft Residual Risk Assessment for the Petroleum
Refining Source Sector), which is available in the docket for this
rulemaking (Docket ID Number EPA-HQ-OAR-2010-0682).
7. What demographic groups might benefit from this regulation?
    To examine the potential for any environmental justice issues that
might be associated with the source categories, we performed a
demographic analysis of the population close to the facilities. In this
analysis, we evaluated the distribution of HAP-related cancer and non-
cancer risks from petroleum refineries across different social,
demographic, and economic groups within the populations living near
facilities identified as having the highest risks. The methodology and
the results of the demographic analyses are included in a technical
report, Draft Risk and Technology Review--Analysis of Socio-Economic
Factors for Populations Living Near Petroleum Refineries, available in
the docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682).
    The results of the demographic analysis are summarized in Table 12
of this preamble. These results, for various demographic groups, are
based on the estimated risks from actual emissions levels for the
population living within 50 km of the facilities.

                         Table 12--Petroleum Refining Demographic Risk Analysis Results
----------------------------------------------------------------------------------------------------------------
                                                                             Population with
                                                                            cancer risk at or   Population with
                                                             Nationwide        above 1-in-1      chronic hazard
                                                                                million         index above 1
----------------------------------------------------------------------------------------------------------------
Total Population.......................................        312,861,265          5,204,234                  0
----------------------------------------------------------------------------------------------------------------
                                                 Race by Percent
----------------------------------------------------------------------------------------------------------------
White..................................................                 72                 50                  0
All Other Races........................................                 28                 50                  0
----------------------------------------------------------------------------------------------------------------
                                                 Race by Percent
----------------------------------------------------------------------------------------------------------------
White..................................................                 72                 50                  0
African American.......................................                 13                 28                  0
Native American........................................                  1                  1                  0
Other and Multiracial..................................                 14                 21                  0
----------------------------------------------------------------------------------------------------------------
                                              Ethnicity by Percent
----------------------------------------------------------------------------------------------------------------
Hispanic...............................................                 17                 29                  0
Non-Hispanic...........................................                 83                 71                  0
----------------------------------------------------------------------------------------------------------------
                                                Income by Percent
----------------------------------------------------------------------------------------------------------------
Below Poverty Level....................................                 14                 21                  0
Above Poverty Level....................................                 86                 79                  0
----------------------------------------------------------------------------------------------------------------

                                              Education by Percent
----------------------------------------------------------------------------------------------------------------
Over 25 and without High School Diploma................                 15                 23                  0
Over 25 and with a High School Diploma.................                 85                 77                  0
----------------------------------------------------------------------------------------------------------------

    The results of the demographic analysis indicate that emissions
from petroleum refineries expose approximately 5,000,000 people to a
cancer risk at or above 1-in-1 million. Implementation of the
provisions included in this proposal is expected to reduce the number
of people estimated to have a cancer risk greater than 1-in-1 million
due to HAP emissions from these sources from 5,000,000 people to about
4,000,000. Our analysis of the demographics of the population within 50
km of the facilities indicates potential disparities in certain
demographic groups, including the African American, Other and
Multiracial, Hispanic, Below the Poverty Level, and Over 25 without a
High School Diploma. The population living within 50 km of the 142
petroleum refineries has a higher percentage of minority, lower income
and lower education persons when compared to the nationwide percentages
of those groups. For example, 50 percent are in one or more minority
demographic group, compared to 28 percent nationwide. As noted above,
approximately 5,000,000 people currently living within 50 km of a
petroleum refinery have a cancer risk greater than 1-in-1 million. We
would expect that half of those people are in one or more minority
demographic groups.
    Because minority groups make up a large portion of the population
living near refineries, as compared with their representation
nationwide, those groups would similarly see a greater benefit from the
implementation of the controls proposed in this rule, if finalized. For
example, we estimate that after implementation of the controls proposed
in this action (i.e., post-controls), about 1,000,000 fewer people will
be exposed to cancer risks greater than 1-in-1 million (i.e., 4,000,000
people). Further, we estimate that approximately 500,000 people no
longer exposed to a cancer risk greater than 1-in-1 million would be in
a minority demographic group. The post-control risk estimates are
discussed further in section III.A.5 of this preamble.
    Although the EPA's proposed fenceline monitoring requirement is
intended to ensure that owners and operators monitor, manage and, if
necessary, reduce fugitive emissions of HAP, we also expect the
collected fenceline data to help the EPA understand and identify
emissions of benzene and other fugitive emissions that are impacting
communities in close proximity to the facility. While currently-
available emissions and monitoring data do not indicate that risks to
nearby populations are unacceptable (see section IV.D.1 of this
preamble), we recognize that the collection of additional data through
routine fenceline monitoring can provide important information to
communities concerned with potential risks associated with emissions
from fugitive sources. We note that the data we are proposing to
collect on a semiannual basis may include exceedances of the fenceline
action level that a facility could have addressed or could still be
actively addressing at the time of the report. As noted in section
IV.B.1.h of this preamble, directly monitoring fugitive emissions from
each potential emissions source at the facility is impractical.
Fenceline monitoring offers a cost-effective alternative for monitoring
fugitive emissions from the entire facility. The EPA's proposal to
require the electronic reporting of fenceline monitoring data on a
semiannual basis will ensure that communities have access to data on
benzene levels near the facility, which is directly relevant to the
potential health risks posed by the facility. The proposed requirements
for fenceline monitoring and corrective action when fugitive emissions
from a facility exceed the specified corrective action level will serve
as an important backstop to protect the health of the populations
surrounding the facility, including minority and low-income
populations.

D. What are our proposed decisions regarding risk acceptability, ample
margin of safety and adverse environmental effects?

1. Risk Acceptability
    As noted in section II.A.1 of this preamble, the EPA sets standards
under CAA section 112(f)(2) using ``a two-step standard-setting
approach, with an analytical first step to determine an `acceptable
risk' that considers all health information, including risk estimation
uncertainty, and includes a presumptive limit on maximum individual
lifetime risk (MIR) of approximately 1 in 10 thousand.\[39]\ '' (54 FR
38045, September 14, 1989).
---------------------------------------------------------------------------

    \39\ 1-in-10 thousand is equivalent to 100-in-1 million. The EPA
currently describes cancer risks as `n-in-1 million'.
---------------------------------------------------------------------------

    In this proposal, we estimate risks based on actual emissions from
petroleum refineries. We also estimate risks from allowable emissions;
as discussed earlier, we consider our analysis of risk from allowable
emissions to be conservative and as such to represent an upper bound
estimate on risk from emissions allowed under the current MACT
standards for the source categories.
a. Estimated Risks From Actual Emissions
    The baseline inhalation cancer risk to the individual most exposed
to emissions from sources regulated by Refinery MACT 1 and 2 is 60-in-1
million based on actual emissions. The estimated incidence of cancer
due to inhalation exposures is 0.3 excess cancer cases per year, or 1
case every 3.3 years. Approximately 5,000,000 people face an increased
cancer risk greater than 1-in-1 million due to inhalation exposure to
actual HAP emissions from these source categories, and approximately
100,000 people face an increased risk greater than 10-in-1 million and
up to 60-in-1 million. The agency estimates that the maximum chronic
non-cancer TOSHI from inhalation exposure is 0.9 due to actual
emissions of HCN from FCCU.

    The screening assessment of worst-case acute inhalation impacts
from actual emissions indicates the potential for five pollutants--
nickel, arsenic, acrolein, benzene and acetaldehyde--to exceed an HQ
value of 1, with an estimated worst-case maximum HQ of 5 for nickel
based on the REL values. One hundred thirty-six of the 142 petroleum
refineries had an estimated worst-case HQ less than or equal to 1 for
all HAP. One facility had an estimated worst-case maximum HQ of 5 and
the remaining five refineries with an HQ above 1 had an estimated
worst-case HQ less than or equal to 3. Considering the conservative,
health-protective nature of the approach that is used to develop these
acute estimates, it is highly unlikely that an individual would have an
acute exposure above the REL. Specifically, the analysis is based on
the assumption that worst-case emissions and meteorology would coincide
with a person being at this exact location for a period of time long
enough to have an exposure level above the conservative REL value.
    The Tier II multipathway screening analysis of actual emissions
indicated the potential for PAH emissions that are about 30 times the
screening level for cancer, dioxin and furans emissions that are about
40 times the cancer screening level and cadmium emissions that are
about 2 times the screening level for non-cancer health effects. No
facility's emissions were above the screening level for mercury. As we
note above, the Tier II multipathway screen is conservative in that it
incorporates many health-protective assumptions. For example, we choose
inputs from the upper end of the range of possible values for the
influential parameters used in the Tier II screen and we assume that
the exposed individual exhibits ingestion behavior that would lead to a
high total exposure. A Tier II exceedance cannot be equated with a risk
value or a HQ or HI. Rather, it represents a high-end estimate of what
the risk or hazard may be. For example, an exceedance of 2 for a non-
carcinogen can be interpreted to mean that we have high confidence that
the HI would be lower than 2. Similarly, an exceedance of 30 for a
carcinogen means that we have high confidence that the risk is lower
than 30-in-1-million. Our confidence comes from the conservative, or
health-protective, assumptions that are used in the Tier II screen.
    The refined analysis that we conducted for a specific facility
showed that the Tier II screen for each pollutant over-predicted the
potential risk when compared to the refined analysis results. That
refined multipathway assessment showed that the Tier II screen resulted
in estimated risks that are higher than the risks estimated by the
refined analysis by 14 times for PAH, 3 times for dioxins and furans,
and 3 times for cadmium. The refined assessment results indicate that
the multipathway risks are considerably lower than the estimated
inhalation risks, and our refined multipathway analysis indicates that
multipathway risks are low enough that, while they are considered in
our proposed decisions, they do not weigh heavily into those decisions
because risks for the source category are driven by inhalation.
b. Estimated Risks From Allowable Emissions
    We estimate that the baseline inhalation cancer risk to the
individual most exposed to emissions from sources regulated by Refinery
MACT 1 and 2 is as high as 100-in-1 million based on allowable
emissions. The EPA estimates that the incidence of cancer due to
inhalation exposures could be as high as 0.6 excess cancer cases per
year, or 1 case approximately every 1.5 years. About 7,000,000 people
face an increased cancer risk greater than 1-in-1 million due to
inhalation exposure to allowable HAP emissions from these source
categories, and greater than 90,000 people face an increased risk
greater than 10-in-1 million, and as high as 100-in-1 million. Further,
we estimate that the maximum chronic non-cancer TOSHI from inhalation
exposure values at all refineries is less than 1 based on allowable
emissions.
    The baseline risks summarized above do not account for additional
risk reductions that we anticipate due to the MACT standards or the
technology review requirements we are proposing in this action.
c. Acceptability Determination
    In determining whether risk is acceptable, the EPA considered all
available health information and risk estimation uncertainty as
described above. As noted above, the agency estimated risk from actual
and allowable emissions. While there are uncertainties associated with
both the actual and allowable emissions, we consider the allowable
emissions to be an upper bound, based on the conservative methods we
used to calculate allowable emissions.
    The results indicate that both the actual and allowable inhalation
cancer risks to the individual most exposed are no greater than
approximately 100-in-1 million, which is the presumptive limit of
acceptability. The MIR based on actual emissions is 60-in-1 million,
approximately 60 percent of the presumptive limit. Based on the results
of the refined site-specific multipathway analysis summarized above and
described in section IV.C.3 of this preamble, we also conclude that the
ingestion cancer risk to the individual most exposed is significantly
less than 100-in-1 million. In addition, the maximum chronic non-cancer
TOSHI due to inhalation exposures is less than 1, and our refined
multipathway analysis indicates that non-cancer ingestion risks are
estimated to be less than non-cancer risk from inhalation. Finally, the
evaluation of acute non-cancer risks was very conservative, and showed
acute risks below a level of concern.
    In determining risk acceptability, we also evaluated population
impacts because of the large number of people living near facilities in
the source category. The analysis indicates that there are
approximately 5 million people exposed to actual emissions resulting in
a cancer risk greater than 1-in-1 million, and a substantially smaller
number of people (100,000) are exposed to a cancer risk of greater than
10-in-1 million but less than 100-in-1 million (with a maximum risk of
60-in-1 million). The inhalation cancer incidence is approximately one
case in every 3 years based on actual emissions. More detail on this
risk analysis is presented in section IV.C and summarized in Tables 10
and 11 of this preamble. The results of the demographic analysis for
petroleum refineries indicate that a greater proportion of certain
minority groups and low-income populations live near refineries than
the national demographic profile. More detail on these population
impacts is presented in section IV.C.7 of this preamble. We did not
identify any sensitivity to pollutants emitted from these source
categories particular to minority and low income populations.
Considering the above information, we propose that the risks remaining
after implementation of the existing NESHAP for the Refinery MACT 1 and
2 source categories is acceptable.
    We also note that the estimated baseline risks for the refineries
source categories include risks from emissions from DCU, which are a
previously unregulated emission source. As discussed in section IV.A.
of this preamble, we are proposing new MACT standards for these sources
that would reduce emissions of HAP by 850 tpy. We estimate that these
new standards would not affect the MIR, but would

reduce the source category cancer incidence by 15 percent.
    We solicit comment on all aspects of our proposed acceptability
determination. We note that while we are proposing that the risks
estimated from actual and allowable emissions are acceptable, the risks
based on allowable emissions are at the presumptive limit of acceptable
risk. Furthermore, a significant number of people live in relative
proximity to refineries across the country, and therefore a large
population is exposed to risks greater than 1-in-1 million. In
particular, we solicit comment on the methodology used to estimate
allowable emissions. As noted above, we consider the allowable
emissions to be an upper bound estimate based on the conservative
methods used to calculate such emissions. We recognize, however, that
some of the health information concerning allowable emissions arguably
borders on the edge of acceptability. Specifically, the analysis of
allowable emissions resulted in a MIR of 100-in-1 million, which is the
presumptive limit of acceptability, a large number of people
(7,000,000) estimated to be exposed at a cancer risk above 1-in-1
million, and an estimated high cancer incidence (one case approximately
every 1.5 years). Although we believe that our allowable emissions
represent an upper end estimate, we nonetheless solicit comment on
whether the health information currently before the Agency should be
deemed unacceptable. We also solicit comment on whether our allowable
emissions analysis reflects a reasonable estimate of emissions allowed
under the current MACT standards. Lastly, we solicit comment on the
acceptability of risk considering individuals' potential cumulative
inhalation and ingestion pathway exposure. Please provide comments and
data supporting your position. Such information will aid the Agency to
make an informed decision on risk acceptability as it moves forward
with this rulemaking.
2. Ample Margin of Safety
    We next considered whether the existing MACT standards provide an
ample margin of safety to protect public health. In addition to
considering all of the health risks and other health information
considered in the risk acceptability determination, in the ample margin
of safety analysis we evaluated the cost and feasibility of available
control technologies and other measures that could be applied in these
source categories to further reduce the risks due to emissions of HAP.
For purposes of the ample margin of safety analysis, we evaluated the
changes in risk that would occur through adoption of a specific
technology by looking at the changes to the risk due to actual
emissions. Due to the nature of the allowable risk analysis, which is
based on model plants and post processing to combine risk results,\40\
we did not evaluate the risk reductions resulting from reducing
allowable emissions at individual emission sources. Such an approach
would require an unnecessarily complex analysis that would not provide
any more useful information than the analysis we undertook using actual
emissions. We note that while we did not conduct a specific analysis
for allowable emissions, it is reasonable to expect reductions in risk
similar to those for actual emissions.
---------------------------------------------------------------------------

    \40\ As described in the memorandum entitled Refinery Emissions
and Risk Estimates for Modeled ``Allowable'' Emissions, available in
Docket EPA-HQ-OAR-2010-0682, the use of model plants and post-
processing was for the purpose of ensuring that our analysis would
provide a conservative estimate of actual emissions and thus a
conservative estimate of risk.
---------------------------------------------------------------------------

    As noted in our discussion of the technology review in section IV.B
of this preamble, we identified a number of developments in practices,
processes or control technologies for reducing HAP emissions from
petroleum refinery processes. As part of the risk review, we evaluated
these developments to determine if any of them could reduce risks and
whether it is necessary to require any of these developments to provide
an ample margin of safety to protect public health.
    We evaluated the health information and control options for all of
the emission sources located at refineries, including: Storage vessels,
equipment leaks, gasoline loading racks, marine vessel loading
operations, cooling towers/heat exchange systems, wastewater collection
and treatment, FCCU, flares, miscellaneous process vents, CRU and SRU.
For each of these sources, we considered chronic cancer and non-cancer
risk metrics as well as acute risk. Regarding our ample margin of
safety analyses for chronic non-cancer risk for the various emission
sources, we note that the baseline TOSHIs are less than 1 for the
entire source category and considerably less than 1 for all of the
emission sources except for the FCCU (which had an TOSHI of 0.9).
Therefore, we did not quantitatively evaluate reductions in the chronic
non-cancer TOSHI for sources other than FCCU in the ample margin of
safety analysis. Regarding our ample margin of safety analyses for
acute risk for all of the various emission sources, we note that our
analyses did not identify acute risks at a level of concern and,
therefore, we did not quantitatively evaluate reductions in the acute
HQ values for each individual emission source in the ample margin of
safety analysis. Accordingly, the following paragraphs focus on cancer
risk in the determination of whether the standards provide an ample
margin of safety to protect public health.
    For storage vessels, as discussed in section IV.B of this preamble,
we identified and evaluated three control options. Under the technology
review, we determined that two of the options, which we call options 1
and 2, are cost effective. We are proposing option 2, which includes
all of the requirements of option 1, as part of the technology review.
The option 2 controls that we are proposing under the technology review
would result in approximately 910 tpy reduction in HAP (a 40-percent
reduction from this emission source). As described in section IV.B of
this preamble, not only are these controls cost effective, but we
estimate a net cost savings because the emission reductions translate
into reduced product loss. These controls would reduce the cancer risk
to the individual most exposed from 60-in-1 million to 50-in-1 million
based on actual emissions at the facility where storage tank emissions
were driving the risk. However, the MIR remains unchanged for the
refinery source categories, at 60-in 1-million, because the facility
with the next highest cancer risk is 60-in-1 million and this risk is
driven by another emission source. The option 2 controls also would
reduce cancer incidence by approximately 2 percent. Finally, we
estimate that the option 2 controls reduce the number of people with a
cancer risk greater than 10-in-1 million storage tanks from 3,000 to 60
and reduce the number of people with a cancer risk greater than 1-in-1
million from storage tanks from 140,000 to 72,000. Since these controls
reduce cancer incidence, and reduce the number of people exposed to
cancer risks greater than 1-in-10 million and 1-in-1 million from
storage tank emissions, and are cost effective, we propose that these
controls are necessary to provide an ample margin of safety to protect
public health. We also evaluated one additional control option for
storage vessels, option 3, which incorporated both options 1 and 2
along with additional monitoring requirements. We estimate incremental
HAP emission reductions (beyond those provided by option 2) of 90 tpy.
The

incremental cost effectiveness for option 3 exceeds $60,000 per ton,
which we do not consider cost effective. In addition, the option 3
controls do not result in quantifiable reductions in the cancer risk to
the individual most exposed or the cancer incidence beyond the
reductions estimated for the option 2 controls. For these reasons, we
propose that it is not necessary to require the option 3 controls in
order to provide an ample margin of safety to protect public health.
    For equipment leaks, we identified and evaluated three control
options discussed previously in the technology review section of this
preamble (section IV.B). These options are:
     Option 1--monitoring and repair at lower leak definitions;
     Option 2--applying monitoring and repair requirements to
connectors; and
     Option 3--optical gas imaging and repair.
    We estimate that these three independent control options reduce
industry-wide emissions of organic HAP by 24 tpy, 86 tpy, and 24 tpy,
respectively. We estimate that none of the control options would reduce
the risk to the individual most exposed. We also estimate that the
cancer incidence would not change perceptively if these controls were
required. Finally, we estimate that the control options do not reduce
the number of people with a cancer risk greater than 10-in-1 million or
the number of people with a cancer risk greater than 1-in-1 million. As
discussed above, the available control options for equipment leaks do
not provide quantifiable risk reductions and, therefore, we propose
that these controls are not necessary to provide an ample margin of
safety.
    For gasoline loading racks, we identified and evaluated one control
option discussed previously in the technology review section of this
preamble (section IV.B). As discussed earlier, this option is a new
development that results in emissions that are higher than the current
level required under Refinery MACT 1. Since we estimate that no
emission reductions would result from this new technology and thus no
reduction in risk, we propose that this control option is not necessary
to provide an ample margin of safety.
    For marine vessel loading operations, we identified and evaluated
two control options discussed previously in the technology review
section of this preamble (section IV.B). The first option would be to
require submerged fill for small and offshore marine vessel loading
operations. Based on actual emissions, we project no HAP emission
reductions for this option, as all marine vessels that are used to
transport bulk refinery liquids are expected to already have the
required submerged fill pipes. Accordingly, we do not project any
changes in risk. While we are proposing this option under the
technology review, because the option is not projected to reduce
emissions or risk, we propose that a submerged loading requirement is
not necessary to provide an ample margin of safety. We also identified
and evaluated the use of add-on controls for gasoline loading at small
marine vessel loading operations. In the technology review, we rejected
this control option because the cost effectiveness exceeded $70,000 ton
of HAP reduced. We estimate that this option would not result in
quantifiable changes to any of the risk metrics. Because add-on
controls would not result in quantifiable risk reductions and we do not
consider the controls to be cost effective, we are proposing that add-
on controls for gasoline loading at small marine vessel loading
operations are not necessary to provide an ample margin of safety.
    For cooling towers and heat exchangers, we did not identify as part
of our technology review any developments in processes, practices or
controls beyond those that we considered in our beyond-the-floor
analysis at the time we set the MACT standards. We note that we issued
MACT standards for heat exchange systems in a final rule on October 28,
2009 (74 FR 55686), but existing sources were not required to comply
until October 29, 2012. As a result, the reductions were not reflected
in the inventories submitted in response to the ICR for refineries and
therefore were not included in our risk analysis based on actual
emissions. We estimate that these MACT standards will result in an
industry-wide reduction of over 600 tons HAP per year (or 85 percent).
The projected contribution to risk associated with cooling tower
emissions after implementation of these MACT standards for heat
exchange systems is approximately 1 percent. Because we did not
identify any control options beyond those required by the current
standards for cooling towers and heat exchange systems, we are
proposing that additional controls for these systems are not necessary
to provide an ample margin of safety.
    For wastewater collection and treatment systems, we identified and
evaluated three options for reducing emissions. We estimate
implementing these independent control options would result in emission
reductions of 158 tpy (4 percent), 549 tpy (15 percent), and 929 tpy
(25 percent), respectively. None of the control options would reduce
the cancer risk to the individual most exposed from 60-in-1 million.
Option 1 would reduce the cancer incidence by less than 1 percent, and
we expect any reduction in cancer incidence that would result from
options 2 or 3 to be small because this source accounts for about 10
percent of the cancer incidence from refineries as a whole and the most
stringent control option would reduce emissions from these source by
only 25 percent. Finally, we estimate that control option 1 would not
reduce the number of people with a cancer risk greater than 10-in-1
million or the number of people with a cancer risk greater than 1-in-1
million. We expect any changes to the number of people with a cancer
risk greater than 1-in-1 million from implementation of options 2 or 3
to be small for the same reasons mentioned above for cancer incidence.
We estimate the cost effectiveness of these options to be $26,600 per
ton, $52,100 per ton, and $54,500 per ton of organic HAP reduced, and
we do not consider any of these options to be cost effective. Because
of the very small reductions in risk and the lack of cost-effective
control options, we propose that these controls are not necessary to
provide an ample margin of safety.
    For FCCU, we did not identify any developments in processes,
practices or control technologies for organic HAP. For inorganic HAP
from FCCU, in the technology review, we identified and evaluated one
control option for an HCN emissions limit and one control option for a
PM emissions limit. The PM limit was adopted for new sources in
Refinery NSPS Ja as part of our review of Refinery NSPS J. We
considered the costs and emission reductions associated with requiring
existing sources to meet the new source level for PM under Refinery
NSPS Ja (i.e., 0.5 g PM/kg of coke burn-off rather than 1.0 g PM/kg).
As indicated in our promulgation of Refinery NSPS Ja, the cost
effectiveness of lowering the PM limit for existing sources to the
level we are requiring for new sources was projected to be $21,000 per
ton of PM reduced (see 73 FR 35845, June 24, 2008). Based on the
typical metal HAP concentration in PM from FCCU, the cost effectiveness
of this option for HAP metals is approximately $1 million per ton of
HAP reduced. We estimate that this control option would not reduce the
cancer risk to the individual most exposed, would not change the cancer
incidence, and would not change the number of people with estimated
cancer

risk greater than 1-in-1 million or 10-in-1 million. For the HCN
emissions limit, we evaluated the costs of controlling HCN using
combustion controls in combination with SCR. The cost effectiveness of
this option was approximately $9,000 per ton of HCN. This control
option would reduce the non-cancer HI from 0.9 to 0.8 and would not
change any of the cancer risk metrics. Based on the cost effectiveness
of these options and the limited reduction in cancer and non-cancer
risk (the non-cancer risk is below a level of concern based on the
existing standards), we propose that additional controls for FCCU are
not necessary to provide an ample margin of safety.
    Flares are used as APCD to control emissions from several emission
sources covered by Refinery MACT 1 and 2. In this proposed rule, under
CAA sections 112(d)(2) and (3), we are proposing operating and
monitoring requirements to ensure flares achieve the 98-percent HAP
destruction efficiency identified as the MACT Floor in the initial MACT
rulemaking in 1995. Flares are critical safety devices that effectively
reduce emissions during startup, shutdown, and process upsets or
malfunctions. In most cases, flares are the only means by which
emissions from pressure relief devices can be controlled. Thus, we find
that properly-functioning flares act to reduce HAP emissions, and
thereby risk, from petroleum refinery operations. The changes to the
flare requirements that we are proposing under CAA sections 112(d)(2)
and (3) will result in sources meeting the level required by the
original standards, and we did not identify any control options that
would further reduce the HAP emissions from flares. Therefore, we are
proposing that additional controls for flares are not necessary to
provide an ample margin of safety.
    For the remaining emission sources within the Refinery MACT 1 and
Refinery MACT 2 source categories, including miscellaneous process
vents, CRU, and SRU, we did not identify any developments in processes
practices and control technologies. Therefore, we are proposing that
additional controls for these three Refinery MACT 1 and 2 emission
sources are not necessary to provide an ample margin of safety.
    In summary, we propose that the original Refinery MACT 1 and 2 MACT
standards, along with the proposed requirements for storage vessels
described above, provide an ample margin of safety to protect public
health. We are specifically requesting comment on whether there are
additional control measures for emission sources subject to Refinery
MACT 1 and Refinery MACT 2 that are necessary to provide an ample
margin of safety to protect public health. In particular, we are
requesting that states identify any controls they have already required
for these facilities, controls they are currently considering, or other
controls of which they may be aware.
    While not part of our decisions regarding residual risk, we note
that DCU are an important emission source with respect to risk from
refineries. As described in section IV.A of this preamble, we are
proposing new MACT standards under CAA sections 112(d)(2) and (3) for
DCU. For informational purposes, we also looked at the risk reductions
that would result from implementation of those standards. We estimate
no reduction in the cancer risk to the individual most exposed and a
decrease in cancer incidence of 0.05 cases per year, or approximately
15 percent. While our decisions on risk acceptability and ample margin
of safety are supported even in the absence of these reductions, if we
finalize the proposed requirements for DCU, they would further
strengthen our conclusions that the standards provide an ample margin
of safety to protect public health.
3. Adverse Environmental Effects
    We conducted an environmental risk screening assessment for the
petroleum refineries source category for lead, mercury, cadmium, PAH,
dioxins and furans, HF, and HCl. For mercury, cadmium, PAH, and dioxins
and furans, none of the individual modeled concentrations for any
facility in the source category exceeded any of the Tier II ecological
benchmarks (either the LOAEL or NOAEL). For lead, we did not estimate
any exceedances of the secondary lead NAAQS. For HF and HCl, the
average modeled concentration around each facility (i.e., the average
concentration of all off-site data points in the modeling domain) did
not exceed any ecological benchmark. Based on these results, EPA
proposes that it is not necessary to set a more stringent standard to
prevent, taking into consideration costs, energy, safety, and other
relevant factors, an adverse environmental effect.

E. What other actions are we proposing?

    We are proposing the following changes to Refinery MACT 1 and 2 as
described below: (1) Revising the SSM provisions in order to ensure
that the subparts are consistent with the court decision in Sierra Club
v. EPA, 551 F. 3d 1019 (D.C. Cir. 2008), which vacated two provisions
that exempted sources from the requirement to comply with otherwise
applicable section 112(d) emission standards during periods of SSM; (2)
proposing to clarify requirements related to open-ended valves or
lines; (3) adding electronic reporting requirements in Refinery MACT 1
and 2; and (4) updating the General Provisions cross-reference tables.
1. SSM
    In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C.
Cir. 2008), the United States Court of Appeals for the District of
Columbia Circuit vacated portions of two provisions in the EPA's CAA
section 112 regulations governing the emissions of HAP during periods
of SSM. Specifically, the Court vacated the SSM exemption contained in
40 CFR 63.6(f)(1) and 40 CFR 63.6(h)(1), holding that under section
302(k) of the CAA, emissions standards or limitations must be
continuous in nature and that the SSM exemption violates the CAA's
requirement that some section 112 standards apply continuously.
    We are proposing the elimination of the SSM exemption in 40 CFR
part 63, subparts CC and UUU. Consistent with Sierra Club v. EPA, we
are proposing standards in these rules that apply at all times. We are
also proposing 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) as explained in more
detail below. For example, we are proposing to eliminate the
incorporation of the General Provisions' requirement that the source
develop an SSM plan. We also are proposing to eliminate and revise
certain recordkeeping and reporting requirements related to the SSM
exemption as further described below.
    The EPA has attempted to ensure that the provisions we are
proposing to eliminate are inappropriate, unnecessary, or redundant in
the absence of the SSM exemption. We are specifically seeking comment
on whether we have successfully done so.
    In proposing the standards in this rule, the EPA has taken into
account startup and shutdown periods and, for the reasons explained
below, we are proposing alternate standards for those periods for a few
select emission sources. We expect facilities can meet nearly all of
the emission standards in Refinery MACT 1 and 2 during startup and
shutdown, including the amendments we are proposing in this action. For
most of the emission sources, APCD are operating prior to process
startup and continue to operate through process shutdown.

    For Refinery MACT 1 and 2, we identified three emission sources for
which specific startup and shutdown provisions may be needed. First, as
noted above, most APCD used to control metal HAP emissions from FCCU
under Refinery MACT 2 (e.g., wet scrubber, fabric filter, cyclone)
would be operating before emissions are routed to them and would be
operating during startup and shutdown events in a manner consistent
with normal operating periods, such that the monitoring parameter
operating limits set during the performance test are maintained and
met. However, we recognize that there are safety concerns associated
with operating an ESP during startup of the FCCU, as described in the
following paragraphs. Therefore, we are proposing specific PM standards
for startup of FCCU controlled with an ESP under Refinery MACT 2.
    During startup of the FCCU, ``torch oil'' (heavy oil typically used
as feed to the unit via the riser) is injected directly into the
regenerator and burned to raise the temperature of the regenerator and
catalyst to levels needed for normal operation. Given the poor mixing
of fuel and air in the regenerator during this initial startup, it is
difficult to maintain optimal combustion characteristics, and high CO
concentrations are common. Elevated CO levels pose an explosion threat
due to the high electric current and potential for sparks within the
ESP. Consequently, it is common practice to bypass the ESP during
startup of the FCCU. Once torch oil is shut off and the regenerator is
fueled by catalyst coke burn-off, the CO levels in the FCCU regenerator
off-gas will stabilize and the gas can be sent to the ESP safely.
    When the ESP is offline, the operating limits for the ESP are
meaningless. During much of the startup process, either catalyst is not
circulating between the FCCU regenerator and reactor or the catalyst
circulation rate is much lower than during normal operations. While the
catalyst is not circulating or is circulating at reduced rates, the PM
and metal HAP emissions are expected to be much lower than during
normal operations. Therefore, the cyclone separators that are internal
to the FCCU regenerator should provide reasonable PM control during
this initial startup. To ensure the internal cyclones are operating
efficiently, we are proposing that FCCU using an ESP as the APCD meet a
30-percent opacity limit (on a 6-minute rolling average basis) during
the period that torch oil is used during FCCU startup. This opacity
limit was selected because it has been used historically to assess
compliance with the PM emission limit for FCCU in Refinery NSPS J and
because the emission limit can be assessed using manual opacity
readings, eliminating the need to install a COMS. We note that Refinery
NSPS J includes the exception for one 6-minute average of up to 60-
percent opacity in a 1-hour period primarily to accommodate soot
blowing events. As no soot blowing should be performed prior to the ESP
coming on-line, we are not including this exception to the proposed 30-
percent opacity limit during startup for FCCU that are controlled by an
ESP.
    Second, for emissions of organic HAP from FCCU under Refinery MACT
2, we also expect that APCD would be operating before emissions are
routed to them, and would be operating during startup and shutdown
events in a manner consistent with normal operating periods, such that
the monitoring parameter operating limits set during the performance
test are maintained and met. However, many FCCU operate in ``complete
combustion'' mode without a post-combustion device. In other words, for
FCCU without a post-combustion device, organic HAP are controlled by
the FCCU itself, so there is no separate APCD that could be operating
during startup and demonstrating continuous compliance with the
monitoring parameter operating limits. Therefore, we are proposing
specific CO standards for startup of FCCU without a post-combustion
device under Refinery MACT 2.
    As mentioned previously, ``torch oil'' is injected directly into
the regenerator and burned during FCCU startup to raise the temperature
of the regenerator and catalyst to levels needed for normal operation.
During this period, CO concentrations often will exceed the 500 ppm
emissions limit due to the poor mixing of fuel and air in the
regenerator. The emissions limit is based on CO emissions, as a
surrogate for organic HAP emissions, and the emission limit is
evaluated using a 1-hour averaging period. This 1-hour averaging period
does not provide adequate time for short-term excursions that occur
during startup to be offset by lower emissions during normal
operational periods.
    Based on available data during normal operations, ensuring adequate
combustion (indicated by CO concentration levels below 500 ppmv)
minimizes organic HAP emissions. Low levels of CO in the exhaust gas
are consistently achieved during normal operations when oxygen
concentrations in the exhaust gas exceed 1-percent by volume (dry
basis). Thus, maintaining an adequate level of excess oxygen for the
combustion of fuel in the FCCU is expected to minimize organic HAP
emissions. Emissions of CO during startup result from a series of
reactions with the fuel source and are dependent on mixing, local
oxygen concentrations, and temperature. While the refinery owner or
operator has direct control over air blast rates, CO emissions may not
always directly correlate with the air blast rate. Exhaust oxygen
concentrations are expected to be more directly linked with air blast
rates and are, therefore, more directly under control of the refinery
owner or operator. We are proposing an excess oxygen concentration of 1
volume percent (dry basis) based on a 1-hour average during startup. We
consider the 1-hour averaging period for the oxygen concentration in
the exhaust gas from the FCCU to be appropriate during periods of FCCU
startup because air blast rates can be directly controlled to ensure
adequate oxygen supply on a short-term basis.
    Third, we note that the SRU is unique in that it essentially is the
APCD for the fuel gas system at the facility. The SRU would be
operating if the refinery is operating, including during startup and
shutdown events. There are typically multiple SRU trains at a facility.
Different trains can be taken off-line as sour gas production decreases
to maintain optimal operating characteristics of the operating SRU
during startup or shutdown of a set of process units. Thus, the sulfur
recovery plant is expected to run continuously and would only shut down
its operation during a complete turnaround or shutdown of the facility.
For these limited situations, the 12-hour averaging time provided for
the SRU emissions limitation under Refinery MACT 2 may not be adequate
time in which to shut down the unit without exceeding the emissions
limitation. Therefore, we are proposing specific standards for SRU
during periods of shutdown.
    We note also that, for SRU subject to Refinery NSPS J or electing
to comply with Refinery NSPS J as provided in Refinery MACT 2, the
emissions limit is in terms of SO2 concentration for SRU
with oxidative control systems or reductive control systems followed by
an incinerator. While the SO2 concentration limit provides a
reasonable proxy of the reduced sulfur HAP emissions during normal
operations, it does not necessarily provide a good indication of
reduced sulfur HAP emissions during periods of shutdown. During periods
of shutdown, the sulfur remaining in the unit is purged and combusted
generally in a thermal oxidizer or a flare. Although the sulfur loading
to the thermal oxidizer

during shutdown may be higher than during normal operations (thereby
causing an increase in the SO2 concentration and exceedance
of the SO2 emissions limitation), appropriate operation of
the thermal oxidizer will adequately control emissions of reduced
sulfur HAP. Thus, during periods of shutdown, the 300 ppmv reduced
sulfur compound emission limit alternative (provided for SRU not
subject to Refinery NSPS J) is a better indicator of reduced sulfur HAP
emissions. In Refinery MACT 2, SRU that elect to comply with the 300
ppmv reduced sulfur compound emission limit (i.e., those not subject to
Refinery NSPS J or electing to comply with Refinery NSPS J) and that
use a thermal incinerator for sulfur HAP control are required to
maintain a minimum temperature and excess oxygen level (as determined
through a source test of the unit) to demonstrate compliance with the
reduced sulfur compound emission limitation.
    In Refinery MACT 2, SRU subject to Refinery NSPS J (or that elect
to comply with Refinery NSPS J) that use an incinerator to control
sulfur HAP emissions are required to install an SO2 CEMS to
demonstrate compliance with the SO2 emission limitation. For
these units, it is impractical to require installation of a reduced
sulfur compound monitor or to require a source test to establish
operating parameters during shutdown of the SRU because of the few
hours per year that the entire series of SRU trains are shutdown.
Although the autoignition temperature of COS is unknown, based on the
autoignition temperature of CS2 (between 200 and 250 [deg]F)
and the typical operating characteristics of thermal oxidizers used to
control emissions from SRU, we are proposing that, for periods of SRU
shutdown, diverting the 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 1200 [deg]F and a minimum outlet oxygen
concentration of 2 volume percent (dry basis). We believe that this
provides adequate assurance of compliance with the 300 ppmv reduced
sulfur compound emission limitation for SRU because incineration at
these temperatures was determined to be the MACT floor in cases where
no tail gas treatment units were used (i.e., units not subject to
Refinery NSPS J).
    For all other emission sources, we believe that the requirements
that apply during normal operations should apply during startup and
shutdown. For Refinery MACT 1, these emission sources include process
vents, transfer operations, storage tanks, equipment leaks, heat
exchange systems, and wastewater. Emission reductions for process vents
and transfer operations, such as gasoline loading racks and marine tank
vessel loading, are typically achieved by routing vapors to thermal
oxidizers, carbon adsorbers, absorbers and flares. It is common
practice to start an APCD prior to startup of the emissions source it
is controlling, so the APCD would be operating before emissions are
routed to it. We expect APCD would be operating during startup and
shutdown events in a manner consistent with normal operating periods,
and that these APCD will be operated to maintain and meet the
monitoring parameter operating limits set during the performance test.
We do not expect startup and shutdown events to affect emissions from
equipment leaks, heat exchange systems, wastewater, or storage tanks.
Leak detection programs associated with equipment leaks and heat
exchange systems are in place to detect leaks, and, therefore, it is
inconsequential whether the process is operating under normal operating
conditions or is in startup or shutdown. Wastewater emissions are also
not expected to be significantly affected by startup or shutdown events
because the control systems used can operate while the wastewater
treatment system is in startup or shutdown. Working and breathing
losses from storage tanks are the same regardless of whether the
process is operating under normal operating conditions or if it is in a
startup or shutdown event. Degassing of a storage tank is common for
shutdown of a process; the residual emissions in a storage tank are
vented as part of the cleaning of the storage tank. We evaluated
degassing controls as a control alternative for storage vessels and do
not consider these controls to be cost effective (see memorandum Survey
of Control Technology for Storage Vessels and Analysis of Impacts for
Storage Vessel Control Options, Docket Item Number EPA-HQ-OAR-2010-
0871-0027). Based on this review, we are not proposing specific
standards for storage vessels during startup or shutdown.
    Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. However, by
contrast, malfunction is defined as a sudden, infrequent, and not
reasonably preventable failure of air pollution control and monitoring
equipment, process equipment or a process to operate in a normal or
usual manner (see 40 CFR 63.2). The EPA has determined that CAA section
112 does not require that emissions that occur during periods of
malfunction be factored into development of section 112 standards.
Under section 112, emissions standards for new sources must be no less
stringent than the level ``achieved'' by the best-controlled similar
source and for existing sources generally must be no less stringent
than the average emission limitation ``achieved'' by the best-
performing 12 percent of sources in the category. There is nothing in
section 112 that directs the EPA to consider malfunctions in
determining the level ``achieved'' by the best-performing sources when
setting emission standards. As the D.C. Circuit has recognized, the
phrase ``average emissions limitation achieved by the best performing
12 percent of'' sources ``says nothing about how the performance of the
best units is to be calculated.'' Nat'l Ass'n of Clean Water Agencies
v. EPA, 734 F.3d 1115, 1141 (D.C. Cir. 2013). While the EPA accounts
for variability in setting emissions standards, nothing in section 112
requires the EPA to consider malfunctions as part of that analysis. A
malfunction should not be treated in the same manner as the type of
variation in performance that occurs during routine operations of a
source. A malfunction is a failure of the source to perform in a
``normal or usual manner'' and no statutory language compels EPA to
consider such events in setting standards based on ``best performers.''
    Further, accounting for malfunctions in setting emissions standards
would be difficult, if not impossible, given the myriad different types
of malfunctions that can occur across all sources in the category, and
given the difficulties associated with predicting or accounting for the
frequency, degree, and duration of various malfunctions that might
occur. As such, the performance of units that are malfunctioning is not
``reasonably'' foreseeable. See, e.g., Sierra Club v. EPA, 167 F. 3d
658, 662 (D.C. Cir. 1999) (the EPA typically has wide latitude in
determining the extent of data-gathering necessary to solve a problem.
We generally defer to an agency's decision to proceed on the basis of
imperfect scientific information, rather than to ``invest the resources
to conduct the perfect study.''). See also, Weyerhaeuser v. Costle, 590
F.2d 1011, 1058 (D.C. Cir. 1978) (``In the nature of things, no general
limit, individual permit, or even any upset provision can anticipate
all upset situations. After a certain point, the transgression of
regulatory limits caused by

`uncontrollable acts of third parties,' such as strikes, sabotage,
operator intoxication or insanity, and a variety of other
eventualities, must be a matter for the administrative exercise of
case-by-case enforcement discretion, not for specification in advance
by regulation.''). In addition, emissions during a malfunction event
can be significantly higher than emissions at any other time of source
operation, and thus, accounting for malfunctions in setting standards
could lead to standards that are significantly less stringent than
levels that are achieved by a well-performing non-malfunctioning
source. It is reasonable to interpret section 112 to avoid such a
result. The EPA's approach to malfunctions is consistent with CAA
section 112 and is a reasonable interpretation of the statute.
    In the event that a source fails to comply with the applicable CAA
section 112(d) standards as a result of a malfunction event, the EPA
would determine an appropriate response based on, among other things,
the good-faith efforts of the source to minimize emissions during
malfunction periods, including preventative and corrective actions, as
well as root cause analyses to ascertain and rectify excess emissions.
The EPA would also consider whether the source's failure to comply with
the CAA section 112(d) standard was, in fact, sudden, infrequent, not
reasonably preventable and was not instead caused in part by poor
maintenance or careless operation, as described in the definition of
malfunction (see 40 CFR 63.2). Further, to the extent the EPA files an
enforcement action against a source for violation of an emission
standard, the source can raise any and all defenses in that enforcement
action and the federal district court will determine what, if any,
relief is appropriate. The same is true for citizen enforcement
actions. Similarly, the presiding officer in an administrative
proceeding can consider any defense raised and determine whether
administrative penalties are appropriate.
    In several prior rules, the EPA had included an affirmative defense
to civil penalties for violations caused by malfunctions in an effort
to create a system that incorporates some flexibility, recognizing that
there is a tension, inherent in many types of air regulation, to ensure
adequate compliance while simultaneously recognizing that despite the
most diligent of efforts, emission standards may be violated under
circumstances entirely beyond the control of the source. Although the
EPA recognized that its case-by-case enforcement discretion provides
sufficient flexibility in these circumstances, it included the
affirmative defense to provide a more formalized approach and more
regulatory clarity. See Weyerhaeuser Co. v. Costle, 590 F.2d 1011,
1057-58 (D.C. Cir. 1978) (holding that an informal case-by-case
enforcement discretion approach is adequate); but see Marathon Oil Co.
v. EPA, 564 F.2d 1253, 1272-73 (9th Cir. 1977) (requiring a more
formalized approach to consideration of ``upsets beyond the control of
the permit holder.''). Under the EPA's regulatory affirmative defense
provisions, if a source could demonstrate in a judicial or
administrative proceeding that it had met the requirements of the
affirmative defense in the regulation, civil penalties would not be
assessed. Recently, the United States Court of Appeals for the District
of Columbia Circuit vacated such an affirmative defense in one of the
EPA's section 112(d) regulations. NRDC v. EPA, No. 10-1371 (D.C. Cir.
April 18, 2014) 2014 U.S. App. LEXIS 7281 (vacating affirmative defense
provisions in section 112(d) rule establishing emission standards for
Portland cement kilns). The court found that the EPA lacked authority
to establish an affirmative defense for private civil suits and held
that under the CAA, the authority to determine civil penalty amounts
lies exclusively with the courts, not the EPA. Specifically, the Court
found: ``As the language of the statute makes clear, the courts
determine, on a case-by-case basis, whether civil penalties are
`appropriate.' '' See NRDC, 2014 U.S. App. LEXIS 7281 at *21 (``[U]nder
this statute, deciding whether penalties are `appropriate' in a given
private civil suit is a job for the courts, not EPA.'').\41\ In light
of NRDC, the EPA is not including a regulatory affirmative defense
provision in this rulemaking. As explained above, if a source is unable
to comply with emissions standards as a result of a malfunction, the
EPA may use its case-by-case enforcement discretion to provide
flexibility, as appropriate. Further, as the D.C. Circuit recognized,
in an EPA or citizen enforcement action, the court has the discretion
to consider any defense raised and determine whether penalties are
appropriate. Cf. NRDC, 2014 U.S. App. LEXIS 7281 at *24. (arguments
that violation were caused by unavoidable technology failure can be
made to the courts in future civil cases when the issue arises). The
same logic applies to EPA administrative enforcement actions.
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    \41\ The court's reasoning in NRDC focuses on civil judicial
actions. The Court noted that ``EPA's ability to determine whether
penalties should be assessed for Clean Air Act violations extends
only to administrative penalties, not to civil penalties imposed by
a court.'' Id.
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a. General Duty
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.6(e)(1)(i) by changing the
``Yes'' in the second column to a ``No.'' Similarly, we are proposing
to revise the 40 CFR part 63, subpart UUU General Provisions table
(Table 44) entry for Sec.  63.6(e)(1)(i) by changing the ``Yes'' in the
third column to a ``No.'' We are making this change because section
63.6(e)(1)(i) describes the general duty to minimize emissions and the
current characterizes what the general duty entails during periods of
SSM and that language is no longer necessary or appropriate in light of
the elimination of the SSM exemption. We are proposing instead to add
general duty regulatory text at 40 CFR 63.642(n) and 40 CFR 63.1570(c)
that reflects the general duty to minimize emissions while eliminating
the reference to periods covered by an SSM exemption. With the
elimination of the SSM exemption, there is no need to differentiate
between normal operations, startup and shutdown, and malfunction events
in describing the general duty. Therefore the language the EPA is
proposing does not include that language from 40 CFR 63.6(e)(1).
    We are also proposing to revise the 40 CFR part 63, subpart CC
General Provisions table (Table 6) entry for 63.6(e)(1)(ii) by changing
the ``Yes'' in the second column to a ``No.'' Similarly, we are also
proposing to revise the 40 CFR part 63, subpart UUU General Provisions
table (Table 44) entry for Sec.  63.6(e)(1)(ii) by changing the ``Yes''
in the third column to a ``No.'' Section 63.6(e)(1)(ii) imposes
requirements that are not necessary with the elimination of the SSM
exemption or are redundant of the general duty requirement being added
at 40 CFR 63.642(n) and 40 CFR 63.1570(c).
b. SSM Plan
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entries for 63.6(e)(3)(i) and
63.6(e)(3)(iii)-63.6(e)(3)(ix) by changing the ``Yes'' in the second
column to a ``No.'' Similarly, we are proposing to revise the 40 CFR
part 63, subpart UUU General Provisions table (Table 44) entries for
Sec.  63.6(e)(3)(i)-(iii), Sec.  63.6(e)(3)(iv), Sec.  63.6(e)(3)(v)-
(viii), Sec.  63.6(e)(3)(ix) to be entries for 63.6(e)(3)(i) and
63.6(e)(3)(iii)-63.6(e)(3)(ix) with ``No'' in the third column and
Sec.  63.6(e)(3)(ii) with ``Not

Applicable'' in the third column (that section is reserved). Generally,
these paragraphs require development of an SSM plan and specify SSM
recordkeeping and reporting requirements related to the SSM plan. As
noted, the EPA is proposing to remove the SSM exemptions. Therefore,
affected units will be subject to an emission standard during such
events. The applicability of a standard during such events will ensure
that sources have ample incentive to plan for and achieve compliance
and thus the SSM plan requirements are no longer necessary.
c. Compliance With Standards
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.6(f)(1) by changing the ``Yes''
in the second column to a ``No.'' Similarly, we are proposing to revise
the 40 CFR part 63, subpart UUU General Provisions table (Table 44)
entry for Sec.  63.6(f)(1) by changing the ``Yes'' in the third column
to a ``No.'' The current language of 40 CFR 63.6(f)(1) exempts sources
from non-opacity standards during periods of SSM. As discussed above,
the court in Sierra Club vacated the exemptions contained in this
provision and held that the CAA requires that some section 112 standard
apply continuously. Consistent with Sierra Club, the EPA is proposing
to revise standards in this rule to apply at all times.
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.6(h)(1) by changing the ``Yes''
in the second column to a ``No.'' Similarly, we are proposing to revise
the 40 CFR part 63, subpart UUU General Provisions table (Table 44)
entry for Sec.  63.6(h)(1) by changing the ``Yes'' in the third column
to a ``No.'' The current language of 40 CFR 63.6(h)(1) exempts sources
from opacity standards during periods of SSM. As discussed above, the
court in Sierra Club vacated the exemptions contained in this provision
and held that the CAA requires that some section 112 standard apply
continuously. Consistent with Sierra Club, the EPA is proposing to
revise standards in this rule to apply at all times.
d. Performance Testing
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.7(e)(1) by changing the ``Yes''
in the second column to a ``No.'' Similarly, we are proposing to revise
the 40 CFR part 63, subpart UUU General Provisions table (Table 44)
entry for Sec.  63.7(e)(1) by changing the ``Yes'' in the third column
to a ``No.'' Section 63.7(e)(1) describes performance testing
requirements. The EPA is instead proposing to add performance testing
requirements at 40 CFR 63.642(d)(3) and 40 CFR 63.1571(b)(1). The
performance testing requirements we are proposing differ from the
General Provisions performance testing provisions in several respects.
The regulatory text does not include the language in 40 CFR 63.7(e)(1)
that restated the SSM exemption. The regulatory text also does not
preclude startup and shutdown periods from being considered
``representative'' for purposes of performance testing, however, the
testing. However, the specific testing provisions proposed at 40 CFR
63.642(d)(3) and 40 CFR 63.1571(b)(1) do not allow performance testing
during startup or shutdown. As in 40 CFR 63.7(e)(1), performance tests
conducted under this subpart may not be conducted during malfunctions
because conditions during malfunctions are often not representative of
normal operating conditions. The EPA is proposing to add language that
requires the owner or operator to record the process information that
is necessary to document operating conditions during the test and
include in such record an explanation to support that such conditions
represent normal operation. Section 63.7(e) requires that the owner or
operator make available to the Administrator such records ``as may be
necessary to determine the condition of the performance test''
available to the Administrator upon request, but does not specifically
require the information to be recorded. The regulatory text EPA is
proposing to add to Refinery MACT 1 and 2 builds on that requirement
and makes explicit the requirement to record the information.
e. Monitoring
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entries for 63.8(c)(1)(i) and
63.8(c)(1)(iii) by changing the ``Yes'' in the second column to a
``No.'' Similarly, we are proposing to revise the 40 CFR part 63,
subpart UUU General Provisions table (Table 44) entry for Sec.
63.8(c)(1)(i) and Sec.  63.8(c)(1)(iii) by changing the ``Yes'' in the
third column to a ``No.'' The cross-references to the general duty and
SSM plan requirements in those subparagraphs are not necessary in light
of other requirements of 40 CFR 63.8 that require good air pollution
control practices (40 CFR 63.8(c)(1)) and that set out the requirements
of a quality control program for monitoring equipment (40 CFR 63.8(d)).
    We are proposing to revise the 40 CFR part 63, subpart UUU General
Provisions table (Table 44) entry for Sec.  63.8(d) to include separate