requirements of paragraphs (d)(1)(viii)(A) and (B) of this section. If
you comply with the periodic testing requirements of Sec.
60.5413a(b)(5)(ii), you are not required to continuously monitor the
gas flow rate under paragraph (d)(1)(viii)(A) of this section.
    (A) The continuous monitoring system must measure gas flow rate at
the inlet to the control device. The monitoring instrument must have an
accuracy of 2 percent or better at the maximum expected
flow rate. The flow rate at the inlet to the combustion device must not
exceed the maximum flow rate determined by the manufacturer.
    (B) A monitoring device that continuously indicates the presence of
the pilot flame while emissions are routed to the control device.
    (2) An organic monitoring device equipped with a continuous
recorder that measures the concentration level of organic compounds in
the exhaust vent stream from the control device. The monitor must meet
the requirements of Performance Specification 8 or 9 of appendix B of
this part. You must install, calibrate, and maintain the monitor
according to the manufacturer's specifications.
    (3) A continuous monitoring system that measures operating
parameters other than those specified in paragraph (d)(1) or (2) of
this section, upon approval of the Administrator as specified in Sec.
60.13(i).
    (e) You must calculate the daily average value for each monitored
operating parameter for each operating day, using the data recorded by
the monitoring system, except for inlet gas flow rate and data from the
heat sensing devices that indicate the presence of a pilot flame. If
the emissions unit operation is continuous, the operating day is a 24-
hour period. If the emissions unit operation is not continuous, the
operating day is the total number of hours of control device operation
per 24-hour period. Valid data points must be available for 75 percent
of the operating hours in an operating day to compute the daily
average.
    (f) For each operating parameter monitor installed in accordance
with the requirements of paragraph (d) of this section, you must comply
with paragraph (f)(1) of this section for all control devices. When
condensers are installed, you must also comply with paragraph (f)(2) of
this section.
    (1) You must establish a minimum operating parameter value or a
maximum operating parameter value, as appropriate for the control
device, to define the conditions at which the control device must be
operated to continuously achieve the applicable performance
requirements of Sec.  60.5412a(a)(1) or (2). You must establish each
minimum or maximum operating parameter value as specified in paragraphs
(f)(1)(i) through (iii) of this section.
    (i) If you conduct performance tests in accordance with the
requirements of Sec.  60.5413a(b) to demonstrate that the control
device achieves the applicable performance requirements specified in
Sec.  60.5412a(a)(1) or (2), then you must establish the minimum
operating parameter value or the maximum operating parameter value
based on values measured during the performance test and supplemented,
as necessary, by a condenser design analysis or control device
manufacturer recommendations or a combination of both.
    (ii) If you use a condenser design analysis in accordance with the
requirements of Sec.  60.5413a(c) to demonstrate that the control
device achieves the applicable performance requirements specified in
Sec.  60.5412a(a)(2), then you must establish the minimum operating
parameter value or the maximum operating parameter value based on the
condenser design analysis and supplemented, as necessary, by the
condenser manufacturer's recommendations.
    (iii) If you operate a control device where the performance test
requirement was met under Sec.  60.5413a(d) to demonstrate that the
control device achieves the applicable performance requirements
specified in Sec.  60.5412a(a)(1), then your control device inlet gas
flow rate must not exceed the maximum inlet gas flow rate determined by
the manufacturer.

    (2) If you use a condenser as specified in paragraph (d)(1)(v) of
this section, you must establish a condenser performance curve showing
the relationship between condenser outlet temperature and condenser
control efficiency, according to the requirements of paragraphs
(f)(2)(i) and (ii) of this section.
    (i) If you conduct a performance test in accordance with the
requirements of Sec.  60.5413a(b) to demonstrate that the condenser
achieves the applicable performance requirements in Sec.
60.5412a(a)(2), then the condenser performance curve must be based on
values measured during the performance test and supplemented as
necessary by control device design analysis, or control device
manufacturer's recommendations, or a combination or both.
    (ii) If you use a control device design analysis in accordance with
the requirements of Sec.  60.5413a(c)(1) to demonstrate that the
condenser achieves the applicable performance requirements specified in
Sec.  60.5412a(a)(2), then the condenser performance curve must be
based on the condenser design analysis and supplemented, as necessary,
by the control device manufacturer's recommendations.
    (g) A deviation for a given control device is determined to have
occurred when the monitoring data or lack of monitoring data result in
any one of the criteria specified in paragraphs (g)(1) through (6) of
this section being met. If you monitor multiple operating parameters
for the same control device during the same operating day and more than
one of these operating parameters meets a deviation criterion specified
in paragraphs (g)(1) through (6) of this section, then a single
excursion is determined to have occurred for the control device for
that operating day.
    (1) A deviation occurs when the daily average value of a monitored
operating parameter is less than the minimum operating parameter limit
(or, if applicable, greater than the maximum operating parameter limit)
established in paragraph (f)(1) of this section or when the heat
sensing device indicates that there is no pilot flame present.
    (2) If you are subject to Sec.  60.5412a(a)(2), a deviation occurs
when the 365-day average condenser efficiency calculated according to
the requirements specified in Sec.  60.5415a(b)(2)(viii)(D) is less
than 95.0 percent.
    (3) If you are subject to Sec.  60.5412a(a)(2) and you have less
than 365 days of data, a deviation occurs when the average condenser
efficiency calculated according to the procedures specified in Sec.
60.5415a(b)(2)(viii)(D)(1) or (2) is less than 95.0 percent.
    (4) A deviation occurs when the monitoring data are not available
for at least 75 percent of the operating hours in a day.
    (5) If the closed vent system contains one or more bypass devices
that could be used to divert all or a portion of the gases, vapors, or
fumes from entering the control device, a deviation occurs when the
requirements of paragraph (g)(5)(i) or (ii) of this section are met.
    (i) For each bypass line subject to Sec.  60.5411a(a)(3)(i)(A), the
flow indicator indicates that flow has been detected and that the
stream has been diverted away from the control device to the
atmosphere.
    (ii) For each bypass line subject to Sec.  60.5411a(a)(3)(i)(B), if
the seal or closure mechanism has been broken, the bypass line valve
position has changed, the key for the lock-and-key type lock has been
checked out, or the car-seal has broken.
    (6) For a combustion control device whose model is tested under
Sec.  60.5413a(d), a deviation occurs when the conditions of paragraphs
(g)(6)(i) or (ii) of this section are met.
    (i) The inlet gas flow rate exceeds the maximum established during
the test conducted under Sec.  60.5413a(d).
    (ii) Failure of the monthly visible emissions test conducted under
Sec.  60.5413a(e)(3) occurs.
    (h) For each control device used to comply with the emission
reduction standard in Sec.  60.5395a(a)(2) for your storage vessel
affected facility, you must demonstrate continuous compliance according
to paragraphs (h)(1) through (h)(4) of this section. You are exempt
from the requirements of this paragraph if you install a control device
model tested in accordance with Sec.  60.5413a(d)(2) through (10),
which meets the criteria in Sec.  60.5413a(d)(11), the reporting
requirement in Sec.  60.5413a(d)(12), and meet the continuous
compliance requirement in Sec.  60.5413a(e).
    (1) For each combustion device you must conduct inspections at
least once every calendar month according to paragraphs (h)(1)(i)
through (iv) of this section. Monthly inspections must be separated by
at least 14 calendar days.
    (i) Conduct visual inspections to confirm that the pilot is lit
when vapors are being routed to the combustion device and that the
continuous burning pilot flame is operating properly.
    (ii) Conduct inspections to monitor for visible emissions from the
combustion device using section 11 of EPA Method 22 of appendix A of
this part. The observation period shall be 15 minutes. Devices must be
operated with no visible emissions, except for periods not to exceed a
total of 1 minute during any 15 minute period.
    (iii) Conduct olfactory, visual and auditory inspections of all
equipment associated with the combustion device to ensure system
integrity.
    (iv) For any absence of the pilot flame, or other indication of
smoking or improper equipment operation (e.g., visual, audible, or
olfactory), you must ensure the equipment is returned to proper
operation as soon as practicable after the event occurs. At a minimum,
you must perform the procedures specified in paragraphs (h)(1)(iv)(A)
and (B) of this section.
    (A) You must check the air vent for obstruction. If an obstruction
is observed, you must clear the obstruction as soon as practicable.
    (B) You must check for liquid reaching the combustor.
    (2) For each vapor recovery device, you must conduct inspections at
least once every calendar month to ensure physical integrity of the
control device according to the manufacturer's instructions. Monthly
inspections must be separated by at least 14 calendar days.
    (3) Each control device must be operated following the
manufacturer's written operating instructions, procedures and
maintenance schedule to ensure good air pollution control practices for
minimizing emissions. Records of the manufacturer's written operating
instructions, procedures, and maintenance schedule must be available
for inspection as specified in Sec.  60.5420a(c)(13).
    (4) Conduct a periodic performance test no later than 60 months
after the initial performance test as specified in Sec.
60.5413a(b)(5)(ii) and conduct subsequent periodic performance tests at
intervals no longer than 60 months following the previous periodic
performance test.

Sec.  60.5420a  What are my notification, reporting, and recordkeeping
requirements?

    (a) You must submit the notifications according to paragraphs
(a)(1) and (2) of this section if you own or operate one or more of the
affected facilities specified in Sec.  60.5365a that was constructed,
modified or reconstructed during the reporting period.
    (1) If you own or operate an affected facility that is the group of
all equipment within a process unit at an onshore natural gas
processing plant, or a sweetening unit at an onshore natural gas
processing plant, you must submit

the notifications required in Sec.  60.7(a)(1), (3), and (4). If you
own or operate a well, centrifugal compressor, reciprocating
compressor, pneumatic controller, pneumatic pump, storage vessel, or
collection of fugitive emissions components at a well site or
collection of fugitive emissions components at a compressor station,
you are not required to submit the notifications required in Sec.
60.7(a)(1), (3), and (4).
    (2)(i) If you own or operate a well affected facility, you must
submit a notification to the Administrator no later than 2 days prior
to the commencement of each well completion operation listing the
anticipated date of the well completion operation. The notification
shall include contact information for the owner or operator; the United
States Well Number; the latitude and longitude coordinates for each
well in decimal degrees to an accuracy and precision of five (5)
decimals of a degree using the North American Datum of 1983; and the
planned date of the beginning of flowback. You may submit the
notification in writing or in electronic format.
    (ii) If you are subject to state regulations that require advance
notification of well completions and you have met those notification
requirements, then you are considered to have met the advance
notification requirements of paragraph (a)(2)(i) of this section.
    (b) Reporting requirements. You must submit annual reports
containing the information specified in paragraphs (b)(1) through (8)
and (12) of this section and performance test reports as specified in
paragraph (b)(9) or (10) of this section, if applicable. You must
submit annual reports following the procedure specified in paragraph
(b)(11) of this section. The initial annual report is due no later than
90 days after the end of the initial compliance period as determined
according to Sec.  60.5410a. Subsequent annual reports are due no later
than same date each year as the initial annual report. If you own or
operate more than one affected facility, you may submit one report for
multiple affected facilities provided the report contains all of the
information required as specified in paragraphs (b)(1) through (8) of
this section. Annual reports may coincide with title V reports as long
as all the required elements of the annual report are included. You may
arrange with the Administrator a common schedule on which reports
required by this part may be submitted as long as the schedule does not
extend the reporting period.
    (1) The general information specified in paragraphs (b)(1)(i)
through (iv) of this section for all reports.
    (i) The company name, facility site name associated with the
affected facility, US Well ID or US Well ID associated with the
affected facility, if applicable, and address of the affected facility.
If an address is not available for the site, include a description of
the site location and provide the latitude and longitude coordinates of
the site in decimal degrees to an accuracy and precision of five (5)
decimals of a degree using the North American Datum of 1983.
    (ii) An identification of each affected facility being included in
the annual report.
    (iii) Beginning and ending dates of the reporting period.
    (iv) A certification by a certifying official of truth, accuracy,
and completeness. This certification shall state that, based on
information and belief formed after reasonable inquiry, the statements
and information in the document are true, accurate, and complete.
    (2) For each well affected facility, the information in paragraphs
(b)(2)(i) through (iii) of this section.
    (i) Records of each well completion operation as specified in
paragraphs (c)(1)(i) through (iv) and (vi) of this section, if
applicable, for each well affected facility conducted during the
reporting period. In lieu of submitting the records specified in
paragraph (c)(1)(i) through (iv) of this section, the owner or operator
may submit a list of the well completions with hydraulic fracturing
completed during the reporting period and the records required by
paragraph (c)(1)(v) of this section for each well completion.
    (ii) Records of deviations specified in paragraph (c)(1)(ii) of
this section that occurred during the reporting period.
    (iii) Records specified in paragraph (c)(1)(vii) of this section,
if applicable, that support a determination under 60.5432a that the
well affected facility is a low pressure well as defined in 60.5430a.
    (3) For each centrifugal compressor affected facility, the
information specified in paragraphs (b)(3)(i) through (iv) of this
section.
    (i) An identification of each centrifugal compressor using a wet
seal system constructed, modified or reconstructed during the reporting
period.
    (ii) Records of deviations specified in paragraph (c)(2) of this
section that occurred during the reporting period.
    (iii) If required to comply with Sec.  60.5380a(a)(2), the records
specified in paragraphs (c)(6) through (11) of this section.
    (iv) If complying with Sec.  60.5380a(a)(1) with a control device
tested under Sec.  60.5413a(d) which meets the criteria in Sec.
60.5413a(d)(11) and Sec.  60.5413a(e), records specified in paragraph
(c)(2)(i) through (c)(2)(vii) of this section for each centrifugal
compressor using a wet seal system constructed, modified or
reconstructed during the reporting period.
    (4) For each reciprocating compressor affected facility, the
information specified in paragraphs (b)(4)(i) and (ii) of this section.
    (i) The cumulative number of hours of operation or the number of
months since initial startup or since the previous reciprocating
compressor rod packing replacement, whichever is later. Alternatively,
a statement that emissions from the rod packing are being routed to a
process through a closed vent system under negative pressure.
    (ii) Records of deviations specified in paragraph (c)(3)(iii) of
this section that occurred during the reporting period.
    (5) For each pneumatic controller affected facility, the
information specified in paragraphs (b)(5)(i) through (iii) of this
section.
    (i) An identification of each pneumatic controller constructed,
modified or reconstructed during the reporting period, including the
identification information specified in Sec.  60.5390a(b)(2) or (c)(2).
    (ii) If applicable, documentation that the use of pneumatic
controller affected facilities with a natural gas bleed rate greater
than 6 standard cubic feet per hour are required and the reasons why.
    (iii) Records of deviations specified in paragraph (c)(4)(v) of
this section that occurred during the reporting period.
    (6) For each storage vessel affected facility, the information in
paragraphs (b)(6)(i) through (vii) of this section.
    (i) An identification, including the location, of each storage
vessel affected facility for which construction, modification or
reconstruction commenced during the reporting period. The location of
the storage vessel shall be in latitude and longitude coordinates in
decimal degrees to an accuracy and precision of five (5) decimals of a
degree using the North American Datum of 1983.
    (ii) Documentation of the VOC emission rate determination according
to Sec.  60.5365a(e) for each storage vessel that became an affected
facility during the reporting period or is returned to service during
the reporting period.

    (iii) Records of deviations specified in paragraph (c)(5)(iii) of
this section that occurred during the reporting period.
    (iv) A statement that you have met the requirements specified in
Sec.  60.5410a(h)(2) and (3).
    (v) You must identify each storage vessel affected facility that is
removed from service during the reporting period as specified in Sec.
60.5395a(c)(1)(ii), including the date the storage vessel affected
facility was removed from service.
    (vi) You must identify each storage vessel affected facility
returned to service during the reporting period as specified in Sec.
60.5395a(c)(3), including the date the storage vessel affected facility
was returned to service.
    (vii) If complying with Sec.  60.5395a(a)(2) with a control device
tested under Sec.  60.5413a(d) which meets the criteria in Sec.
60.5413a(d)(11) and Sec.  60.5413a(e), records specified in paragraphs
(c)(5)(vi)(A) through (F) of this section for each storage vessel
constructed, modified, reconstructed or returned to service during the
reporting period.
    (7) For the collection of fugitive emissions components at each
well site and the collection of fugitive emissions components at each
compressor station within the company-defined area, the records of each
monitoring survey including the information specified in paragraphs
(b)(7)(i) through (xii) of this section. For the collection of fugitive
emissions components at a compressor station, if a monitoring survey is
waived under Sec.  60.5397a(g)(5), you must include in your annual
report the fact that a monitoring survey was waived and the calendar
months that make up the quarterly monitoring period for which the
monitoring survey was waived.
    (i) Date of the survey.
    (ii) Beginning and end time of the survey.
    (iii) Name of operator(s) performing survey. If the survey is
performed by optical gas imaging, you must note the training and
experience of the operator.
    (iv) Ambient temperature, sky conditions, and maximum wind speed at
the time of the survey.
    (v) Monitoring instrument used.
    (vi) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
    (vii) Number and type of components for which fugitive emissions
were detected.
    (viii) Number and type of fugitive emissions components that were
not repaired as required in Sec.  60.5397a(h).
    (ix) Number and type of difficult-to-monitor and unsafe-to-monitor
fugitive emission components monitored.
    (x) The date of successful repair of the fugitive emissions
component.
    (xi) Number and type of fugitive emission components placed on
delay of repair and explanation for each delay of repair.
    (xii) Type of instrument used to resurvey a repaired fugitive
emissions component that could not be repaired during the initial
fugitive emissions finding.
    (8) For each pneumatic pump affected facility, the information
specified in paragraphs (b)(8)(i) through (iii) of this section.
    (i) For each pneumatic pump that is constructed, modified or
reconstructed during the reporting period, you must provide
certification that the pneumatic pump meets one of the conditions
described in paragraphs (b)(8)(i)(A), (B) or (C) of this section.
    (A) No control device or process is available on site.
    (B) A control device or process is available on site and the owner
or operator has determined in accordance with Sec.  60.5393a(b)(5) that
it is technically infeasible to capture and route the emissions to the
control device or process.
    (C) Emissions from the pneumatic pump are routed to a control
device or process. If the control device is designed to achieve less
than 95 percent emissions reduction, specify the percent emissions
reductions the control device is designed to achieve.
    (ii) For any pneumatic pump affected facility which has been
previously reported as required under paragraph (b)(8)(i) of this
section and for which a change in the reported condition has occurred
during the reporting period, provide the identification of the
pneumatic pump affected facility and the date it was previously
reported and a certification that the pneumatic pump meets one of the
conditions described in paragraphs (b)(8)(ii)(A), (B) or (C) or (D) of
this section.
    (A) A control device has been added to the location and the
pneumatic pump now reports according to paragraph (b)(8)(i)(C) of this
section.
    (B) A control device has been added to the location and the
pneumatic pump affected facility now reports according to paragraph
(b)(8)(i)(B) of this section.
    (C) A control device or process has been removed from the location
or otherwise is no longer available and the pneumatic pump affected
facility now report according to paragraph (b)(8)(i)(A) of this
section.
    (D) A control device or process has been removed from the location
or is otherwise no longer available and the owner or operator has
determined in accordance with Sec.  60.5393a(b)(5) through an
engineering evaluation that it is technically infeasible to capture and
route the emissions to another control device or process.
    (iii) Records of deviations specified in paragraph (c)(16)(ii) of
this section that occurred during the reporting period.
    (9) Within 60 days after the date of completing each performance
test (see Sec.  60.8) required by this subpart, except testing
conducted by the manufacturer as specified in Sec.  60.5413a(d), you
must submit the results of the performance test following the procedure
specified in either paragraph (b)(9)(i) or (ii) of this section.
    (i) For data collected using test methods supported by the EPA's
Electronic Reporting Tool (ERT) as listed on the EPA's ERT Web site
(https://www3.epa.gov/ttn/chief/ert/ert_info.html) at the time of the
test, you must submit the results of the performance test to the EPA
via the Compliance and Emissions Data Reporting Interface (CEDRI).
(CEDRI can be accessed through the EPA's Central Data Exchange (CDX)
(https://cdx.epa.gov/).) Performance test data must be submitted in a
file format generated through the use of the EPA's ERT or an alternate
electronic file format consistent with the extensible markup language
(XML) schema listed on the EPA's ERT Web site. If you claim that some
of the performance test information being submitted is confidential
business information (CBI), you must submit a complete file generated
through the use of the EPA's ERT or an alternate electronic file
consistent with the XML schema listed on the EPA's ERT Web site,
including information claimed to be CBI, on a compact disc, flash
drive, or other commonly used electronic storage media to the EPA. The
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAQPS/CORE CBI Office, Attention: Group Leader, Measurement Policy
Group, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. The same ERT or
alternate file with the CBI omitted must be submitted to the EPA via
the EPA's CDX as described earlier in this paragraph.
    (ii) For data collected using test methods that are not supported
by the EPA's ERT as listed on the EPA's ERT Web site at the time of the
test, you must submit the results of the performance test to the
Administrator at the appropriate address listed in Sec.  60.4.

    (10) For combustion control devices tested by the manufacturer in
accordance with Sec.  60.5413a(d), an electronic copy of the
performance test results required by Sec.  60.5413a(d) shall be
submitted via email to<EMAIL_ADDRESS>unless the test results
for that model of combustion control device are posted at the following
Web site: epa.gov/airquality/oilandgas/.
    (11) You must submit reports to the EPA via the CEDRI. (CEDRI can
be accessed through the EPA's CDX (https://cdx.epa.gov/).) You must use
the appropriate electronic report in CEDRI for this subpart or an
alternate electronic file format consistent with the extensible markup
language (XML) schema listed on the CEDRI Web site (https://www3.epa.gov/ttn/chief/cedri/). If the reporting form specific to this
subpart is not available in CEDRI at the time that the report is due,
you must submit the report to the Administrator at the appropriate
address listed in Sec.  60.4. Once the form has been available in CEDRI
for at least 90 calendar days, you must begin submitting all subsequent
reports via CEDRI. The reports must be submitted by the deadlines
specified in this subpart, regardless of the method in which the
reports are submitted.
    (12) You must submit the certification signed by the qualified
professional engineer according to Sec.  60.5411a(d) for each closed
vent system routing to a control device or process.
    (c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec.  60.7(f) and in paragraphs (c)(1)
through (16) of this section. All records required by this subpart must
be maintained either onsite or at the nearest local field office for at
least 5 years. Any records required to be maintained by this subpart
that are submitted electronically via the EPA's CDX may be maintained
in electronic format.
    (1) The records for each well affected facility as specified in
paragraphs (c)(1)(i) through (vii) of this section, as applicable. For
each well affected facility for which you make a claim that the well
affected facility is not subject to the requirements for well
completions pursuant to 60.5375a(g), you must maintain the record in
paragraph (c)(1)(vi), only.
    (i) Records identifying each well completion operation for each
well affected facility;
    (ii) Records of deviations in cases where well completion
operations with hydraulic fracturing were not performed in compliance
with the requirements specified in Sec.  60.5375a.
    (iii) Records required in Sec.  60.5375a(b) or (f)(3) for each well
completion operation conducted for each well affected facility that
occurred during the reporting period. You must maintain the records
specified in paragraphs (c)(1)(iii)(A) through (C) of this section.
    (A) For each well affected facility required to comply with the
requirements of Sec.  60.5375a(a), you must record: The location of the
well; the United States Well Number; the date and time of the onset of
flowback following hydraulic fracturing or refracturing; the date and
time of each attempt to direct flowback to a separator as required in
Sec.  60.5375a(a)(1)(ii); the date and time of each occurrence of
returning to the initial flowback stage under Sec.  60.5375a(a)(1)(i);
and the date and time that the well was shut in and the flowback
equipment was permanently disconnected, or the startup of production;
the duration of flowback; duration of recovery and disposition of
recovery (i.e., routed to the gas flow line or collection system, re-
injected into the well or another well, used as an onsite fuel source,
or used for another useful purpose that a purchased fuel or raw
material would serve); duration of combustion; duration of venting; and
specific reasons for venting in lieu of capture or combustion. The
duration must be specified in hours. In addition, for wells where it is
technically infeasible to route the recovered gas to any of the four
options specified in Sec.  60.5375a(a)(1)(ii), you must record the
reasons for the claim of technical infeasibility with respect to all
four options provided in that subparagraph, including but not limited
to; name and location of the nearest gathering line and technical
considerations preventing routing to this line; capture, reinjection,
and reuse technologies considered and aspects of gas or equipment
preventing use of recovered gas as a fuel onsite; and technical
considerations preventing use of recovered gas for other useful purpose
that that a purchased fuel or raw material would serve.
    (B) For each well affected facility required to comply with the
requirements of Sec.  60.5375a(f), you must maintain the records
specified in paragraph (c)(1)(iii)(A) of this section except that you
do not have to record the duration of recovery to the flow line.
    (C) For each well affected facility for which you make a claim that
it meets the criteria of Sec.  60.5375a(a)(1)(iii)(A), you must
maintain the following:
    (1) Records specified in paragraph (c)(1)(iii)(A) of this section
except that you do not have to record: The date and time of each
attempt to direct flowback to a separator; the date and time of each
occurrence of returning to the initial flowback stage; duration of
recovery and disposition of recovery (i.e. routed to the gas flow line
or collection system, re-injected into the well or another well, used
as an onsite fuel source, or used for another useful purpose that a
purchased fuel or raw material would serve.
    (2) If applicable, records that the conditions of Sec.
60.5375a(1)(iii)(A) are no longer met and that the well completion
operation has been stopped and a separator installed. The records shall
include the date and time the well completion operation was stopped and
the date and time the separator was installed.
    (3) A record of the claim signed by the certifying official that no
liquids collection is at the well site. The claim must include a
certification by a certifying official of truth, accuracy and
completeness. This certification shall state that, based on information
and belief formed after reasonable inquiry, the statements and
information in the document are true, accurate, and complete.
    (iv) For each well affected facility for which you claim an
exception under Sec.  60.5375a(a)(3), you must record: The location of
the well; the United States Well Number; the specific exception
claimed; the starting date and ending date for the period the well
operated under the exception; and an explanation of why the well meets
the claimed exception.
    (v) For each well affected facility required to comply with both
Sec.  60.5375a(a)(1) and (3), if you are using a digital photograph in
lieu of the records required in paragraphs (c)(1)(i) through (iv) of
this section, you must retain the records of the digital photograph as
specified in Sec.  60.5410a(a)(4).
    (vi) For each well affected facility for which you make a claim
that the well affected facility is not subject to the well completion
standards according to 60.5375a(g), you must maintain:
    (A) A record of the analysis that was performed in order the make
that claim, including but not limited to, GOR values for established
leases and data from wells in the same basin and field;
    (B) The location of the well; the United States Well Number;
    (C) A record of the claim signed by the certifying official. The
claim must include a certification by a certifying official of truth,
accuracy, and completeness. This certification shall state that, based
on information and belief formed after reasonable inquiry, the
statements and information in the

document are true, accurate, and complete.
    (vii) For each well affected facility for which you determine
according to Sec.  60.5432a that it is a low pressure well, a record of
the determination and supporting inputs and calculations.
    (2) For each centrifugal compressor affected facility, you must
maintain records of deviations in cases where the centrifugal
compressor was not operated in compliance with the requirements
specified in Sec.  60.5380a. Except as specified in paragraph
(c)(2)(vii) of this section, you must maintain the records in
paragraphs (c)(2)(i) through (vi) of this section for each control
device tested under Sec.  60.5413a(d) which meets the criteria in Sec.
60.5413a(d)(11) and Sec.  60.5413a(e) and used to comply with Sec.
60.5380a(a)(1) for each centrifugal compressor.
    (i) Make, model and serial number of purchased device.
    (ii) Date of purchase.
    (iii) Copy of purchase order.
    (iv) Location of the centrifugal compressor and control device in
latitude and longitude coordinates in decimal degrees to an accuracy
and precision of five (5) decimals of a degree using the North American
Datum of 1983.
    (v) Inlet gas flow rate.
    (vi) Records of continuous compliance requirements in Sec.
60.5413a(e) as specified in paragraphs (c)(2)(vi)(A) through (E) of
this section.
    (A) Records that the pilot flame is present at all times of
operation.
    (B) Records that the device was operated with no visible emissions
except for periods not to exceed a total of 1 minute during any 15
minute period.
    (C) Records of the maintenance and repair log.
    (D) Records of the visible emissions test following return to
operation from a maintenance or repair activity.
    (E) Records of the manufacturer's written operating instructions,
procedures and maintenance schedule to ensure good air pollution
control practices for minimizing emissions.
    (vii) As an alternative to the requirements of paragraph (c)(2)(iv)
of this section, you may maintain records of one or more digital
photographs with the date the photograph was taken and the latitude and
longitude of the centrifugal compressor and control device imbedded
within or stored with the digital file. As an alternative to imbedded
latitude and longitude within the digital photograph, the digital
photograph may consist of a photograph of the centrifugal compressor
and control device with a photograph of a separately operating GPS
device within the same digital picture, provided the latitude and
longitude output of the GPS unit can be clearly read in the digital
photograph.
    (3) For each reciprocating compressor affected facility, you must
maintain the records in paragraphs (c)(3)(i) through (iii) of this
section.
    (i) Records of the cumulative number of hours of operation or
number of months since initial startup or the previous replacement of
the reciprocating compressor rod packing, whichever is later.
Alternatively, a statement that emissions from the rod packing are
being routed to a process through a closed vent system under negative
pressure.
    (ii) Records of the date and time of each reciprocating compressor
rod packing replacement, or date of installation of a rod packing
emissions collection system and closed vent system as specified in
Sec.  60.5385a(a)(3).
    (iii) Records of deviations in cases where the reciprocating
compressor was not operated in compliance with the requirements
specified in Sec.  60.5385a.
    (4) For each pneumatic controller affected facility, you must
maintain the records identified in paragraphs (c)(4)(i) through (v) of
this section, as applicable.
    (i) Records of the date, location and manufacturer specifications
for each pneumatic controller constructed, modified or reconstructed.
    (ii) Records of the demonstration that the use of pneumatic
controller affected facilities with a natural gas bleed rate greater
than the applicable standard are required and the reasons why.
    (iii) If the pneumatic controller is not located at a natural gas
processing plant, records of the manufacturer's specifications
indicating that the controller is designed such that natural gas bleed
rate is less than or equal to 6 standard cubic feet per hour.
    (iv) If the pneumatic controller is located at a natural gas
processing plant, records of the documentation that the natural gas
bleed rate is zero.
    (v) Records of deviations in cases where the pneumatic controller
was not operated in compliance with the requirements specified in Sec.
60.5390a.
    (5) For each storage vessel affected facility, you must maintain
the records identified in paragraphs (c)(5)(i) through (vi) of this
section.
    (i) If required to reduce emissions by complying with Sec.
60.5395a(a)(2), the records specified in Sec. Sec.  60.5420a(c)(6)
through (8), 60.5416a(c)(6)(ii), and 60.5416a(c)(7)(ii). You must
maintain the records in paragraph (c)(5)(vi) of this part for each
control device tested under Sec.  60.5413a(d) which meets the criteria
in Sec.  60.5413a(d)(11) and Sec.  60.5413a(e) and used to comply with
Sec.  60.5395a(a)(2) for each storage vessel.
    (ii) Records of each VOC emissions determination for each storage
vessel affected facility made under Sec.  60.5365a(e) including
identification of the model or calculation methodology used to
calculate the VOC emission rate.
    (iii) Records of deviations in cases where the storage vessel was
not operated in compliance with the requirements specified in
Sec. Sec.  60.5395a, 60.5411a, 60.5412a, and 60.5413a, as applicable.
    (iv) For storage vessels that are skid-mounted or permanently
attached to something that is mobile (such as trucks, railcars, barges
or ships), records indicating the number of consecutive days that the
vessel is located at a site in the oil and natural gas production
segment, natural gas processing segment or natural gas transmission and
storage segment. If a storage vessel is removed from a site and, within
30 days, is either returned to the site or replaced by another storage
vessel at the site to serve the same or similar function, then the
entire period since the original storage vessel was first located at
the site, including the days when the storage vessel was removed, will
be added to the count towards the number of consecutive days.
    (v) You must maintain records of the identification and location of
each storage vessel affected facility.
    (vi) Except as specified in paragraph (c)(5)(vi)(G) of this
section, you must maintain the records specified in paragraphs
(c)(5)(vi)(A) through (F) of this section for each control device
tested under Sec.  60.5413a(d) which meets the criteria in Sec.
60.5413a(d)(11) and Sec.  60.5413a(e) and used to comply with Sec.
60.5395a(a)(2) for each storage vessel.
    (A) Make, model and serial number of purchased device.
    (B) Date of purchase.
    (C) Copy of purchase order.
    (D) Location of the control device in latitude and longitude
coordinates in decimal degrees to an accuracy and precision of five (5)
decimals of a degree using the North American Datum of 1983.
    (E) Inlet gas flow rate.
    (F) Records of continuous compliance requirements in Sec.
60.5413a(e) as specified in paragraphs (c)(5)(vi)(F)(1) through (5) of
this section.
    (1) Records that the pilot flame is present at all times of
operation.
    (2) Records that the device was operated with no visible emissions
except for periods not to exceed a total of 1 minute during any 15
minute period.

    (3) Records of the maintenance and repair log.
    (4) Records of the visible emissions test following return to
operation from a maintenance or repair activity.
    (5) Records of the manufacturer's written operating instructions,
procedures and maintenance schedule to ensure good air pollution
control practices for minimizing emissions.
    (G) As an alternative to the requirements of paragraph
(c)(5)(vi)(D) of this section, you may maintain records of one or more
digital photographs with the date the photograph was taken and the
latitude and longitude of the storage vessel and control device
imbedded within or stored with the digital file. As an alternative to
imbedded latitude and longitude within the digital photograph, the
digital photograph may consist of a photograph of the storage vessel
and control device with a photograph of a separately operating GPS
device within the same digital picture, provided the latitude and
longitude output of the GPS unit can be clearly read in the digital
photograph.
    (6) Records of each closed vent system inspection required under
Sec.  60.5416a(a)(1) and (2) for centrifugal compressors, reciprocating
compressors and pneumatic pumps, or Sec.  60.5416a(c)(1) for storage
vessels.
    (7) A record of each cover inspection required under Sec.
60.5416a(a)(3) for centrifugal or reciprocating compressors or Sec.
60.5416a(c)(2) for storage vessels.
    (8) If you are subject to the bypass requirements of Sec.
60.5416a(a)(4) for centrifugal compressors, reciprocating compressors
or pneumatic pumps, or Sec.  60.5416a(c)(3) for storage vessels, a
record of each inspection or a record of each time the key is checked
out or a record of each time the alarm is sounded.
    (9) If you are subject to the closed vent system no detectable
emissions requirements of Sec.  60.5416a(b) for centrifugal
compressors, reciprocating compressors or pneumatic pumps, a record of
the monitoring conducted in accordance with Sec.  60.5416a(b).
    (10) For each centrifugal compressor or pneumatic pump affected
facility, records of the schedule for carbon replacement (as determined
by the design analysis requirements of Sec.  60.5413a(c)(2) or (3)) and
records of each carbon replacement as specified in Sec.
60.5412a(c)(1).
    (11) For each centrifugal compressor affected facility subject to
the control device requirements of Sec.  60.5412a(a), (b), and (c),
records of minimum and maximum operating parameter values, continuous
parameter monitoring system data, calculated averages of continuous
parameter monitoring system data, results of all compliance
calculations, and results of all inspections.
    (12) For each carbon adsorber installed on storage vessel affected
facilities, records of the schedule for carbon replacement (as
determined by the design analysis requirements of Sec.  60.5412a(d)(2))
and records of each carbon replacement as specified in Sec.
60.5412a(c)(1).
    (13) For each storage vessel affected facility subject to the
control device requirements of Sec.  60.5412a(c) and (d), you must
maintain records of the inspections, including any corrective actions
taken, the manufacturers' operating instructions, procedures and
maintenance schedule as specified in Sec.  60.5417a(h)(3). You must
maintain records of EPA Method 22 of appendix A-7 of this part, section
11 results, which include: Company, location, company representative
(name of the person performing the observation), sky conditions,
process unit (type of control device), clock start time, observation
period duration (in minutes and seconds), accumulated emission time (in
minutes and seconds), and clock end time. You may create your own form
including the above information or use Figure 22-1 in EPA Method 22 of
appendix A-7 of this part. Manufacturer's operating instructions,
procedures and maintenance schedule must be available for inspection.
    (14) A log of records as specified in Sec.  60.5412a(d)(1)(iii),
for all inspection, repair and maintenance activities for each control
device failing the visible emissions test.
    (15) For each collection of fugitive emissions components at a well
site and each collection of fugitive emissions components at a
compressor station, the records identified in paragraphs (c)(15)(i)
through (iii) of this section.
    (i) The fugitive emissions monitoring plan as required in Sec.
60.5397a(b), (c), and (d).
    (ii) The records of each monitoring survey as specified in
paragraphs (c)(15)(ii)(A) through (I) of this section.
    (A) Date of the survey.
    (B) Beginning and end time of the survey.
    (C) Name of operator(s) performing survey. You must note the
training and experience of the operator.
    (D) Monitoring instrument used.
    (E) When optical gas imaging is used to perform the survey, one or
more digital photographs or videos, captured from the optical gas
imaging instrument used for conduct of monitoring, of each required
monitoring survey being performed. The digital photograph must include
the date the photograph was taken and the latitude and longitude of the
collection of fugitive emissions components at a well site or
collection of fugitive emissions components at a compressor station
imbedded within or stored with the digital file. As an alternative to
imbedded latitude and longitude within the digital file, the digital
photograph or video may consist of an image of the monitoring survey
being performed with a separately operating GPS device within the same
digital picture or video, provided the latitude and longitude output of
the GPS unit can be clearly read in the digital image.
    (F) Fugitive emissions component identification when Method 21 is
used to perform the monitoring survey.
    (G) Ambient temperature, sky conditions, and maximum wind speed at
the time of the survey.
    (H) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
    (I) Documentation of each fugitive emission, including the
information specified in paragraphs (c)(15)(ii)(I)(1) through (12) of
this section.
    (1) Location.
    (2) Any deviations from the monitoring plan or a statement that
there were no deviations from the monitoring plan.
    (3) Number and type of components for which fugitive emissions were
detected.
    (4) Number and type of difficult-to-monitor and unsafe-to-monitor
fugitive emission components monitored.
    (5) Instrument reading of each fugitive emissions component that
requires repair when Method 21 is used for monitoring.
    (6) Number and type of fugitive emissions components that were not
repaired as required in Sec.  60.5397a(h).
    (7) Number and type of components that were tagged as a result of
not being repaired during the monitoring survey when the fugitive
emissions were initially found as required in Sec.  60.5397a(h)(3)(ii).
    (8) If a fugitive emissions component is not tagged, a digital
photograph or video of each fugitive emissions component that could not
be repaired during the monitoring survey when the fugitive emissions
were initially found as required in Sec.  60.5397a(h)(3)(ii). The
digital photograph or video must clearly identify the location of the
component that must be repaired. Any digital photograph or video
required under this paragraph can also be used to meet the requirements
under paragraph

(c)(15)(ii)(E) of this section, as long as the photograph or video is
taken with the optical gas imaging instrument, includes the date and
the latitude and longitude are either imbedded or visible in the
picture.
    (9) Repair methods applied in each attempt to repair the fugitive
emissions components.
    (10) Number and type of fugitive emission components placed on
delay of repair and explanation for each delay of repair.
    (11) The date of successful repair of the fugitive emissions
component.
    (12) Instrumentation used to resurvey a repaired fugitive emissions
component that could not be repaired during the initial fugitive
emissions finding.
    (iii) For the collection of fugitive emissions components at a
compressor station, if a monitoring survey is waived under Sec.
60.5397a(g)(5), you must maintain records of the average calendar month
temperature, including the source of the information, for each calendar
month of the quarterly monitoring period for which the monitoring
survey was waived.
    (16) For each pneumatic pump affected facility, you must maintain
the records identified in paragraphs (c)(16)(i) through (v) of this
section.
    (i) Records of the date, location and manufacturer specifications
for each pneumatic pump constructed, modified or reconstructed.
    (ii) Records of deviations in cases where the pneumatic pump was
not operated in compliance with the requirements specified in Sec.
60.5393a.
    (iii) Records on the control device used for control of emissions
from a pneumatic pump including the installation date, manufacturer's
specifications, and if the control device is designed to achieve less
than 95 percent emission reduction, a design evaluation or
manufacturer's specifications indicating the percentage reduction
achieved the control device is designed to achieve.
    (iv) Records substantiating a claim according to Sec.
60.5393a(b)(5) that it is technically infeasible to capture and route
emissions from a pneumatic pump to a control device or process;
including the qualified professional engineer certification according
to Sec.  60.5393a(b)(5)(ii)and the records of the engineering
assessment of technical infeasibility performed according to Sec.
60.5393a(b)(5)(iii).
    (v) You must retain copies of all certifications, engineering
assessments and related records for a period of five years and make
them available if directed by the implementing agency.
    (17) For each closed vent system routing to a control device or
process, the records of the assessment conducted according to Sec.
60.5411a(d):
    (i) A copy of the assessment conducted according to Sec.
60.5411a(d)(1);
    (ii) A copy of the certification according to Sec.
60.5411a(d)(1)(i); and
    (iii) The owner or operator shall retain copies of all
certifications, assessments and any related records for a period of
five years, and make them available if directed by the delegated
authority.

Sec.  60.5421a  What are my additional recordkeeping requirements for
my affected facility subject to GHG and VOC requirements for onshore
natural gas processing plants?

    (a) You must comply with the requirements of paragraph (b) of this
section in addition to the requirements of Sec.  60.486a.
    (b) The following recordkeeping requirements apply to pressure
relief devices subject to the requirements of Sec.  60.5401a(b)(1).
    (1) When each leak is detected as specified in Sec.
60.5401a(b)(2), a weatherproof and readily visible identification,
marked with the equipment identification number, must be attached to
the leaking equipment. The identification on the pressure relief device
may be removed after it has been repaired.
    (2) When each leak is detected as specified in Sec.
60.5401a(b)(2), the information specified in paragraphs (b)(2)(i)
through (x) of this section must be recorded in a log and shall be kept
for 2 years in a readily accessible location:
    (i) The instrument and operator identification numbers and the
equipment identification number.
    (ii) The date the leak was detected and the dates of each attempt
to repair the leak.
    (iii) Repair methods applied in each attempt to repair the leak.
    (iv) ``Above 500 ppm'' if the maximum instrument reading measured
by the methods specified in Sec.  60.5400a(d) after each repair attempt
is 500 ppm or greater.
    (v) ``Repair delayed'' and the reason for the delay if a leak is
not repaired within 15 calendar days after discovery of the leak.
    (vi) The signature of the owner or operator (or designate) whose
decision it was that repair could not be effected without a process
shutdown.
    (vii) The expected date of successful repair of the leak if a leak
is not repaired within 15 days.
    (viii) Dates of process unit shutdowns that occur while the
equipment is unrepaired.
    (ix) The date of successful repair of the leak.
    (x) A list of identification numbers for equipment that are
designated for no detectable emissions under the provisions of Sec.
60.482-4a(a). The designation of equipment subject to the provisions of
Sec.  60.482-4a(a) must be signed by the owner or operator.

Sec.  60.5422a  What are my additional reporting requirements for my
affected facility subject to GHG and VOC requirements for onshore
natural gas processing plants?

    (a) You must comply with the requirements of paragraphs (b) and (c)
of this section in addition to the requirements of Sec.  60.487a(a),
(b), (c)(2)(i) through (iv), and (c)(2)(vii) through (viii). You must
submit semiannual reports to the EPA via the Compliance and Emissions
Data Reporting Interface (CEDRI). (CEDRI can be accessed through the
EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).) Use the
appropriate electronic report in CEDRI for this subpart or an alternate
electronic file format consistent with the extensible markup language
(XML) schema listed on the CEDRI Web site (https://www3.epa.gov/ttn/chief/cedri/). If the reporting form specific to this subpart is not
available in CEDRI at the time that the report is due, submit the
report to the Administrator at the appropriate address listed in Sec.
60.4. Once the form has been available in CEDRI for at least 90 days,
you must begin submitting all subsequent reports via CEDRI. The report
must be submitted by the deadline specified in this subpart, regardless
of the method in which the report is submitted.
    (b) An owner or operator must include the following information in
the initial semiannual report in addition to the information required
in Sec.  60.487a(b)(1) through (4): Number of pressure relief devices
subject to the requirements of Sec.  60.5401a(b) except for those
pressure relief devices designated for no detectable emissions under
the provisions of Sec.  60.482-4a(a) and those pressure relief devices
complying with Sec.  60.482-4a(c).
    (c) An owner or operator must include the information specified in
paragraphs (c)(1) and (2) of this section in all semiannual reports in
addition to the information required in Sec.  60.487a(c)(2)(i) through
(vi):
    (1) Number of pressure relief devices for which leaks were detected
as required in Sec.  60.5401a(b)(2); and
    (2) Number of pressure relief devices for which leaks were not
repaired as required in Sec.  60.5401a(b)(3).

Sec.  60.5423a  What additional recordkeeping and reporting
requirements apply to my sweetening unit affected facilities at onshore
natural gas processing plants?

    (a) You must retain records of the calculations and measurements
required in Sec.  60.5405a(a) and (b) and Sec.  60.5407a(a) through (g)
for at least 2 years following the date of the measurements. This
requirement is included under Sec.  60.7(f) of the General Provisions.
    (b) You must submit a report of excess emissions to the
Administrator in your annual report if you had excess emissions during
the reporting period. The excess emissions report must be submitted to
the EPA via the Compliance and Emissions Data Reporting Interface
(CEDRI). (CEDRI can be accessed through the EPA's Central Data Exchange
(CDX) (https://cdx.epa.gov/).) You must use the appropriate electronic
report in CEDRI for this subpart or an alternate electronic file format
consistent with the extensible markup language (XML) schema listed on
the CEDRI Web site (https://www3.epa.gov/ttn/chief/cedri/). If the
reporting form specific to this subpart is not available in CEDRI at
the time that the report is due, you must submit the report to the
Administrator at the appropriate address listed in Sec.  60.4. Once the
form has been available in CEDRI for at least 90 days, you must begin
submitting all subsequent reports via CEDRI. The report must be
submitted by the deadline specified in this subpart, regardless of the
method in which the report is submitted. For the purpose of these
reports, excess emissions are defined as specified in paragraphs (b)(1)
and (2) of this section.
    (1) Any 24-hour period (at consistent intervals) during which the
average sulfur emission reduction efficiency (R) is less than the
minimum required efficiency (Z).
    (2) For any affected facility electing to comply with the
provisions of Sec.  60.5407a(b)(2), any 24-hour period during which the
average temperature of the gases leaving the combustion zone of an
incinerator is less than the appropriate operating temperature as
determined during the most recent performance test in accordance with
the provisions of Sec.  60.5407a(b)(3). Each 24-hour period must
consist of at least 96 temperature measurements equally spaced over the
24 hours.
    (c) To certify that a facility is exempt from the control
requirements of these standards, for each facility with a design
capacity less than 2 LT/D of H2S in the acid gas (expressed as sulfur)
you must keep, for the life of the facility, an analysis demonstrating
that the facility's design capacity is less than 2 LT/D of
H2S expressed as sulfur.
    (d) If you elect to comply with Sec.  60.5407a(e) you must keep,
for the life of the facility, a record demonstrating that the
facility's design capacity is less than 150 LT/D of H2S expressed as
sulfur.
    (e) The requirements of paragraph (b) of this section remain in
force until and unless the EPA, in delegating enforcement authority to
a state under section 111(c) of the Act, approves reporting
requirements or an alternative means of compliance surveillance adopted
by such state. In that event, affected sources within the state will be
relieved of obligation to comply with paragraph (b) of this section,
provided that they comply with the requirements established by the
state. Electronic reporting to the EPA cannot be waived, and as such,
the provisions of this paragraph do not relieve owners or operators of
affected facilities of the requirement to submit the electronic reports
required in this section to the EPA.

Sec.  60.5425a  What parts of the General Provisions apply to me?

    Table 3 to this subpart shows which parts of the General Provisions
in Sec. Sec.  60.1 through 60.19 apply to you.

Sec.  60.5430a  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein shall have
the meaning given them in the Act, in subpart A or subpart VVa of part
60; and the following terms shall have the specific meanings given
them.
    Acid gas means a gas stream of hydrogen sulfide (H2S)
and carbon dioxide (CO2) that has been separated from sour
natural gas by a sweetening unit.
    Alaskan North Slope means the approximately 69,000 square-mile area
extending from the Brooks Range to the Arctic Ocean.
    API Gravity means the weight per unit volume of hydrocarbon liquids
as measured by a system recommended by the American Petroleum Institute
(API) and is expressed in degrees.
    Artificial lift equipment means mechanical pumps including, but not
limited to, rod pumps and electric submersible pumps used to flowback
fluids from a well.
    Bleed rate means the rate in standard cubic feet per hour at which
natural gas is continuously vented (bleeds) from a pneumatic
controller.
    Capital expenditure means, in addition to the definition in 40 CFR
60.2, an expenditure for a physical or operational change to an
existing facility that exceeds P, the product of the facility's
replacement cost, R, and an adjusted annual asset guideline repair
allowance, A, as reflected by the following equation: P = R x A, where:
    (1) The adjusted annual asset guideline repair allowance, A, is the
product of the percent of the replacement cost, Y, and the applicable
basic annual asset guideline repair allowance, B, divided by 100 as
reflected by the following equation:

A = Y x (B / 100);

    (2) The percent Y is determined from the following equation: Y =
1.0 - 0.575 log x, where x is 2011 minus the year of construction; and
    (3) The applicable basic annual asset guideline repair allowance,
B, is 4.5.
    Centrifugal compressor means any machine for raising the pressure
of a natural gas by drawing in low pressure natural gas and discharging
significantly higher pressure natural gas by means of mechanical
rotating vanes or impellers. Screw, sliding vane, and liquid ring
compressors are not centrifugal compressors for the purposes of this
subpart.
    Certifying official means one of the following:
    (1) For a corporation: A president, secretary, treasurer, or vice-
president of the corporation in charge of a principal business
function, or any other person who performs similar policy or decision-
making functions for the corporation, or a duly authorized
representative of such person if the representative is responsible for
the overall operation of one or more manufacturing, production, or
operating facilities applying for or subject to a permit and either:
    (i) The facilities employ more than 250 persons or have gross
annual sales or expenditures exceeding $25 million (in second quarter
1980 dollars); or
    (ii) The Administrator is notified of such delegation of authority
prior to the exercise of that authority. The Administrator reserves the
right to evaluate such delegation;
    (2) For a partnership (including but not limited to general
partnerships, limited partnerships, and limited liability partnerships)
or sole proprietorship: A general partner or the proprietor,
respectively. If a general partner is a corporation, the provisions of
paragraph (1) of this definition apply;
    (3) For a municipality, State, Federal, or other public agency:
Either a principal executive officer or ranking elected official. For
the purposes of this part, a principal executive officer of a Federal
agency includes the chief

executive officer having responsibility for the overall operations of a
principal geographic unit of the agency (e.g., a Regional Administrator
of EPA); or
    (4) For affected facilities:
    (i) The designated representative in so far as actions, standards,
requirements, or prohibitions under title IV of the Clean Air Act or
the regulations promulgated thereunder are concerned; or
    (ii) The designated representative for any other purposes under
part 60.
    Collection system means any infrastructure that conveys gas or
liquids from the well site to another location for treatment, storage,
processing, recycling, disposal or other handling.
    Completion combustion device means any ignition device, installed
horizontally or vertically, used in exploration and production
operations to combust otherwise vented emissions from completions.
Completion combustion devices include pit flares.
    Compressor station means any permanent combination of one or more
compressors that move natural gas at increased pressure through
gathering or transmission pipelines, or into or out of storage. This
includes, but is not limited to, gathering and boosting stations and
transmission compressor stations. The combination of one or more
compressors located at a well site, or located at an onshore natural
gas processing plant, is not a compressor station for purposes of Sec.
60.5397a.
    Condensate means hydrocarbon liquid separated from natural gas that
condenses due to changes in the temperature, pressure, or both, and
remains liquid at standard conditions.
    Continuous bleed means a continuous flow of pneumatic supply
natural gas to a pneumatic controller.
    Crude oil and natural gas source category means:
    (1) Crude oil production, which includes the well and extends to
the point of custody transfer to the crude oil transmission pipeline or
any other forms of transportation; and
    (2) Natural gas production, processing, transmission, and storage,
which include the well and extend to, but do not include, the local
distribution company custody transfer station.
    Custody transfer means the transfer of crude oil or natural gas
after processing and/or treatment in the producing operations, or from
storage vessels or automatic transfer facilities or other such
equipment, including product loading racks, to pipelines or any other
forms of transportation.
    Dehydrator means a device in which an absorbent directly contacts a
natural gas stream and absorbs water in a contact tower or absorption
column (absorber).
    Delineation well means a well drilled in order to determine the
boundary of a field or producing reservoir.
    Deviation means any instance in which an affected source subject to
this subpart, or an owner or operator of such a source:
    (1) Fails to meet any requirement or obligation established by this
subpart including, but not limited to, any emission limit, operating
limit, or work practice standard;
    (2) Fails to meet any term or condition that is adopted to
implement an applicable requirement in this subpart and that is
included in the operating permit for any affected source required to
obtain such a permit; or
    (3) Fails to meet any emission limit, operating limit, or work
practice standard in this subpart during startup, shutdown, or
malfunction, regardless of whether or not such failure is permitted by
this subpart.
    Equipment, as used in the standards and requirements in this
subpart relative to the equipment leaks of GHG (in the form of methane)
and VOC from onshore natural gas processing plants, means each pump,
pressure relief device, open-ended valve or line, valve, and flange or
other connector that is in VOC service or in wet gas service, and any
device or system required by those same standards and requirements in
this subpart.
    Field gas means feedstock gas entering the natural gas processing
plant.
    Field gas gathering means the system used transport field gas from
a field to the main pipeline in the area.
    Flare means a thermal oxidation system using an open (without
enclosure) flame. Completion combustion devices as defined in this
section are not considered flares.
    Flow line means a pipeline used to transport oil and/or gas to a
processing facility or a mainline pipeline.
    Flowback means the process of allowing fluids and entrained solids
to flow from a well following a treatment, either in preparation for a
subsequent phase of treatment or in preparation for cleanup and
returning the well to production. The term flowback also means the
fluids and entrained solids that emerge from a well during the flowback
process. The flowback period begins when material introduced into the
well during the treatment returns to the surface following hydraulic
fracturing or refracturing. The flowback period ends when either the
well is shut in and permanently disconnected from the flowback
equipment or at the startup of production. The flowback period includes
the initial flowback stage and the separation flowback stage.
    Fugitive emissions component means any component that has the
potential to emit fugitive emissions of methane or VOC at a well site
or compressor station, including but not limited to valves, connectors,
pressure relief devices, open-ended lines, flanges, covers and closed
vent systems not subject to Sec.  60.5411a, thief hatches or other
openings on a controlled storage vessel not subject to Sec.  60.5395a,
compressors, instruments, and meters. Devices that vent as part of
normal operations, such as natural gas-driven pneumatic controllers or
natural gas-driven pumps, are not fugitive emissions components,
insofar as the natural gas discharged from the device's vent is not
considered a fugitive emission. Emissions originating from other than
the vent, such as the thief hatch on a controlled storage vessel, would
be considered fugitive emissions.
    Gas processing plant process unit means equipment assembled for the
extraction of natural gas liquids from field gas, the fractionation of
the liquids into natural gas products, or other operations associated
with the processing of natural gas products. A process unit can operate
independently if supplied with sufficient feed or raw materials and
sufficient storage facilities for the products.
    Gas to oil ratio (GOR) means the ratio of the volume of gas at
standard temperature and pressure that is produced from a volume of oil
when depressurized to standard temperature and pressure.
    Greenfield site means a site, other than a natural gas processing
plant, which is entirely new construction. Natural gas processing
plants are not considered to be greenfield sites, even if they are
entirely new construction.
    Hydraulic fracturing means the process of directing pressurized
fluids containing any combination of water, proppant, and any added
chemicals to penetrate tight formations, such as shale or coal
formations, that subsequently require high rate, extended flowback to
expel fracture fluids and solids during completions.
    Hydraulic refracturing means conducting a subsequent hydraulic
fracturing operation at a well that has previously undergone a
hydraulic fracturing operation.
    In light liquid service means that the piece of equipment contains
a liquid

that meets the conditions specified in Sec.  60.485a(e) or Sec.
60.5401a(f)(2).
    In wet gas service means that a compressor or piece of equipment
contains or contacts the field gas before the extraction step at a gas
processing plant process unit.
    Initial flowback stage means the period during a well completion
operation which begins at the onset of flowback and ends at the
separation flowback stage.
    Intermediate hydrocarbon liquid means any naturally occurring,
unrefined petroleum liquid.
    Intermittent/snap-action pneumatic controller means a pneumatic
controller that is designed to vent non-continuously.
    Liquefied natural gas unit means a unit used to cool natural gas to
the point at which it is condensed into a liquid which is colorless,
odorless, non-corrosive and non-toxic.
    Liquid collection system means tankage and/or lines at a well site
to contain liquids from one or more wells or to convey liquids to
another site.
    Local distribution company (LDC) custody transfer station means a
metering station where the LDC receives a natural gas supply from an
upstream supplier, which may be an interstate transmission pipeline or
a local natural gas producer, for delivery to customers through the
LDC's intrastate transmission or distribution lines.
    Low pressure well means a well that satisfies at least one of the
following conditions:
    (1) The static pressure at the wellhead following fracturing but
prior to the onset of flowback is less than the flow line pressure at
the sales meter;
    (2) The pressure of flowback fluid immediately before it enters the
flow line, as determined under Sec.  60.5432a, is less than the flow
line pressure at the sales meter; or
    (3) Flowback of the fracture fluids will not occur without the use
of artificial lift equipment.
    Maximum average daily throughput means the earliest calculation of
daily average throughput during the 30-day PTE evaluation period
employing generally accepted methods.
    Natural gas-driven diaphragm pump means a positive displacement
pump powered by pressurized natural gas that uses the reciprocating
action of flexible diaphragms in conjunction with check valves to pump
a fluid. A pump in which a fluid is displaced by a piston driven by a
diaphragm is not considered a diaphragm pump for purposes of this
subpart. A lean glycol circulation pump that relies on energy exchange
with the rich glycol from the contactor is not considered a diaphragm
pump.
    Natural gas-driven pneumatic controller means a pneumatic
controller powered by pressurized natural gas.
    Natural gas liquids means the hydrocarbons, such as ethane,
propane, butane, and pentane that are extracted from field gas.
    Natural gas processing plant (gas plant) means any processing site
engaged in the extraction of natural gas liquids from field gas,
fractionation of mixed natural gas liquids to natural gas products, or
both. A Joule-Thompson valve, a dew point depression valve, or an
isolated or standalone Joule-Thompson skid is not a natural gas
processing plant.
    Natural gas transmission means the pipelines used for the long
distance transport of natural gas (excluding processing). Specific
equipment used in natural gas transmission includes the land, mains,
valves, meters, boosters, regulators, storage vessels, dehydrators,
compressors, and their driving units and appurtenances, and equipment
used for transporting gas from a production plant, delivery point of
purchased gas, gathering system, storage area, or other wholesale
source of gas to one or more distribution area(s).
    Nonfractionating plant means any gas plant that does not
fractionate mixed natural gas liquids into natural gas products.
    Non-natural gas-driven pneumatic controller means an instrument
that is actuated using other sources of power than pressurized natural
gas; examples include solar, electric, and instrument air.
    Onshore means all facilities except those that are located in the
territorial seas or on the outer continental shelf.
    Pneumatic controller means an automated instrument used for
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature.
    Pressure vessel means a storage vessel that is used to store
liquids or gases and is designed not to vent to the atmosphere as a
result of compression of the vapor headspace in the pressure vessel
during filling of the pressure vessel to its design capacity.
    Process unit means components assembled for the extraction of
natural gas liquids from field gas, the fractionation of the liquids
into natural gas products, or other operations associated with the
processing of natural gas products. A process unit can operate
independently if supplied with sufficient feed or raw materials and
sufficient storage facilities for the products.
    Produced water means water that is extracted from the earth from an
oil or natural gas production well, or that is separated from crude
oil, condensate, or natural gas after extraction.
    Qualified Professional Engineer means an individual who is licensed
by a state as a Professional Engineer to practice one or more
disciplines of engineering and who is qualified by education, technical
knowledge and experience to make the specific technical certifications
required under this subpart. Professional engineers making these
certifications must be currently licensed in at least one state in
which the certifying official is located.
    Reciprocating compressor means a piece of equipment that increases
the pressure of a process gas by positive displacement, employing
linear movement of the driveshaft.
    Reciprocating compressor rod packing means a series of flexible
rings in machined metal cups that fit around the reciprocating
compressor piston rod to create a seal limiting the amount of
compressed natural gas that escapes to the atmosphere, or other
mechanism that provides the same function.
    Recovered gas means gas recovered through the separation process
during flowback.
    Recovered liquids means any crude oil, condensate or produced water
recovered through the separation process during flowback.
    Reduced emissions completion means a well completion following
fracturing or refracturing where gas flowback that is otherwise vented
is captured, cleaned, and routed to the gas flow line or collection
system, re-injected into the well or another well, used as an onsite
fuel source, or used for other useful purpose that a purchased fuel or
raw material would serve, with no direct release to the atmosphere.
    Reduced sulfur compounds means H2S, carbonyl sulfide
(COS), and carbon disulfide (CS2).
    Removed from service means that a storage vessel affected facility
has been physically isolated and disconnected from the process for a
purpose other than maintenance in accordance with Sec.  60.5395a(c)(1).
    Returned to service means that a storage vessel affected facility
that was removed from service has been:
    (1) Reconnected to the original source of liquids or has been used
to replace any storage vessel affected facility; or
    (2) Installed in any location covered by this subpart and
introduced with crude oil, condensate, intermediate hydrocarbon liquids
or produced water.

    Routed to a process or route to a process means the emissions are
conveyed via a closed vent system to any enclosed portion of a process
that is operational where the emissions are predominantly recycled and/
or consumed in the same manner as a material that fulfills the same
function in the process and/or transformed by chemical reaction into
materials that are not regulated materials and/or incorporated into a
product; and/or recovered.
    Salable quality gas means natural gas that meets the flow line or
collection system operator specifications, regardless of whether such
gas is sold.
    Separation flowback stage means the period during a well completion
operation when it is technically feasible for a separator to function.
The separation flowback stage ends either at the startup of production,
or when the well is shut in and permanently disconnected from the
flowback equipment.
    Startup of production means the beginning of initial flow following
the end of flowback when there is continuous recovery of salable
quality gas and separation and recovery of any crude oil, condensate or
produced water.
    Storage vessel means a tank or other vessel that contains an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water, and that is constructed primarily of
nonearthen materials (such as wood, concrete, steel, fiberglass, or
plastic) which provide structural support. A well completion vessel
that receives recovered liquids from a well after startup of production
following flowback for a period which exceeds 60 days is considered a
storage vessel under this subpart. A tank or other vessel shall not be
considered a storage vessel if it has been removed from service in
accordance with the requirements of Sec.  60.5395a(c)(1) until such
time as such tank or other vessel has been returned to service. For the
purposes of this subpart, the following are not considered storage
vessels:
    (1) Vessels that are skid-mounted or permanently attached to
something that is mobile (such as trucks, railcars, barges or ships),
and are intended to be located at a site for less than 180 consecutive
days. If you do not keep or are not able to produce records, as
required by Sec.  60.5420a(c)(5)(iv), showing that the vessel has been
located at a site for less than 180 consecutive days, the vessel
described herein is considered to be a storage vessel from the date the
original vessel was first located at the site. This exclusion does not
apply to a well completion vessel as described above.
    (2) Process vessels such as surge control vessels, bottoms
receivers or knockout vessels.
    (3) Pressure vessels designed to operate in excess of 204.9
kilopascals and without emissions to the atmosphere.
    Sulfur production rate means the rate of liquid sulfur accumulation
from the sulfur recovery unit.
    Sulfur recovery unit means a process device that recovers element
sulfur from acid gas.
    Surface site means any combination of one or more graded pad sites,
gravel pad sites, foundations, platforms, or the immediate physical
location upon which equipment is physically affixed.
    Sweetening unit means a process device that removes hydrogen
sulfide and/or carbon dioxide from the sour natural gas stream.
    Total Reduced Sulfur (TRS) means the sum of the sulfur compounds
hydrogen sulfide, methyl mercaptan, dimethyl sulfide, and dimethyl
disulfide as measured by Method 16 of appendix A-6 of this part.
    Total SO2 equivalents means the sum of volumetric or mass
concentrations of the sulfur compounds obtained by adding the quantity
existing as SO2 to the quantity of SO2 that would
be obtained if all reduced sulfur compounds were converted to
SO2 (ppmv or kg/dscm (lb/dscf)).
    Underground storage vessel means a storage vessel stored below
ground.
    Well means a hole drilled for the purpose of producing oil or
natural gas, or a well into which fluids are injected.
    Well completion means the process that allows for the flowback of
petroleum or natural gas from newly drilled wells to expel drilling and
reservoir fluids and tests the reservoir flow characteristics, which
may vent produced hydrocarbons to the atmosphere via an open pit or
tank.
    Well completion operation means any well completion with hydraulic
fracturing or refracturing occurring at a well affected facility.
    Well completion vessel means a vessel that contains flowback during
a well completion operation following hydraulic fracturing or
refracturing. A well completion vessel may be a lined earthen pit, a
tank or other vessel that is skid-mounted or portable. A well
completion vessel that receives recovered liquids from a well after
startup of production following flowback for a period which exceeds 60
days is considered a storage vessel under this subpart.
    Well site means one or more surface sites that are constructed for
the drilling and subsequent operation of any oil well, natural gas
well, or injection well. For purposes of the fugitive emissions
standards at Sec.  60.5397a, well site also means a separate tank
battery surface site collecting crude oil, condensate, intermediate
hydrocarbon liquids, or produced water from wells not located at the
well site (e.g., centralized tank batteries).
    Wellhead means the piping, casing, tubing and connected valves
protruding above the earth's surface for an oil and/or natural gas
well. The wellhead ends where the flow line connects to a wellhead
valve. The wellhead does not include other equipment at the well site
except for any conveyance through which gas is vented to the
atmosphere.
    Wildcat well means a well outside known fields or the first well
drilled in an oil or gas field where no other oil and gas production
exists.

Sec.  60.5432a  How do I determine whether a well is a low pressure
well using the low pressure well equation?

    (a) To determine that your well is a low pressure well subject to
Sec.  60.5375a(f), you must determine whether the characteristics of
the well are such that the well meets the definition of low pressure
well in Sec.  60.5430a. To determine that the well meets the definition
of low pressure well in Sec.  60.5430a, you must use the low pressure
well equation below:
[GRAPHIC] [TIFF OMITTED] TR03JN16.006

Where:

(1) PL is the pressure of flowback fluid immediately before it
enters the flow line, expressed in pounds force per square inch
(psia), and is to be calculated using the equation above;
(2) PR is the pressure of the reservoir containing oil, gas, and
water at the well site, expressed in psia;
(3) Lis the true vertical depth of the well, expressed in feet (ft);
(4) qo is the flow rate of oil in the well, expressed in cubic feet/
second (cu ft/sec);
(5) qg is the flow rate of gas in the well, expressed in cu ft/sec;
(6) qw is the flow rate of water in the well, expressed in cu ft/
sec;
(7) [rho]o is the density of oil in the well, expressed in pounds
mass per cubic feet (lbm/cu ft).
    (b) You must determine the four values in paragraphs (a)(4)
through (7) of this section, using the calculations in paragraphs
(b)(1) through (b)(15) of this section.

    (1) Determine the value of the bottom hole pressure, PBH (psia),
based on available information at the well site, or by calculating it
using the reservoir pressure, PR (psia), in the following equation:
[GRAPHIC] [TIFF OMITTED] TR03JN16.007

    (2) Determine the value of the bottom hole temperature, TBH (F),
based on available information at the well site, or by calculating it
using the true vertical depth of the well, L (ft), in the following
equation:

TBH (F) = (0.014 x L) + 79.081

    (3) Calculate the value of the applicable natural gas specific
gravity that would result from a separator pressure of 100 psig,
[gamma]gs, using the following equation with: Separator at standard
conditions (pressure, p = 14.7 (psia), temperature, T = 60 (F)); the
oil API gravity at the well site, [gamma]0; and the gas
specific gravity at the separator under standard conditions, [gamma]gp
= 0.75:
[GRAPHIC] [TIFF OMITTED] TR03JN16.008

    (4) Calculate the value of the applicable dissolved GOR, Rs (scf/
STBO), using the following equation with: The bottom hole pressure, PBH
(psia), determined in (b)(1) of this section; the bottom hole
temperature, TBH (F), determined in (b)(2) of this section; the gas
gravity at separator pressure of 100 psig, [gamma]gs, calculated in
(b)(3) of this section; the oil API gravity, [gamma]o, at the well
site; and the constants, C1, C2, and C3, found in Table A:
[GRAPHIC] [TIFF OMITTED] TR03JN16.009

            Table A--Coefficients for the correlation for Rs
------------------------------------------------------------------------
                                                  [gamma]API  [gamma]API
                    Constant                         <= 30       > 30
------------------------------------------------------------------------
C1..............................................      0.0362      0.0178
C2..............................................      1.0937      1.1870
C3..............................................     25.7240      23.931
------------------------------------------------------------------------

    (5) Calculate the value of the oil formation volume factor, Bo
(bbl/STBO), using the following equation with: the bottom hole
temperature, TBH (F), determined in paragraph (b)(2) of this section;
the gas gravity at separator pressure of 100 psig, [gamma]gs,
calculated in paragraph (b)(3) of this section; the dissolved GOR, Rs
(scf/STBO), calculated in paragraph (b)(4) of this section; the oil API
gravity, [gamma]o, at the well site; and the constants, C1, C2, and C3,
found in Table B:
[GRAPHIC] [TIFF OMITTED] TR03JN16.010

                                Table B--Coefficients for the Correlation for Bo
----------------------------------------------------------------------------------------------------------------
                           Constant                                 [gamma]API <= 30         [gamma]API > 30
----------------------------------------------------------------------------------------------------------------
C1............................................................            4.677 x 10 -4            4.670 x 10 -4
C2............................................................            1.751 x 10 -5            1.100 x 10 -5
C3............................................................           -1.811 x 10 -8            1.337 x 10 -9
----------------------------------------------------------------------------------------------------------------

[GRAPHIC] [TIFF OMITTED] TR03JN16.011

[GRAPHIC] [TIFF OMITTED] TR03JN16.012

    (10) Calculate the critical pressure, Pc (psia), and
critical temperature, Tc (R), using the equations below
with: Gas gravity at standard conditions (pressure, P = 14.7 (psia),
temperature, T = 60 (F)), [gamma] = 0.75; and where the mole fractions
of nitrogen, carbon dioxide and hydrogen sulfide in the gas are XN2 =
0.168225, XCO2 = 0.013163, and XH2S = 0.013680, respectively:

Pc(psia) = 678 - 50 [middot] ([gamma]g - 0.5) - 206.7 [middot] XN2 +
440 [middot] XCO2 + 606.7 [middot] XH2S
Tc(R) = 326 + 315.7 [middot] ([gamma]g - 0.5) - 240 [middot] XN2 - 88.3
[middot] XCO2 + 133.3 [middot] XH2S
    (11) Calculate reduced pressure, Pr, and reduced
temperature, Tr, using the following equations with: the
bottom hole pressure, PBH, as determined in paragraph (b)(1) of this
section; the bottom hole temperature, TBH (F), as determined in
paragraph (b)(2) of this section in the following equations:
[GRAPHIC] [TIFF OMITTED] TR03JN16.013

    (12)(i) Calculate the gas compressibility factor, Z, using the
following equation with the reduced pressure, Pr, calculated
in paragraph (b)(11) of this section:
[GRAPHIC] [TIFF OMITTED] TR03JN16.014

    (ii) The values for A, B, C, D in the above equation, are
calculated using the following equations with the reduced pressure,
Pr, and reduced temperature, Tr, calculated in
paragraph (b)(11) of this section:

[GRAPHIC] [TIFF OMITTED] TR03JN16.015

    (15) Calculate the flow rate of water in the well, qw (cu ft/sec),
using the following equation with the water production rate Qw (bbl/
day) at the well site:
[GRAPHIC] [TIFF OMITTED] TR03JN16.016

    Sec. Sec.  60.5433a-60.5499a [Reserved]

      Table 1 to Subpart OOOOa of Part 60--Required Minimum Initial SO2 Emission Reduction Efficiency (Zi)
----------------------------------------------------------------------------------------------------------------
                                                             Sulfur feed rate (X), LT/D
  H2S content of acid gas (Y), %   -----------------------------------------------------------------------------
                                     2.0 < X < 5.0      5.0 < X < 15.0       15.0 < X < 300.0       X > 300.0
----------------------------------------------------------------------------------------------------------------
Y > 50............................            79.0        88.51X0.0101Y0.0125 or 99.9, whichever is smaller.
----------------------------------------------------------------------------------------------------------------
20 < Y < 50.......................            79.0    88.51X0.0101Y0.0125 or 97.9, whichever is            97.9
                                                                       smaller
----------------------------------------------------------------------------------------------------------------
10 < Y < 20.......................            79.0   88.51X0.0101Y0.0125           93.5                    93.5
                                                      or 93.5, whichever
                                                      is smaller.
----------------------------------------------------------------------------------------------------------------
Y < 10............................            79.0           79.0                  79.0                    79.0
----------------------------------------------------------------------------------------------------------------

          Table 2 to Subpart OOOOa of Part 60--Required Minimum SO2 Emission Reduction Efficiency (Zc)
----------------------------------------------------------------------------------------------------------------
                                                             Sulfur feed rate (X), LT/D
  H2S content of acid gas (Y), %   -----------------------------------------------------------------------------
                                     2.0 < X < 5.0      5.0 < X < 15.0       15.0 < X < 300.0       X > 300.0
----------------------------------------------------------------------------------------------------------------
Y > 50............................            74.0        85.35X0.0144Y0.0128 or 99.9, whichever is smaller.
----------------------------------------------------------------------------------------------------------------
20 < Y < 50.......................            74.0    85.35X0.0144Y0.0128 or 97.5, whichever is            97.5
                                                                       smaller
----------------------------------------------------------------------------------------------------------------
10 < Y < 20.......................            74.0   85.35X0.0144Y0.0128           90.8                    90.8
                                                      or 90.8, whichever
                                                      is smaller.
----------------------------------------------------------------------------------------------------------------
Y < 10............................            74.0           74.0                  74.0                    74.0
----------------------------------------------------------------------------------------------------------------

    X = The sulfur feed rate from the sweetening unit (i.e., the
H2S in the acid gas), expressed as sulfur, Mg/D(LT/D),
rounded to one decimal place.
    Y = The sulfur content of the acid gas from the sweetening unit,
expressed as mole percent H2S (dry basis) rounded to one
decimal place.
    Z = The minimum required sulfur dioxide (SO2) emission
reduction efficiency, expressed as percent carried to one decimal
place. Zi refers to the reduction efficiency required at the
initial performance test. Zc refers to the reduction
efficiency required on a continuous basis after compliance with
Zi has been demonstrated.
    As stated in Sec.  60.5425a, you must comply with the following
applicable General Provisions:

            Table 3 to Subpart OOOOa of Part 60--Applicability of General Provisions to Subpart OOOOa
----------------------------------------------------------------------------------------------------------------
   General provisions  citation      Subject of citation         Applies to subpart?            Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1.......................  General applicability  Yes
                                     of the General
                                     Provisions.
Sec.   60.2.......................  Definitions..........  Yes...........................  Additional terms
                                                                                defined in Sec.
                                                                                60.5430a.
Sec.   60.3.......................  Units and              Yes
                                     abbreviations.
Sec.   60.4.......................  Address..............  Yes
Sec.   60.5.......................  Determination of       Yes
                                     construction or
                                     modification.
Sec.   60.6.......................  Review of plans......  Yes
Sec.   60.7.......................  Notification and       Yes...........................  Except that Sec.
                                     record keeping.                                        60.7 only applies as
                                                                                specified in Sec.
                                                                                60.5420a(a).
Sec.   60.8.......................  Performance tests....  Yes...........................  Performance testing
                                                                                is required for
                                                                                control devices used
                                                                                on storage vessels,
                                                                                centrifugal
                                                                                compressors and
                                                                                pneumatic pumps.
Sec.   60.9.......................  Availability of        Yes
                                     information.
Sec.   60.10......................  State authority......  Yes
Sec.   60.11......................  Compliance with        No............................  Requirements are
                                     standards and                                          specified in subpart
                                     maintenance                                            OOOOa.
                                     requirements.
Sec.   60.12......................  Circumvention........  Yes
Sec.   60.13......................  Monitoring             Yes...........................  Continuous monitors
                                     requirements.                                          are required for
                                                                                storage vessels.
Sec.   60.14......................  Modification.........  Yes...........................  To the extent any
                                                                                provision in Sec.
                                                                                60.14 conflicts with
                                                                                specific provisions
                                                                                in subpart OOOOa, it
                                                                                is superseded by
                                                                                subpart OOOOa
                                                                                provisions.
Sec.   60.15......................  Reconstruction.......  Yes...........................  Except that Sec.
                                                                                60.15(d) does not
                                                                                apply to wells,
                                                                                pneumatic
                                                                                controllers,
                                                                                pneumatic pumps,
                                                                                centrifugal
                                                                                compressors,
                                                                                reciprocating
                                                                                compressors or
                                                                                storage vessels.
Sec.   60.16......................  Priority list........  Yes
Sec.   60.17......................  Incorporations by      Yes
                                     reference.
Sec.   60.18......................  General control        Yes
                                     device and work
                                     practice
                                     requirements.

Sec.   60.19......................  General notification   Yes
                                     and reporting
                                     requirement.
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2016-11971 Filed 6-2-16; 8:45 am]
 BILLING CODE 6560-50-P