entries for specific paragraphs of 40 CFR 63.8(d), including an entry
for Sec.  63.10(d)(3) with ``No'' in the third column. The final
sentence in 40 CFR 63.8(d)(3) refers to the General Provisions' SSM
plan requirement which is no longer applicable. The EPA is proposing to
add to the rule at 40 CFR 63.1576(b)(3) text that is identical to 40
CFR 63.8(d)(3) except that the final sentence is replaced with the
following sentence: ``The program of corrective action should be
included in the plan required under Sec.  63.8(d)(2).''
f. Recordkeeping
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.10(b)(2)(i) by changing the
``Yes'' in the second column to a ``No.'' Section 63.10(b)(2)(i)
describes the recordkeeping requirements during startup and shutdown.
These recording provisions are no longer necessary because the EPA is
proposing that recordkeeping and reporting applicable to normal
operations will apply to startup and shutdown. In the absence of
special provisions applicable to startup and shutdown, such as a
startup and shutdown plan, there is no reason to retain additional
recordkeeping for startup and shutdown periods.
    We are proposing to revise the 40 CFR part 63, subpart UUU General
Provisions table (Table 44) entry for Sec.  63.10(b) to include
separate entries for specific paragraphs of 40 CFR 63.10(b), including
an entry for Sec.  63.10(b)(2)(i) with ``No'' in the third column.
Section 63.10(b)(2)(i) describes the recordkeeping requirements during
startup and shutdown. We are instead proposing to add recordkeeping
requirements to 40 CFR 63.1576(a)(2). When a source is subject to a
different standard during startup and shutdown, it will be important to
know when such startup and shutdown periods begin and end in order to
determine compliance with the appropriate standard. Thus, the EPA is
proposing to add language to 40 CFR 63.1576(a)(2) requiring that
sources subject to an emission standard during startup or shutdown that
differs from the emission standard that applies at all other times must
record the date, time, and duration of such periods.
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.10(b)(2)(ii) 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.
63.10(b) to include separate entries for specific paragraphs of 40 CFR
63.10(b), including an entry for Sec.  63.10(b)(2)(ii) with ``No'' in
the third column. Section 63.10(b)(2)(ii) describes the recordkeeping
requirements during a malfunction. The EPA is proposing to add such
requirements to 40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2). The
regulatory text we are proposing to add differs from the General
Provisions language that was cross-referenced, which provides the
creation and retention of a record of the occurrence and duration of
each malfunction of process, air pollution control, and monitoring
equipment. The proposed text would apply to any failure to meet an
applicable standard and would require the source to record the date,
time, and duration of the failure. The EPA is also proposing to add to
40 CFR 63.655(i)(11) and 40 CFR 63.1576(a)(2) a requirement that
sources keep records that include a list of the affected source or
equipment and actions taken to minimize emissions, an estimate of the
quantity of each regulated pollutant emitted over the standard for
which the source failed to meet a standard, and a description of the
method used to estimate the emissions. Examples of such methods would
include product-loss calculations, mass balance calculations,
measurements when available, or engineering judgment based on known
process parameters. The EPA is proposing to require that sources keep
records of this information to ensure that there is adequate
information to allow the EPA to determine the severity of any failure
to meet a standard, and to provide data that may document how the
source met the general duty to minimize emissions when the source has
failed to meet an applicable standard.
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.10(b)(2)(iv) 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.  63.10(b) to include separate entries for
specific paragraphs of 40 CFR 63.10(b), including an entry for Sec.
63.10(b)(2)(iv)-(v) with ``No'' in the third column. When applicable,
40 CFR 63.10(b)(2)(iv) requires sources to record actions taken during
SSM events when actions were inconsistent with their SSM plan. The
requirement is no longer appropriate because SSM plans will no longer
be required. The requirement previously applicable under 40 CFR
63.10(b)(2)(iv)(B) to record actions to minimize emissions and record
corrective actions is now applicable by reference to 40 CFR
63.655(i)(11)(iii) and 40 CFR 63.1576(a)(2)(iii).
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entry for 63.10(b)(2)(v) 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.  63.10(b) to include separate entries for
specific paragraphs of 40 CFR 63.10(b), including an entry for Sec.
63.10(b)(2)(iv)-(v) with ``No'' in the third column. When applicable,
40 CFR 63.10(b)(2)(v) requires sources to record actions taken during
SSM events to show that actions taken were consistent with their SSM
plan. The requirement is no longer appropriate because SSM plans would
no longer be required.
    We are proposing to revise the 40 CFR part 63, subpart UUU General
Provisions table (Table 44) entry for Sec.  63.10(c)(9)-(15) to include
separate entries for specific paragraphs of 40 CFR 63.10(c), including
an entry for Sec.  63.10(c)(15) with ``No'' in the third column. The
EPA is proposing that 40 CFR 63.10(c)(15) no longer apply. When
applicable, the provision allows an owner or operator to use the
affected source's SSM plan or records kept to satisfy the recordkeeping
requirements of the SSM plan, specified in 40 CFR 63.6(e), to also
satisfy the requirements of 40 CFR 63.10(c)(10) through (12). The EPA
is proposing to eliminate this requirement because SSM plans would no
longer be required, and therefore 40 CFR 63.10(c)(15) no longer serves
any useful purpose for affected units.
g. Reporting
    We are proposing to revise the 40 CFR part 63, subpart CC General
Provisions table (Table 6) entries for 63.10(d)(5)(i) and
63.10(d)(5)(ii) by combining them into one entry for 63.10(d)(5) with a
``No'' in the second column. Similarly, we are proposing to revise the
40 CFR part 63, subpart UUU General Provisions table (Table 44) entries
for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry
for 63.10(d)(5) with a ``No'' in the third column. Section 63.10(d)(5)
describes the reporting requirements for startups, shutdowns, and
malfunctions. To replace the General Provisions reporting requirement,
the EPA is proposing to add reporting requirements to 40 CFR
63.655(g)(12), 40 CFR 63.1575(c)(4), 40 CFR 63.1575(d), and 40 CFR
63.1575(e). The General Provisions requirement that was cross-
referenced requires periodic SSM reports as a stand-alone report. In
its place, we are proposing language that requires sources that fail to
meet an applicable standard at any time to report the information
concerning such events in the periodic report already required under
each of these rules. We are proposing that the report must contain the
number, date, time, duration, and the cause of such events (including
unknown cause, if applicable), a list of the affected source or
equipment, an estimate of the quantity of each regulated pollutant
emitted over any emission limit, and a description of the method used
to estimate the emissions.
    Examples of methods that can be used to estimate emissions would
include product-loss calculations, mass balance calculations,
measurements when available, or engineering judgment based on known
process parameters. The EPA is proposing this requirement to ensure
that there is adequate information to determine compliance, to allow
the EPA to determine the severity of the failure to meet an applicable
standard, and to provide data that may document how the source met the
general duty to minimize emissions during a failure to meet an
applicable standard.
    We will no longer require owners or operators to determine whether
actions taken to correct a malfunction are consistent with an SSM plan,
because SSM plans would no longer be required. The proposed rule
eliminates the cross-reference to 40 CFR 63.10(d)(5)(i) that contains
the description of the previously required SSM report format and
submittal schedule from this section. These specifications are no
longer necessary because the events will be reported in otherwise
required reports with similar format and submittal requirements.
    As noted above, we are proposing to revise the 40 CFR part 63,
subpart CC General Provisions table (Table 6) entries for
63.10(d)(5)(i) and 63.10(d)(5)(ii) by combining them into one entry for
63.10(d)(5) with a ``No'' in the second column. Similarly, we are
proposing to revise the 40 CFR part 63, subpart UUU General Provisions
table (Table 44) entries for 63.10(d)(5)(i) and 63.10(d)(5)(ii) by
combining them into one entry for 63.10(d)(5) with a ``No'' in the
third column. Section 63.10(d)(5)(ii) describes an immediate report for
startups, shutdown, and malfunctions when a source fails to meet an
applicable standard but does not follow the SSM plan. We are proposing
to no longer require owners and operators to report when actions taken
during a startup, shutdown, or malfunction were not consistent with an
SSM plan,

because such plans would no longer be required.
2. Electronic Reporting
    In this proposal, the EPA is describing a process to increase the
ease and efficiency of performance test data submittal while improving
data accessibility. Specifically, the EPA is proposing that owners and
operators of petroleum refineries submit electronic copies of required
performance test and performance evaluation reports by direct computer-
to-computer electronic transfer using EPA-provided software. The direct
computer-to-computer electronic transfer is accomplished through the
EPA's Central Data Exchange (CDX) using the Compliance and Emissions
Data Reporting Interface (CEDRI). The CDX is EPA's portal for submittal
of electronic data. The EPA-provided software is called the Electronic
Reporting Tool (ERT) which is used to generate electronic reports of
performance tests and evaluations. The ERT generates an electronic
report package which will be submitted using the CEDRI. The submitted
report package will be stored in the CDX archive (the official copy of
record) and the EPA's public database called WebFIRE. All stakeholders
will have access to all reports and data in WebFIRE and accessing these
reports and data will be very straightforward and easy (see the WebFIRE
Report Search and Retrieval link at http://cfpub.epa.gov/webfire/index.cfm?action=fire.searchERTSubmission). A description and
instructions for use of the ERT can be found at http://www.epa.gov/ttn/chief/ert/index.html and CEDRI can be accessed through the CDX Web site
(www.epa.gov/cdx). A description of the WebFIRE database is available
at: http://cfpub.epa.gov/oarweb/index.cfm?action=fire.main.
    The proposal to submit performance test data electronically to the
EPA applies only to those performance tests (and/or performance
evaluations) conducted using test methods that are supported by the
ERT. The ERT supports most of the commonly used EPA reference methods.
A listing of the pollutants and test methods supported by the ERT is
available at: http://www.epa.gov/ttn/chief/ert/index.html.
    We believe that industry would benefit from this proposed approach
to electronic data submittal. Specifically, by using this approach,
industry will save time in the performance test submittal process.
Additionally, the standardized format that the ERT uses allows sources
to create a more complete test report resulting in less time spent on
data backfilling if a source failed to include all data elements
required to be submitted. Also through this proposal industry may only
need to submit a report once to meet the requirements of the applicable
subpart because stakeholders can readily access these reports from the
WebFIRE database. This also benefits industry by cutting back on
recordkeeping costs as the performance test reports that are submitted
to the EPA using CEDRI are no longer required to be retained in hard
copy, thereby reducing staff time needed to coordinate these records.
    Since the EPA will already have performance test data in hand,
another benefit to industry is that fewer or less substantial data
collection requests in conjunction with prospective required residual
risk assessments or technology reviews will be needed. This would
result in a decrease in staff time needed to respond to data collection
requests.
    State, local and tribal air pollution control agencies (S/L/Ts) may
also benefit from having electronic versions of the reports they are
now receiving. For example, S/L/Ts may be able to conduct a more
streamlined and accurate review of electronic data submitted to them.
For example, the ERT would allow for an electronic review process,
rather than a manual data assessment, therefore, making review and
evaluation of the source provided data and calculations easier and more
efficient. In addition, the public stands to benefit from electronic
reporting of emissions data because the electronic data will be easier
for the public to access. How the air emissions data are collected,
accessed and reviewed will be more transparent for all stakeholders.
    One major advantage of the proposed submittal of performance test
data through the ERT is a standardized method to compile and store much
of the documentation required to be reported by this rule. The ERT
clearly states what testing information would be required by the test
method and has the ability to house additional data elements that might
be required by a delegated authority.
    In addition the EPA must have performance test data to conduct
effective reviews of CAA sections 111 and 112 standards, as well as for
many other purposes including compliance determinations, emission
factor development and annual emission rate determinations. In
conducting these required reviews, the EPA has found it ineffective and
time consuming, not only for us, but also for regulatory agencies and
source owners and operators, to locate, collect and submit performance
test data. In recent years, stack testing firms have typically
collected performance test data in electronic format, making it
possible to move to an electronic data submittal system that would
increase the ease and efficiency of data submittal and improve data
accessibility.
    A common complaint heard from industry and regulators is that
emission factors are outdated or not representative of a particular
source category. With timely receipt and incorporation of data from
most performance tests, the EPA would be able to ensure that emission
factors, when updated, represent the most current range of operational
practices. Finally, another benefit of the proposed data submittal to
WebFIRE electronically is that these data would greatly improve the
overall quality of existing and new emissions factors by supplementing
the pool of emissions test data for establishing emissions factors.
    In summary, in addition to supporting regulation development,
control strategy development and other air pollution control
activities, having an electronic database populated with performance
test data would save industry, state, local and tribal agencies and the
EPA significant time, money and effort while also improving the quality
of emission inventories and air quality regulations.
    In addition, we are proposing that the fenceline data at each
monitor location (as proposed above) would be reported electronically
on a semiannual basis. All data reported electronically would be
submitted to CDX through CEDRI and made available to the public.
3. Technical Amendments to Refinery MACT 1 and 2
a. Open-Ended Valves and Lines
    Refinery MACT 1 requires an owner or operator to control emissions
from equipment leaks according to the requirements of either 40 CFR
part 60, subpart VV or 40 CFR part 63, subpart H. For open-ended valves
and lines, both subparts require that the open end be equipped with a
cap, blind flange, plug or second valve that ``shall seal the open end
at all times.'' However, neither subpart defines ``seal'' or explains
in practical and enforceable terms what constitutes a sealed open-ended
valve or line. This has led to uncertainty on the part of the owner or
operator as to whether compliance is being achieved. Inspections under
the EPA's Air Toxics LDAR initiative have provided evidence that while
certain open-ended lines may be equipped with a cap, blind flange, plug
or second valve, they are not

operating in a ``sealed'' manner as the EPA interprets that term.
    In response to this uncertainty, we are proposing to amend 40 CFR
63.648 to clarify what is meant by ``seal.'' This proposed amendment
clarifies that, for the purpose of complying with the requirements of
40 CFR 63.648, open-ended valves and lines are ``sealed'' by the cap,
blind flange, plug, or second valve when there are no detectable
emissions from the open-ended valve or line at or above an instrument
reading of 500 ppm. We solicit comment on this approach to reducing the
compliance uncertainty associated with open-ended valves and lines and
our proposed amendment.
b. General Provisions Cross-Referencing
    We have reviewed the application of 40 CFR part 63, subpart A
(General Provisions) to Refinery MACT 2. The applicable requirements of
40 CFR part 63, subpart A are contained in Table 44 of 40 CFR part 63,
subpart UUU. As a result of our review, we are proposing several
amendments to Table 44 of 40 CFR part 63, subpart UUU (in addition to
those discussed in section IV.E.1 of this preamble that address SSM) to
bring the table up-to-date with requirements of the General Provisions
that have been amended since this table was created, to correct cross-
references, and to incorporate additional sections of the General
Provisions that are necessary to implement other subparts that are
cross-referenced by this rule.
    Although we reviewed the application of the General Provisions to
Refinery MACT 1 and amended Table 6 of 40 CFR part 63, subpart CC in
2009, we are proposing a few additional technical corrections to this
table (in addition to those discussed in section IV.E.1 of this
preamble that address SSM). We are not discussing the details of these
proposed technical corrections in this preamble but the rationale for
each change to Table 6 of 40 CFR part 63, subpart CC and Table 44 of 40
CFR part 63, subpart UUU (including the proposed amendments to address
SSM discussed above), is included in Docket ID Number EPA-HQ-OAR-2010-
0682.
4. Amendments to Refinery NSPS J and Ja
    As discussed in section II.B.2 of this preamble, we are addressing
a number of technical corrections and clarifications for Refinery NSPS
J and Ja to address some of the issues raised in the petition for
reconsideration and to improve consistency and clarity of the rule
requirements. These issues are addressed in detail in API's amended
petition, dated August 21, 2008 (see Docket Item Number EPA-HQ-OAR-
2007-0011-0246) and the meeting minutes for a September 11, 2008
meeting between EPA and API (see Docket Item Number EPA-HQ-OAR-2007-
0011-0266).
a. The Depressurization Work Practice Standard for Delayed Coking Units
    HOVENSA and the Industry Petitioners raised several issues with the
analysis conducted to support the DCU work practice standard in
Refinery NSPS Ja. With the promulgation and implementation of the
standards we are proposing for the DCU under Refinery MACT 1, the DCU
work practice standards in Refinery NSPS Ja are not expected to result
in any further decreases in emissions from the DCU. Any DCU that
becomes subject to Refinery NSPS Ja would already be in compliance with
Refinery MACT 1, which is a more stringent standard than the DCU work
practice standards in Refinery NSPS Ja. As such, we are contemplating
various ideas for harmonizing the requirements for the DCU in these two
regulations. One option is to amend Refinery NSPS Ja to incorporate the
same requirements being proposed for Refinery MACT 1 (the DCU work
practice standard in Refinery NSPS Ja is less stringent than the
proposed requirements for Refinery MACT 1). Another option we are
contemplating is deleting the DCU work practice standard within
Refinery NSPS Ja once the DCU standards in Refinery MACT 1 are
promulgated and fully implemented. We believe deletion of this work
practice standard is consistent with the objectives of Executive Order
13563, ``Improving Regulation and Regulatory Review.'' We solicit
comment on these options as well as any other comments regarding the
interaction between the DCU requirements in these two rules (i.e., the
need to keep the DCU work practice standard in Refinery NSPS Ja after
promulgation of these revisions to Refinery MACT 1.)
b. Technical Corrections and Clarifications
    In addition to their primary issues, the Industry Petitioners
enumerated several points of clarification and recommended amendments
to Refinery NSPS J and Ja. These issues are addressed in detail in
API's amended petition for reconsideration, dated August 21, 2008 (see
Docket Item Number EPA-HQ-OAR-2007-0011-0246) and the meeting minutes
for a September 11, 2008 meeting between EPA and API (see Docket Item
Number EPA-HQ-OAR-2007-0011-0266). We are including several proposed
amendments in this rulemaking to specifically address these issues.
These amendments are discussed in the remainder of this section. We are
addressing these issues now while we are proposing amendments for
Refinery MACT 2 in an effort to improve consistency and clarity for
sources regulated under both the NSPS and Refinery MACT 2.
    We are proposing a series of amendments to the requirements for
sulfur recovery plants in 40 CFR 60.102a, to clarify the applicable
emission limits for different types of sulfur recovery plants based on
whether oxygen enrichment is used. These amendments also clarify that
emissions averaging across a group of emission points within a given
sulfur recovery plant is allowed from each of the different types of
sulfur recovery plants, and that emissions averaging is specific to the
SO2 or reduced sulfur standards (and not to the
H2S limit). The 10 ppmv H2S limit for reduction
control systems not followed by incineration must be met on a release
point-specific basis. These amendments are being made to clarify the
original intent of the Refinery NSPS Ja requirements for sulfur
recovery plants.
    We are proposing a series of corresponding amendments in 40 CFR
60.106a to clarify the monitoring requirements, particularly when
oxygen enrichment or emissions averaging is used. The monitoring
requirements in Refinery NSPS Ja were incomplete for these provisions
and did not specify all of the types of monitoring devices needed for
implementation. We are also proposing in 40 CFR 60.106a to use the term
``reduced sulfur compounds'' when referring to the emission limits and
monitoring devices needed to comply with the reduced sulfur compound
emission limits for sulfur recovery plants with reduction control
systems not followed by incineration. The term ``reduced sulfur
compounds'' is a defined term in Refinery NSPS Ja, and the emissions
limit for sulfur recovery plants with reduction control systems not
followed by incineration is specific to ``reduced sulfur compounds.''
Therefore, the proposed amendments to the monitoring provisions provide
clarification of the requirements by using a consistent, defined term.
    We are proposing amendments to 40 CFR 60.102a(g)(1) to clarify that
CO boilers, while part of the FCCU affected facility, can also be fuel
gas combustion devices (FGCD). Industry Petitioners suggested that the
CO boiler should only be subject to the FCCU NOX and
SO2

limits and should not be considered a FGCD. While Refinery NSPS Ja
clearly states that the coke burn-off exhaust from the FCCU catalyst
regenerator is not considered to be fuel gas, other fuels combusted in
the CO boiler must meet the H2S concentration requirements
for fuel gas like any other FGCD. This amendment is provided to clarify
our original intent with respect to fuel gas. Industry Petitioners also
noted that some CO boiler ``furnaces'' may be used as process heaters
rather than steam-generating boilers. While we did not originally
contemplate that CO furnaces would be used as process heaters,
available data from the detailed ICR suggests that there are a few CO
furnaces used as process heaters. These CO furnaces are all forced-
draft process heaters, and the newly amended NOX emissions
limit in Refinery NSPS Ja for forced-draft process heaters is 60 ppmv,
averaged over a 30-day period. Given the longer averaging time of the
process heater NOX limits, these two emission limits (for
FCCU NOX and for process heater NOX) are
reasonably comparable and are not expected to result in a significant
difference in the control systems selected for compliance. As such, we
are not amending or clarifying the NOX standards for the
FCCU or process heaters at this time. We are, however, clarifying
(through this response) that if an emission source meets the definition
of more than one affected facility, that source would need to comply
with all requirements applicable to the emissions source.
    We are proposing to revise the annual testing requirement in 40 CFR
60.104a(b) to clarify our original intent. Instead of requiring a PM
performance test at least once every 12 months, the rule would require
a PM performance test annually and specify that annually means once per
calendar year, with an interval of at least 8 months but no more than
16 months between annual tests. This provision will ensure that testing
is conducted at a reasonable interval while giving owners and operators
flexibility in scheduling the testing. We are also proposing to amend
40 CFR 60.104a(f) to clarify that the provisions of that paragraph are
specific to owners or operators of an FCCU or FCU that use a cyclone to
comply with the PM per coke burn-off emissions limit (rather than just
the PM limit) in 40 CFR 60.102a(b)(1), to clarify that facilities
electing to comply with the concentration limit using a PM CEMS would
not also be required to install a COMS. We are also proposing to amend
40 CFR 60.104a(j) to delete the requirements to measure flow for the
H2S concentration limit for fuel gas, as these are not
needed in the performance evaluation.
    We are proposing amendments to 40 CFR 60.105a(b)(1)(ii)(A) to
require corrective action be completed to repair faulty (leaking or
plugged) air or water lines within 12 hours of identification of an
abnormal pressure reading during the daily checks. We are also
proposing amendments to 40 CFR 60.105a(i) to include periods when
abnormal pressure readings for a jet ejector-type wet scrubber (or
other type of wet scrubber equipped with atomizing spray nozzles) are
not corrected within 12 hours of identification, and periods when a bag
leak detection system alarm (for a fabric filter) is not alleviated
within the time period specified in the rule. These proposed amendments
are necessary so that periods when the APCD operation is compromised
are properly managed and/or reported.
    We are proposing amendments to 40 CFR 60.105(b)(1)(iv) and
60.107a(b)(1)(iv) to allow using tubes with a maximum span between 10
and 40 ppmv, inclusive, when 1<=N<=10, where N = number of pump strokes
rather than requiring use of tubes with ranges 0-10/0-100 ppm (N = 10/
1) because different length-of-stain tube manufacturers have different
span ranges, and none of the commercially-available tubes have a
specific span of 0-10/0-100 ppm (N = 10/1). We are also proposing to
amend 40 CFR 60.105(b)(3)(iii) and 40 CFR 60.107a(b)(3)(iii) to specify
that the temporary daily stain sampling must be made using length-of
stain tubes with a maximum span between 200 and 400 ppmv, inclusive,
when 1<=N<=5, where N = number of pump strokes. This proposed amendment
clarifies this monitoring requirement, ensures the proper tube range is
used, and provides some flexibility in span range to accommodate
different manufacturers of the length-of-stain tubes. We also propose
to delete the last sentence in 40 CFR 60.105(b)(3)(iii), as there is no
long-term H2S concentration limit in Refinery NSPS J.
    We are proposing to clarify that flares are subject to the
performance test requirements. We are also proposing to clarify those
performance test requirements in 40 CFR 60.107a(e)(1)(ii) and 40 CFR
60.107a(e)(2)(ii) to remove the distinction between flares with or
without routine flow. The term ``routine flow'' is not defined and it
is difficult to make this distinction in practice.

F. What compliance dates are we proposing?

    Amendments to Refinery MACT 1 and 2 proposed in this rulemaking for
adoption under CAA section 112(d)(2) and (3) and CAA section 112(d)(6)
are subject to the compliance deadlines outlined in the CAA under
section 112(i). For all of the requirements we are proposing under CAA
section 112(d)(2) and (3) or CAA section 112(d)(6) except for storage
vessels, which we are also requiring under 112 (f)(2), we are proposing
the following compliance dates. As provided in CAA section 112(i), new
sources would be required to comply with these requirements by the
effective date of the final amendments to Refinery MACT 1 and 2 or
startup, whichever is later.
    For existing sources, CAA section 112(i) provides that the
compliance date shall be as expeditiously as practicable, but no later
than 3 years after the effective date of the standard. In determining
what compliance period is as expeditious as practicable, we consider
the amount of time needed to plan and construct projects and change
operating procedures. Under CAA section 112(d)(2) and (3), we are
proposing new operating requirements for DCU. In order to comply with
these new requirements, we project that most DCU owners or operators
would need to install additional controls (e.g., steam ejector
systems). Similarly, the proposed revision in the CRU pressure limit
exclusions would require operational changes and, in some cases,
additional controls. The addition of new control equipment would
require engineering design, solicitation and review of vendor quotes,
contracting and installation of the equipment, which would need to be
timed with process unit outage and operator training. Therefore, we are
proposing that it is necessary to provide 3 years after the effective
date of the final rule for these sources to comply with the DCU and CRU
requirements.
    We are proposing new operating and monitoring requirements for
flares under CAA section 112(d)(2) and (3). We anticipate that these
requirements would require the installation of new flare monitoring
equipment and we project most refineries would install new control
systems to monitor and adjust assist gas (air or steam) addition rates.
Similar to the addition of new control equipment, these new monitoring
requirements for flares would require engineering evaluations,
solicitation and review of vendor quotes, contracting and installation
of the equipment, and operator training.

Installation of new monitoring and control equipment on flares will
require the flare to be taken out of service. Depending on the
configuration of the flares and flare header system, taking the flare
out of service may also require a significant portion of the refinery
operations to be shut down. Therefore, we are proposing that it is
necessary to provide 3 years after the effective date of the final rule
for owners or operators to comply with the new operating and monitoring
requirements for flares.
    Under CAA section 112(d)(2) and (3), we are proposing new vent
control requirements for bypasses. These requirements would typically
require the addition of piping and potentially new control
requirements. As these vent controls would most likely be routed to the
flare, we are proposing to provide 3 years after the effective date of
the final rule for owners or operators to afford coordination of these
bypass modifications with the installation of the new monitoring
equipment for the flares.
    Under our technology review, we are proposing to require fenceline
monitoring pursuant to CAA section 112(d)(6). These proposed provisions
would require refinery owners or operators to install a number of
monitoring stations around the facility fenceline. While the diffusive
tube sampling system is relatively low-tech and is easy to install,
site-specific factors must be considered in the placement of the
monitoring systems. We also assume all refinery owners or operators
would invest in the analytical equipment needed to perform automated
sample analysis on-site and time is needed to select an appropriate
vendor for this equipment. Furthermore, additional monitoring systems
may be needed to account for near-field contributing sources, for which
the development and approval of a site-specific monitoring plan.
Considering all of the requirements needed to implement the fenceline
monitoring system, we are proposing to provide 3 years from the
effective date of the final rule for refinery owners or operators to
install and begin collecting ambient air samples around the fenceline
of their facility following an approved (if necessary) site-specific
monitoring plan.
    As a result of our technology review for equipment leaks, we are
proposing to allow the use of optical gas imaging devices in lieu of
using EPA Method 21 of 40 CFR part 60, Appendix A-7 without the annual
compliance demonstration with EPA Method 21 as required in the AWP (see
73 FR 73202, December 22, 2008), provided that the owner and operator
follows the provisions of Appendix K to 40 CFR part 60. Facilities
could begin to comply with the optical gas imaging alternative as soon
as Appendix K to 40 CFR part 60 is promulgated. Alternatively, as is
currently provided in the AWP, the refinery owner or operator can elect
to use the optical gas imaging monitoring option prior to installation
and use of the fenceline monitoring system, provided they conduct an
annual compliance demonstration using EPA Method 21 as required in the
AWP.
    Under our technology review for marine vessel loading operations,
we are proposing to add a requirement for submerged filling for small
and for offshore marine vessel loading operations. We anticipate that
the submerged fill pipes are already in place on all marine vessels
used to transport petroleum refinery liquids, so we are proposing that
existing sources comply with this requirement on the effective date of
the final rule. We request comment regarding the need to provide
additional time to comply with the submerged filling requirement;
please provide in your comment a description of the vessels loaded that
do not already have a submerged fill pipe, how these vessels comply
with (or are exempt from) the Coast Guard requirements at 46 CFR
153.282, and an estimate of the time needed to add the required
submerged fill pipes to these vessels.
    We are also proposing to require FCCU owners and operators
currently subject to Refinery NSPS J (or electing that compliance
option in Refinery MACT 2) to transition from the Refinery NSPS J
option to one of the alternatives included in the proposed rule. We are
also proposing altering the averaging times for some of the operating
limits. A PM performance test is needed in order to establish these new
operating limits prior to transitioning to the proposed requirements.
Additionally, we are proposing that a PM performance test be conducted
for each FCCU once every 5 years. We do not project any new control or
monitoring equipment will be needed in order to comply with the
proposed provisions; however, compliance with the proposed provisions
is dependent on conducting a performance test. Establishing an early
compliance date for the first performance test can cause scheduling
issues as refinery owners or operators compete for limited number of
testing contractors. Considering these scheduling issues, we propose to
require the first performance test for PM and compliance with the new
operating limits be completed no later than 18 months after the
effective date of the final rule.
    In this action, we are proposing revisions to the SSM provisions of
Refinery MACT 1 and 2, including specific startup or shutdown standards
for certain emission sources, and we are proposing electronic reporting
requirements in Refinery MACT 1 and 2. The proposed monitoring
requirements associated with the new startup and shutdown standards are
expected to be present on the affected source, so we do not expect that
owners or operators will need additional time to transition to these
requirements. Similarly, the electronic reporting requirements are not
expected to require a significant change in operation or equipment, so
these requirements should be able to be implemented more quickly than
those that require installation of new control or monitoring equipment.
Based on our review of these requirements, we propose that these
requirements become effective upon the effective date of the final
rule.
    Finally, we are proposing additional requirements for storage
vessels under CAA sections 112(d)(6) and (f)(2). The compliance
deadlines for standards developed under CAA section 112(f)(2) are
delineated in CAA sections 112(f)(3) and (4). As provided in CAA
section 112(f)(4), risk standards shall not apply to existing sources
until 90 days after the effective date of the rule, but the
Administrator may grant a waiver for a particular source for a period
of up to 2 years after the effective date. While additional controls
will be necessary to comply with the proposed new control and fitting
requirements for storage vessels, the timing for installation of these
controls is specified within the Generic MACT (40 CFR part 63, subpart
WW). Therefore, we propose that these new requirements for storage
vessels become effective 90 days following the effective date of the
final rule.

V. Summary of Cost, Environmental and Economic Impacts

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

    The sources affected by significant amendments to the petroleum
refinery standards include storage vessels, equipment leaks, fugitive
emissions and DCU subject to Refinery MACT 1. The proposed amendments
for other sources subject to one or more of the petroleum refinery
standards are expected to have minimal air quality and cost impacts.
    The total capital investment cost of the proposed amendments and
standards is estimated at $239 million, $82.8 million from proposed
amendments and $156 million from

standards to ensure compliance. We estimate annualized costs to be
approximately $4.53 million, which includes an estimated $14.4 million
credit for recovery of lost product and the annualized cost of capital.
We also estimate annualized costs of the proposed standards to ensure
compliance to be approximately $37.9 million. The proposed amendments
would achieve a nationwide HAP emission reduction of 1,760 tpy, with a
concurrent reduction in VOC emissions of 18,800 tpy. Table 13 of this
preamble summarizes the cost and emission reduction impacts of the
proposed amendments, and Table 14 of this preamble summarizes the costs
of the proposed standards to ensure compliance.

                                                                       Table 13--Nationwide Impacts of Proposed Amendments
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                    Total annualized
                                                   Total capital      cost without    Product recovery  Total annualized    VOC emission          Cost          HAP emission          Cost
                Affected source                     investment     credit (million $/  credit (million  costs (million $/ reductions (tpy)  effectiveness ($/ reductions (tpy)  effectiveness ($/
                                                    (million $)           yr)               $/yr)              yr)                              ton VOC)                            ton HAP)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Storage Vessels................................              18.5               3.13            (8.16)            (5.03)            14,600             (345)               910           (5,530)
Delayed Coking Units...........................              52.0              10.2             (6.20)              3.98             4,250               937               850             4,680
Fugitive Emissions (Fenceline Monitoring)......              12.2               5.58  ................              5.58  ................  ................  ................  ................
                                                ------------------------------------------------------------------------------------------------------------------------------------------------
    Total......................................              82.8              18.9             (14.4)              4.53            18,800               241             1,760             2,570
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

                     Table 14--Nationwide Costs of Proposed Amendments to Ensure Compliance
----------------------------------------------------------------------------------------------------------------
                                                                       Total
                                                   Total capital    annualized        Product          Total
                 Affected source                    investment     cost without      recovery       annualized
                                                    (million $)       credit          credit      costs (million
                                                                  (million $/yr)  (million $/yr)       $/yr)
----------------------------------------------------------------------------------------------------------------
Relief Valve Monitoring.........................            9.54            1.36  ..............            1.36
Flare Monitoring................................          147              36.3   ..............           36.3
FCCU Testing....................................           --               0.21  ..............            0.21
                                                 ---------------------------------------------------------------
    Total.......................................          156              37.9               --           37.9
----------------------------------------------------------------------------------------------------------------

    Note that any corrective actions taken in response to the fenceline
monitoring program are not included in the impacts shown in Table 13.
Any corrective actions associated with fenceline monitoring will result
in additional emission reductions and additional costs.
    The impacts shown in Table 14 do not consider emission reductions
associated with relief valve or flare monitoring provisions or emission
reductions that may occur as a result of the additional FCCU testing
requirements. The proposed operational and monitoring requirements for
flares at refineries have the potential to reduce excess emissions from
flares by approximately 3,800 tpy of HAP, 33,000 tpy of VOC, and
327,000 metric tonnes per year of CO2e. When added to the
reductions in CO2e achieved from proposed controls on DCU,
these proposed amendments are projected to result in reductions of
670,000 metric tonnes of CO2e due to reductions of methane
emissions.\42\
---------------------------------------------------------------------------

    \42\ The flare operational and monitoring requirements are
projected to reduce methane emissions by 29,500 tpy while increasing
CO2 emissions by 260,000 tpy, resulting in a net GHG
reduction of 327,000 metric tonnes per year of CO2e,
assuming a global warming potential of 21 for methane. Combined with
methane emissions reduction of 18,000 tpy from the proposed controls
on DCU, the overall GHG reductions of the proposed amendments is
670,000 metric tonnes per year of CO2e assuming a global
warming potential of 21 for methane.
---------------------------------------------------------------------------

B. What are the economic impacts?

    We performed a national economic impact analysis for petroleum
product producers. All petroleum product refiners will incur annual
compliance costs of much less than 1 percent of their sales. For all
firms, the minimum cost-to-sales ratio is <0.01 percent; the maximum
cost-to-sales ratio is 0.87 percent; and the mean cost-to-sales ratio
is 0.03 percent. Therefore, the overall economic impact of this
proposed rule should be minimal for the refining industry and its
consumers.
    In addition, the EPA performed a screening analysis for impacts on
small businesses by comparing estimated annualized engineering
compliance costs at the firm-level to firm sales. The screening
analysis found that the ratio of compliance cost to firm revenue falls
below 1 percent for the 28 small companies likely to be affected by the
proposal. For small firms, the minimum cost-to-sales ratio is <0.01
percent; the maximum cost-to-sales ratio is 0.62 percent; and the mean
cost-to-sales ratio is 0.07 percent.
    More information and details of this analysis are provided in the
technical document Economic Impact Analysis for Petroleum Refineries
Proposed Amendments to the National Emissions Standards for Hazardous
Air Pollutants, which is available in the docket for this proposed rule
(Docket ID Number EPA-HQ-OAR-2010-0682).

C. What are the benefits?

    The proposed rule is anticipated to result in a reduction of 1,760
tons of HAP (based on allowable emissions under the MACT standards) and
18,800 tons of VOC emissions per year, not including potential emission
reductions that may occur as a result of the proposed provisions for
flares or fenceline monitoring. These avoided emissions will result in
improvements in air quality and reduced negative health effects
associated with exposure to air pollution of these emissions; however,
we have not quantified or monetized the benefits of reducing these
emissions for this rulemaking.

VI. Request for Comments

    We solicit comments on all aspects of this proposed action. In
addition to general comments on this proposed action, we are also
interested in additional data that may improve the risk assessments and
other analyses. We are specifically interested in receiving any
improvements to the data used in the site-specific emissions profiles
used for risk modeling. Such data should include supporting
documentation in sufficient detail to allow characterization of the
quality and representativeness of the data or information. Section VII
of this preamble provides more information on submitting data.

VII. Submitting Data Corrections

    The site-specific emissions profiles used in the source category
risk and demographic analyses and instructions are available on the RTR
Web page at: http://www.epa.gov/ttn/atw/rrisk/rtrpg.html. The data
files include detailed information for each HAP emissions release point
for the facilities in the source categories.
    If you believe that the data are not representative or are
inaccurate, please identify the data in question, provide your reason
for concern and provide any ``improved'' data that you have, if
available. When you submit data, we request that you provide
documentation of the basis for the revised values to support your
suggested changes. To submit comments on the data downloaded from the
RTR page, complete the following steps:
    1. Within this downloaded file, enter suggested revisions to the
data fields appropriate for that information.
    2. Fill in the commenter information fields for each suggested
revision (i.e., commenter name, commenter organization, commenter email
address, commenter phone number and revision comments).
    3. Gather documentation for any suggested emissions revisions
(e.g., performance test reports, material balance calculations).
    4. Send the entire downloaded file with suggested revisions in
Microsoft[supreg] Access format and all accompanying documentation to
Docket ID Number EPA-HQ-OAR-2010-0682 (through one of the methods
described in the ADDRESSES section of this preamble).
    5. If you are providing comments on a single facility or multiple
facilities, you need only submit one file for all facilities. The file
should contain all suggested changes for all sources at that facility.
We request that all data revision comments be submitted in the form of
updated Microsoft[supreg] Excel files that are generated by the
Microsoft[supreg] Access file. These files are provided on the RTR Web
page at: http://www.epa.gov/ttn/atw/rrisk/rtrpg.html.

VIII. Statutory and Executive Order Reviews

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

    Under Executive Order 12866 (58 FR 51735, October 4, 1993), this
action is a ``significant regulatory action'' because it raises novel
legal and policy issues. Accordingly, the EPA submitted this action to
the Office of Management and Budget (OMB) for review under Executive
Orders 12866 and 13563 (76 FR 3821, January 21, 2011) and any changes
made in response to OMB recommendations have been documented in the
docket for this action (Docket ID Number EPA-HQ-OAR-2010-0682).

B. Paperwork Reduction Act

    The information collection requirements in this rule have been
submitted for approval to OMB under the Paperwork Reduction Act, 44
U.S.C. 3501, et seq.
    Revisions and burden associated with amendments to 40 CFR part 63,
subparts CC and UUU are discussed in the following paragraphs. OMB has
previously approved the information collection requirements contained
in the existing regulations in 40 CFR part 63, subparts CC and UUU
under the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501, et
seq., OMB control numbers for the EPA's regulations in 40 CFR are
listed in 40 CFR part 9. Burden is defined at 5 CFR 1320.3(b).
    The ICR document prepared by the EPA for the amendments to the
Petroleum Refinery MACT standards for 40 CFR part 63, subpart CC has
been assigned the EPA ICR number 1692.08. Burden changes associated
with these amendments would result from new monitoring, recordkeeping
and reporting requirements. The estimated annual increase in
recordkeeping and reporting burden hours is 53,619 hours; the frequency
of response is semiannual for all reports for all respondents that must
comply with the rule's reporting requirements; and the estimated
average number of likely respondents per year is 95 (this is the
average in the second year). The cost burden to respondents resulting
from the collection of information includes the total capital cost
annualized over the equipment's expected useful life (about $17
million, which includes monitoring equipment for bypass valves,
fenceline monitoring, relief valves, and flares), a total operation and
maintenance component (about $16 million per year for fenceline and
flare monitoring), and a labor cost component (about $4.5 million per
year, the cost of the additional 53,619 labor hours). An agency may not
conduct or sponsor (and a person is not required to respond to) a
collection of information unless it displays a currently-valid OMB
control number.
    The ICR document prepared by the EPA for the amendments to the
Petroleum Refinery MACT standards for 40 CFR part 63, subpart UUU has
been assigned the EPA ICR number 1844.07. Burden changes associated
with these amendments would result from new testing, recordkeeping and
reporting requirements being proposed with this action. The estimated
average burden per response is 26 hours; the frequency of response is
both once and every 5 years for respondents that have FCCU, and the
estimated average number of likely respondents per year is 67. The cost
burden to respondents resulting from the collection of information
includes the performance testing costs (approximately $356,000 per year
over the first 3 years for the initial performance test and $213,000
per year starting in the fourth year), and a labor cost component
(approximately $238,000 per year for 2,860 additional labor hours). An
agency may not conduct or sponsor (and a person is not required to
respond to) a collection of information unless it displays a currently-
valid OMB control number.
    To comment on the agency's need for this information, the accuracy
of the provided burden estimates, and any suggested methods for
minimizing respondent burden, the EPA has established a public docket
for this rule, which includes the ICR, under Docket ID Number EPA-HQ-
OAR-2010-0682. Submit any comments related to the ICR to the EPA and
OMB. See the ADDRESSES section at the beginning of this preamble for
where to submit comments to the EPA. Send comments to OMB at the Office
of Information and Regulatory Affairs, Office of Management and Budget,
725 17th Street NW., Washington, DC 20503, Attention: Desk Office for
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after June 30, 2014, a comment to OMB is best
assured of having its full effect if OMB receives it by July 30, 2014.
The final rule will respond to any OMB or public comments on the
information collection requirements contained in this proposal.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency
to prepare a regulatory flexibility analysis of any rule subject to
notice and comment rulemaking requirements under the Administrative
Procedure Act or any other statute, unless the agency certifies that
the rule will not have a significant economic impact on a substantial
number of small entities (SISNOSE). Small entities include small
businesses, small organizations and small governmental jurisdictions.
For purposes of assessing the impacts of this proposed rule on small
entities, a small entity is defined as: (1) A small business in the
petroleum refining industry

having 1,500 or fewer employees (Small Business Administration (SBA),
2011); (2) a small governmental jurisdiction that is a government of a
city, county, town, school district or special district with a
population of less than 50,000; and (3) a small organization that is
any not-for-profit enterprise which is independently owned and operated
and is not dominant in its field.
    After considering the economic impacts of this proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The small
entities subject to the requirements of this proposed rule are small
refiners. We have determined that 36 companies (59 percent of the 61
total) employ fewer than 1,500 workers and are considered to be small
businesses. For small businesses, the average cost-to-sales ratio is
about 0.05 percent, the median cost-to-sales ratio is 0.02 percent and
the maximum cost-to-sales ratio is 0.55 percent. The potential costs do
not have a more significant impact on small refiners and because no
small firms are expected to have cost-to-sales ratios greater than 1
percent, we determined that the cost impacts for this rulemaking will
not have a SISNOSE.
    Although not required by the RFA to convene a Small Business
Advocacy Review (SBAR) Panel; because the EPA has determined that this
proposal would not have a significant economic impact on a substantial
number of small entities, the EPA originally convened a panel to obtain
advice and recommendations from small entity representatives
potentially subject to this rule's requirements. The panel was not
formally concluded; however, a summary of the outreach conducted and
the written comments submitted by the small entity representatives can
be found in the docket for this proposed rule (Docket ID Number EPA-HQ-
OAR-2010-0682).
    We continue to be interested in the potential impacts of the
proposed rule on small entities and welcome comments on issues related
to such impacts.

D. Unfunded Mandates Reform Act

    This proposed rule does not contain a federal mandate under the
provisions of Title II of the Unfunded Mandates Reform Act of 1995
(UMRA), 2 U.S.C. 1531-1538 that may result in expenditures of $100
million or more for state, local and tribal governments, in the
aggregate, or the private sector in any one year. As discussed earlier
in this preamble, these amendments result in nationwide costs of $42.4
million per year for the private sector. Thus, this proposed rule is
not subject to the requirements of sections 202 or 205 of the UMRA.
    This proposed rule is also not subject to the requirements of
section 203 of UMRA because it contains no regulatory requirements that
might significantly or uniquely affect small governments because it
contains no requirements that apply to such governments and does not
impose obligations upon them.

E. Executive Order 13132: Federalism

    This rule does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. None of the facilities subject to
this action are owned or operated by state governments, and, because no
new requirements are being promulgated, nothing in this proposal will
supersede state regulations. Thus, Executive Order 13132 does not apply
to this rule.
    In the spirit of Executive Order 13132, and consistent with the EPA
policy to promote communications between the EPA and state and local
governments, the EPA specifically solicits comment on this proposed
rule from state and local officials.

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

    This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have
substantial direct effects on tribal governments, on the relationship
between the federal government and Indian tribes, or on the
distribution of power and responsibilities between the federal
government and Indian tribes as specified in Executive Order 13175.
Thus, Executive Order 13175 does not apply to this action.
    Although Executive Order 13175 does not apply to this action, the
EPA consulted with tribal officials in developing this action. The EPA
sent out letters to tribes nationwide to invite them to participate in
a tribal consultation meeting and solicit their input on this
rulemaking. The EPA conducted the tribal consultation meeting on
December 14, 2011. Participants from eight tribes attended the meeting,
but they were interested only in outreach, and none of the tribes had
delegation for consultation. The EPA presented all the information
prepared for the consultation and conducted a question and answer
session where participants asked clarifying questions about the
information that was presented and generally expressed their support of
the rulemaking requirements.
    The EPA specifically solicits additional comment on this proposed
action from tribal officials.

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

    This action is not subject to Executive Order 13045 (62 FR 19885,
April 23, 1997) because it is not economically significant as defined
in Executive Order 12866, and because the agency does not believe the
environmental health or safety risks addressed by this action present a
disproportionate risk to children. This action's health and risk
assessments are contained in sections III.A and B and sections IV.C and
D of this preamble.
    The public is invited to submit comments or identify peer-reviewed
studies and data that assess effects of early life exposure to
emissions from petroleum refineries.

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

    This action is not a ``significant energy action'' as defined under
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not
likely to have significant adverse effect on the supply, distribution
or use of energy. The overall economic impact of this proposed rule
should be minimal for the refining industry and its consumers.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 104-113, 12(d) (15 U.S.C. 272 note)
directs the EPA to use voluntary consensus standards (VCS) in its
regulatory activities unless to do so would be inconsistent with
applicable law or otherwise impractical. VCS are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by VCS bodies. The
NTTAA directs the EPA to provide Congress, through OMB, explanations
when the agency decides not to use available and applicable VCS.
    This proposed rulemaking involves technical standards. The EPA
proposes to use ISO 16017-2, ``Air quality Sampling and analysis of
volatile organic compounds in ambient air,

indoor air and workplace air by sorbent tube/thermal desorption/
capillary gas chromatography Part 2: Diffusive sampling'' as an
acceptable alternative to EPA Method 325A. This method is available at
http://www.iso.org. This method was chosen because it meets the
requirements of EPA Method 301 for equivalency, documentation and
validation data for diffusive tube sampling.
    The EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable VCS and to explain why such standards should be used in this
regulation.

J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies and activities on minority populations and low-income
populations in the United States.
    The EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority, low-income or indigenous populations because it
maintains or increases the level of environmental protection for all
affected populations without having any disproportionately high and
adverse human health or environmental effects on any population,
including any minority, low-income or indigenous populations. Further,
the EPA believes that implementation of the provisions of this rule
will provide an ample margin of safety to protect public health of all
demographic groups.
    To examine the potential for any environmental justice issues that
might be associated with the refinery source categories associated with
today's proposed rule, we evaluated the percentages of various social,
demographic and economic groups within the at-risk populations living
near the facilities where these source categories are located and
compared them to national averages. Our analysis of the demographics of
the population with estimated risks greater than 1-in-1 million
indicates potential disparities in risks between demographic groups,
including the African American, Other and Multiracial, Hispanic, Below
the Poverty Level, and Over 25 without a High School Diploma groups. In
addition, 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. These groups stand to benefit the most from the emission
reductions achieved by this proposed rulemaking, and this proposed
rulemaking is projected to result in 1 million fewer people exposed to
risks greater than 1-in-1 million.
    The EPA defines ``Environmental Justice'' to include meaningful
involvement of all people regardless of race, color, national origin or
income with respect to the development, implementation and enforcement
of environmental laws, regulations and policies. To promote meaningful
involvement, the EPA conducted numerous outreach activities and
discussions, including targeted outreach (such as conference calls and
Webinars) to communities and environmental justice organizations. In
addition, after the rule is proposed, the EPA will be conducting a
webinar to inform the public about the proposed rule and to outline how
to submit written comments to the docket. Further stakeholder and
public input is expected through public comment and follow-up meetings
with interested stakeholders.

List of Subjects

40 CFR Part 60

    Environmental protection, Administrative practice and procedure,
Air pollution control, Incorporation by reference, Intergovernmental
relations, Reporting and recordkeeping requirements.

40 CFR Part 63

    Environmental protection, Air pollution control, Hazardous
substances, Incorporation by reference, Reporting and recordkeeping
requirements, Volatile organic compounds.

    Dated: May 15, 2014.
Gina McCarthy,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is proposed to be amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

    Authority: 42 U.S.C. 7401, et seq.

Subpart J--[AMENDED]

0
2. Section 60.105 is amended by:
0
a. Revising paragraph (b)(1)(iv) and
0
b. Revising paragraph (b)(3)(iii) to read as follows:

Sec.  60.105  Monitoring of emissions and operations.

* * * * *
    (b) * * *
    (1) * * *
    (iv) The supporting test results from sampling the requested fuel
gas stream/system demonstrating that the sulfur content is less than 5
ppmv. Sampling data must include, at minimum, 2 weeks of daily
monitoring (14 grab samples) for frequently operated fuel gas streams/
systems; for infrequently operated fuel gas streams/systems, seven grab
samples must be collected unless other additional information would
support reduced sampling. The owner or operator shall use detector
tubes (``length-of-stain tube'' type measurement) following the ``Gas
Processors Association Standard 2377-86, Test for Hydrogen Sulfide and
Carbon Dioxide in Natural Gas Using Length of Stain Tubes,'' 1986
Revision (incorporated by reference--see Sec.  60.17), using tubes with
a maximum span between 10 and 40 ppmv inclusive when 1<=N<=10, where N
= number of pump strokes, to test the applicant fuel gas stream for
H2S; and
* * * * *
    (3) * * *
    (iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application and the owner or operator chooses not to submit new
information to support an exemption, the owner or operator must begin
H2S monitoring using daily stain sampling to demonstrate
compliance using length-of-stain tubes with a maximum span between 200
and 400 ppmv inclusive when 1<=N<=5, where N = number of pump strokes.
The owner or operator must begin monitoring according to the
requirements in paragraphs (a)(1) or (a)(2) of this section as soon as
practicable but in no case later than 180 days after the operation
change. During daily stain tube sampling, a daily sample exceeding 162
ppmv is an

exceedance of the 3-hour H2S concentration limit.
* * * * *

Subpart Ja--[AMENDED]

0
3. Section 60.100a is amended by revising the first sentence of
paragraph (b) to read as follows:

Sec.  60.100a  Applicability, designation of affected facility, and
reconstruction.

* * * * *
    (b) Except for flares, the provisions of this subpart apply only to
affected facilities under paragraph (a) of this section which either
commence construction, modification or reconstruction after May 14,
2007, or elect to comply with the provisions of this subpart in lieu of
complying with the provisions in subpart J of this part. * * *
0
4. Section 60.101a is amended by:
0
a. Revising the definition of ``Corrective action''; and
0
b. Adding, in alphabetical order, a definition for ``Sour water'' to
read as follows:

Sec.  60.101a  Definitions.

* * * * *
    Corrective action means the design, operation and maintenance
changes that one takes consistent with good engineering practice to
reduce or eliminate the likelihood of the recurrence of the primary
cause and any other contributing cause(s) of an event identified by a
root cause analysis as having resulted in a discharge of gases from an
affected facility in excess of specified thresholds.
* * * * *
    Sour water means water that contains sulfur compounds (usually
H2S) at concentrations of 10 parts per million by weight or
more.
* * * * *
0
5. Section 60.102a is amended by:
0
a. Revising paragraphs (b)(1)(i) and (iii);
0
b. Revising paragraph (f); and
0
c. Revising paragraph (g)(1).
    The revisions read as follows:

Sec.  60.102a  Emissions limitations.

* * * * *
    (b) * * *
    (1) * * *
    (i) 1.0 gram per kilogram (g/kg) (1 pound (lb) per 1,000 lb) coke
burn-off or, if a PM continuous emission monitoring system (CEMS) is
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0
percent excess air for each modified or reconstructed FCCU.
* * * * *
    (iii) 1.0 g/kg (1 lb/1,000 lb) coke burn-off or, if a PM CEMS is
used, 0.040 grain per dry standard cubic feet (gr/dscf) corrected to 0
percent excess air for each affected FCU.
* * * * *
    (f) Except as provided in paragraph (f)(3), each owner or operator
of an affected sulfur recovery plant shall comply with the applicable
emission limits in paragraphs (f)(1) or (2) of this section.
    (1) For a sulfur recovery plant with a design production capacity
greater than 20 long tons per day (LTD), the owner or operator shall
comply with the applicable emission limit in paragraphs (f)(1)(i) or
(f)(1)(ii) of this section. If the sulfur recovery plant consists of
multiple process trains or release points, the owner or operator shall
comply with the applicable emission limit for each process train or
release point individually or comply with the applicable emission limit
in paragraphs (f)(1)(i) or (f)(1)(ii) of this section as a flow rate
weighted average for a group of release points from the sulfur recovery
plant provided that flow is monitored as specified in Sec.
60.106a(a)(7); if flow is not monitored as specified in Sec.
60.106a(a)(7), the owner or operator shall comply with the applicable
emission limit in paragraphs (f)(1)(i) or (f)(1)(ii) of this section
for each process train or release point individually. For a sulfur
recovery plant with a design production capacity greater than 20 long
LTD and a reduction control system not followed by incineration, the
owner or operator shall also comply with the H2S emission
limit in paragraph (f)(1)(iii) of this section for each individual
release point.
    (i) For a sulfur recovery plant with an oxidation control system or
a reduction control system followed by incineration, the owner or
operator shall not discharge or cause the discharge of any gases into
the atmosphere (SO2) in excess of the emission limit
calculated using Equation 1 of this section. For Claus units that use
only ambient air in the Claus burner or that elect not to monitor
O2 concentration of the air/oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery plants, this SO2
emissions limit is 250 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TP30JN14.058

Where:

ELS = Emission limit for large sulfur recovery plant,
ppmv (as SO2, dry basis at zero percent excess air);
k1 = Constant factor for emission limit conversion:
k1 = 1 for converting to the SO2 limit for a
sulfur recovery plant with an oxidation control system or a
reduction control system followed by incineration and k1
= 1.2 for converting to the reduced sulfur compounds limit for a
sulfur recovery plant with a reduction control system not followed
by incineration; and
%O2 = O2 concentration of the air/oxygen
mixture supplied to the Claus burner, percent by volume (dry basis).
If only ambient air is used for the Claus burner or if the owner or
operator elects not to monitor O2 concentration of the
air/oxygen mixture used in the Claus burner or for non-Claus sulfur
recovery plants, use 20.9% for %O2.

    (ii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
reduced sulfur compounds in excess of the emission limit calculated
using Equation 1 of this section. For Claus units that use only ambient
air in the Claus burner or for non-Claus sulfur recovery plants, this
reduced sulfur compounds emission limit is 300 ppmv calculated as ppmv
SO2 (dry basis) at 0-percent excess air.
    (iii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
hydrogen sulfide (H2S) in excess of 10 ppmv calculated as
ppmv SO2 (dry basis) at zero percent excess air.
    (2) For a sulfur recovery plant with a design production capacity
of 20 LTD or less, the owner or operator shall comply with the
applicable emission limit in paragraphs (f)(2)(i) or (f)(2)(ii) of this
section. If the sulfur recovery plant consists of multiple process
trains or release points, the owner or operator may comply with the
applicable emission limit for each process train or release point
individually or comply with the applicable emission limit in paragraphs
(f)(2)(i) or (f)(2)(ii) of this

section as a flow rate weighted average for a group of release points
from the sulfur recovery plant provided that flow is monitored as
specified in Sec.  60.106a(a)(7); if flow is not monitored as specified
in Sec.  60.106a(a)(7), the owner or operator shall comply with the
applicable emission limit in paragraphs (f)(2)(i) or (f)(2)(ii) of this
section for each process train or release point individually. For a
sulfur recovery plant with a design production capacity of 20 LTD or
less and a reduction control system not followed by incineration, the
owner or operator shall also comply with the H2S emission
limit in paragraph (f)(2)(iii) of this section for each individual
release point.
    (i) For a sulfur recovery plant with an oxidation control system or
a reduction control system followed by incineration, the owner or
operator shall not discharge or cause the discharge of any gases into
the atmosphere containing SO2 in excess of the emission
limit calculated using Equation 2 of this section. For Claus units that
use only ambient air in the Claus burner or that elect not to monitor
O2 concentration of the air/oxygen mixture used in the Claus
burner or for non-Claus sulfur recovery plants, this SO2
emission limit is 2,500 ppmv (dry basis) at zero percent excess air.
[GRAPHIC] [TIFF OMITTED] TP30JN14.059

Where:

ESS = Emission limit for small sulfur recovery plant,
ppmv (as SO2, dry basis at zero percent excess air);
k1 = Constant factor for emission limit conversion:
k1 = 1 for converting to the SO2 limit for a
sulfur recovery plant with an oxidation control system or a
reduction control system followed by incineration and k1
= 1.2 for converting to the reduced sulfur compounds limit for a
sulfur recovery plant with a reduction control system not followed
by incineration; and
%O2 = O2 concentration of the air/oxygen
mixture supplied to the Claus burner, percent by volume (dry basis).
If only ambient air is used in the Claus burner or if the owner or
operator elects not to monitor O2 concentration of the
air/oxygen mixture used in the Claus burner or for non-Claus sulfur
recovery plants, use 20.9% for %O2.

    (ii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
reduced sulfur compounds in excess of the emission limit calculated
using Equation 2 of this section. For Claus units that use only ambient
air in the Claus burner or for non-Claus sulfur recovery plants, this
reduced sulfur compounds emission limit is 3,000 ppmv calculated as
ppmv SO2 (dry basis) at zero percent excess air.
    (iii) For a sulfur recovery plant with a reduction control system
not followed by incineration, the owner or operator shall not discharge
or cause the discharge of any gases into the atmosphere containing
H2S in excess of 100 ppmv calculated as ppmv SO2
(dry basis) at zero percent excess air.
    (3) The emission limits in paragraphs (f)(1) and (2) shall not
apply during periods of maintenance of the sulfur pit, which shall not
exceed 240 hours per year. The owner or operator must document the time
periods during which the sulfur pit vents were not controlled and
measures taken to minimize emissions during these periods. Examples of
these measures include not adding fresh sulfur or shutting off vent
fans.
    (g) * * *
    (1) Except as provided in (g)(1)(iii) of this section, for each
fuel gas combustion device, the owner or operator shall comply with
either the emission limit in paragraph (g)(1)(i) of this section or the
fuel gas concentration limit in paragraph (g)(1)(ii) of this section.
For CO boilers or furnaces that are part of a fluid catalytic cracking
unit or fluid coking unit affected facility, the owner or operator
shall comply with the fuel gas concentration limit in paragraph
(g)(1)(ii) of this section for all fuel gas streams combusted in these
units.
* * * * *
0
6. Section 60.104a is amended by:
0
a. Revising the first sentence of paragraph (a);
0
b. Revising paragraph (b);
0
c. Revising paragraph (f) introductory text;
0
d. Revising paragraph (h) introductory text;
0
e. Adding paragraph (h)(6); and
0
f. Removing and reserving paragraphs (j)(1) through (3).
    The revisions and additions read as follows:

Sec.  60.104a  Performance tests.

* * * * *
    (a) The owner or operator shall conduct a performance test for each
FCCU, FCU, sulfur recovery plant and fuel gas combustion device to
demonstrate initial compliance with each applicable emissions limit in
Sec.  60.102a and conduct a performance test for each flare to
demonstrate initial compliance with the H2S concentration
requirement in Sec.  60.103a(h) according to the requirements of Sec.
60.8. * * *
    (b) The owner or operator of a FCCU or FCU that elects to monitor
control device operating parameters according to the requirements in
Sec.  60.105a(b), to use bag leak detectors according to the
requirements in Sec.  60.105a(c), or to use COMS according to the
requirements in Sec.  60.105a(e) shall conduct a PM performance test at
least annually (i.e., once per calendar year, with an interval of at
least 8 months but no more than 16 months between annual tests) and
furnish the Administrator a written report of the results of each test.
* * * * *
    (f) The owner or operator of an FCCU or FCU that uses cyclones to
comply with the PM per coke burn-off emissions limit in Sec.
60.102a(b)(1) shall establish a site-specific opacity operating limit
according to the procedures in paragraphs (f)(1) through (3) of this
section.
* * * * *
    (h) The owner or operator shall determine compliance with the
SO2 emissions limits for sulfur recovery plants in
Sec. Sec.  60.102a(f)(1)(i) and 60.102a(f)(2)(i) and the reduced sulfur
compounds and H2S emissions limits for sulfur recovery
plants in Sec. Sec.  60.102a(f)(1)(ii), 60.102a(f)(1)(iii),
60.102a(f)(2)(ii) and 60.102a(f)(2)(iii) using the following methods
and procedures:
* * * * *
    (6) If oxygen or oxygen-enriched air is used in the Claus burner
and either Equation 1 or 2 of this subpart is used to determine the
applicable emissions limit, determine the average O2
concentration of the air/oxygen mixture supplied to the Claus burner,
in percent by volume (dry basis), for the performance test using all
hourly average O2 concentrations determined during the test
runs using the procedures in Sec.  60.106a(a)(5) or (6).
* * * * *
0
7. Section 60.105a is amended by:
0
a. Revising paragraph (b)(1)(i);
0
b. Revising paragraph (b)(1)(ii)(A);

0
c. Revising paragraph (b)(2);
0
d. Revising paragraph (h)(1);
0
e. Revising paragraph (h)(3)(i);
0
f. Revising paragraph (i)(1);
0
g. Redesignating paragraphs (i)(2) through (6) as (i)(3) through (7);
0
h. Adding paragraph (i)(2); and
0
i. Revising newly redesignated paragraph (i)(7).
    The revisions and additions read as follows:

Sec.  60.105a  Monitoring of emissions and operations for fluid
catalytic cracking units (FCCU) and fluid coking units (FCU).

* * * * *
    (b) * * *
    (1) * * *
    (i) For units controlled using an electrostatic precipitator, the
owner or operator shall use CPMS to measure and record the hourly
average total power input and secondary current to the entire system.
    (ii) * * *
    (A) As an alternative to pressure drop, the owner or operator of a
jet ejector type wet scrubber or other type of wet scrubber equipped
with atomizing spray nozzles must conduct a daily check of the air or
water pressure to the spray nozzles and record the results of each
check. Faulty (e.g., leaking or plugged) air or water lines must be
repaired within 12 hours of identification of an abnormal pressure
reading.
* * * * *
    (2) For use in determining the coke burn-off rate for an FCCU or
FCU, the owner or operator shall install, operate, calibrate, and
maintain an instrument for continuously monitoring the concentrations
of CO2, O2 (dry basis), and if needed, CO in the
exhaust gases prior to any control or energy recovery system that burns
auxiliary fuels. A CO monitor is not required for determining coke
burn-off rate when no auxiliary fuel is burned and a continuous CO
monitor is not required in accordance with Sec.  60.105a(h)(3).
    (i) The owner or operator shall install, operate, and maintain each
CO2 and O2 monitor according to Performance
Specification 3 of Appendix B to part 60.
    (ii) The owner or operator shall conduct performance evaluations of
each CO2 and O2 monitor according to the
requirements in Sec.  60.13(c) and Performance Specification 3 of
Appendix B to part 60. The owner or operator shall use Method 3 of
Appendix A-3 to part 60 for conducting the relative accuracy
evaluations.
    (iii) If a CO monitor is required, the owner or operator shall
install, operate, and maintain each CO monitor according to Performance
Specification 4 or 4A of Appendix B to part 60. If this CO monitor also
serves to demonstrate compliance with the CO emissions limit in Sec.
60.102a(b)(4), the span value for this instrument is 1,000 ppm;
otherwise, the span value for this instrument should be set at
approximately 2 times the typical CO concentration expected in the FCCU
of FCU flue gas prior to any emission control or energy recovery system
that burns auxiliary fuels.
    (iv) If a CO monitor is required, the owner or operator shall
conduct performance evaluations of each CO monitor according to the
requirements in Sec.  60.13(c) and Performance Specification 4 of
Appendix B to part 60. The owner or operator shall use Method 10, 10A,
or 10B of Appendix A-3 to part 60 for conducting the relative accuracy
evaluations.
    (v) The owner or operator shall comply with the quality assurance
requirements of procedure 1 of Appendix F to part 60, including
quarterly accuracy determinations for CO2 and CO monitors,
annual accuracy determinations for O2 monitors, and daily
calibration drift tests.
* * * * *
    (h) * * *
    (1) The owner or operator shall install, operate, and maintain each
CO monitor according to Performance Specification 4 or 4A of appendix B
to part 60. The span value for this instrument is 1,000 ppmv CO.
* * * * *
    (3) * * *
    (i) The demonstration shall consist of continuously monitoring CO
emissions for 30 days using an instrument that meets the requirements
of Performance Specification 4 or 4A of appendix B to part 60. The span
value shall be 100 ppmv CO instead of 1,000 ppmv, and the relative
accuracy limit shall be 10 percent of the average CO emissions or 5
ppmv CO, whichever is greater. For instruments that are identical to
Method 10 of appendix A-4 to part 60 and employ the sample conditioning
system of Method 10A of appendix A-4 to part 60, the alternative
relative accuracy test procedure in section 10.1 of Performance
Specification 2 of appendix B to part 60 may be used in place of the
relative accuracy test.
* * * * *
    (i) * * *
    (1) If a CPMS is used according to Sec.  60.105a(b)(1), all 3-hour
periods during which the average PM control device operating
characteristics, as measured by the continuous monitoring systems under
Sec.  60.105a(b)(1), fall below the levels established during the
performance test. If the alternative to pressure drop CPMS is used for
the owner or operator of a jet ejector type wet scrubber or other type
of wet scrubber equipped with atomizing spray nozzles, each day in
which abnormal pressure readings are not corrected within 12 hours of
identification.
    (2) If a bag leak detection system is used according to Sec.
60.105a(c), each day in which the cause of an alarm is not alleviated
within the time period specified in Sec.  60.105a(c)(3).
* * * * *
    (7) All 1-hour periods during which the average CO concentration as
measured by the CO continuous monitoring system under Sec.  60.105a(h)
exceeds 500 ppmv or, if applicable, all 1-hour periods during which the
average temperature and O2 concentration as measured by the
continuous monitoring systems under Sec.  60.105a(h)(4) fall below the
operating limits established during the performance test.
* * * * *
0
8. Section 60.106a is amended by:
0
a. Revising paragraph (a)(1)(i);
0
b. Adding paragraphs (a)(1)(iv) through (vii);
0
c. Revising paragraph (a)(2) introductory text;
0
d. Revising paragraphs (a)(2)(i) and (ii);
0
e. Revising the first sentence of paragraph (a)(2)(iii);
0
f. Removing paragraphs (a)(2)(iv) and (v);
0
g. Redesignating (a)(2)(vi) through (ix) as (a)(2)(iv) through (vii);
0
h. Revising the first sentence of paragraph (a)(3) introductory text;
0
i. Revising paragraph (a)(3)(i);
0
j. Adding paragraphs (a)(4) through (7); and
0
k. Revising paragraphs (b)(2) and (3).
    The revisions and additions read as follows:

Sec.  60.106a  Monitoring of emissions and operations for sulfur
recovery plants.

    (a) * * *
    (1) * * *
    (i) The span value for the SO2 monitor is two times the
applicable SO2 emission limit at the highest O2
concentration in the air/oxygen stream used in the Claus burner, if
applicable.
* * * * *
    (iv) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
Appendix B to part 60.
    (v) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.
    (vi) The owner or operator shall conduct performance evaluations
for the

O2 monitor according to the requirements of Sec.  60.13(c)
and Performance Specification 3 of Appendix B to part 60. The owner or
operator shall use Methods 3, 3A, or 3B of Appendix A-2 to part 60 for
conducting the relative accuracy evaluations. The method ANSI/ASME PTC
19.10-1981, ``Flue and Exhaust Gas Analyses,'' (incorporated by
reference--see Sec.  60.17) is an acceptable alternative to EPA Method
3B of Appendix A-2 to part 60.
    (vii) The owner or operator shall comply with the applicable
quality assurance procedures of Appendix F to part 60 for each monitor,
including annual accuracy determinations for each O2
monitor, and daily calibration drift determinations.
    (2) For sulfur recovery plants that are subject to the reduced
sulfur compounds emission limit in Sec.  60.102a(f)(1)(ii) or Sec.
60.102a(f)(2)(ii), the owner or operator shall install, operate,
calibrate, and maintain an instrument for continuously monitoring and
recording the concentration of reduced sulfur compounds and
O2 emissions into the atmosphere. The reduced sulfur
compounds emissions shall be calculated as SO2 (dry basis,
zero percent excess air).
    (i) The span value for the reduced sulfur compounds monitor is two
times the applicable reduced sulfur compounds emission limit as
SO2 at the highest O2 concentration in the air/
oxygen stream used in the Claus burner, if applicable.
    (ii) The owner or operator shall install, operate, and maintain
each reduced sulfur compounds CEMS according to Performance
Specification 5 of Appendix B to part 60.
    (iii) The owner or operator shall conduct performance evaluations
of each reduced sulfur compounds monitor according to the requirements
in Sec.  60.13(c) and Performance Specification 5 of Appendix B to part
60. * * *
* * * * *
    (3) In place of the reduced sulfur compounds monitor required in
paragraph (a)(2) of this section, the owner or operator may install,
calibrate, operate, and maintain an instrument using an air or
O2 dilution and oxidation system to convert any reduced
sulfur to SO2 for continuously monitoring and recording the
concentration (dry basis, 0 percent excess air) of the total resultant
SO2. * * *
    (i) The span value for this monitor is two times the applicable
reduced sulfur compounds emission limit as SO2 at the
highest O2 concentration in the air/oxygen stream used in
the Claus burner, if applicable.
* * * * *
    (4) For sulfur recovery plants that are subject to the
H2S emission limit in Sec.  60.102a(f)(1)(iii) or Sec.
60.102a(f)(2)(iii), the owner or operator shall install, operate,
calibrate, and maintain an instrument for continuously monitoring and
recording the concentration of H2S, and O2
emissions into the atmosphere. The H2S emissions shall be
calculated as SO2 (dry basis, zero percent excess air).
    (i) The span value for this monitor is two times the applicable
H2S emission limit.
    (ii) The owner or operator shall install, operate, and maintain
each H2S CEMS according to Performance Specification 7 of
appendix B to part 60.
    (iii) The owner or operator shall conduct performance evaluations
for each H2S monitor according to the requirements of Sec.
60.13(c) and Performance Specification 7 of appendix B to part 60. The
owner or operator shall use Methods 11 or 15 of appendix A-5 to part 60
or Method 16 of appendix A-6 to part 60 for conducting the relative
accuracy evaluations. The method ANSI/ASME PTC 19.10-1981, ``Flue and
Exhaust Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is
an acceptable alternative to EPA Method 15A of appendix A-5 to part 60.
    (iv) The owner or operator shall install, operate, and maintain
each O2 monitor according to Performance Specification 3 of
appendix B to part 60.
    (v) The span value for the O2 monitor must be selected
between 10 and 25 percent, inclusive.
    (vi) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to part 60. The
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec.  60.17) is an acceptable
alternative to EPA Method 3B of appendix A-2 to part 60.
    (vii) The owner or operator shall comply with the applicable
quality assurance procedures of appendix F to part 60 for each monitor,
including annual accuracy determinations for each O2
monitor, and daily calibration drift determinations.
    (5) For sulfur recovery plants that use oxygen or oxygen enriched
air in the Claus burner and that elects to monitor O2
concentration of the air/oxygen mixture supplied to the Claus burner,
the owner or operator shall install, operate, calibrate, and maintain
an instrument for continuously monitoring and recording the
O2 concentration of the air/oxygen mixture supplied to the
Claus burner in order to determine the allowable emissions limit.
    (i) The owner or operator shall install, operate, and maintain each
O2 monitor according to Performance Specification 3 of
appendix B to part 60.
    (ii) The span value for the O2 monitor shall be 100
percent.
    (iii) The owner or operator shall conduct performance evaluations
for the O2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 3 of appendix B to part 60. The
owner or operator shall use Methods 3, 3A, or 3B of appendix A-2 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec.  60.17) is an acceptable
alternative to EPA Method 3B of appendix A-2 to part 60.
    (iv) The owner or operator shall comply with the applicable quality
assurance procedures of appendix F to part 60 for each monitor,
including annual accuracy determinations for each O2
monitor, and daily calibration drift determinations.
    (v) The owner or operator shall use the hourly average
O2 concentration from this monitor for use in Equation 1 or
2 of Sec.  60.102a(f), as applicable, for each hour and determine the
allowable emission limit as the arithmetic average of 12 contiguous 1-
hour averages (i.e., the rolling 12-hour average).
    (6) As an alternative to the O2 monitor required in
paragraph (a)(5) of this section, the owner or operator may install,
calibrate, operate, and maintain a CPMS to measure and record the
volumetric gas flow rate of ambient air and oxygen-enriched gas
supplied to the Claus burner and calculate the hourly average
O2 concentration of the air/oxygen mixture used in the Claus
burner as specified in paragraphs (a)(6)(i) through (iv) of this
section in order to determine the allowable emissions limit as
specified in paragraphs (a)(6)(v) of this section.
    (i) The owner or operator shall install, calibrate, operate and
maintain each flow monitor according to the manufacturer's procedures
and specifications and the following requirements.
    (A) The owner or operator shall install locate the monitor in a
position that

provides a representative measurement of the total gas flow rate.
    (B) Use a flow sensor with a measurement sensitivity of no more
than 5 percent of the flow rate or 10 cubic feet per minute, whichever
is greater.
    (C) Use a flow monitor that is maintainable online, is able to
continuously correct for temperature, pressure and, for ambient air
flow monitor, moisture content, and is able to record dry flow in
standard conditions (as defined in Sec.  60.2) over one-minute
averages.
    (D) At least quarterly, perform a visual inspection of all
components of the monitor for physical and operational integrity and
all electrical connections for oxidation and galvanic corrosion if the
flow monitor is not equipped with a redundant flow sensor.
    (E) Recalibrate the flow monitor in accordance with the
manufacturer's procedures and specifications biennially (every two
years) or at the frequency specified by the manufacturer.
    (ii) The owner or operator shall use 20.9 percent as the oxygen
content of the ambient air.
    (iii) The owner or operator shall use product specifications (e.g.,
as reported in material safety data sheets) for percent oxygen for
purchased oxygen. For oxygen produced onsite, the percent oxygen shall
be determined by periodic measurements or process knowledge.
    (iv) The owner or operator shall calculate the hourly average
O2 concentration of the air/oxygen mixture used in the Claus
burner using Equation 10 of this section:
[GRAPHIC] [TIFF OMITTED] TP30JN14.001

Where:

%O2 = O2 concentration of the air/oxygen
mixture used in the Claus burner, percent by volume (dry basis);
20.9 = O2 concentration in air, percent dry basis;
Qair = Volumetric flow rate of ambient air used in the
Claus burner, dscfm;
%O2,oxy = O2 concentration in the enriched
oxygen stream, percent dry basis; and
Qoxy = Volumetric flow rate of enriched oxygen stream
used in the Claus burner, dscfm.

    (v) The owner or operator shall use the hourly average
O2 concentration determined using Equation 8 of this section
for use in Equation 1 or 2 of Sec.  60.102a(f), as applicable, for each
hour and determine the allowable emission limit as the arithmetic
average of 12 contiguous 1-hour averages (i.e., the rolling 12-hour
average).
    (7) Owners or operators of a sulfur recovery plant that elects to
comply with the SO2 emission limit in Sec.  60.102a(f)(1)(i)
or Sec.  60.102a(f)(2)(i) or the reduced sulfur compounds emission
limit in Sec.  60.102a(f)(1)(ii) or Sec.  60.102a(f)(2)(ii) as a flow
rate weighted average for a group of release points from the sulfur
recovery plant rather than for each process train or release point
individually shall install, calibrate, operate, and maintain a CPMS to
measure and record the volumetric gas flow rate of each release point
within the group of release points from the sulfur recovery plant as
specified in paragraphs (a)(7)(i) through (iv) of this section.
    (i) The owner or operator shall install, calibrate, operate and
maintain each flow monitor according to the manufacturer's procedures
and specifications and the following requirements.
    (A) The owner or operator shall install locate the monitor in a
position that provides a representative measurement of the total gas
flow rate.
    (B) Use a flow sensor with a measurement sensitivity of no more
than 5 percent of the flow rate or 10 cubic feet per minute, whichever
is greater.
    (C) Use a flow monitor that is maintainable online, is able to
continuously correct for temperature, pressure, and moisture content,
and is able to record dry flow in standard conditions (as defined in
Sec.  60.2) over one-minute averages.
    (D) At least quarterly, perform a visual inspection of all
components of the monitor for physical and operational integrity and
all electrical connections for oxidation and galvanic corrosion if the
flow monitor is not equipped with a redundant flow sensor.
    (E) Recalibrate the flow monitor in accordance with the
manufacturer's procedures and specifications biennially (every two
years) or at the frequency specified by the manufacturer.
    (ii) The owner or operator shall correct the flow to 0 percent
excess air using Equation 11 of this section:
[GRAPHIC] [TIFF OMITTED] TP30JN14.002

Where:

Qadj = Volumetric flow rate adjusted to 0 percent excess
air, dry standard cubic feet per minute (dscfm);
Cmeas = Volumetric flow rate measured by the flow meter
corrected to dry standard conditions, dscfm;
20.9c = 20.9 percent O2-0.0 percent
O2 (defined O2 correction basis), percent;
20.9 = O2 concentration in air, percent; and
%O2 = O2 concentration measured on a dry
basis, percent.

    (iii) The owner or operator shall calculate the flow weighted
average SO2 or reduced sulfur compounds concentration for
each hour using Equation 12 of this section:
[GRAPHIC] [TIFF OMITTED] TP30JN14.003

Where:

Cave = Flow weighted average concentration of the
pollutant, ppmv (dry basis, zero percent excess air). The pollutant
is either SO2 [if complying with the SO2
emission limit in Sec.  60.102a(f)(1)(i) or Sec.  60.102a(f)(2)(i)]
or reduced sulfur compounds [if complying with the reduced sulfur
compounds emission limit in Sec.  60.102a(f)(1)(ii) or Sec.
60.102a(f)(2)(ii)];
N = Number of release points within the group of release points from
the sulfur recovery plant for which emissions averaging is elected;
Cn = Pollutant concentration in the nth release point
within the group of release points from the sulfur recovery plant
for which emissions averaging is elected, ppmv (dry basis, zero
percent excess air);
Qadj,n = Volumetric flow rate of the nth release point
within the group of release points from the sulfur recovery plant
for which emissions averaging is elected, dry standard cubic feet
per minute (dscfm, adjusted to 0 percent excess air).

    (iv) For sulfur recovery plants that use oxygen or oxygen enriched
air in the Claus burner, the owner or operator shall use Equation 10 of
this section and the hourly emission limits determined in paragraphs
(a)(5)(v) or (a)(6)(v) of this section in-place of the pollutant
concentration to determine the flow weighted average hourly emission
limit for each hour. The allowable emission limit shall be calculated
as the arithmetic average of 12 contiguous 1-hour averages (i.e., the
rolling 12-hour average).
    (b) * * *
    (2) All 12-hour periods during which the average concentration of
reduced sulfur compounds (as SO2) as measured by the reduced
sulfur compounds continuous monitoring system required under paragraph
(a)(2) or (3) of this section exceeds the applicable emission limit; or
    (3) All 12-hour periods during which the average concentration of
H2S as measured by the H2S continuous monitoring
system required under paragraph (a)(4) of this section exceeds the
applicable emission limit (dry basis, 0 percent excess air).
0
9. Section 60.107a is amended by:
0
a. Revising paragraphs (a)(1)(i) and (ii);
0
b. Revising paragraph (b)(1)(iv);
0
c. Revising the first sentence of paragraph (b)(3)(iii);
0
d. Revising paragraph (d)(3);
0
e. Revising paragraph (e)(1) introductory text;
0
f. Revising paragraph (e)(1)(ii);
0
g. Revising paragraph (e)(2) introductory text;
0
h. Revising paragraph (e)(2)(ii);
0
i. Revising paragraph (e)(2)(vi)(C);
0
j. Revising paragraph (e)(3); and
0
k. Revising paragraph (h)(5).
    The revisions read as follows:

Sec.  60.107a  Monitoring of emissions and operations for fuel gas
combustion devices and flares.

    (a) * * *
    (1) * * *
    (i) The owner or operator shall install, operate, and maintain each
SO2 monitor according to Performance Specification 2 of
appendix B to part 60. The span value for the SO2 monitor is
50 ppmv SO2.
    (ii) The owner or operator shall conduct performance evaluations
for the SO2 monitor according to the requirements of Sec.
60.13(c) and Performance Specification 2 of appendix B to part 60. The
owner or operator shall use Methods 6, 6A, or 6C of appendix A-4 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,''
(incorporated by reference--see Sec.  60.17) is an acceptable
alternative to EPA Method 6 or 6A of appendix A-4 to part 60. Samples
taken by Method 6 of appendix A-4 to part 60 shall be taken at a flow
rate of approximately 2 liters/min for at least 30 minutes. The
relative accuracy limit shall be 20 percent or 4 ppmv, whichever is
greater, and the calibration drift limit shall be 5 percent of the
established span value.
* * * * *
    (b) * * *
    (1) * * *
    (iv) The supporting test results from sampling the requested fuel
gas stream/system demonstrating that the sulfur content is less than 5
ppmv H2S. Sampling data must include, at minimum, 2 weeks of
daily monitoring (14 grab samples) for frequently operated fuel gas
streams/systems; for infrequently operated fuel gas streams/systems,
seven grab samples must be collected unless other additional
information would support reduced sampling. The owner or operator shall
use detector tubes (``length-of-stain tube'' type measurement)
following the ``Gas Processors Association Standard 2377-86, Test for
Hydrogen Sulfide and Carbon Dioxide in Natural Gas Using Length of
Stain Tubes,'' 1986 Revision (incorporated by reference--see Sec.
60.17), using tubes with a maximum span between 10 and 40 ppmv
inclusive when 1<=N<=10, where N = number of pump strokes, to test the
applicant fuel gas stream for H2S; and
* * * * *
    (3) * * *
    (iii) If the operation change results in a sulfur content that is
outside the range of concentrations included in the original
application and the owner or operator chooses not to submit new
information to support an exemption, the owner or operator must begin
H2S monitoring using daily stain sampling to demonstrate
compliance using length-of-stain tubes with a maximum span between 200
and 400 ppmv inclusive when 1<=N<=5, where N = number of pump strokes.
* * *
* * * * *
    (d) * * *
    (3) As an alternative to the requirements in paragraph (d)(2) of
this section, the owner or operator of a gas-fired process heater shall
install, operate and maintain a gas composition analyzer and determine
the average F factor of the fuel gas using the factors in Table 1 of
this subpart and Equation 13 of this section. If a single fuel gas
system provides fuel gas to several process heaters, the F factor may
be determined at a single location in the fuel gas system provided it
is representative of the fuel gas fed to the affected process
heater(s).
[GRAPHIC] [TIFF OMITTED] TP30JN14.004

Where:

Fd = F factor on dry basis at 0% excess air, dscf/MMBtu.
Xi = mole or volume fraction of each component in the
fuel gas.
MEVi = molar exhaust volume, dry standard cubic feet per
mole (dscf/mol).
MHCi = molar heat content, Btu per mole (Btu/mol).
1,000,000 = unit conversion, Btu per MMBtu.

* * * * *
    (e) * * *
    (1) Total reduced sulfur monitoring requirements. The owner or
operator shall install, operate, calibrate and maintain an instrument
or instruments for continuously monitoring and

recording the concentration of total reduced sulfur in gas discharged
to the flare.
* * * * *
    (ii) The owner or operator shall conduct performance evaluations of
each total reduced sulfur monitor according to the requirements in
Sec.  60.13(c) and Performance Specification 5 of Appendix B to part
60. The owner or operator of each total reduced sulfur monitor shall
use EPA Method 15A of Appendix A-5 to part 60 for conducting the
relative accuracy evaluations. The method ANSI/ASME PTC 19.10-1981
(incorporated by reference--see Sec.  60.17) is an acceptable
alternative to EPA Method 15A of Appendix A-5 to part 60. The
alternative relative accuracy procedures described in section 16.0 of
Performance Specification 2 of Appendix B to part 60 (cylinder gas
audits) may be used for conducting the relative accuracy evaluations,
except that it is not necessary to include as much of the sampling
probe or sampling line as practical.
* * * * *
    (2) H2S monitoring requirements. The owner or operator
shall install, operate, calibrate, and maintain an instrument or
instruments for continuously monitoring and recording the concentration
of H2S in gas discharged to the flare according to the
requirements in paragraphs (e)(2)(i) through (iii) of this section and
shall collect and analyze samples of the gas and calculate total sulfur
concentrations as specified in paragraphs (e)(2)(iv) through (ix) of
this section.
* * * * *
    (ii) The owner or operator shall conduct performance evaluations of
each H2S monitor according to the requirements in Sec.
60.13(c) and Performance Specification 7 of Appendix B to part 60. The
owner or operator shall use EPA Method 11, 15 or 15A of Appendix A-5 to
part 60 for conducting the relative accuracy evaluations. The method
ANSI/ASME PTC 19.10-1981 (incorporated by reference--see Sec.  60.17)
is an acceptable alternative to EPA Method 15A of Appendix A-5 to part
60. The alternative relative accuracy procedures described in section
16.0 of Performance Specification 2 of Appendix B to part 60 (cylinder
gas audits) may be used for conducting the relative accuracy
evaluations, except that it is not necessary to include as much of the
sampling probe or sampling line as practical.
* * * * *
    (vi) * * *
    (C) Determine the acceptable range for subsequent weekly samples
based on the 95-percent confidence interval for the distribution of
daily ratios based on the 10 individual daily ratios using Equation 14
of this section.
[GRAPHIC] [TIFF OMITTED] TP30JN14.060

Where:

AR = Acceptable range of subsequent ratio determinations, unitless.
RatioAvg = 10-day average total sulfur-to-H2S
concentration ratio, unitless.
2.262 = t-distribution statistic for 95-percent 2-sided confidence
interval for 10 samples (9 degrees of freedom).
SDev = Standard deviation of the 10 daily average total sulfur-to-
H2S concentration ratios used to develop the 10-day
average total sulfur-to-H2S concentration ratio,
unitless.
* * * * *
    (3) SO2 monitoring requirements. The owner or operator
shall install, operate, calibrate, and maintain an instrument for
continuously monitoring and recording the concentration of
SO2 from a process heater or other fuel gas combustion
device that is combusting gas representative of the fuel gas in the
flare gas line according to the requirements in paragraph (a)(1) of
this section, determine the F factor of the fuel gas at least daily
according to the requirements in paragraphs (d)(2) through (4) of this
section, determine the higher heating value of the fuel gas at least
daily according to the requirements in paragraph (d)(7) of this
section, and calculate the total sulfur content (as SO2) in
the fuel gas using Equation 15 of this section.

    Where:

TSFG = Total sulfur concentration, as SO2, in
the fuel gas, ppmv.
CSO2 = Concentration of SO2 in the
exhaust gas, ppmv (dry basis at 0-percent excess air).
Fd = F factor gas on dry basis at 0-percent excess air,
dscf/MMBtu.
HHVFG = Higher heating value of the fuel gas, MMBtu/scf.
* * * * *
    (h) * * *
    (5) Daily O2 limits for fuel gas combustion devices.
Each day during which the concentration of O2 as measured by
the O2 continuous monitoring system required under paragraph
(c)(6) or (d)(8) of this section exceeds the O2 operating
limit or operating curve determined during the most recent biennial
performance test.

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS
FOR SOURCE CATEGORIES

0
10. The authority citation for part 63 continues to read as follows:

    Authority:  42 U.S.C. 7401, et seq.

Subpart A--[Amended]

0
11. Section 63.14 is amended by:
0
a. Revising paragraph (g)(14);
0
b. Adding paragraphs (g)(95) and (96);
0
c. Adding paragraph (i)(2);
0
d. Adding paragraphs (l)(21) through (23); and
0
e. Adding paragraphs (m)(3) and (s).
    The revisions and additions read as follows:

Sec.  63.14  Incorporation by reference.

* * * * *
    (g) * * *
    (14) ASTM D1945-03 (Reapproved 2010), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography, (Approved January 1,
2010), IBR approved for Sec. Sec.  63.670(j), 63.772(h), and
63.1282(g).
* * * * *
    (95) ASTM D6196-03 (Reapproved 2009), Standard Practice for
Selection of Sorbents, Sampling, and Thermal Desorption Analysis
Procedures for Volatile Organic Compounds in Air, IBR approved for
appendix A to part 63: Method 325A, Sections 1.2 and 6.1, and Method
325B, Sections 1.3, 7.1.2, 7.1.3, and A.1.1.
    (96) ASTM UOP539-12, Refinery Gas Analysis by Gas Chromatography,
IBR approved for Sec.  63.670(j).
* * * * *
    (i) * * *
    (2) BS EN 14662-4:2005, Ambient Air Quality: Standard Method for
the Measurement of Benzene Concentrations--Part 4: Diffusive Sampling
Followed By Thermal Desorption and Gas Chromatography, IBR approved for
appendix A to part 63: Method 325A, Section 1.2, and Method 325B,
Sections 1.3, 7.1.3, and A.1.1.
* * * * *
    (l) * * *
    (21) EPA-454/R-99-005, Office of Air Quality Planning and Standards
(OAQPS), Meteorological Monitoring

Guidance for Regulatory Modeling Applications, February 2000, IBR
approved for appendix A to part 63: Method 325A, Section 8.3.
    (22) EPA-454/B-08-002, Office of Air Quality Planning and Standards
(OAQPS), Quality Assurance Handbook for Air Pollution Measurement
Systems, Volume IV: Meteorological Measurements, Version 2.0 (Final),
March 2008, IBR approved for Sec.  63.658(d) and appendix A to part 63:
Method 325A, Sections 8.1.4 and 10.0.
    (23) EPA-454/B-13-003, Office of Air Quality Planning and Standards
(OAQPS), Quality Assurance Handbook for Air Pollution Measurement
Systems, Volume II: Ambient Air Quality Monitoring Program, May 2013,
IBR approved for Sec.  63.658(c) and appendix A to part 63: Method
325A, Section 4.1.
    (m) * * *
    (3) ISO 16017-2:2003, Indoor, Ambient and Workplace Air--Sampling
and Analysis of Volatile Organic Compounds by Sorbent Tube/Thermal
Desorption/Capillary Gas Chromatography--Part 2: Diffusive Sampling,
First edition, June 11, 2003, IBR approved for appendix A to part 63:
Method 325A, Sections 1.2, 6.1, and 6.5, and Method 325B, Sections 1.3,
7.1.2, 7.1.3, and A.1.1.
* * * * *
    (s) U.S. Department of the Interior, 1849 C Street NW., Washington,
DC 20240,<PHONE_NUMBER>, www.doi.gov.
    (1) Bulletin 627, Bureau of Mines, Flammability Characteristics of
Combustible Gases and Vapors, 1965, IBR approved for Sec.  63.670(l).
    (2) [Reserved]

Subpart Y--[Amended]

0
12. Section 63.560 is amended by revising paragraph (a)(4) to read as
follows:

Sec.  63.560  Applicability and designation of affected source.

    (a) * * *
    (4) Existing sources with emissions less than 10 and 25 tons must
meet the submerged fill standards of 46 CFR 153.282.
* * * * *

Subpart CC--[Amended]

0
13. Section 63.640 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (c) introductory text;
0
c. Adding paragraph (c)(9);
0
d. Revising paragraph (d)(5);
0
e. Revising paragraph (h);
0
f. Revising paragraph (k)(1);
0
g. Revising paragraph (l) introductory text;
0
h. Revising paragraph (l)(2) introductory text;
0
i. Revising paragraph (l)(2)(i);
0
j. Revising paragraph (l)(3) introductory text;
0
k. Revising paragraph (m) introductory text;
0
l. Revising paragraph (n) introductory text;
0
m. Revising paragraphs (n)(1) through (5);
0
n. Revising paragraph (n)(8) introductory text;
0
o. Revising paragraph (n)(8)(ii);
0
p. Adding paragraphs (n)(8)(vii) and (viii);
0
q. Revising paragraph (n)(9)(i);
0
r. Adding paragraph (n)(10);
0
s. Revising paragraph (o)(2)(i) introductory text;
0
t. Adding paragraph (o)(2)(i)(D);
0
u. Revising paragraph (o)(2)(ii) introductory text;
0
v. Adding paragraph (o)(2)(ii)(C); and
0
w. Revising paragraph (p)(2).
    The revisions and additions read as follows:

Sec.  63.640  Applicability and designation of affected source.

    (a) This subpart applies to petroleum refining process units and to
related emissions points that are specified in paragraphs (c)(1)
through (9) of this section that are located at a plant site and that
meet the criteria in paragraphs (a)(1) and (2) of this section:
* * * * *
    (c) For the purposes of this subpart, the affected source shall
comprise all emissions points, in combination, listed in paragraphs
(c)(1) through (c)(9) of this section that are located at a single
refinery plant site.
* * * * *
    (9) All releases associated with the decoking operations of a
delayed coking unit, as defined in this subpart.
* * * * *
    (d) * * *
    (5) Emission points routed to a fuel gas system, as defined in
Sec.  63.641 of this subpart, provided that on and after [THE DATE 3
YEARS AFTER THE DATE OF PUBLICATION OF THE FINAL RULE AMENDMENTS IN THE
FEDERAL REGISTER], any flares receiving gas from that fuel gas system
are in compliance with Sec.  63.670. No other testing, monitoring,
recordkeeping, or reporting is required for refinery fuel gas systems
or emission points routed to refinery fuel gas systems.
* * * * *
    (h) Sources subject to this subpart are required to achieve
compliance on or before the dates specified in table 11 of this
subpart, except as provided in paragraphs (h)(1) through (3) of this
section.
    (1) Marine tank vessels at existing sources shall be in compliance
with this subpart, except for Sec. Sec.  63.657 through 63.661, no
later than August 18, 1999, unless the vessels are included in an
emissions average to generate emission credits. Marine tank vessels
used to generate credits in an emissions average shall be in compliance
with this subpart no later than August 18, 1998 unless an extension has
been granted by the Administrator as provided in Sec.  63.6(i).
    (2) Existing Group 1 floating roof storage vessels meeting the
applicability criteria in item 1 of the definition of Group 1 storage
vessel shall be in compliance with Sec.  63.646 at the first degassing
and cleaning activity after August 18, 1998, or August 18, 2005,
whichever is first.
    (3) An owner or operator may elect to comply with the provisions of
Sec.  63.648(c) through (i) as an alternative to the provisions of
Sec.  63.648(a) and (b). In such cases, the owner or operator shall
comply no later than the dates specified in paragraphs (h)(3)(i)
through (h)(3)(iii) of this section.
    (i) Phase I (see table 2 of this subpart), beginning on August 18,
1998;
    (ii) Phase II (see table 2 of this subpart), beginning no later
than August 18, 1999; and
    (iii) Phase III (see table 2 of this subpart), beginning no later
than February 18, 2001.
* * * * *
    (k) * * *
    (1) The reconstructed source, addition, or change shall be in
compliance with the new source requirements in item (1), (2), or (3) of
table 11 of this subpart, as applicable, upon initial startup of the
reconstructed source or by August 18, 1995, whichever is later; and
* * * * *
    (l) If an additional petroleum refining process unit is added to a
plant site or if a miscellaneous process vent, storage vessel, gasoline
loading rack, marine tank vessel loading operation, heat exchange
system, or decoking operation that meets the criteria in paragraphs
(c)(1) through (9) of this section is added to an existing petroleum
refinery or if another deliberate operational process change creating
an additional Group 1 emissions point(s) (as defined in Sec.  63.641)
is made to an existing petroleum refining process unit, and if the
addition or process change is not subject to the new source
requirements as determined according to paragraphs (i) or (j) of this
section, the requirements in paragraphs (l)(1) through (4) of this

section shall apply. Examples of process changes include, but are not
limited to, changes in production capacity, or feed or raw material
where the change requires construction or physical alteration of the
existing equipment or catalyst type, or whenever there is replacement,
removal, or addition of recovery equipment. For purposes of this
paragraph and paragraph (m) of this section, process changes do not
include: Process upsets, unintentional temporary process changes, and
changes that are within the equipment configuration and operating
conditions documented in the Notification of Compliance Status report
required by Sec.  63.655(f).
* * * * *
    (2) The added emission point(s) and any emission point(s) within
the added or changed petroleum refining process unit shall be in
compliance with the applicable requirements in item (4) of table 11 of
this subpart by the dates specified in paragraphs (l)(2)(i) or
(l)(2)(ii) of this section.
    (i) If a petroleum refining process unit is added to a plant site
or an emission point(s) is added to any existing petroleum refining
process unit, the added emission point(s) shall be in compliance upon
initial startup of any added petroleum refining process unit or
emission point(s) or by the applicable compliance date in item (4) of
table 11 of this subpart, whichever is later.
* * * * *
    (3) The owner or operator of a petroleum refining process unit or
of a storage vessel, miscellaneous process vent, wastewater stream,
gasoline loading rack, marine tank vessel loading operation, heat
exchange system, or decoking operation meeting the criteria in
paragraphs (c)(1) through (9) of this section that is added to a plant
site and is subject to the requirements for existing sources shall
comply with the reporting and recordkeeping requirements that are
applicable to existing sources including, but not limited to, the
reports listed in paragraphs (l)(3)(i) through (vii) of this section. A
process change to an existing petroleum refining process unit shall be
subject to the reporting requirements for existing sources including,
but not limited to, the reports listed in paragraphs (l)(3)(i) through
(l)(3)(vii) of this section. The applicable reports include, but are
not limited to:
* * * * *
    (m) If a change that does not meet the criteria in paragraph (l) of
this section is made to a petroleum refining process unit subject to
this subpart, and the change causes a Group 2 emission point to become
a Group 1 emission point (as defined in Sec.  63.641), then the owner
or operator shall comply with the applicable requirements of this
subpart for existing sources, as specified in item (4) of table 11 of
this subpart, for the Group 1 emission point as expeditiously as
practicable, but in no event later than 3 years after the emission
point becomes Group 1.
* * * * *
    (n) Overlap of subpart CC with other regulations for storage
vessels. As applicable, paragraphs (n)(1), (n)(3), (n)(4), (n)(6), and
(n)(7) of this section apply for Group 2 storage vessels and paragraphs
(n)(2) and (n)(5) of this section apply for Group 1 storage vessels.
    (1) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is subject to the provisions of
40 CFR part 60, subpart Kb is required to comply only with the
requirements of 40 CFR part 60, subpart Kb, except as provided in
paragraph (n)(8) of this section. After the compliance dates specified
in paragraph (h) of this section, a Group 2 storage vessel that is
subject to the provisions of CFR part 61, subpart Y is required to
comply only with the requirements of 40 CFR part 60, subpart Y, except
as provided in paragraph (n)(10) of this section.
    (2) After the compliance dates specified in paragraph (h) of this
section, a Group 1 storage vessel that is also subject to 40 CFR part
60, subpart Kb is required to comply only with either 40 CFR part 60,
subpart Kb, except as provided in paragraph (n)(8) of this section; or
this subpart. After the compliance dates specified in paragraph (h) of
this section, a Group 1 storage vessel that is also subject to 40 CFR
part 61, subpart Y is required to comply only with either 40 CFR part
61, subpart Y, except as provided in paragraph (n)(10) of this section;
or this subpart.
    (3) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is part of a new source and is
subject to 40 CFR 60.110b, but is not required to apply controls by 40
CFR 60.110b or 60.112b, is required to comply only with this subpart.
    (4) After the compliance dates specified in paragraph (h) of this
section, a Group 2 storage vessel that is part of a new source and is
subject to 40 CFR 61.270, but is not required to apply controls by 40
CFR 61.271, is required to comply only with this subpart.
    (5) After the compliance dates specified in paragraph (h) of this
section, a Group 1 storage vessel that is also subject to the
provisions of 40 CFR part 60, subparts K or Ka is required to only
comply with the provisions of this subpart.
* * * * *
    (8) Storage vessels described by paragraph (n)(1) of this section
are to comply with 40 CFR part 60, subpart Kb except as provided in
paragraphs (n)(8)(i) through (n)(8)(vi) of this section. Storage
vessels described by paragraph (n)(2) electing to comply with part 60,
subpart Kb of this chapter shall comply with subpart Kb except as
provided in paragraphs (n)(8)(i) through (n)(8)(vii) of this section.
* * * * *
    (ii) If the owner or operator determines that it is unsafe to
perform the seal gap measurements required in Sec.  60.113b(b) of
subpart Kb or to inspect the vessel to determine compliance with Sec.
60.113b(a) of subpart Kb because the roof appears to be structurally
unsound and poses an imminent danger to inspecting personnel, the owner
or operator shall comply with the requirements in either Sec.
63.120(b)(7)(i) or Sec.  63.120(b)(7)(ii) of subpart G (only up to the
compliance date specified in paragraph (h) of this section for
compliance with Sec.  63.660, as applicable) or either Sec.
63.1063(c)(2)(iv)(A) or Sec.  63.1063(c)(2)(iv)(B) of subpart WW.
* * * * *
    (vii) To be in compliance with Sec.  60.112b(a)(2)(ii) of this