access hatches, gauge wells, etc.) and can be opened to the atmosphere.
    (ii) You must initially conduct the inspections specified in
paragraph (a)(3)(i) of this section following the installation of the
cover. Thereafter, you must perform the inspection at least once every
calendar year, except as provided in paragraphs (e) and (f) of this
section. You must maintain records of the inspection results as
specified in Sec.  60.5420(c)(7).
    (4) For each bypass device, except as provided for in Sec.
60.5411, you must meet the requirements of paragraphs (a)(4)(i) or (ii)
of this section.
    (i) Set the flow indicator to take a reading at least once every 15
minutes at the inlet to the bypass device that could divert the steam
away from the control device to the atmosphere.
    (ii) If the bypass device valve installed at the inlet to the
bypass device is secured in the non-diverting position using a car-seal
or a lock-and-key type configuration, visually inspect the seal or
closure mechanism at least once every month to verify that the valve is
maintained in the non-diverting position and the vent stream is not
diverted through the bypass device. You must maintain records of the
inspections according to Sec.  60.5420(c)(8).
    (b) No detectable emissions test methods and procedures. If you are
required to conduct an inspection of a closed vent system or cover at
your storage vessel or centrifugal compressor affected facility as
specified in paragraphs (a)(1), (2), or (3) of this section, you must
meet the requirements of paragraphs (b)(1) through (13) of this
section.
    (1) You must conduct the no detectable emissions test procedure in
accordance with Method 21 at 40 CFR part 60, appendix A-7.
    (2) The detection instrument must meet the performance criteria of
Method 21 at 40 CFR part 60, appendix A-7, except that the instrument
response factor criteria in section 3.1.2(a) of Method 21 must be for
the average composition of the fluid and not for each individual
organic compound in the stream.
    (3) You must calibrate the detection instrument before use on each
day of its use by the procedures specified in Method 21 at 40 CFR part
60, appendix A-7.
    (4) Calibration gases must be as specified in paragraphs (b)(4)(i)
and (ii) of this section.
    (i) Zero air (less than 10 parts per million by volume hydrocarbon
in air).
    (ii) A mixture of methane in air at a concentration less than
10,000 parts per million by volume.
    (5) You may choose to adjust or not adjust the detection instrument
readings to account for the background organic concentration level. If
you choose to adjust the instrument readings for the background level,
you must determine the background level value according to the
procedures in Method 21 at 40 CFR part 60, appendix A-7.
    (6) Your detection instrument must meet the performance criteria
specified in paragraphs (b)(6)(i) and (ii) of this section.
    (i) Except as provided in paragraph (b)(6)(ii) of this section, the
detection instrument must meet the performance criteria of Method 21 at
40 CFR part 60, appendix A-7, except the instrument response factor
criteria in section 3.1.2(a) of Method 21 must be for the average
composition of the process fluid, not each individual volatile organic
compound in the stream. For

process streams that contain nitrogen, air, or other inerts that are
not organic hazardous air pollutants or volatile organic compounds, you
must calculate the average stream response factor on an inert-free
basis.
    (ii) If no instrument is available that will meet the performance
criteria specified in paragraph (b)(6)(i) of this section, you may
adjust the instrument readings by multiplying by the average response
factor of the process fluid, calculated on an inert-free basis, as
described in paragraph (b)(6)(i) of this section.
    (7) You must determine if a potential leak interface operates with
no detectable emissions using the applicable procedure specified in
paragraph (b)(7)(i) or (ii) of this section.
    (i) If you choose not to adjust the detection instrument readings
for the background organic concentration level, then you must directly
compare the maximum organic concentration value measured by the
detection instrument to the applicable value for the potential leak
interface as specified in paragraph (b)(8) of this section.
    (ii) If you choose to adjust the detection instrument readings for
the background organic concentration level, you must compare the value
of the arithmetic difference between the maximum organic concentration
value measured by the instrument and the background organic
concentration value as determined in paragraph (b)(5) of this section
with the applicable value for the potential leak interface as specified
in paragraph (b)(8) of this section.
    (8) A potential leak interface is determined to operate with no
detectable organic emissions if the organic concentration value
determined in paragraph (b)(7) of this section is less than 500 parts
per million by volume.
    (9) Repairs. In the event that a leak or defect is detected, you
must repair the leak or defect as soon as practicable according to the
requirements of paragraphs (b)(9)(i) and (ii) of this section, except
as provided in paragraph (d) of this section.
    (i) A first attempt at repair must be made no later than 5 calendar
days after the leak is detected.
    (ii) Repair must be completed no later than 15 calendar days after
the leak is detected.
    (10) Delay of repair. Delay of repair of a closed vent system or
cover for which leaks or defects have been detected is allowed if the
repair is technically infeasible without a shutdown, or if you
determine that emissions resulting from immediate repair would be
greater than the fugitive emissions likely to result from delay of
repair. You must complete repair of such equipment by the end of the
next shutdown.
    (11) Unsafe to inspect requirements. You may designate any parts of
the closed vent system or cover as unsafe to inspect if the
requirements in paragraphs (e)(1) and (2) of this section are met.
Unsafe to inspect parts are exempt from the inspection requirements of
paragraphs (a)(1) through (3) of this section.
    (A) You determine that the equipment is unsafe to inspect because
inspecting personnel would be exposed to an imminent or potential
danger as a consequence of complying with paragraphs (a)(1), (2), or
(3) of this section.
    (B) You have a written plan that requires inspection of the
equipment as frequently as practicable during safe-to-inspect times.
    (12) Difficult to inspect requirements. You may designate any parts
of the closed vent system or cover as difficult to inspect, if the
requirements in paragraphs (b)(12)(i) and (ii) of this section are met.
Difficult to inspect parts are exempt from the inspection requirements
of paragraphs (a)(1) through (3) of this section.
    (i) You determine that the equipment cannot be inspected without
elevating the inspecting personnel more than 2 meters above a support
surface.
    (ii) You have a written plan that requires inspection of the
equipment at least once every 5 years.
    (13) Records. Records shall be maintained as specified in this
section and in Sec.  60.5420(c)(9).

Sec.  60.5417  What are the continuous control device monitoring
requirements for my storage vessel or centrifugal compressor affected
facility?

    You must meet the applicable requirements of this section to
demonstrate continuous compliance for each control device used to meet
emission standards for your storage vessel or centrifugal compressor
affected facility.
    (a) You must install and operate a continuous parameter monitoring
system for each control device as specified in paragraphs (c) through
(j) of this section, except as provided for in paragraph (b) of this
section. If you install and operate a flare in accordance with Sec.
60.5412(a)(3), you are exempt from the requirements of paragraphs (e)
and (f) of this section.
    (b) You are exempt from the monitoring requirements specified in
paragraphs (c) through (j) of this section for the control devices
listed in paragraphs (b)(1) and (2) of this section.
    (1) A boiler or process heater in which all vent streams are
introduced with the primary fuel or is used as the primary fuel.
    (2) A boiler or process heater with a design heat input capacity
equal to or greater than 44 megawatts.
    (c) You must design and operate the continuous monitoring system so
that a determination can be made on whether the control device is
achieving the applicable performance requirements of Sec.  60.5412. For
each continuous parameter monitoring system, you must meet the
specifications and requirements in paragraphs (c)(1) through (4) of
this section.
    (1) Each continuous parameter monitoring system must measure data
values at least once every hour and record the parameters in paragraphs
(c)(1)(i) or (ii) of this section.
    (i) Each measured data value.
    (ii) Each block average value for each 1-hour period or shorter
periods calculated from all measured data values during each period. If
values are measured more frequently than once per minute, a single
value for each minute may be used to calculate the hourly (or shorter
period) block average instead of all measured values.
    (2) You must prepare a site-specific monitoring plan that addresses
the monitoring system design, data collection, and the quality
assurance and quality control elements outlined in paragraphs (c)(2)(i)
through (v) of this section. You must install, calibrate, operate, and
maintain each continuous parameter monitoring system in accordance with
the procedures in your approved site-specific monitoring plan.
    (i) The performance criteria and design specifications for the
monitoring system equipment, including the sample interface, detector
signal analyzer, and data acquisition and calculations.
    (ii) Sampling interface (e.g., thermocouple) location such that the
monitoring system will provide representative measurements.
    (iii) Equipment performance checks, system accuracy audits, or
other audit procedures.
    (iv) Ongoing operation and maintenance procedures in accordance
with provisions in Sec.  60.13(b).
    (v) Ongoing reporting and recordkeeping procedures in accordance
with provisions in Sec.  60.7(c), (d), and (f).
    (3) You must conduct the continuous parameter monitoring system
equipment performance checks, system accuracy audits, or other audit
procedures specified in the site-specific monitoring plan at least once
every 12 months.
    (4) You must conduct a performance evaluation of each continuous
parameter monitoring system in

accordance with the site-specific monitoring plan.
    (d) You must install, calibrate, operate, and maintain a device
equipped with a continuous recorder to measure the values of operating
parameters appropriate for the control device as specified in either
paragraph (d)(1), (2), or (3) of this section.
    (1) A continuous monitoring system that measures the operating
parameters in paragraphs (d)(1)(i) through (viii) of this section, as
applicable.
    (i) For a thermal vapor incinerator that demonstrates during the
performance test conducted under Sec.  60.5413 that combustion zone
temperature is an accurate indicator of performance, a temperature
monitoring device equipped with a continuous recorder. The monitoring
device must have a minimum accuracy of 1 percent of the
temperature being monitored in [deg]C, or 2.5 [deg]C,
whichever value is greater. You must install the temperature sensor at
a location representative of the combustion zone temperature.
    (ii) For a catalytic vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The device must be capable
of monitoring temperature at two locations and have a minimum accuracy
of 1 percent of the temperature being monitored in [deg]C,
or 2.5 [deg]C, whichever value is greater. You must install
one temperature sensor in the vent stream at the nearest feasible point
to the catalyst bed inlet, and you must install a second temperature
sensor in the vent stream at the nearest feasible point to the catalyst
bed outlet.
    (iii) For a flare, a heat sensing monitoring device equipped with a
continuous recorder that indicates the continuous ignition of the pilot
flame.
    (iv) For a boiler or process heater, a temperature monitoring
device equipped with a continuous recorder. The temperature monitoring
device must have a minimum accuracy of 1 percent of the
temperature being monitored in [deg]C, or 2.5 [deg]C,
whichever value is greater. You must install the temperature sensor at
a location representative of the combustion zone temperature.
    (v) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device must have a
minimum accuracy of 1 percent of the temperature being
monitored in [deg]C, or 2.8 [deg]C, whichever value is
greater. You must install the temperature sensor at a location in the
exhaust vent stream from the condenser.
    (vi) For a regenerative-type carbon adsorption system, a continuous
monitoring system that meets the specifications in paragraphs
(d)(1)(vi)(A) and (B) of this section.
    (A) The continuous parameter monitoring system must measure and
record the average total regeneration stream mass flow or volumetric
flow during each carbon bed regeneration cycle. The flow sensor must
have a measurement sensitivity of 5 percent of the flow rate or 10
cubic feet per minute, whichever is greater. You must check the
mechanical connections for leakage at least every month, and you must
perform a visual inspection at least every 3 months of all components
of the flow continuous parameter monitoring system for physical and
operational integrity and all electrical connections for oxidation and
galvanic corrosion if your flow continuous parameter monitoring system
is not equipped with a redundant flow sensor; and
    (B) The continuous parameter monitoring system must measure and
record the average carbon bed temperature for the duration of the
carbon bed steaming cycle and measure the actual carbon bed temperature
after regeneration and within 15 minutes of completing the cooling
cycle. The temperature monitoring device must have a minimum accuracy
of 1 percent of the temperature being monitored in [deg]C,
or 2.5 [deg]C, whichever value is greater.
    (vii) For a nonregenerative-type carbon adsorption system, you must
monitor the design carbon replacement interval established using a
performance test performed as specified in Sec.  60.5413(b). The design
carbon replacement interval must be based on the total carbon working
capacity of the control device and source operating schedule.
    (viii) For a combustion control device whose model is tested under
Sec.  60.5413(d), a continuous monitoring system meeting the
requirements of paragraphs (d)(1)(viii)(A) and (B) 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.
    (B) A heat sensing monitoring device equipped with a continuous
recorder that indicates the continuous ignition of the pilot flame.
    (2) A continuous monitoring system that measures the concentration
level of organic compounds in the exhaust vent stream from the control
device using an organic monitoring device equipped with a continuous
recorder. The monitor must meet the requirements of Performance
Specification 8 or 9 of 40 CFR part 60, appendix B. 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. 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.  60.5412(a). 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.  60.5413(b) to demonstrate that the control device
achieves the applicable performance requirements specified in Sec.
60.5412(a), 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.  60.5413(c) to demonstrate that the control device
achieves the applicable performance requirements specified in Sec.
60.5412(a), 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.  60.5413(d) to demonstrate that the
control device achieves the applicable performance requirements
specified in Sec.  60.5412(a), then you must establish the maximum
inlet gas flow rate based on the performance test and supplemented, as
necessary, by the manufacturer recommendations.
    (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.  60.5413(b) to demonstrate that the condenser
achieves the applicable performance requirements in Sec.  60.5412(a),
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.  60.5413(c)(1) to demonstrate that the
condenser achieves the applicable performance requirements specified in
Sec.  60.5412(a), 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 (g)(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.
    (2) If you meet Sec.  60.5412(a)(2), a deviation occurs when the
365-day average condenser efficiency calculated according to the
requirements specified in Sec.  60.5415(e)(8)(iv) is less than 95.0
percent.
    (3) If you meet Sec.  60.5412(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.
60.5415(e)(8)(iv)(A) or (B) is less than 90.0 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 paragraphs (g)(5)(i) and (ii) of this section are met.
    (i) For each bypass line subject to Sec.  60.5411(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.  60.5411(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.  60.5413(d), a deviation occurs when the conditions of paragraphs
(g)(6)(i) or (ii) are met.
    (i) The inlet gas flow rate exceeds the maximum established during
the test conducted under Sec.  60.5413(d).
    (ii) Failure of the monthly visible emissions test conducted under
Sec.  60.5415(e)(7)(iii) occurs.

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

    (a) You must submit the notifications required in Sec.  60.7(a)(1)
and (4), and 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.  60.5365 that was constructed, modified, or reconstructed during
the reporting period.
    (1) If you own or operate a gas well, pneumatic controller or
storage vessel affected facility 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 gas 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 API
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 (6)
of this section to the Administrator and performance test reports as
specified in paragraph (b)(7) of this section. The initial annual
report is due 30 days after the end of the initial compliance period as
determined according to Sec.  60.5410. Subsequent annual reports are
due on the 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 (6)
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.
    (i) The company name and address of the affected facility.
    (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 responsible 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 gas well affected facility, the information in
paragraphs (b)(2)(i) through (ii) of this section.
    (i) Records of each well completion operation as specified in
paragraph (c)(1)(i) through (iv) of this section for each gas well
affected facility conducted during the reporting period. In lieu of
submitting the records specified in paragraph (c)(1)(i) through (iv),
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.
    (3) For each centrifugal compressor affected facility, the
information specified in paragraphs (b)(3)(i) and (ii) 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.  60.5380(a)(1), the records
of closed vent system and cover inspections specified in paragraph
(c)(6) of this section.
    (4) For each reciprocating compressor affected facility, the
information specified in paragraphs (b)(4)(i) through (ii) of this
section.
    (i) The cumulative number of hours or operation or the number of
months since initial startup, October 15, 2012, or since the previous
reciprocating compressor rod packing replacement, whichever is later.
    (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 (v) 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.  60.5390(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 (iii) of this section.
    (i) An identification of each storage vessel with VOC emissions
greater than 6 tpy constructed, modified or reconstructed during the
reporting period.
    (ii) Documentation that the VOC emission rate is less than 6 tpy
for meeting the requirements in Sec.  60.5395(a).
    (iii) Records of deviations specified in paragraph (c)(5)(iii) of
this section that occurred during the reporting period.
    (7)(i) Within 60 days after the date of completing each performance
test (see Sec.  60.8 of this part) as required by this subpart you must
submit the results of the performance tests required by this subpart to
EPA's WebFIRE database by using the Compliance and Emissions Data
Reporting Interface (CEDRI) that is accessed through EPA's Central Data
Exchange (CDX) (www.epa.gov/cdx). Performance test data must be
submitted in the file format generated through use of EPA's Electronic
Reporting Tool (ERT) (see http://www.epa.gov/ttn/chief/ert/index.html).
Only data collected using test methods on the ERT Web site are subject
to this requirement for submitting reports electronically to WebFIRE.
Owners or operators who claim that some of the information being
submitted for performance tests is confidential business information
(CBI) must submit a complete ERT file including information claimed to
be CBI on a compact disk or other commonly used electronic storage
media (including, but not limited to, flash drives) to EPA. The
electronic media must be clearly marked as CBI and mailed to U.S. EPA/
OAPQS/CORE CBI Office, Attention: WebFIRE Administrator, MD C404-02,
4930 Old Page Rd., Durham, NC 27703. The same ERT file with the CBI
omitted must be submitted to EPA via CDX as described earlier in this
paragraph. At the discretion of the delegated authority, you must also
submit these reports, including the confidential business information,
to the delegated authority in the format specified by the delegated
authority.
    (ii) All reports required by this subpart not subject to the
requirements in paragraph (a)(2)(i) of this section must be sent to the
Administrator at the appropriate address listed in Sec.  63.13 of this
part. The Administrator or the delegated authority may request a report
in any form suitable for the specific case (e.g., by commonly used
electronic media such as Excel spreadsheet, on CD or hard copy). The
Administrator retains the right to require submittal of reports subject
to paragraph (a)(2)(i) and (ii) of this section in paper format.
    (c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec.  60.7(f) and in paragraphs (c)(1)
through (10) of this section. All records must be maintained for at
least 5 years.
    (1) The records for each gas well affected facility as specified in
paragraphs (c)(1)(i) through (v) of this section.
    (i) Records identifying each well completion operation for each gas
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.  60.5375.
    (iii) Records required in Sec.  60.5375(b) or (f) for each well
completion operation conducted for each gas well affected facility that
occurred during the reporting period. You must maintain the records
specified in paragraphs (c)(1)(iii)(A) and (B) of this section.
    (A) For each gas well affected facility required to comply with the
requirements of Sec.  60.5375(a), you must record: The location of the
well; the API well number; the duration of flowback; duration of
recovery to the flow line; duration of combustion; duration of venting;
and specific reasons for venting in lieu of capture or combustion. The
duration must be specified in hours of time.
    (B) For each gas well affected facility required to comply with the
requirements of Sec.  60.5375(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.
    (iv) For each gas well facility for which you claim an exception
under Sec.  60.5375(a)(3), you must record: The location of the well;
the API 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 gas well affected facility required to comply with
both Sec.  60.5375(a)(1) and (3), records of the digital photograph as
specified in Sec.  60.5410(a)(4).
    (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.  60.5380.
    (3) For each reciprocating compressors 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 October 15, 2012, or the
previous replacement of the reciprocating compressor rod packing,
whichever is later.
    (ii) Records of the date and time of each reciprocating compressor
rod packing replacement.
    (iii) Records of deviations in cases where the reciprocating
compressor was not operated in compliance with the requirements
specified in Sec.  60.5385.
    (4) For each pneumatic controller affected facility, you must
maintain the records identified in paragraphs (c)(4)(i) through (v) of
this section.
    (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 6 standard cubic feet per hour 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.
60.5390.
    (5) For each storage vessel affected facility, you must maintain
the records identified in paragraphs (c)(5)(i) through (iv) of this
section.
    (i) If required to reduce emissions by complying with Sec.
60.5395, the records specified in Sec.  60.5416 of this subpart.
    (ii) Records of the determination that the VOC emission rate is
less than 6 tpy per storage vessel for the exemption under Sec.
60.5395(a), 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.  60.5395, 60.5411, 60.5412, and 60.5413.
    (iv) For 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 vessel is removed from a site and, within 30 days, is
either returned to or replaced by another vessel at the site to serve
the same or similar function, then the entire period since the original
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.
    (6) For each storage vessel or centrifugal compressor subject to
the closed vent system inspection requirements of Sec.  60.5416(a)(1)
and (2), records of each inspection.
    (7) For each storage vessel or centrifugal compressor subject to
the cover requirements of Sec.  60.5416(a)(3), a record of each
inspection.
    (8) For each storage vessel or centrifugal compressor subject to
the bypass requirements of Sec.  60.5416(a)(4), a record of each
inspection or a record each time the key is checked out or a record of
each time the alarm is sounded.
    (9) For each closed vent system used to comply with this subpart
that must operate with no detectable emissions, a record of the
monitoring conducted in accordance with Sec.  60.5416(b)(13).
    (10) Records of the schedule for carbon replacement (as determined
by the design analysis requirements of Sec.  60.5413(c)(2) or (3)) and
records of each carbon replacement as specified in Sec.  60.5412(c)(1).
    (11) For each storage vessel or centrifugal compressor subject to
the control device requirements of Sec.  60.5412, 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.

Sec.  60.5421  What are my additional recordkeeping requirements for my
affected facility subject to 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.  60.5401(b)(1) of
this subpart.
    (1) When each leak is detected as specified in Sec.  60.5401(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.  60.5401(b)(2),
the following information 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 paragraph (a) of this section 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.  60.5422  What are my additional reporting requirements for my
affected facility subject to 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).
    (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.  60.5401(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 following information 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.  60.5401(b)(2); and
    (2) Number of pressure relief devices for which leaks were not
repaired as required in Sec.  60.5401(b)(3).

Sec.  60.5423  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.  60.5405(a) and (b) and Sec.  60.5407(a) through (g)
for at least 2 years following the date of the measurements. This
requirement is included under Sec.  60.7(d) 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. For the purpose of these reports, excess
emissions are defined as:
    (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.  60.5407(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.  60.5407(b)(2). 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 that 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.  60.5407(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.

Sec.  60.5425  What part 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.  60.5430  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.
    Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding.
    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.
    Bleed rate means the rate in standard cubic feet per hour at which
natural gas is continuously vented (bleeds) from a pneumatic
controller.
    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.
    City gate means the delivery point at which natural gas is
transferred from a transmission pipeline to the local gas utility.
    Completion combustion device means any ignition device, installed
horizontally or vertically, used in exploration and production
operations to combust otherwise vented emissions from completions.
    Compressor station means any permanent combination of one or more
compressors that move natural gas at increased pressure from fields, in
transmission pipelines, or into storage.
    Continuous bleed means a continuous flow of pneumatic supply
natural gas to the process control device (e.g., level control,
temperature control, pressure control) where the supply gas pressure is
modulated by the process condition, and then flows to the valve
controller where the signal is compared with the process set-point to
adjust gas pressure in the valve actuator.
    Custody transfer means the transfer of 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).
    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.
    Delineation well means a well drilled in order to determine the
boundary of a field or producing reservoir.
    Equipment 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 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 from
the well to a processing facility, a mainline pipeline, re-injection,
or other useful purpose.
    Flowback means the process of allowing fluids to flow from a
natural

gas 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 flowback period begins when material introduced into
the well during the treatment returns to the surface immediately
following hydraulic fracturing or refracturing. The flowback period
ends with either well shut in or when the well is producing
continuously to the flow line or to a storage vessel for collection,
whichever occurs first.
    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 well or natural gas well means an onshore well drilled
principally for production of natural gas.
    Hydraulic fracturing or refracturing 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.  60.5401(g)(2) of this part.
    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.
    Intermittent/snap-action pneumatic controller means a pneumatic
controller that vents 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.
    Low pressure gas well means a well with reservoir pressure and
vertical well depth such that 0.445 times the reservoir pressure (in
psia) minus 0.038 times the vertical well depth (in feet) minus 67.578
psia is less than the flow line pressure at the sales meter.
    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.
    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.
    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 flow line or collection system,
re-injected into the well or another well, used as an on-site 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).
    Responsible 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 delegation of authority to such representatives is
approved in advance by the permitting authority;
    (2) For a partnership or sole proprietorship: A general partner or
the proprietor, respectively;
    (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.

    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
unit 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 composition,
moisture, or other limits set by the purchaser of the natural gas,
regardless of whether such gas is sold.
    Storage vessel means a unit that is constructed primarily of
nonearthen materials (such as wood, concrete, steel, fiberglass, or
plastic) which provides structural support and is designed to contain
an accumulation of liquids or other materials. 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.  60.5420(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 since the
original vessel was first located at the site.
    (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 to part 60 of this
chapter.
    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 an oil or gas well, a hole drilled for the purpose of
producing oil or 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 gas well affected facility.
    Well site means one or more areas that are directly disturbed
during the drilling and subsequent operation of, or affected by,
production facilities directly associated with any oil well, gas well,
or injection well and its associated well pad.
    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.

       Table 1 to Subpart OOOO 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 <=                               15.0 < X <=
                                              5.0            5.0 < X <= 15.0           300.0         X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50...............................            79.0   88.51X\0.0101\Y\0.0125\ or 99.9, whichever is smaller.
                                                       ---------------------------------------------------------
20 <= Y < 50..........................            79.0       88.5X\0.0101\Y\0.0125\ or 97.9,                97.9
                                                                  whichever is smaller.
                                                       ------------------------------------------
10 <= Y < 20..........................            79.0  88.5X\0.0101\Y\0.0125\              93.5            93.5
                                                         or 97.9, whichever is
                                                         smaller.
Y < 10................................            79.0  79.0....................            79.0            79.0
----------------------------------------------------------------------------------------------------------------

           Table 2 to Subpart OOOO 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 <=                               15.0 < X <=
                                              5.0            5.0 < X <= 15.0           300.0         X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50...............................            74.0   85.35X\0.0144\Y\0.0128\ or 99.9, whichever is smaller.
                                                       ---------------------------------------------------------
20 <= Y < 50..........................            74.0      85.35X\0.0144\Y\0.0128\ or 97.9,                97.5
                                                                  whichever is smaller.
                                                       ---------------------------------------------------------
10 <= Y < 20..........................            74.0      85.35X\0.0144\Y\0.0128\ or 90.8,                90.8
                                                                  whichever is smaller.
                                                       ---------------------------------------------------------
Y < 10................................            74.0  74.0....................            74.0            74.0
----------------------------------------------------------------------------------------------------------------
E = The sulfur emission rate expressed as elemental sulfur, kilograms per hour (kg/hr) [pounds per hour (lb/
  hr)], rounded to one decimal place.
R = The sulfur emission reduction efficiency achieved in percent, carried to one decimal place.
S = The sulfur production rate, kilograms per hour (kg/hr) [pounds per hour (lb/hr)], rounded to one decimal
  place.

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.  60.5425, you must comply with the following
applicable General Provisions:

             Table 3 to Subpart OOOO of Part 60--Applicability of General Provisions to Subpart OOOO
----------------------------------------------------------------------------------------------------------------
General  provisions  citation     Subject of citation         Applies to  subpart?             Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1..................  General applicability of  Yes.                           ........................
                                the General Provisions.
Sec.   60.2..................  Definitions.............  Yes..........................  Additional terms defined
                                                                                in Sec.   60.5430.
Sec.   60.3..................  Units and abbreviations.  Yes.                           ........................
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 record   Yes..........................  Except that Sec.   60.7
                                keeping.                                                 only applies as
                                                                                specified in Sec.
                                                                                60.5420(a).
Sec.   60.8..................  Performance tests.......  Yes..........................  Performance testing is
                                                                                required for control
                                                                                devices used on storage
                                                                                vessels and centrifugal
                                                                                compressors.
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                                              OOOO.
                                requirements.
Sec.   60.12.................  Circumvention...........  Yes.                           ........................
Sec.   60.13.................  Monitoring requirements.  Yes..........................  Continuous monitors are
                                                                                required for storage
                                                                                vessels.
Sec.   60.14.................  Modification............  Yes.                           ........................
Sec.   60.15.................  Reconstruction..........  Yes.                           ........................
Sec.   60.16.................  Priority list...........  Yes.                           ........................
Sec.   60.17.................  Incorporations by         Yes.                           ........................
                                reference.
Sec.   60.18.................  General control device    Yes..........................  Except that Sec.   60.18
                                requirements.                                            does not apply to
                                                                                flares.
Sec.   60.19.................  General notification and  Yes.                           ........................
                                reporting requirement.
----------------------------------------------------------------------------------------------------------------

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

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

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

0
9. Section 63.14 is amended by:
0
a. Revising paragraphs (b) introductory text, (b)(28), and (b)(64);
0
b. Adding paragraphs (b)(73), (74), and (75); and
0
c. Revising paragraphs (i) introductory text and (i)(1) to read as
follows:

Sec.  63.14  Incorporations by reference.

* * * * *
    (b) The following materials are available for purchase from at
least one of the following addresses: American Society for Testing and
Materials (ASTM), 100 Barr Harbor Drive, Post Office Box C700, West
Conshohocken, PA 19428-2959, Telephone<PHONE_NUMBER>, and are also
available at the following Web site: http://www.astm.org; or ProQuest,
789 East Eisenhower Parkway, Ann Arbor, MI 48106-1346, Telephone (734)
761-4700, and are also available at the following Web site: http://www.proquest.com.
* * * * *
    (28) ASTM D6420-99 (Reapproved 2004), Standard Test Method for
Determination of Gaseous Organic Compounds by Direct Interface Gas
Chromatography-Mass Spectrometry (Approved October 1, 2004), IBR
approved for Sec. Sec.  60.485(g), 60.485a(g), 63.772(a), 63.772(e),
63.1282(a), 63.1282(d), 63.2351(b), 63.2354(b) and table 8 to subpart
HHHHHHH of this part.
* * * * *
    (64) ASTM D6522-00 (Reapproved 2005), Standard Test Method for
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen
Concentrations in Emissions from Natural Gas Fired Reciprocating
Engines, Combustion Turbines, Boilers, and Process Heaters Using
Portable Analyzers, approved October 1, 2005, IBR approved for table 4
to subpart ZZZZ of this part, table 5 to subpart DDDDD of this part,
table 4 to subpart JJJJJJ of this part and Sec. Sec.  63.772(e),
63.772(h), 63.1282(d) and 63.1282(g).
* * * * *
    (73) ASTM D1945-03 (Reapproved 2010) Standard Test Method for
Analysis of Natural Gas by Gas Chromatography (Approved January 1,
2010), IBR approved for Sec. Sec.  63.772(h) and 63.1282(g).
    (74) ASTM D3588-98 (Reapproved 2003) Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels (Approved May 10, 2003), IBR approved for Sec. Sec.
63.772(h) and 63.1282(g).
    (75) ASTM D4891-89 (Reapproved 2006) Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion (Approved June 1, 2006), IBR approved for Sec. Sec.
63.772(h) and 63.1282(g).
* * * * *
    (i) The following material is available for purchase from at least
one of the following addresses: American Society of Mechanical
Engineers (ASME), Three Park Avenue, New York, NY 10016-

5990, Telephone<PHONE_NUMBER>, and are also available at the following
Web site: http://www.asme.org; or HIS, Incorporated, 15 Inverness Way
East, Englewood, CO 80112, Telephone<PHONE_NUMBER>, and are also
available at the following Web site: http://global.ihs.com.
    (1) ANSI/ASME PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part
10, Instruments and Apparatus], issued August 31, 1981 IBR approved for
Sec. Sec.  63.309(k), 63.772(e), 63.772(h), 63.865(b), 63.1282(d),
63.1282(g), 63.3166(a), 63.3360(e), 63.3545(a), 63.3555(a), 63.4166(a),
63.4362(a), 63.4766(a), 63.4965(a), 63.5160(d), 63.9307(c), 63.9323(a),
63.11148(e), 63.11155(e), 63.11162(f), 63.11163(g), 63.11410(j),
63.11551(a) and 63.11646(a), 63.11945, table 5 to subpart DDDDD of this
part, table 4 to subpart JJJJJ of this part, table 5 to subpart UUUUU
of this part and table 1 to subpart ZZZZZ of this part.
* * * * *

Subpart HH--[Amended]

0
10. Section 63.760 is amended by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(i);
0
c. Revising paragraph (a)(1)(iii);
0
d. Revising paragraph (a)(2);
0
e. Revising paragraph (b)(1)(i);
0
f. Adding paragraph (c);
0
g. Revising paragraph (f) introductory text;
0
h. Revising paragraph (f)(1);
0
i. Revising paragraph (f)(2);
0
j. Adding paragraphs (f)(7), (f)(8), and (f)(9); and
0
k. Removing and reserving paragraph (g)(1).
    The revisions and additions read as follows:

Sec.  63.760  Applicability and designation of affected source.

    (a) * * *
    (1) Facilities that are major or area sources of hazardous air
pollutants (HAP) as defined in Sec.  63.761. Emissions for major source
determination purposes can be estimated using the maximum natural gas
or hydrocarbon liquid throughput, as appropriate, calculated in
paragraphs (a)(1)(i) through (iii) of this section. As an alternative
to calculating the maximum natural gas or hydrocarbon liquid
throughput, the owner or operator of a new or existing source may use
the facility's design maximum natural gas or hydrocarbon liquid
throughput to estimate the maximum potential emissions. Other means to
determine the facility's major source status are allowed, provided the
information is documented and recorded to the Administrator's
satisfaction in accordance with Sec.  63.10(b)(3). A facility that is
determined to be an area source, but subsequently increases its
emissions or its potential to emit above the major source levels, and
becomes a major source, must comply thereafter with all provisions of
this subpart applicable to a major source starting on the applicable
compliance date specified in paragraph (f) of this section. Nothing in
this paragraph is intended to preclude a source from limiting its
potential to emit through other appropriate mechanisms that may be
available through the permitting authority.
    (i) If the owner or operator documents, to the Administrator's
satisfaction, a decline in annual natural gas or hydrocarbon liquid
throughput, as appropriate, each year for the 5 years prior to October
15, 2012, the owner or operator shall calculate the maximum natural gas
or hydrocarbon liquid throughput used to determine maximum potential
emissions according to the requirements specified in paragraph
(a)(1)(i)(A) of this section. In all other circumstances, the owner or
operator shall calculate the maximum throughput used to determine
whether a facility is a major source in accordance with the
requirements specified in paragraph (a)(1)(i)(B) of this section.
    (A) The maximum natural gas or hydrocarbon liquid throughput is the
average of the annual natural gas or hydrocarbon liquid throughput for
the 3 years prior to October 15, 2012, multiplied by a factor of 1.2.
    (B) The maximum natural gas or hydrocarbon liquid throughput is the
highest annual natural gas or hydrocarbon liquid throughput over the 5
years prior to October 15, 2012, multiplied by a factor of 1.2.
* * * * *
    (iii) The owner or operator shall determine the maximum values for
other parameters used to calculate emissions as the maximum for the
period over which the maximum natural gas or hydrocarbon liquid
throughput is determined in accordance with paragraph (a)(1)(i)(A) or
(B) of this section. Parameters, other than glycol circulation rate,
shall be based on either highest measured values or annual average. For
estimating maximum potential emissions from glycol dehydration units,
the glycol circulation rate used in the calculation shall be the unit's
maximum rate under its physical and operational design consistent with
the definition of potential to emit in Sec.  63.2.
    (2) Facilities that process, upgrade, or store hydrocarbon liquids.
* * * * *
    (b) * * *
    (1) * * *
    (i) Each glycol dehydration unit as specified in paragraphs
(b)(1)(i)(A) through (C) of this section.
    (A) Each large glycol dehydration unit;
    (B) Each small glycol dehydration unit for which construction
commenced on or before August 23, 2011, is an existing small glycol
dehydration unit; and
    (C) Each small glycol dehydration unit for which construction
commenced after August 23, 2011, is a new small glycol dehydration
unit.
* * * * *
    (c) Any source that determines it is not a major source but has
actual emissions of 5 tons per year or more of a single HAP, or 12.5
tons per year or more of a combination of HAP (i.e., 50 percent of the
major source thresholds), shall update its major source determination
within 1 year of the prior determination or October 15, 2012, whichever
is later, and each year thereafter, using gas composition data measured
during the preceding 12 months.
* * * * *
    (f) The owner or operator of an affected major source shall achieve
compliance with the provisions of this subpart by the dates specified
in paragraphs (f)(1), (2), and (f)(7) through (9) of this section. The
owner or operator of an affected area source shall achieve compliance
with the provisions of this subpart by the dates specified in
paragraphs (f)(3) through (6) of this section.
    (1) Except as specified in paragraphs (f)(7) through (9) of this
section, the owner or operator of an affected major source, the
construction or reconstruction of which commenced before February 6,
1998, shall achieve compliance with the applicable provisions of this
subpart no later than June 17, 2002, except as provided for in Sec.
63.6(i). The owner or operator of an area source, the construction or
reconstruction of which commenced before February 6, 1998, that
increases its emissions of (or its potential to emit) HAP such that the
source becomes a major source that is subject to this subpart shall
comply with this subpart 3 years after becoming a major source.
    (2) Except as specified in paragraphs (f)(7) through (9) of this
section, the owner or operator of an affected major source, the
construction or reconstruction of which commences on

or after February 6, 1998, shall achieve compliance with the applicable
provisions of this subpart immediately upon initial startup or June 17,
1999, whichever date is later. Area sources, other than production
field facilities identified in (f)(9) of this section, the construction
or reconstruction of which commences on or after February 6, 1998, that
become major sources shall comply with the provisions of this standard
immediately upon becoming a major source.
* * * * *
    (7) Each affected existing small glycol dehydration unit, as
defined in Sec.  63.761, located at a major source, that commenced
construction before August 23, 2011, must achieve compliance no later
than October 15, 2015, except as provided in Sec.  63.6(i).
    (8) Each affected new small glycol dehydration unit, as defined in
Sec.  63.761, located at a major source, that commenced construction on
or after August 23, 2011, must achieve compliance immediately upon
initial startup or October 15, 2012, whichever is later.
    (9) A production field facility, as defined in Sec.  63.761,
constructed on or before August 23, 2011, that was previously
determined to be an area source but becomes a major source (as defined
in paragraph 3 of the major source definition in Sec.  63.761) on the
October 15, 2012 must achieve compliance no later than October 15,
2015, except as provided in Sec.  63.6(i).
* * * * *

0
11. Section 63.761 is amended by:
0
a. Adding, in alphabetical order, definitions for the terms
``affirmative defense,'' ``BTEX,'' ``flare,'' ``large glycol
dehydration unit,'' ``responsible official'' and ``small glycol
dehydration unit'';
0
b. Revising the definitions for ``associated equipment,'' ``glycol
dehydration unit baseline operations,'' and ``storage vessel''; and
0
c. Revising paragraph (3) of the definition for ``major source'' to
read as follows:

Sec.  63.761  Definitions.

* * * * *
    Affirmative defense means, in the context of an enforcement
proceeding, a response or defense put forward by a defendant, regarding
which the defendant has the burden of proof, and the merits of which
are independently and objectively evaluated in a judicial or
administrative proceeding.
* * * * *
    Associated equipment, as used in this subpart and as referred to in
section 112(n)(4) of the Act, means equipment associated with an oil or
natural gas exploration or production well, and includes all equipment
from the wellbore to the point of custody transfer, except glycol
dehydration units and storage vessels.
* * * * *
    BTEX means benzene, toluene, ethyl benzene and xylene.
* * * * *
    Flare means a thermal oxidation system using an open flame (i.e.,
without enclosure).
* * * * *
    Glycol dehydration unit baseline operations means operations
representative of the large glycol dehydration unit operations as of
June 17, 1999 and the small glycol dehydrator unit operations as of
August 23, 2011. For the purposes of this subpart, for determining the
percentage of overall HAP emission reduction attributable to process
modifications, baseline operations shall be parameter values
(including, but not limited to, glycol circulation rate or glycol-HAP
absorbency) that represent actual long-term conditions (i.e., at least
1 year). Glycol dehydration units in operation for less than 1 year
shall document that the parameter values represent expected long-term
operating conditions had process modifications not been made.
* * * * *
    Large glycol dehydration unit means a glycol dehydration unit with
an actual annual average natural gas flowrate equal to or greater than
85 thousand standard cubic meters per day and actual annual average
benzene emissions equal to or greater than 0.90 Mg/yr, determined
according to Sec.  63.772(b). A glycol dehydration unit complying with
the 0.9 Mg/yr control option under Sec.  63.765(b)(1)(ii) is considered
to be a large dehydrator.
    Major source * * *
    (3) For facilities that are production field facilities, only HAP
emissions from glycol dehydration units and storage vessels shall be
aggregated for a major source determination. For facilities that are
not production field facilities, HAP emissions from all HAP emission
units shall be aggregated for a major source determination.
* * * * *
    Responsible 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 delegation of authority to such representatives is
approved in advance by the permitting authority;
    (2) For a partnership or sole proprietorship: a general partner or
the proprietor, respectively;
    (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 sources:
    (i) The designated representative in so far as actions, standards,
requirements, or prohibitions under title IV of the Act or the
regulations promulgated thereunder are concerned; and
    (ii) The designated representative for any other purposes under
part 70.
* * * * *
    Small glycol dehydration unit means a glycol dehydration unit,
located at a major source, with an actual annual average natural gas
flowrate less than 85 thousand standard cubic meters per day or actual
annual average benzene emissions less than 0.90 Mg/yr, determined
according to Sec.  63.772(b).
* * * * *
    Storage vessel means a tank or other vessel that is designed to
contain an accumulation of crude oil, condensate, intermediate
hydrocarbon liquids, or produced water and that is constructed
primarily of non-earthen materials (e.g., wood, concrete, steel,
plastic) that provide structural support. The following process units
are not considered storage vessels: Surge control vessels and knockout
vessels.
* * * * *

0
12. Section 63.762 is revised to read as follows:

Sec.  63.762  Affirmative defense for violations of emission standards
during malfunction.

    (a) The provisions set forth in this subpart shall apply at all
times.
    (b) [Reserved]
    (c) [Reserved]
    (d) In response to an action to enforce the standards set forth in
this subpart, you may assert an affirmative defense to

a claim for civil penalties for violations of such standards that are
caused by malfunction, as defined in 40 CFR 63.2. Appropriate penalties
may be assessed; however, if you fail to meet your burden of proving
all of the requirements in the affirmative defense, the affirmative
defense shall not be available for claims for injunctive relief.
    (1) To establish the affirmative defense in any action to enforce
such a standard, you must timely meet the reporting requirements in
paragraph (d)(2) of this section, and must prove by a preponderance of
evidence that:
    (i) The violation:
    (A) Was caused by a sudden, infrequent, and unavoidable failure of
air pollution control equipment, process equipment, or a process to
operate in a normal or usual manner; and
    (B) Could not have been prevented through careful planning, proper
design or better operation and maintenance practices; and
    (C) Did not stem from any activity or event that could have been
foreseen and avoided, or planned for; and
    (D) Was not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
    (ii) Repairs were made as expeditiously as possible when a
violation occurred. Off-shift and overtime labor were used, to the
extent practicable to make these repairs; and
    (iii) The frequency, amount and duration of the violation
(including any bypass) were minimized to the maximum extent
practicable; and
    (iv) If the violation resulted from a bypass of control equipment
or a process, then the bypass was unavoidable to prevent loss of life,
personal injury, or severe property damage; and
    (v) All possible steps were taken to minimize the impact of the
violation on ambient air quality, the environment, and human health;
and
    (vi) All emissions monitoring and control systems were kept in
operation if at all possible, consistent with safety and good air
pollution control practices; and
    (vii) All of the actions in response to the violation were
documented by properly signed, contemporaneous operating logs; and
    (viii) At all times, the affected source was operated in a manner
consistent with good practices for minimizing emissions; and
    (ix) A written root cause analysis has been prepared, the purpose
of which is to determine, correct, and eliminate the primary causes of
the malfunction and the violation resulting from the malfunction event
at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of any emissions that were
the result of the malfunction.
    (2) Report. The owner or operator seeking to assert an affirmative
defense shall submit a written report to the Administrator with all
necessary supporting documentation, that it has met the requirements
set forth in paragraph (d)(1) of this section. This affirmative defense
report shall be included in the first periodic compliance, deviation
report or excess emission report otherwise required after the initial
occurrence of the violation of the relevant standard (which may be the
end of any applicable averaging period). If such compliance, deviation
report or excess emission report is due less than 45 days after the
initial occurrence of the violation, the affirmative defense report may
be included in the second compliance, deviation report or excess
emission report due after the initial occurrence of the violation of
the relevant standard.

0
13. Section 63.764 is amended by:
0
a. Revising paragraph (e)(1) introductory text;
0
b. Revising paragraph (i); and
0
c. Adding paragraph (j).
    The revisions and addition read as follows:

Sec.  63.764  General standards.

* * * * *
    (e) Exemptions. (1) The owner or operator of an area source is
exempt from the requirements of paragraph (d) of this section if the
criteria listed in paragraph (e)(1)(i) or (ii) of this section are met,
except that the records of the determination of these criteria must be
maintained as required in Sec.  63.774(d)(1).
* * * * *
    (i) In all cases where the provisions of this subpart require an
owner or operator to repair leaks by a specified time after the leak is
detected, it is a violation of this standard to fail to take action to
repair the leak(s) within the specified time. If action is taken to
repair the leak(s) within the specified time, failure of that action to
successfully repair the leak(s) is not a violation of this standard.
However, if the repairs are unsuccessful, and a leak is detected, the
owner or operator shall take further action as required by the
applicable provisions of this subpart.
    (j) At all times the owner or operator must operate and maintain
any affected source, including associated air pollution control
equipment and monitoring equipment, in a manner consistent with safety
and good air pollution control practices for minimizing emissions.
Determination of whether such operation and maintenance procedures are
being used will be based on information available to the Administrator
which may include, but is not limited to, monitoring results, review of
operation and maintenance procedures, review of operation and
maintenance records, and inspection of the source.

0
14. Section 63.765 is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (b)(1);
0
c. Revising paragraph (c)(2); and
0
d. Revising paragraph (c)(3).
    The revisions read as follows:

Sec.  63.765  Glycol dehydration unit process vent standards.

    (a) This section applies to each glycol dehydration unit subject to
this subpart that must be controlled for air emissions as specified in
either paragraph (c)(1)(i) or paragraph (d)(1)(i) of Sec.  63.764.
    (b) * * *
    (1) For each glycol dehydration unit process vent, the owner or
operator shall control air emissions by either paragraph (b)(1)(i),
(ii), or (iii) of this section.
    (i) The owner or operator of a large glycol dehydration unit, as
defined in Sec.  63.761, shall connect the process vent to a control
device or a combination of control devices through a closed-vent
system. The closed-vent system shall be designed and operated in
accordance with the requirements of Sec.  63.771(c). The control
device(s) shall be designed and operated in accordance with the
requirements of Sec.  63.771(d).
    (ii) The owner or operator of a large glycol dehydration unit shall
connect the process vent to a control device or combination of control
devices through a closed-vent system and the outlet benzene emissions
from the control device(s) shall be reduced to a level less than 0.90
megagrams per year. The closed-vent system shall be designed and
operated in accordance with the requirements of Sec.  63.771(c). The
control device(s) shall be designed and operated in accordance with the
requirements of Sec.  63.771(d), except that the performance levels
specified in Sec.  63.771(d)(1)(i) and (ii) do not apply.
    (iii) You must limit BTEX emissions from each existing small glycol
dehydration unit process vent, as defined in Sec.  63.761, to the limit
determined in Equation 1 of this section. You must limit BTEX emissions
from each new small glycol dehydration unit process vent, as defined in
Sec.  63.761, to the limit determined in Equation 2 of this section.
The limits determined using Equation 1 or Equation 2 must be met in
accordance

with one of the alternatives specified in paragraphs (b)(1)(iii)(A)
through (D) of this section.
[GRAPHIC] [TIFF OMITTED] TR16AU12.009

    Equation 1

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per
year;
3.28 x 10-4 = BTEX emission limit, grams BTEX/standard
cubic meter-ppmv;
Throughput = Annual average daily natural gas throughput, standard
cubic meters per day.
Ci,BTEX = average annual BTEX concentration of the
natural gas at the inlet to the glycol dehydration unit, ppmv.

[GRAPHIC] [TIFF OMITTED] TR16AU12.010

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per
year;
4.66 x 10-6 = BTEX emission limit, grams BTEX/standard
cubic meter-ppmv;
Throughput = Annual average daily natural gas throughput, standard
cubic meters per day.
Ci,BTEX = average annual BTEX concentration of the
natural gas at the inlet to the glycol dehydration unit, ppmv.

    (A) Connect the process vent to a control device or combination of
control devices through a closed-vent system. The closed vent system
shall be designed and operated in accordance with the requirements of
Sec.  63.771(c). The control device(s) shall be designed and operated
in accordance with the requirements of Sec.  63.771(f).
    (B) Meet the emissions limit through process modifications in
accordance with the requirements specified in Sec.  63.771(e).
    (C) Meet the emissions limit for each small glycol dehydration unit
using a combination of process modifications and one or more control
devices through the requirements specified in paragraphs (b)(1)(iii)(A)
and (B) of this section.
    (D) Demonstrate that the emissions limit is met through actual
uncontrolled operation of the small glycol dehydration unit. Document
operational parameters in accordance with the requirements specified in
Sec.  63.771(e) and emissions in accordance with the requirements
specified in Sec.  63.772(b)(2).
* * * * *
    (c) * * *
    (2) The owner or operator shall demonstrate, to the Administrator's
satisfaction, that the total HAP emissions to the atmosphere from the
large glycol dehydration unit process vent are reduced by 95.0 percent
through process modifications, or a combination of process
modifications and one or more control devices, in accordance with the
requirements specified in Sec.  63.771(e).
    (3) Control of HAP emissions from a GCG separator (flash tank) vent
is not required if the owner or operator demonstrates, to the
Administrator's satisfaction, that total emissions to the atmosphere
from the glycol dehydration unit process vent are reduced by one of the
levels specified in paragraph (c)(3)(i) through (iv) of this section,
through the installation and operation of controls as specified in
paragraph (b)(1) of this section.
    (i) For any large glycol dehydration unit, HAP emissions are
reduced by 95.0 percent or more.
    (ii) For any large glycol dehydration unit, benzene emissions are
reduced to a level less than 0.90 megagrams per year.
    (iii) For each existing small glycol dehydration unit, BTEX
emissions are reduced to a level less than the limit calculated by
Equation 1 of paragraph (b)(1)(iii) of this section.
    (iv) For each new small glycol dehydration unit, BTEX emissions are
reduced to a level less than the limit calculated by Equation 2 of
paragraph (b)(1)(iii) of this section.

0
15. Section 63.766 is amended by:
0
a. Adding paragraph (b)(3); and
0
b. Revising paragraph (d) to read as follows:

Sec.  63.766  Storage vessel standards.

* * * * *
    (b) * * *
    (3) The owner or operator shall control air emissions by connecting
the cover, through a closed-vent system that meets the conditions
specified in Sec.  63.771(c), to a process natural gas line.
* * * * *
    (d) This section does not apply to storage vessels for which the
owner or operator is subject to and controlled under the requirements
specified in 40 CFR part 60, subparts Kb or OOOO; or is subject to and
controlled under the requirements specified under 40 CFR part 63
subparts G or CC. Storage vessels subject to and controlled under 40
CFR part 60, subpart OOOO shall submit the periodic reports specified
in Sec.  63.775(e).

0
16. Section 63.769 is amended by:
0
a. Revising paragraph (b);
0
b. Revising paragraph (c) introductory text; and
0
c. Revising paragraph (c)(8).

The revisions read as follows:

Sec.  63.769  Equipment leak standards.

* * * * *
    (b) This section does not apply to ancillary equipment and
compressors for which the owner or operator is subject to and
controlled under the requirements specified in subpart H of this part;
or is subject to and controlled under the requirements specified in 40
CFR part 60, subpart OOOO. Ancillary equipment and compressors subject
to and controlled under 40 CFR part 60, subpart OOOO shall submit the
periodic reports specified in Sec.  63.775(e).
    (c) For each piece of ancillary equipment and each compressor
subject to this section located at an existing or new source, the owner
or operator shall meet the requirements specified in 40 CFR part 61,
subpart V, Sec. Sec.  61.241 through 61.247, except as specified in
paragraphs (c)(1) through (8) of this section, except that for valves
subject to Sec.  61.242-7(b) or Sec.  61.243-1, a leak is detected if
an instrument reading of 500 ppm or greater is measured. A leak
detected from a valve at a source constructed on or before August 23,
2011 shall be repaired in accordance with the schedule in Sec.  61.242-
7(d), or by October 15, 2013, whichever is later. A leak detected from
a valve at a source constructed after August 23, 2011 shall be repaired
in accordance with the schedule in Sec.  61.242-7(d), or by October 15,
2012, whichever is later.
* * * * *

    (8) Flares, as defined in Sec.  63.761, used to comply with this
subpart shall comply with the requirements of Sec.  63.11(b).

0
17. Section 63.771 is amended by:
0
a. Revising paragraph (c)(1);
0
b. Revising the heading of paragraph (d);
0
c. Adding paragraph (d) introductory text;
0
d. Revising paragraph (d)(1)(i)(C);
0
e. Revising paragraph (d)(1)(ii);
0
f. Revising paragraph (d)(1)(iii);
0
g. Revising paragraph (d)(4)(i);
0
h. Revising paragraph (d)(5)(i);
0
i. Revising paragraph (e)(2);
0
j. Revising paragraph (e)(3) introductory text;
0
k. Revising paragraph (e)(3)(ii); and
0
l. Adding paragraph (f).

    The revisions and additions read as follows:

Sec.  63.771  Control equipment requirements.

* * * * *
    (c) Closed-vent system requirements. (1) The closed-vent system
shall route all gases, vapors, and fumes emitted from the material in
an emissions unit to a control device that meets the requirements
specified in paragraph (d) of this section.
* * * * *
    (d) Control device requirements for sources except small glycol
dehydration units. Owners and operators of small glycol dehydration
units, shall comply with the control device requirements in paragraph
(f) of this section.
    (1) * * *
    (i) * * *
    (C) Operates at a minimum temperature of 760 degrees C, provided
the control device has demonstrated, under Sec.  63.772(e), that
combustion zone temperature is an indicator of destruction efficiency.
* * * * *
    (ii) A vapor recovery device (e.g., carbon adsorption system or
condenser) or other non-destructive control device that is designed and
operated to reduce the mass content of either TOC or total HAP in the
gases vented to the device by 95.0 percent by weight or greater as
determined in accordance with the requirements of Sec.  63.772(e).
    (iii) A flare, as defined in Sec.  63.761, that is designed and
operated in accordance with the requirements of Sec.  63.11(b).
* * * * *
    (4) * * *
    (i) Each control device used to comply with this subpart shall be
operating at all times when gases, vapors, and fumes are vented from
the HAP emissions unit or units through the closed-vent system to the
control device, as required under Sec.  63.765, Sec.  63.766, and Sec.
63.769. An owner or operator may vent more than one unit to a control
device used to comply with this subpart.
* * * * *
    (5) * * *
    (i) Following the initial startup of the control device, all carbon
in the control device shall be replaced with fresh carbon on a regular,
predetermined time interval that is no longer than the carbon service
life established for the carbon adsorption system. Records identifying
the schedule for replacement and records of each carbon replacement
shall be maintained as required in Sec.  63.774(b)(7)(ix). The schedule
for replacement shall be submitted with the Notification of Compliance
Status Report as specified in Sec.  63.775(d)(5)(iv). Each carbon
replacement must be reported in the Periodic Reports as specified in
Sec.  63.772(e)(2)(xii).
* * * * *
    (e) * * *
    (2) The owner or operator shall document, to the Administrator's
satisfaction, the conditions for which glycol dehydration unit baseline
operations shall be modified to achieve the 95.0 percent overall HAP
emission reduction, or BTEX limit determined in Sec.
63.765(b)(1)(iii), as applicable, either through process modifications
or through a combination of process modifications and one or more
control devices. If a combination of process modifications and one or
more control devices are used, the owner or operator shall also
establish the emission reduction to be achieved by the control device
to achieve an overall HAP emission reduction of 95.0 percent for the
glycol dehydration unit process vent or, if applicable, the BTEX limit
determined in Sec.  63.765(b)(1)(iii) for the small glycol dehydration
unit process vent. Only modifications in glycol dehydration unit
operations directly related to process changes, including but not
limited to changes in glycol circulation rate or glycol-HAP absorbency,
shall be allowed. Changes in the inlet gas characteristics or natural
gas throughput rate shall not be considered in determining the overall
emission reduction due to process modifications.
    (3) The owner or operator that achieves a 95.0 percent HAP emission
reduction or meets the BTEX limit determined in Sec.
63.765(b)(1)(iii), as applicable, using process modifications alone
shall comply with paragraph (e)(3)(i) of this section. The owner or
operator that achieves a 95.0 percent HAP emission reduction or meets
the BTEX limit determined in Sec.  63.765(b)(1)(iii), as applicable,
using a combination of process modifications and one or more control
devices shall comply with paragraphs (e)(3)(i) and (ii) of this
section.
* * * * *
    (ii) The owner or operator shall comply with the control device
requirements specified in paragraph (d) or (f) of this section, as
applicable, except that the emission reduction or limit achieved shall
be the emission reduction or limit specified for the control device(s)
in paragraph (e)(2) of this section.
    (f) Control device requirements for small glycol dehydration units.
(1) The control device used to meet BTEX the emission limit calculated
in Sec.  63.765(b)(1)(iii) shall be one of the control devices
specified in paragraphs (f)(1)(i) through (iii) of this section.
    (i) An enclosed combustion device (e.g., thermal vapor incinerator,
catalytic vapor incinerator, boiler, or process heater) that is
designed and operated to meet the levels specified in paragraphs
(f)(1)(i)(A) or (B) of this section. If a boiler or process heater is
used as the control device, then the vent stream shall be introduced
into the flame zone of the boiler or process heater.
    (A) The mass content of BTEX in the gases vented to the device is
reduced as determined in accordance with the requirements of Sec.
63.772(e).
    (B) The concentration of either TOC or total HAP in the exhaust
gases at the outlet of the device is reduced to a level equal to or
less than 20 parts per million by volume on a dry basis corrected to 3
percent oxygen as determined in accordance with the requirements of
Sec.  63.772(e).
    (ii) A vapor recovery device (e.g., carbon adsorption system or
condenser) or other non-destructive control device that is designed and
operated to reduce the mass content of BTEX in the gases vented to the
device as determined in accordance with the requirements of Sec.
63.772(e).
    (iii) A flare, as defined in Sec.  63.761, that is designed and
operated in accordance with the requirements of Sec.  63.11(b).
    (2) The owner or operator shall operate each control device in
accordance with the requirements specified in paragraphs (f)(2)(i) and
(ii) of this section.
    (i) Each control device used to comply with this subpart shall be
operating at all times. An owner or operator may vent more than one
unit to a control device used to comply with this subpart.

    (ii) For each control device monitored in accordance with the
requirements of Sec.  63.773(d), the owner or operator shall
demonstrate compliance according to the requirements of either Sec.
63.772(f) or (h).
    (3) For each carbon adsorption system used as a control device to
meet the requirements of paragraph (f)(1)(ii) of this section, the
owner or operator shall manage the carbon as required under (d)(5)(i)
and (ii) of this section.

0
18. Section 63.772 is amended by:
0
a. Revising paragraph (b) introductory text;
0
b. Revising paragraph (b)(1)(ii);
0
c. Revising paragraph (b)(2);
0
d. Revising paragraph (c)(6)(i);
0
e. Adding paragraph (d);
0
f. Revising paragraph (e) introductory text;
0
g. Revising paragraphs (e)(1)(i) through (v);
0
h. Revising paragraph (e)(2);
0
i. Revising paragraph (e)(3) introductory text;
0
j. Revising paragraph (e)(3)(i)(B);
0
k. Revising paragraph (e)(3)(iv)(C)(1);
0
l. Adding paragraphs (e)(3)(v) and (vi);
0
m. Revising paragraph (e)(4) introductory text;
0
n. Revising paragraph (e)(4)(i);
0
o. Revising paragraph (e)(5);
0
p. Revising paragraph (f) introductory text;
0
q. Revising paragraphs (f)(2) and (3);
0
r. Adding paragraphs (f)(4) through (6);
0
s. Revising paragraph (g) introductory text;
0
t. Revising paragraph (g)(1) and paragraph (g)(2) introductory text;
0
u. Revising paragraph (g)(2)(iii);
0
v. Revising paragraph (g)(3);
0
w. Adding paragraph (h); and
0
x. Adding paragraph (i).

The revisions and additions read as follows:

Sec.  63.772  Test methods, compliance procedures, and compliance
demonstrations.

* * * * *
    (b) Determination of glycol dehydration unit flowrate, benzene
emissions, or BTEX emissions. The procedures of this paragraph shall be
used by an owner or operator to determine glycol dehydration unit
natural gas flowrate, benzene emissions, or BTEX emissions.
    (1) * * *
    (ii) The owner or operator shall document, to the Administrator's
satisfaction, the actual annual average natural gas flowrate to the
glycol dehydration unit.
    (2) The determination of actual average benzene or BTEX emissions
from a glycol dehydration unit shall be made using the procedures of
either paragraph (b)(2)(i) or (ii) of this section. Emissions shall be
determined either uncontrolled, or with federally enforceable controls
in place.
    (i) The owner or operator shall determine actual average benzene or
BTEX emissions using the model GRI-GLYCalcTM, Version 3.0 or
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model
shall be representative of actual operating conditions of the glycol
dehydration unit and may be determined using the procedures documented
in the Gas Research Institute (GRI) report entitled ``Atmospheric Rich/
Lean Method for Determining Glycol Dehydrator Emissions'' (GRI-95/
0368.1); or
    (ii) The owner or operator shall determine an average mass rate of
benzene or BTEX emissions in kilograms per hour through direct
measurement using the methods in Sec.  63.772(a)(1)(i) or (ii), or an
alternative method according to Sec.  63.7(f). Annual emissions in
kilograms per year shall be determined by multiplying the mass rate by
the number of hours the unit is operated per year. This result shall be
converted to megagrams per year.
    (c) * * *
    (6) * * *
    (i) Except as provided in paragraph (c)(6)(ii) of this section, the
detection instrument shall meet the performance criteria of Method 21
of 40 CFR part 60, appendix A, except the instrument response factor
criteria in section 3.1.2(a) of Method 21 shall be for the average
composition of the process fluid, not each individual volatile organic
compound in the stream. For process streams that contain nitrogen, air,
or other inert gases that are not organic hazardous air pollutants or
volatile organic compounds, the average stream response factor shall be
calculated on an inert-free basis.
* * * * *
    (d) Test procedures and compliance demonstrations for small glycol
dehydration units. This paragraph applies to the test procedures for
small dehydration units.
    (1) If the owner or operator is using a control device to comply
with the emission limit in Sec.  63.765(b)(1)(iii), the requirements of
paragraph (e) of this section apply. Compliance is demonstrated using
the methods specified in paragraph (f) of this section.
    (2) If no control device is used to comply with the emission limit
in Sec.  63.765(b)(1)(iii), the owner or operator must determine the
glycol dehydration unit BTEX emissions as specified in paragraphs
(d)(2)(i) through (iii) of this section. Compliance is demonstrated if
the BTEX emissions determined as specified in paragraphs (d)(2)(i)
through (iii) are less than the emission limit calculated using the
equation in Sec.  63.765(b)(1)(iii).
    (i) Method 1 or 1A, 40 CFR part 60, appendix A, as appropriate,
shall be used for selection of the sampling sites at the outlet of the
glycol dehydration unit process vent. Any references to particulate
mentioned in Methods 1 and 1A do not apply to this section.
    (ii) The gas volumetric flowrate shall be determined using Method
2, 2A, 2C, or 2D, 40 CFR part 60, appendix A, as appropriate.
    (iii) The BTEX emissions from the outlet of the glycol dehydration
unit process vent shall be determined using the procedures specified in
paragraph (e)(3)(v) of this section. As an alternative, the mass rate
of BTEX at the outlet of the glycol dehydration unit process vent may
be calculated using the model GRI-GLYCalcTM, Version 3.0 or
higher, and the procedures presented in the associated GRI-
GLYCalcTM Technical Reference Manual. Inputs to the model
shall be representative of actual operating conditions of the glycol
dehydration unit and shall be determined using the procedures
documented in the Gas Research Institute (GRI) report entitled
``Atmospheric Rich/Lean Method for Determining Glycol Dehydrator
Emissions'' (GRI-95/0368.1). When the BTEX mass rate is calculated for
glycol dehydration units using the model GRI-GLYCalcTM, all
BTEX measured by Method 18, 40 CFR part 60, appendix A, shall be
summed.
    (e) Control device performance test procedures. This paragraph
applies to the performance testing of control devices. The owners or
operators shall demonstrate that a control device achieves the
performance requirements of Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1)
using a performance test as specified in paragraph (e)(3) of this
section. Owners or operators using a condenser have the option to use a
design analysis as specified in paragraph (e)(4) of this section. The
owner or operator may elect to use the alternative procedures in
paragraph (e)(5) of this section for performance testing of a condenser
used to control emissions from a glycol dehydration unit process vent.
Flares shall meet the provisions in paragraph (e)(2) of this section.
As an alternative to conducting a performance test under this section
for combustion control devices, a control device that can be

demonstrated to meet the performance requirements of Sec.
63.771(d)(1), (e)(3)(ii) or (f)(1) through a performance test conducted
by the manufacturer, as specified in paragraph (h) of this section, can
be used.
    (1) * * *
    (i) Except as specified in paragraph (e)(2) of this section, a
flare, as defined in Sec.  63.761, that is designed and operated in
accordance with Sec.  63.11(b);
    (ii) Except for control devices used for small glycol dehydration
units, a boiler or process heater with a design heat input capacity of
44 megawatts or greater;
    (iii) Except for control devices used for small glycol dehydration
units, a boiler or process heater into which the vent stream is
introduced with the primary fuel or is used as the primary fuel;
    (iv) Except for control devices used for small glycol dehydration
units, a boiler or process heater burning hazardous waste for which the
owner or operator has either been issued a final permit under 40 CFR
part 270 and complies with the requirements of 40 CFR part 266, subpart
H; or has certified compliance with the interim status requirements of
40 CFR part 266, subpart H;
    (v) Except for control devices used for small glycol dehydration
units, a hazardous waste incinerator for which the owner or operator
has been issued a final permit under 40 CFR part 270 and complies with
the requirements of 40 CFR part 264, subpart O; or has certified
compliance with the interim status requirements of 40 CFR part 265,
subpart O.
* * * * *
    (2) An owner or operator shall design and operate each flare, as
defined in Sec.  63.761, in accordance with the requirements specified
in Sec.  63.11(b) and the compliance determination shall be conducted
using Method 22 of 40 CFR part 60, appendix A, to determine visible
emissions.
    (3) For a performance test conducted to demonstrate that a control
device meets the requirements of Sec.  63.771(d)(1), (e)(3)(ii) or
(f)(1), the owner or operator shall use the test methods and procedures
specified in paragraphs (e)(3)(i) through (v) of this section. The
initial and periodic performance tests shall be conducted according to
the schedule specified in paragraph (e)(3)(vi) of this section.
    (i) * * *
    (B) To determine compliance with the enclosed combustion device
total HAP concentration limit specified in Sec.  63.771(d)(1)(i)(B), or
the BTEX emission limit specified in Sec.  63.765(b)(1)(iii) the
sampling site shall be located at the outlet of the combustion device.
* * * * *
    (iv) * * *
    (C) * * *
    (1) The emission rate correction factor for excess air, integrated
sampling and analysis procedures of Method 3A or 3B, 40 CFR part 60,
appendix A, ASTM D6522-00 (Reapproved 2005), or ANSI/ASME PTC 19.10-
1981, Part 10 (manual portion only) (incorporated by reference as
specified in Sec.  63.14) shall be used to determine the oxygen
concentration. The samples shall be taken during the same time that the
samples are taken for determining TOC concentration or total HAP
concentration.
* * * * *
    (v) To determine compliance with the BTEX emission limit specified
in Sec.  63.765(b)(1)(iii) the owner or operator shall use one of the
following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420-99
(Reapproved 2004), as specified in Sec.  63.772(a)(1)(ii) (incorporated
by reference as specified in Sec.  63.14); or any other method or data
that have been validated according to the applicable procedures in
Method 301, 40 CFR part 63, appendix A. The following procedures shall
be used to calculate BTEX emissions:
    (A) The minimum sampling time for each run shall be 1 hour in which
either an integrated sample or a minimum of four grab samples shall be
taken. If grab sampling is used, then the samples shall be taken at
approximately equal intervals in time, such as 15-minute intervals
during the run.
    (B) The mass rate of BTEX (Eo) shall be computed using
the equations and procedures specified in paragraphs (e)(3)(v)(B)(1)
and (2) of this section.
    (1) The following equation shall be used:
    [GRAPHIC] [TIFF OMITTED] TR16AU12.011

Where:

Eo = Mass rate of BTEX at the outlet of the control
device, dry basis, kilogram per hour.
Coj = Concentration of sample component j of the gas
stream at the outlet of the control device, dry basis, parts per
million by volume.
Moj = Molecular weight of sample component j of the gas
stream at the outlet of the control device, gram/gram-mole.
Qo = Flowrate of gas stream at the outlet of the control
device, dry standard cubic meter per minute.
K2 = Constant, 2.494 x 10-6 (parts per
million) (gram-mole per standard cubic meter) (kilogram/gram)
(minute/hour), where standard temperature (gram-mole per standard
cubic meter) is 20 degrees C.
n = Number of components in sample.

    (2) When the BTEX mass rate is calculated, only BTEX compounds
measured by Method 18, 40 CFR part 60, appendix A, or ASTM D6420-99
(Reapproved 2004) (incorporated by reference as specified in Sec.
63.14) as specified in Sec.  63.772(a)(1)(ii), shall be summed using
the equations in paragraph (e)(3)(v)(B)(1) of this section.
    (vi) The owner or operator shall conduct performance tests
according to the schedule specified in paragraphs (e)(3)(vi)(A) and (B)
of this section.
    (A) An initial performance test shall be conducted within 180 days
after the compliance date that is specified for each affected source in
Sec.  63.760(f)(7) through (8), except that the initial performance
test for existing combustion control devices (i.e., control devices
installed on or before August 23, 2011) at major sources shall be
conducted no later than October 15, 2015. If the owner or operator of
an existing combustion control device at a major source chooses to
replace such device with a control device whose model is tested under
Sec.  63.772(h), then the newly installed device shall comply with all
provisions of this subpart no later than October 15, 2015. The
performance test results shall be submitted in the Notification of
Compliance Status Report as required in Sec.  63.775(d)(1)(ii).
    (B) Periodic performance tests shall be conducted for all control
devices required to conduct initial performance tests except as
specified in paragraphs (e)(3)(vi)(B)(1) and (2) of this section. The
first periodic performance test shall be conducted no later than 60
months after the initial performance test required in paragraph
(e)(3)(vi)(A) of this section. Subsequent periodic performance tests
shall be conducted at intervals no longer than 60 months following the
previous periodic performance test or whenever a source desires to
establish a new operating limit. The periodic performance test results
must be submitted in the next Periodic Report as specified in Sec.
63.775(e)(2)(xi). Combustion control devices meeting the criteria in
either paragraph (e)(3)(vi)(B)(1) or (2) of this section are not
required to conduct periodic performance tests.
    (1) A control device whose model is tested under, and meets the
criteria of, Sec.  63.772(h), or
    (2) A combustion control device demonstrating during the
performance test under Sec.  63.772(e) that combustion

zone temperature is an indicator of destruction efficiency and operates
at a minimum temperature of 760 degrees C.
    (4) For a condenser design analysis conducted to meet the
requirements of Sec.  63.771(d)(1), (e)(3)(ii), or (f)(1), the owner or
operator shall meet the requirements specified in paragraphs (e)(4)(i)
and (ii) of this section. Documentation of the design analysis shall be
submitted as a part of the Notification of Compliance Status Report as
required in Sec.  63.775(d)(1)(i).
    (i) The condenser design analysis shall include an analysis of the
vent stream composition, constituent concentrations, flowrate, relative
humidity, and temperature, and shall establish the design outlet
organic compound concentration level, design average temperature of the
condenser exhaust vent stream, and the design average temperatures of
the coolant fluid at the condenser inlet and outlet. As an alternative
to the condenser design analysis, an owner or operator may elect to use
the procedures specified in paragraph (e)(5) of this section.
* * * * *
    (5) As an alternative to the procedures in paragraph (e)(4)(i) of
this section, an owner or operator may elect to use the procedures
documented in the GRI report entitled, ``Atmospheric Rich/Lean Method
for Determining Glycol Dehydrator Emissions'' (GRI-95/0368.1) as inputs
for the model GRI-GLYCalcTM, Version 3.0 or higher, to
generate a condenser performance curve.
    (f) Compliance demonstration for control device performance
requirements. This paragraph applies to the demonstration of compliance
with the control device performance requirements specified in Sec.
63.771(d)(1)(i), (e)(3), and (f)(1). Compliance shall be demonstrated
using the requirements in paragraphs (f)(1) through (3) of this
section. As an alternative, an owner or operator that installs a
condenser as the control device to achieve the requirements specified
in Sec.  63.771(d)(1)(ii), (e)(3), or (f)(1) may demonstrate compliance
according to paragraph (g) of this section. An owner or operator may
switch between compliance with paragraph (f) of this section and
compliance with paragraph (g) of this section only after at least 1
year of operation in compliance with the selected approach.
Notification of such a change in the compliance method shall be
reported in the next Periodic Report, as required in Sec.  63.775(e),
following the change.
* * * * *
    (2) The owner or operator shall calculate the daily average of the
applicable monitored parameter in accordance with Sec.  63.773(d)(4)
except that the inlet gas flowrate to the control device shall not be
averaged.
    (3) Compliance with the operating parameter limit is achieved when
the daily average of the monitoring parameter value calculated under
paragraph (f)(2) of this section is either equal to or greater than the
minimum or equal to or less than the maximum monitoring value
established under paragraph (f)(1) of this section. For inlet gas
flowrate, compliance with the operating parameter limit is achieved
when the value is equal to or less than the value established under
Sec.  63.772(h) or under the performance test conducted under Sec.
63.772(e), as applicable.
    (4) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required monitoring
system quality assurance or quality control activities (including, as
applicable, system accuracy audits and required zero and span
adjustments), the CMS required in Sec.  63.773(d) must be operated at
all times the affected source is operating. A monitoring system
malfunction is any sudden, infrequent, not reasonably preventable
failure of the monitoring system to provide valid data. Monitoring
system failures that are caused in part by poor maintenance or careless
operation are not malfunctions. Monitoring system repairs are required
to be completed in response to monitoring system malfunctions and to
return the monitoring system to operation as expeditiously as
practicable.
    (5) Data recorded during monitoring system malfunctions, repairs
associated with monitoring system malfunctions, or required monitoring
system quality assurance or control activities may not be used in
calculations used to report emissions or operating levels. All the data
collected during all other required data collection periods must be
used in assessing the operation of the control device and associated
control system.
    (6) Except for periods of monitoring system malfunctions, repairs
associated with monitoring system malfunctions, and required quality
monitoring system quality assurance or quality control activities
(including, as applicable, system accuracy audits and required zero and
span adjustments), failure to collect required data is a deviation of
the monitoring requirements.
    (g) Compliance demonstration with percent reduction or emission
limit performance requirements--condensers. This paragraph applies to
the demonstration of compliance with the performance requirements
specified in Sec.  63.771(d)(1)(ii), (e)(3), or (f)(1) for condensers.
Compliance shall be demonstrated using the procedures in paragraphs
(g)(1) through (3) of this section.
    (1) The owner or operator shall establish a site-specific condenser
performance curve according to Sec.  63.773(d)(5)(ii). For sources
required to meet the BTEX limit in accordance with Sec.  63.771(e) or
(f)(1) the owner or operator shall identify the minimum percent
reduction necessary to meet the BTEX limit.
    (2) Compliance with the requirements in Sec.  63.771(d)(1)(ii),
(e)(3), or (f)(1) shall be demonstrated by the procedures in paragraphs
(g)(2)(i) through (iii) of this section.
* * * * *
    (iii) Except as provided in paragraphs (g)(2)(iii)(A) and (B) of
this section, at the end of each operating day, the owner or operator
shall calculate the 365-day average HAP, or BTEX, emission reduction,
as appropriate, from the condenser efficiencies as determined in
paragraph (g)(2)(ii) of this section for the preceding 365 operating
days. If the owner or operator uses a combination of process
modifications and a condenser in accordance with the requirements of
Sec.  63.771(e), the 365-day average HAP, or BTEX, emission reduction
shall be calculated using the emission reduction achieved through
process modifications and the condenser efficiency as determined in
paragraph (g)(2)(ii) of this section, both for the previous 365
operating days.
    (A) After the compliance dates specified in Sec.  63.760(f), an
owner or operator with less than 120 days of data for determining
average HAP, or BTEX, emission reduction, as appropriate, shall
calculate the average HAP, or BTEX emission reduction, as appropriate,
for the first 120 days of operation after the compliance dates. For
sources required to meet the overall 95.0 percent reduction
requirement, compliance is achieved if the 120-day average HAP emission
reduction is equal to or greater than 90.0 percent. For sources
required to meet the BTEX limit under Sec.  63.765(b)(1)(iii),
compliance is achieved if the average BTEX emission reduction is at
least 95.0 percent of the required 365-day value identified under
paragraph (g)(1) of this section (i.e., at least 76.0 percent if the
365-day design value is 80.0 percent).
    (B) After 120 days and no more than 364 days of operation after the
compliance dates specified in

Sec.  63.760(f), the owner or operator shall calculate the average HAP
emission reduction as the HAP emission reduction averaged over the