Federal Register, or the date of the previous reciprocating compressor
rod packing replacement, whichever is later. The cumulative number of
hours of operation must be included in the annual report as required in
Sec.  60.5420(b)(4).
    (2) You have replaced the reciprocating compressor rod packing
before the total number of hours of operation reaches 26,000 hours.
    (d) For each pneumatic controller affected facility, continuous
compliance is demonstrated by maintaining the records demonstrating
that you have installed and operated the pneumatic controllers as
required in Sec.  60.5390(a), (b) or (c).
    (e) For each storage vessel affected facility, continuous
compliance is demonstrated according to Sec.  63.772(f) of this
chapter.
    (f) For affected facilities at onshore natural gas processing
plants, continuous compliance with VOC requirements is demonstrated if
you are in compliance with the requirements of Sec.  60.5400.
    (g) For each sweetening unit affected facility at onshore natural
gas processing plants, you must demonstrate continuous compliance with
the standards for SO2 specified in

Sec.  60.5405(b) according to paragraphs (g)(1) and (g)(2) of this
section.
    (1) The minimum required SO2 emission reduction
efficiency (Zc) is compared to the emission reduction
efficiency (R) achieved by the sulfur recovery technology.
    (i) If R >= Zc, your affected facility is in compliance.
    (ii) If R < Zc, your affected facility is not in
compliance.
    (2) The emission reduction efficiency (R) achieved by the sulfur
reduction technology must be determined using the procedures in Sec.
60.5406(c)(1).
    (h) Affirmative defense for exceedance of emission limit during
malfunction. In response to an action to enforce the standards set
forth in Sec. Sec.  60.5375, 60.5380, 60.5385, 60.5390, 60.5395,
60.5400, and 60.5405, you may assert an affirmative defense to a claim
for civil penalties for exceedances of such standards that are caused
by malfunction, as defined at Sec.  60.2. 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 limit, you must timely meet the notification requirements in
Sec.  60.5420(a), and must prove by a preponderance of evidence that:
    (i) The excess emissions:
    (A) Were caused by a sudden, infrequent, and unavoidable failure of
air pollution control and monitoring 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) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
    (ii) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs; and
    (iii) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
    (iv) If the excess emissions 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
excess emissions 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 excess emissions were
documented by properly signed, contemporaneous operating logs; and
    (viii) At all times, the facility 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 excess emissions resulting from the malfunction
event at issue. The analysis shall also specify, using best monitoring
methods and engineering judgment, the amount of excess emissions that
were the result of the malfunction.
    (2) The owner or operator of the facility experiencing an
exceedance of its emission limit(s) during a malfunction shall notify
the Administrator by telephone or facsimile (FAX) transmission as soon
as possible, but no later than 2 business days after the initial
occurrence of the malfunction, if it wishes to avail itself of an
affirmative defense to civil penalties for that malfunction. The owner
or operator seeking to assert an affirmative defense shall also submit
a written report to the Administrator within 45 days of the initial
occurrence of the exceedance of the standards in Sec. Sec.  60.5375,
60.5380, 60.5385, 60.5390, 60.5395, and 60.5400 to demonstrate, with
all necessary supporting documentation, that it has met the
requirements set forth in paragraph (a) of this section. The owner or
operator may seek an extension of this deadline for up to 30 additional
days by submitting a written request to the Administrator before the
expiration of the 45-day period. Until a request for an extension has
been approved by the Administrator, the owner or operator is subject to
the requirement to submit such report within 45 days of the initial
occurrence of the exceedance.

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

    (a) You must submit the notifications required in Sec.  60.7(a)(1),
(a)(3) and (a)(4), and according to paragraphs (a)(1) and (a)(2) of
this section, if you own or operate one or more of the affected
facilities specified in Sec.  60.5365. For the purposes of this
subpart, a workover that occurs after August 23, 2011 at each affected
facility for which construction, reconstruction, or modification
commenced on or before August 23, 2011 is considered a modification for
which a notification must be submitted under Sec.  60.7(a)(4).
    (1) If you own or operate a pneumatic controller affected facility
you are not required to submit the notifications required in Sec.
60.7(a)(1), (a)(3) and (a)(4).
    (2) If you own or operate a gas wellhead affected facility, you
must submit a notification to the Administrator within 30 days of the
commencement of the well completion operation. The notification must
include the date of commencement of the well completion operation, the
latitude and longitude coordinates of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using the North
American Datum of 1983.
    (b) Reporting requirements. You must submit annual reports
containing the information specified in paragraphs (b)(1) through
(b)(6) of this section to the Administrator. The initial annual report
is due 1 year after the initial startup date for your affected facility
or 1 year after the date of publication of the final rule in the
Federal Register, whichever is later. 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 (b)(6)
of this section.
    (1) The general information specified in paragraphs (b)(1)(i)
through (b)(1)(iii) 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.
    (2) For each gas wellhead affected facility, the information in
paragraphs (b)(2)(i) through (b)(2)(iii) of this section.
    (i) An identification of each well completion operation, as defined
in Sec.  60.5430, for each gas wellhead affected facility conducted
during the reporting period;
    (ii) A record of deviations in cases where well completion
operations with hydraulic fracturing were not performed in compliance
with the requirements

specified in Sec.  60.5375 for each gas well affected facility.
    (iii) Records specified in Sec.  60.5375(b) for each well
completion operation that occurred during the reporting period.
    (3) For each centrifugal compressor affected facility installed
during the reporting period, documentation that the centrifugal
compressor is equipped with dry seals.
    (4) For each reciprocating compressor affected facility, the
information specified in paragraphs (b)(4)(i) and (b)(4)(ii) of this
section.
    (i) The cumulative number of hours or operation since initial
startup, the date of publication of the final rule in the Federal
Register, or since the previous reciprocating compressor rod packing
replacement, whichever is later.
    (ii) Documentation that the reciprocating compressor rod packing
was replaced before the cumulative number of hours of operation reached
24,000 hours.
    (5) For each pneumatic controller affected facility, the
information specified in paragraphs (b)(5)(i) through (b)(5)(iv) of
this section.
    (i) The date, location and manufacturer specifications for each
pneumatic controller installed.
    (ii) If applicable, documentation that the use of high bleed
pneumatic devices is predicated and the reasons why.
    (iii) For pneumatic controllers not installed at a natural gas
processing plant, the manufacturer's guarantee that the device is
designed such that natural gas emissions are less than 6 standard cubic
feet per hour.
    (iv) For pneumatic controllers installed at a natural gas
processing plant, documentation that each controllers has zero natural
gas emissions.
    (6) For each storage vessel affected facility, the information in
paragraphs (b)(6)(i) and (b)(6)(ii) of this section.
    (i) If required to reduce emissions by complying with Sec.
60.5395(a)(1), the records specified in Sec.  63.774(b)(2) through
(b)(8) of this chapter.
    (ii) Documentation that the annual average condensate throughput is
less than 1 barrel per day per storage vessel and crude oil throughput
is less than 21 barrels per day per storage for meeting the
requirements in Sec.  60.5395(a)(1) or (a)(2).
    (c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec.  60.7(f) and in paragraphs (c)(1)
through (c)(5) of this section
    (1) The records for each gas wellhead affected facility as
specified in paragraphs (c)(1)(i) through (c)(1)(iii).
    (i) Records identifying each well completion operation for each gas
wellhead affected facility conducted during the reporting period;
    (ii) Record 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 wellhead affected facility
that occurred during the reporting period. You must maintain the
records specified in paragraphs (c)(1)(iii)(A) and (c)(1)(iii)(B) of
this section.
    (A) For each gas wellheads affected facility required to comply
with the requirements of Sec.  60.5375(a), you must record: The
location of the well; the duration of flowback; duration of recovery to
the sales 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 wellhead 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 sales line. In
addition, you must record the distance, in miles, of the nearest
gathering line.
    (2) For each centrifugal compressor affected facility, you must
maintain records on the type of seal system installed.
    (3) For each reciprocating compressors affected facility, you must
maintain the records in paragraphs (c)(3)(i) and (c)(3)(ii) of this
section.
    (i) Records of the cumulative number of hours of operation since
initial startup or the date of publication of the final rule in the
Federal Register, 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.
    (4) For each pneumatic controller affected facility, you must
maintain the records identified in paragraphs (c)(4)(i) through
(c)(4)(iv) of this section.
    (i) Records of the date, location and manufacturer specifications
for each pneumatic controller installed.
    (ii) Records of the determination that the use of high bleed
pneumatic devices is predicated and the reasons why.
    (iii) If the pneumatic controller affected facility is not located
at a natural gas processing plant, records of the manufacturer's
guarantee that the device is designed such that natural gas emissions
are less than 6 standard cubic feet per hour.
    (iv) If the pneumatic controller affected facility is located at a
natural gas processing plant, records of the documentation that only
instrument air controllers are used.
    (5) For each storage vessel affected facility, you must maintain
the records identified in paragraphs (c)(5)(i) and (c)(5)(ii) of this
section.
    (i) If required to reduce emissions by complying with Sec.  63.766,
the records specified in Sec.  63.774(b)(2) through (8) of this
chapter.
    (ii) Records of the determination that the annual average
condensate throughput is less than 1 barrel per day per storage vessel
and crude oil throughput is less than 21 barrels per day per storage
vessel for the exemption under Sec.  60.5395(a)(1) and (a)(2).

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 written report of excess emissions to the
Administrator semiannually. 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.
    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.
    Centrifugal compressor means a piece of equipment that compresses a
process gas by means of mechanical rotating vanes or impellers.
    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 or
workovers.
    Compressor means a piece of equipment that compresses process gas
and is usually a centrifugal compressor or a reciprocating compressor.
    Compressor station means any permanent combination of compressors
that move natural gas at increased pressure from fields, in
transmission pipelines, or into storage.
    Condensate means a hydrocarbon liquid separated from natural gas
that condenses due to changes in the temperature, pressure, or both,
and remains liquid at standard conditions, as specified in Sec.  60.2.
For the purposes of this subpart, a hydrocarbon liquid with an API
gravity equal to or greater than 40 degrees is considered condensate.
    Crude oil means crude petroleum oil or any other hydrocarbon
liquid, which are produced at the well in liquid form by ordinary
production methods, and which are not the result of condensation of gas
before or after it leaves the reservoir. For the purposes of this
subpart, a hydrocarbon liquid with an API gravity less than 40 degrees
is considered crude oil.
    Dehydrator means a device in which an absorbent directly contacts a
natural gas stream and absorbs water in a contact tower or absorption
column (absorber).
    Delineation well means a well drilled in order to determine the
boundary of a field or producing reservoir.
    Equipment means each pump, pressure relief device, open-ended valve
or line, valve, compressor, 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 to 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.
    Flowback means the process of allowing fluids to flow from the well
following a treatment, either in

preparation for a subsequent phase of treatment or in preparation for
cleanup and returning the well to production.
    Flow line means surface pipe through which oil and/or natural gas
travels from the well.
    Gas-driven pneumatic controller means a pneumatic controller
powered by pressurized natural gas.
    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 means a well, the principal production of which at the
mouth of the well is gas.
    High-bleed pneumatic devices means automated, continuous bleed flow
control devices powered by pressurized natural gas and used for
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature. Part of the gas power stream which is
regulated by the process condition flows to a valve actuator controller
where it vents continuously (bleeds) to the atmosphere at a rate in
excess of six standard cubic feet per hour.
    Hydraulic fracturing means the process of directing pressurized
liquids, containing water, proppant, and any added chemicals, to
penetrate tight sand, shale, or coal formations that involve high rate,
extended back flow to expel fracture fluids and sand during completions
and well workovers.
    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(h)(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.
    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-bleed pneumatic controller means automated flow control devices
powered by pressurized natural gas and used for maintaining a process
condition such as liquid level, pressure, delta-pressure and
temperature. Part of the gas power stream which is regulated by the
process condition flows to a valve actuator controller where it vents
continuously (bleeds) to the atmosphere at a rate equal to or less than
six standard cubic feet per hour.
    Modification means any physical change in, or change in the method
of operation of, an affected facility which increases the amount of VOC
or natural gas emitted into the atmosphere by that facility or which
results in the emission of VOC or natural gas into the atmosphere not
previously emitted. For the purposes of this subpart, each recompletion
of a fractured or refractured existing gas well is considered to be a
modification.
    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.
    Nonfractionating plant means any gas plant that does not
fractionate mixed natural gas liquids into natural gas products.
    Non gas-driven pneumatic device 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.
    Plunger lift system means an intermittent gas lift that uses gas
pressure buildup in the casing-tubing annulus to push a steel plunger,
and the column of fluid ahead of it, up the well tubing to the surface.
    Pneumatic controller means an automated instrument used for
maintaining a process condition such as liquid level, pressure, delta-
pressure and temperature.
    Pneumatic pump means a pump that uses pressurized natural gas to
move a piston or diaphragm, which pumps liquids on the opposite side of
the piston or diaphragm.
    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 where gas
flowback that is otherwise vented is captured, cleaned, and routed to
the sales line.
    Reduced emissions recompletion means a well completion following
refracturing of a gas well where gas flowback that is otherwise vented
is captured, cleaned, and routed to the sales line.
    Reduced sulfur compounds means H2S, carbonyl sulfide
(COS), and carbon disulfide (CS2).
    Routed to a process or route to a process means the emissions are
conveyed 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.
    Sales line means pipeline, generally small in diameter, used to
transport oil or gas from the well to a processing facility or a
mainline pipeline.
    Storage vessel means a stationary vessel or series of stationary
vessels that are either manifolded together or are located at a single
well site and that have potential for VOC emissions equal to or greater
than 10 tpy.
    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 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 tank means a storage tank 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 flow of
petroleum or natural gas from newly drilled wells to expel drilling and
reservoir fluids and tests the reservoir flow characteristics, steps
which may vent produced gas to the atmosphere via an open pit or tank.
Well completion also involves connecting the well bore to the
reservoir, which may include treating the formation or installing
tubing, packer(s), or lifting equipment.
    Well completion operation means any well completion or well
workover occurring at a gas wellhead affected facility.
    Well site means the 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 <= 5.0    5.0 < X <= 15.0     15.0 < X <= 300.0        X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50.........................             79.0         88.51X0.0101Y0.0125 or 99.9, whichever is smaller
----------------------------------------------------------------------------------------------------------------
20 <= Y < 50....................             79.0   88.5X0.0101Y0.0125 or 97.9, whichever is         97.9
                                                                     smaller
----------------------------------------------------------------------------------------------------------------
10 <= Y < 20....................             79.0   88.5X0.0101Y0.0125.          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 <= 5.0    5.0 < X <= 15.0     15.0 < X <= 300.0        X > 300.0
----------------------------------------------------------------------------------------------------------------
Y >= 50.........................             74.0         85.35X0.0144Y0.0128 or 99.9, whichever is smaller
----------------------------------------------------------------------------------------------------------------
20 <= Y < 50....................             74.0    85.35X0.0144Y0.0128 or 97.9, whichever          97.5
                                                                    is smaller
----------------------------------------------------------------------------------------------------------------
10 <= Y < 20....................             74.0   85.35X0.0144Y0.0128          90.8                90.8
                                                    or 90.8, whichever
                                                     is smaller.
----------------------------------------------------------------------------------------------------------------
Y < 10..........................             74.0           74.0                 74.0                74.0
----------------------------------------------------------------------------------------------------------------

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.

             Table 3 to Subpart OOOO of Part 60--Applicability of General Provisions to Subpart OOOO
         [As stated in Sec.   60.5425, you must comply with the following applicable General Provisions]
----------------------------------------------------------------------------------------------------------------
   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.........  No...................  Performance testing is
                                                                                required for storage
                                                                                vessels as specified in
                                                                                40 CFR part 63, subpart
                                                                                HH.
Sec.   60.9.......................  Availability of             Yes.
                                     information.
Sec.   60.10......................  State authority...........  Yes.
Sec.   60.11......................  Compliance with standards   No...................  Requirements are
                                     and maintenance                                    specified in subpart
                                     requirements.                                      OOOO.
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.
                                     requirements.
Sec.   60.19......................  General notification and    Yes.
                                     reporting requirement.
----------------------------------------------------------------------------------------------------------------

PART 63--[AMENDED]

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

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

    9. Section 63.14 is amended by:
    a. Adding paragraphs (b)(69), (b)(70), (b)(71) and (b)(72); and
    b. Revising paragraph (i)(1) to read as follows:

Sec.  63.14  Incorporations by reference.

* * * * *
    (b) * * *
* * * * *
    (69) ASTM D1945-03(2010) Standard Test Method for Analysis of
Natural Gas by Gas Chromatography, IBR approved for Sec. Sec.  63.772
and 63.1282.
    (70) ASTM D5504-08 Standard Test Method for Determination of Sulfur
Compounds in Natural Gas and Gaseous Fuels by Gas Chromatography and
Chemiluminescence, IBR approved for Sec. Sec.  63.772 and 63.1282.
    (71) ASTM D3588-98(2003) Standard Practice for Calculating Heat
Value, Compressibility Factor, and Relative Density of Gaseous Fuels,
IBR approved for Sec. Sec.  63.772 and 63.1282.
    (72) ASTM D4891-89(2006) Standard Test Method for Heating Value of
Gases in Natural Gas Range by Stoichiometric Combustion, IBR approved
for Sec. Sec.  63.772 and 63.1282.
* * * * *
    (i) * * *
    (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)(1)(iii), 63.771(e), 63.865(b), 63.1281(d),
63.3166(a)(3), 63.3360(e)(1)(iii), 63.3545(a)(3), 63.3555(a)(3),
63.4166(a)(3), 63.4362(a)(3), 63.4766(a)(3), 63.4965(a)(3),
63.5160(d)(1)(iii), 63.9307(c)(2), 63.9323(a)(3), 63.11148(e)(3)(iii),
63.11155(e)(3), 63.11162(f)(3)(iii) and (f)(4), 63.11163(g)(1)(iii) and
(g)(2), 63.11410(j)(1)(iii), 63.11551(a)(2)(i)(C), 63.11646(a)(1)(iii),
table 5 to subpart DDDDD of this part, and table 1 to subpart ZZZZZ of
this part.
* * * * *

Subpart HH--[Amended]

    10. Section 63.760 is amended by:
    a. Revising paragraph (a)(1) introductory text;
    b. Revising paragraph (a)(1)(iii);
    c. Revising paragraph (a)(2);
    d. Revising paragraph (b)(1)(ii);
    e. Revising paragraph (f) introductory text;
    f. Revising paragraph (f)(1);
    g. Revising paragraph (f)(2); and
    h. Adding paragraphs (f)(7), (f)(8), (f)(9) and (f)(10) to 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.
* * * * *
    (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
prior to the point where hydrocarbon liquids enter either the Organic
Liquids Distribution (Non-gasoline) or Petroleum Refineries source
categories.
* * * * *

    (b) * * *
    (1) * * *
    (ii) Each storage vessel;
* * * * *
    (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), (f)(2), and (f)(7) through (f)(10) 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 (f)(6) of this section.
    (1) Except as specified in paragraphs (f)(7) through (10) 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 (10) 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 small glycol dehydration unit and each storage
vessel that is not a storage vessel with the potential for flash
emissions located at a major source, that commenced construction before
August 23, 2011 must achieve compliance no later than 3 years after the
date of publication of the final rule in the Federal Register, except
as provided in Sec.  63.6(i).
    (8) Each affected small glycol dehydration unit and each storage
vessel that is not a storage vessel with the potential for flash
emissions, both 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 the date of publication
of the final rule in the Federal Register, whichever is later.
    (9) A production field facility, as defined in Sec.  63.761,
constructed 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 date of publication
of the final rule in the Federal Register must achieve compliance no
later than 3 years after the date of publication of the final rule in
the Federal Register, except as provided in Sec.  63.6(i).
    (10) Each large glycol dehydration unit, as defined in Sec.
63.761, that has complied with the provisions of this subpart prior to
August 23, 2011 by reducing its benzene emissions to less than 0.9
megagrams per year must achieve compliance no later than 90 days after
the date of publication of the final rule in the Federal Register,
except as provided in Sec.  63.6(i).
* * * * *
    11. Section 63.761 is amended by:
    a. Adding, in alphabetical order, new definitions for the terms
``affirmative defense,'' ``BTEX,'' ``flare,'' ``large glycol
dehydration units'' and ``small glycol dehydration units'';
    b. Revising the definitions for ``associated equipment,''
``facility,'' ``glycol dehydration unit baseline operations,'' and
``temperature monitoring device''; and
    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.
* * * * *
    Facility means any grouping of equipment where hydrocarbon liquids
are processed, upgraded (i.e., remove impurities or other constituents
to meet contract specifications), or stored; or where natural gas is
processed, upgraded, or stored. For the purpose of a major source
determination, facility (including a building, structure, or
installation) means oil and natural gas production and processing
equipment that is located within the boundaries of an individual
surface site as defined in this section. Equipment that is part of a
facility will typically be located within close proximity to other
equipment located at the same facility. Pieces of production equipment
or groupings of equipment located on different oil and gas leases,
mineral fee tracts, lease tracts, subsurface or surface unit areas,
surface fee tracts, surface lease tracts, or separate surface sites,
whether or not connected by a road, waterway, power line or pipeline,
shall not be considered part of the same facility. Examples of
facilities in the oil and natural gas production source category
include, but are not limited to, well sites, satellite tank batteries,
central tank batteries, a compressor station that transports natural
gas to a natural gas processing plant, and natural gas processing
plants.
* * * * *
    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).
* * * * *
    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.
* * * * *
    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).
* * * * *
    Temperature monitoring device means an instrument used to monitor
temperature and having a minimum accuracy of  1 percent of
the temperature being monitored expressed in [deg]C, or
2.5 [deg]C, whichever is greater. The temperature monitoring device may
measure temperature in degrees Fahrenheit or degrees Celsius, or both.
* * * * *
    12. Section 63.762 is revised to read as follows:

Sec.  63.762  Startups and shutdowns.

    (a) The provisions set forth in this subpart shall apply at all
times.
    (b) The owner or operator shall not shut down items of equipment
that are required or utilized for compliance with the provisions of
this subpart during times when emissions are being routed to such items
of equipment, if the shutdown would contravene requirements of this
subpart applicable to such items of equipment. This paragraph does not
apply if the owner or operator must shut down the equipment to avoid
damage due to a contemporaneous startup or shutdown, of the affected
source or a portion thereof.
    (c) During startups and shutdowns, the owner or operator shall
implement measures to prevent or minimize excess emissions to the
maximum extent practical.
    (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 exceedances 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 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 limit, you must timely meet the notification requirements in
paragraph (d)(2) of this section, and must prove by a preponderance of
evidence that:
    (i) The excess emissions:
    (A) Were caused by a sudden, infrequent, and unavoidable failure of
air pollution control and monitoring 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) Were not part of a recurring pattern indicative of inadequate
design, operation, or maintenance; and
    (ii) Repairs were made as expeditiously as possible when the
applicable emission limitations were being exceeded. Off-shift and
overtime labor were used, to the extent practicable to make these
repairs; and
    (iii) The frequency, amount and duration of the excess emissions
(including any bypass) were minimized to the maximum extent practicable
during periods of such emissions; and
    (iv) If the excess emissions 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
excess emissions 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 excess emissions 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 to determine,
correct, and eliminate the primary causes of the malfunction and the
excess emissions resulting from the malfunction event at issue. The
analysis shall also specify, using best monitoring methods and
engineering judgment, the amount of excess emissions that were the
result of the malfunction.
    (2) Notification. The owner or operator of the affected source
experiencing exceedance of its emission limit(s) during a malfunction
shall notify the Administrator by telephone or facsimile transmission
as soon as possible, but no later than two business days after the
initial occurrence of the malfunction, if it wishes to avail itself of
an affirmative defense to civil penalties for that malfunction. The
owner or operator seeking to assert an affirmative defense shall also
submit a written report to the Administrator within 45 days of the
initial occurrence of the exceedance of the standard in this subpart to
demonstrate, with all necessary supporting documentation, that it has
met the requirements set forth in paragraph (d)(1) of this section. The
owner or operator may seek an extension of this deadline for up to 30
additional days by submitting a written request to the Administrator
before the expiration of the 45 day period. Until a request for an
extension has been approved by the Administrator, the owner or operator
is subject to the requirement to submit such report within 45 days of
the initial occurrence of the exceedance.
    13. Section 63.764 is amended by:
    a. Revising paragraph (c)(2) introductory text;
    b. Revising paragraph (e)(1) introductory text;
    c. Revising paragraph (i); and
    d. Adding paragraph (j) to read as follows:

Sec.  63.764  General standards.

* * * * *
    (c) * * *
    (2) For each storage vessel subject to this subpart, the owner or
operator shall comply with the requirements specified in paragraphs
(c)(2)(i) through (iii) of this section.
* * * * *
    (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.
    14. Section 63.765 is amended by:
    a. Revising paragraph (a);
    b. Revising paragraph (b)(1);
    c. Revising paragraph (c)(2); and
    d. Revising paragraph (c)(3) to 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 glycol dehydration unit located at
an area source, that must be controlled as specified in Sec.
63.764(d)(1)(i), 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 small glycol
dehydration unit process vent, as defined in Sec.  63.761, to the limit
determined in Equation 1 of this section. The limit 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] TP23AU11.002

Where:

ELBTEX = Unit-specific BTEX emission limit, megagrams per
year;
1.10 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 = 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), (ii), or (iii) 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 area source dehydration units, benzene emissions are
reduced to a level less than 0.90 megagrams per year.
    (iii) For each small glycol dehydration unit, BTEX emissions are
reduced to a level less than the limit calculated by paragraph
(b)(1)(iii) of this section.
    15. Section 63.766 is amended by:
    a. Revising paragraph (a);
    b. Revising paragraph (b) introductory text;
    c. Revising paragraph (b)(1); and
    d. Revising paragraph (d) to read as follows:

Sec.  63.766  Storage vessel standards.

    (a) This section applies to each storage vessel (as defined in
Sec.  63.761) subject to this subpart.
    (b) The owner or operator of a storage vessel (as defined in Sec.
63.761) shall comply with one of the control requirements specified in
paragraphs (b)(1) and (2) of this section.
    (1) The owner or operator shall equip the affected storage vessel
with a cover that is connected, through a closed-vent system that meets
the conditions specified in Sec.  63.771(c), to a control device or a
combination of control devices that meets any of the conditions
specified in Sec.  63.771(d). The cover shall be designed and operated
in accordance with the requirements of Sec.  63.771(b).
* * * * *
    (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, subpart Kb; or the requirements specified under 40 CFR
part 63 subparts G or CC.
    16. Section 63.769 is amended by:
    a. Revising paragraph (b);
    b. Revising paragraph (c) introductory text; and
    b. Revising paragraph (c)(8) to 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 the requirements specified in 40 CFR part 60, subpart KKK.
    (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 for valves
subject to Sec.  61.247-2(b) a leak is detected if an instrument
reading of 500 ppm or greater is measured.
* * * * *
    (8) Flares, as defined in Sec.  63.761, used to comply with this
subpart shall comply with the requirements of Sec.  63.11(b).
    17. Section 63.771 is amended by:
    a. Revising paragraph (c)(1) introductory text;
    b. Revising the heading of paragraph (d);
    c. Adding paragraph (d) introductory text;
    d. Revising paragraph (d)(1)(i) introductory text;
    e. Revising paragraph (d)(1)(i)(C);
    f. Revising paragraph (d)(1)(ii);
    g. Revising paragraph (d)(1)(iii);
    h. Revising paragraph (d)(4)(i);
    i. Revising paragraph (d)(5)(i);
    j. Revising paragraph (e)(2);
    k. Revising paragraph (e)(3) introductory text;
    l. Revising paragraph (e)(3)(ii); and
    m. Adding paragraph (f) to 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) An enclosed combustion device (e.g., thermal vapor incinerator,
catalytic vapor incinerator, boiler, or process heater) that is
designed and operated in accordance with one of the following
performance requirements:
* * * * *
    (C) For a control device that can demonstrate a uniform combustion
zone temperature during the performance test conducted under Sec.
63.772(e), operates at a minimum temperature of 760 degrees C.
* * * * *
    (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 (e)(3)(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 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). 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; or
    (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); or
    (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.
    18. Section 63.772 is amended by:
    a. Revising paragraph (b) introductory text;
    b. Revising paragraph (b)(1)(ii);
    c. Revising paragraph (b)(2);
    d. Adding paragraph (d);
    e. Revising paragraph (e) introductory text;
    f. Revising paragraphs (e)(1)(i) through (v);
    g. Revising paragraph (e)(2);
    h. Revising paragraph (e)(3) introductory text;
    i. Revising paragraph (e)(3)(i)(B);
    j. Revising paragraph (e)(3)(iv)(C)(1);
    k. Adding paragraphs (e)(3)(v) and (vi);
    l. Revising paragraph (e)(4) introductory text;
    m. Revising paragraph (e)(4)(i);
    n. Revising paragraph (e)(5);
    o. Revising paragraph (f) introductory text;
    p. Adding paragraphs (f)(2) through (f)(6);
    q. Revising paragraph (g) introductory text;
    r. Revising paragraph (g)(1) and paragraph (g)(2) introductory
text;
    s. Revising paragraph (g)(2)(iii);
    t. Revising paragraph (g)(3);
    u. Adding paragraph (h); and
    v. Adding paragraph (i) to 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 (b)(2)(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-GLYCalc\TM\, Version 3.0 or higher,
and the procedures presented in the associated GRI-GLYCalc\TM\
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.
* * * * *
    (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-GLYCalc\TM\, Version 3.0 or higher,
and the procedures presented in the associated GRI-GLYCalc\TM\
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-GLYCalc\TM\, 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. 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.  63.765(b)(1)(iii), or
the BTEX emission limit specified in Sec.  63.771(f)(1) 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, 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.  63.771(f)(1) the owner or operator shall use one of the
following methods: Method 18, 40 CFR part 60, appendix A; ASTM D6420-99
(2004), as specified in Sec.  63.772(a)(1)(ii); 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] TP23AU11.003

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
(2004) 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 at existing major sources
shall be conducted no later than 3 years after the date of publication
of the final rule in the Federal Register. If the owner or operator of
an existing combustion control device at an existing 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 3 years after
the date of publication of the final rule in the Federal Register. 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 tested under Sec.  63.772(e) that
meets the outlet TOC or HAP performance level specified in Sec.
63.771(d)(1)(i)(B) and that

establishes a correlation between firebox or combustion chamber
temperature and the TOC or HAP performance level.
    (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 (e)(4)(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-GLYCalc\TM\, 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 flow rate 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 flow
rate, 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).
    (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 number of days between the current day and
the applicable compliance date. For sources required to meet the
overall 95.0-percent reduction requirement, compliance with the
performance requirements is achieved if the 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).
    (3) If the owner or operator has data for 365 days or more of
operation, compliance is achieved based on the applicable criteria in
paragraphs (g)(3)(i) or (ii) of this section.
    (i) For sources meeting the HAP emission reduction specified in
Sec.  63.771(d)(1)(ii) or (e)(3) the average HAP emission reduction
calculated in paragraph (g)(2)(iii) of this section is equal to or
greater than 95.0 percent.
    (ii) For sources required to meet the BTEX limit under Sec.
63.771(e)(3) or (f)(1), compliance is achieved if the average BTEX
emission reduction calculated in paragraph (g)(2)(iii) of this section
is equal to or greater than the minimum percent reduction identified in
paragraph (g)(1) of this section.
* * * * *
    (h) Performance testing for combustion control devices--
manufacturers' performance test. (1) This paragraph applies to the
performance testing of a combustion control device conducted by the
device manufacturer. The manufacturer shall demonstrate that a specific
model of control device achieves the performance requirements in (h)(7)
of this section by conducting a performance test as specified in
paragraphs (h)(2) through (6) of this section.
    (2) Performance testing shall consist of three one-hour (or longer)
test runs for each of the four following firing rate settings making a
total of 12 test runs per test. Propene (propylene) gas shall be used
for the testing fuel. All fuel analyses shall be performed by an
independent third-party laboratory (not affiliated with the control
device manufacturer or fuel supplier).
    (i) 90-100 percent of maximum design rate (fixed rate).
    (ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70
percent of the maximum design rate. Within the first 5 minutes, ramp
the firing rate to 100 percent of the maximum design rate. Hold at 100
percent for 5 minutes. In the 10-15 minute time range, ramp back down
to 70 percent of the maximum design rate. Repeat three more times for a
total of 60 minutes of sampling.
    (iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30
percent of the maximum design rate. Within the first 5 minutes, ramp
the firing rate to 70 percent of the maximum design rate. Hold at 70
percent for 5 minutes. In the 10-15 minute time range, ramp back down
to 30 percent of the maximum design rate. Repeat three more times for a
total of 60 minutes of sampling.
    (iv) 0-30-0 percent (ramp up, ramp down). Begin the test at 0
percent of the maximum design rate. Within the first 5 minutes, ramp
the firing rate to 100 percent of the maximum design rate. Hold at 30
percent for 5 minutes. In the 10-15 minute time range, ramp back down
to 0 percent of the maximum design rate. Repeat three more times for a
total of 60 minutes of sampling.
    (3) All models employing multiple enclosures shall be tested
simultaneously and with all burners operational. Results shall be
reported for the each enclosure individually and for the average of the
emissions from all interconnected combustion enclosures/chambers.
Control device operating data shall be collected continuously
throughout the performance test using an electronic Data Acquisition
System and strip chart. Data shall be submitted with the test report in
accordance with paragraph (8)(iii) of this section.
    (4) Inlet testing shall be conducted as specified in paragraphs
(h)(4)(i) through (iii) of this section.
    (i) The fuel flow metering system shall be located in accordance
with Method 2A, 40 CFR part 60, appendix A-1, (or other approved
procedure) to measure fuel flow rate at the control device inlet
location. The fitting for filling fuel sample containers shall be
located a minimum of 8 pipe diameters upstream of any inlet fuel flow
monitoring meter.
    (ii) Inlet flow rate shall be determined using Method 2A, 40 CFR
part 60, appendix A-1. Record the start and stop reading for each 60-
minute THC test. Record the gas pressure and temperature at 5-minute
intervals throughout each 60-minute THC test.
    (iii) Inlet fuel sampling shall be conducted in accordance with the
criteria in paragraphs (h)(4)(iii)(A) and (B) of this section.
    (A) At the inlet fuel sampling location, securely connect a
Silonite-coated stainless steel evacuated canister fitted with a flow
controller sufficient to fill the canister over a 1 hour period.
Filling shall be conducted as specified in the following:
    (1) Open the canister sampling valve at the beginning of the total
hydrocarbon (THC) test, and close the canister at the end of the THC
test.
    (2) Fill one canister for each THC test run.
    (3) Label the canisters individually and record on a chain of
custody form.
    (B) Each fuel sample shall be analyzed using the following methods.
The results shall be included in the test report.
    (1) Hydrocarbon compounds containing between one and five atoms of
carbon plus benzene using ASTM D1945-03.
    (2) Hydrogen (H2), carbon monoxide (CO), carbon dioxide
(CO2), nitrogen (N2), oxygen (O2)
using ASTM D1945-03.
    (3) Carbonyl sulfide, carbon disulfide plus mercaptans using ASTM
D5504.
    (4) Higher heating value using ASTM D3588-98 or ASTM D4891-89.
    (5) Outlet testing shall be conducted in accordance with the
criteria in paragraphs (h)(5)(i) through (v) of this section.
    (i) Sampling and flowrate measured in accordance with the
following:
    (A) The outlet sampling location shall be a minimum of 4 equivalent
stack diameters downstream from the highest peak flame or any other
flow disturbance, and a minimum of one equivalent stack diameter
upstream of the exit or any other flow disturbance. A minimum of two
sample ports shall be used.
    (B) Flow rate shall be measured using Method 1, 40 CFR part 60,
Appendix 1, for determining flow measurement traverse point location;
and Method 2, 40 CFR part 60, Appendix 1, shall be used to measure duct
velocity. If low flow conditions are encountered (i.e., velocity
pressure differentials less than 0.05 inches of water) during the
performance test, a more sensitive manometer shall be used to obtain an
accurate flow profile.
    (ii) Molecular weight shall be determined as specified in
paragraphs (h)(4)(iii)(B), (h)(5)(ii)(A), and (h)(5)(ii)(B) of this
section.
    (A) An integrated bag sample shall be collected during the Method
4, 40 CFR part 60, Appendix A, moisture test. Analyze the bag sample
using a gas chromatograph-thermal conductivity detector (GC-TCD)
analysis meeting the following criteria:
    (1) Collect the integrated sample throughout the entire test, and
collect

representative volumes from each traverse location.
    (2) The sampling line shall be purged with stack gas before opening
the valve and beginning to fill the bag.
    (3) The bag contents shall be kneaded or otherwise vigorously mixed
prior to the GC analysis.
    (4) The GC-TCD calibration procedure in Method 3C, 40 CFR part 60,
Appendix A, shall be modified by using EPAAlt-045 as follows: For the
initial calibration, triplicate injections of any single concentration
must agree within 5 percent of their mean to be valid. The calibration
response factor for a single concentration re-check must be within 10
percent of the original calibration response factor for that
concentration. If this criterion is not met, the initial calibration
using at least three concentration levels shall be repeated.
    (B) Report the molecular weight of: O2, CO2,
methane (CH4), and N2 and include in the test report
submitted under Sec.  63.775(d)(iii). Moisture shall be determined
using Method 4, 40 CFR part 60, Appendix A. Traverse both ports with
the Method 4, 40 CFR part 60, Appendix A, sampling train during each
test run. Ambient air shall not be introduced into the Method 3C, 40
CFR part 60, Appendix A, integrated bag sample during the port change.
    (iii) Carbon monoxide shall be determined using Method 10, 40 CFR
part 60, Appendix A. The test shall be run at the same time and with
the sample points used for the EPA Method 25A, 40 CFR part 60, Appendix
A, testing. An instrument range of 0-10 per million by volume-dry
(ppmvd) shall be used.
    (iv) Visible emissions shall be determined using Method 22, 40 CFR
part 60, Appendix A. The test shall be performed continuously during
each test run. A digital color photograph of the exhaust point, taken
from the position of the observer and annotated with date and time,
will be taken once per test run and the four photos included in the
test report.
    (6) Total hydrocarbons (THC) shall be determined as specified by
the following criteria:
    (i) Conduct THC sampling using Method 25A, 40 CFR part 60, Appendix
A, except the option for locating the probe in the center 10 percent of
the stack shall not be allowed. The THC probe must be traversed to 16.7
percent, 50 percent, and 83.3 percent of the stack diameter during the
testing.
    (ii) A valid test shall consist of three Method 25A, 40 CFR part
60, Appendix A, tests, each no less than 60 minutes in duration.
    (iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane)
measurement range is preferred; as an alternative a 0-30 ppmvw (as
carbon) measurement range may be used.
    (iv) Calibration gases will be propane in air and be certified
through EPA Protocol 1--``EPA Traceability Protocol for Assay and
Certification of Gaseous Calibration Standards,'' September 1997, as
amended August 25, 1999, EPA-600/R-97/121 (or more recent if updated
since 1999).
    (v) THC measurements shall be reported in terms of ppmvw as
propane.
    (vi) THC results shall be corrected to 3 percent CO2, as
measured by Method 3C, 40 CFR part 60, Appendix A.
    (vii) Subtraction of methane/ethane from the THC data is not
allowed in determining results.
    (7) Performance test criteria:
    (i) The control device model tested must meet the criteria in
paragraphs (h)(7)(i)(A) through (C) of this section:
    (A) Method 22, 40 CFR part 60, Appendix A, results under paragraph
(h)(5)(v) of this section with no indication of visible emissions, and
    (B) Average Method 25A, 40 CFR part 60, Appendix A, results under
paragraph (h)(6) of this section equal to or less than 10.0 ppmvw THC
as propane corrected to 3.0 percent CO2, and
    (C) Average CO emissions determined under paragraph (h)(5)(iv) of
this section equal to or less than 10 parts ppmvd, corrected to 3.0
percent CO2.
    (ii) The manufacturer shall determine a maximum inlet gas flow rate
which shall not be exceeded for each control device model to achieve
the criteria in paragraph (h)(7)(i) of this section.
    (iii) A control device meeting the criteria in paragraphs
(h)(7)(i)(A) through (C) of this section will have demonstrated a
destruction efficiency of 98.0 percent for HAP regulated under this
subpart.
    (8) The owner or operator of a combustion control device model
tested under this section shall submit the information listed in
paragraphs (h)(8)(i) through (iii) of this section in the test report
required under Sec.  63.775(d)(1)(iii).
    (i) Full schematic of the control device and dimensions of the
device components.
    (ii) Design net heating value (minimum and maximum) of the device.
    (iii) Test fuel gas flow range (in both mass and volume). Include
the minimum and maximum allowable inlet gas flow rate.
    (iv) Air/stream injection/assist ranges, if used.
    (v) The test parameter ranges listed in paragraphs (h)(8)(v)(A)
through (O) of this section, as applicable for the tested model.
    (A) Fuel gas delivery pressure and temperature.
    (B) Fuel gas moisture range.
    (C) Purge gas usage range.
    (D) Condensate (liquid fuel) separation range.
    (E) Combustion zone temperature range. This is required for all
devices that measure this parameter.
    (F) Excess combustion air range.
    (G) Flame arrestor(s).
    (H) Burner manifold pressure.
    (I) Pilot flame sensor.
    (J) Pilot flame design fuel and fuel usage.
    (K) Tip velocity range.
    (L) Momentum flux ratio.
    (M) Exit temperature range.
    (N) Exit flow rate.
    (O) Wind velocity and direction.
    (vi) The test report shall include all calibration quality
assurance/quality control data, calibration gas values, gas cylinder
certification, and strip charts annotated with test times and
calibration values.
    (i) Compliance demonstration for combustion control devices--
manufacturers' performance test. This paragraph applies to the
demonstration of compliance for a combustion control device tested
under the provisions in paragraph (h) of this section. 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),
by installing a device tested under paragraph (h) of this section and
complying with the following criteria:
    (1) The inlet gas flow rate shall meet the range specified by the
manufacturer. Flow rate shall be measured as specified in Sec.
63.773(d)(3)(i)(H)(1).
    (2) A pilot flame shall be present at all times of operation. The
pilot flame shall be monitored in accordance with Sec.
63.773(d)(3)(i)(H)(2).
    (3) Devices shall be operated with no visible emissions, except for
periods not to exceed a total of 5 minutes during any 2 consecutive
hours. A visible emissions test using Method 22, 40 CFR part 60,
Appendix A, shall be performed monthly. The observation period shall be
2 hours and shall be used according to Method 22.
    (4) Compliance with the operating parameter limit is achieved when
the following criteria are met:
    (i) The inlet gas flow rate monitored under paragraph (i)(1) of
this section is equal to or below the maximum established by the
manufacturer; and
    (ii) The pilot flame is present at all times; and
    (iii) During the visible emissions test performed under paragraph
(i)(3) of this

section the duration of visible emissions does not exceed a total of 5
minutes during the observation period. Devices failing the visible
emissions test shall follow the requirements in paragraphs
(i)(4)(iii)(A) and (B) of this section.
    (A) Following the first failure, the fuel nozzle(s) and burner
tubes shall be replaced.
    (B) If, following replacement of the fuel nozzle(s) and burner
tubes as specified in paragraph (i)(4)(iii)(A), the visible emissions
test is not passed in the next scheduled test, either a performance
test shall be performed under paragraph (e) of this section, or the
device shall be replaced with another control device whose model was
tested, and meets, the requirements in paragraph (h) of this section.
    19. Section 63.773 is amended by:
    a. Adding paragraph (b);
    b. Revising paragraph (d)(1) introductory text;
    c. Revising paragraph (d)(1)(ii) and adding paragraphs (d)(1)(iii)
and (iv);
    d. Revising paragraphs (d)(2)(i) and (d)(2)(ii);
    e. Revising paragraphs (d)(3)(i)(A) and (B);
    f. Revising paragraphs (d)(3)(i)(D) and (E);
    g. Revising paragraphs (d)(3)(i)(F)(1) and (2);
    h. Revising paragraph (d)(3)(i)(G);
    i. Adding paragraph (d)(3)(i)(H);
    j. Revising paragraph (d)(4);
    k. Revising paragraph (d)(5)(i);
    l. Revising paragraphs (d)(5)(ii)(A) through (C);
    m. Revising paragraphs (d)(6)(ii) and (iii);
    n. Adding paragraph (d)(6)(vi);
    o. Revising paragraph (d)(8)(i)(A); and
    p. Revising paragraph (d)(8)(ii) to read as follows:

Sec.  63.773  Inspection and monitoring requirements.

* * * * *
    (b) The owner or operator of a control device whose model was
tested under Sec.  63.772(h) shall develop an inspection and
maintenance plan for each control device. At a minimum, the plan shall
contain the control device manufacturer's recommendations for ensuring
proper operation of the device. Semi-annual inspections shall be
conducted for each control device with maintenance and replacement of
control device components made in accordance with the plan.
* * * * *
    (d) Control device monitoring requirements. (1) For each control
device, except as provided for in paragraph (d)(2) of this section, the
owner or operator shall install and operate a continuous parameter
monitoring system in accordance with the requirements of paragraphs
(d)(3) through (9) of this section. Owners or operators that install
and operate a flare in accordance with Sec.  63.771(d)(1)(iii) or
(f)(1)(iii) are exempt from the requirements of paragraphs (d)(4) and
(5) of this section. The continuous monitoring system shall be designed
and operated so that a determination can be made on whether the control
device is achieving the applicable performance requirements of Sec.
63.771(d), (e)(3) or (f)(1). Each continuous parameter monitoring
system shall meet the following specifications and requirements:
* * * * *
    (ii) A site-specific monitoring plan must be prepared that
addresses the monitoring system design, data collection, and the
quality assurance and quality control elements outlined in paragraph
(d) of this section and in Sec.  63.8(d). Each CPMS must be installed,
calibrated, operated, and maintained in accordance with the procedures
in your approved site-specific monitoring plan. Using the process
described in Sec.  63.8(f)(4), you may request approval of monitoring
system quality assurance and quality control procedures alternative to
those specified in paragraphs (d)(1)(ii)(A) through (E) of this section
in your site-specific monitoring plan.
    (A) The performance criteria and design specifications for the
monitoring system equipment, including the sample interface, detector
signal analyzer, and data acquisition and calculations;
    (B) Sampling interface (e.g., thermocouple) location such that the
monitoring system will provide representative measurements;
    (C) Equipment performance checks, system accuracy audits, or other
audit procedures;
    (D) Ongoing operation and maintenance procedures in accordance with
provisions in Sec.  63.8(c)(1) and (c)(3); and
    (E) Ongoing reporting and recordkeeping procedures in accordance
with provisions in Sec.  63.10(c), (e)(1), and (e)(2)(i).
    (iii) The owner or operator must conduct the CPMS equipment
performance checks, system accuracy audits, or other audit procedures
specified in the site-specific monitoring plan at least once every 12
months.
    (iv) The owner or operator must conduct a performance evaluation of
each CPMS in accordance with the site-specific monitoring plan.
    (2) * * *
    (i) Except for control devices for small glycol dehydration units,
a boiler or process heater in which all vent streams are introduced
with the primary fuel or is used as the primary fuel; or
    (ii) Except for control devices for small glycol dehydration units,
a boiler or process heater with a design heat input capacity equal to
or greater than 44 megawatts.
    (3) * * *
    (i) * * *
    (A) For a thermal vapor incinerator that demonstrates during the
performance test conducted under Sec.  63.772(e) that the combustion
zone temperature is an accurate indicator of performance, a temperature
monitoring device equipped with a continuous recorder. The monitoring
device shall have a minimum accuracy of  1 percent of the
temperature being monitored in degrees C, or  2.5 degrees
C, whichever value is greater. The temperature sensor shall be
installed at a location representative of the combustion zone
temperature.
    (B) For a catalytic vapor incinerator, a temperature monitoring
device equipped with a continuous recorder. The device shall be capable
of monitoring temperature at two locations and have a minimum accuracy
of  1 percent of the temperature being monitored in degrees
C, or  2.5 degrees C, whichever value is greater. One
temperature sensor shall be installed in the vent stream at the nearest
feasible point to the catalyst bed inlet and a second temperature
sensor shall be installed in the vent stream at the nearest feasible
point to the catalyst bed outlet.
* * * * *
    (D) For a boiler or process heater a temperature monitoring device
equipped with a continuous recorder. The temperature monitoring device
shall have a minimum accuracy of  1 percent of the
temperature being monitored in degrees C, or  2.5 degrees
C, whichever value is greater. The temperature sensor shall be
installed at a location representative of the combustion zone
temperature.
    (E) For a condenser, a temperature monitoring device equipped with
a continuous recorder. The temperature monitoring device shall have a
minimum accuracy of  1 percent of the temperature being
monitored in degrees C, or  2.8 degrees C, whichever value
is greater. The temperature sensor shall be installed at a location in
the exhaust vent stream from the condenser.
    (F) * * *
    (1) A continuous parameter monitoring system to 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. The mechanical connections
for leakage must be checked at least every month, and a visual
inspection must be performed at least every 3 months of all components
of the flow CPMS for physical and operational integrity and all
electrical connections for oxidation and galvanic corrosion if your
flow CPMS is not equipped with a redundant flow sensor; and
    (2) A continuous parameter monitoring system to measure and record
the average carbon bed temperature for the duration of the carbon bed
steaming cycle and to measure the actual carbon bed temperature after
regeneration and within 15 minutes of completing the cooling cycle. The
temperature monitoring device shall have a minimum accuracy of  1 percent of the temperature being monitored in degrees C, or
 2.5 degrees C, whichever value is greater.
    (G) For a nonregenerative-type carbon adsorption system, the owner
or operator shall monitor the design carbon replacement interval
established using a performance test performed in accordance with Sec.
63.772(e)(3) shall be based on the total carbon working capacity of the
control device and source operating schedule.
    (H) For a control device model whose model is tested under Sec.
63.772(h):
    (1) A continuous monitoring system that measures gas flow rate at
the inlet to the control device. The monitoring instrument shall have
an accuracy of plus or minus 2 percent or better.
    (2) A heat sensing monitoring device equipped with a continuous
recorder that indicates the continuous ignition of the pilot flame.
* * * * *
    (4) Using the data recorded by the monitoring system, except for
inlet gas flow rate, the owner or operator must calculate the daily
average value for each monitored operating parameter for each operating
day. 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.
    (5) * * *
    (i) The owner or operator shall 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.  63.771(d)(1), (e)(3)(ii) or (f)(1).
Each minimum or maximum operating parameter value shall be established
as follows:
    (A) If the owner or operator conducts performance tests in
accordance with the requirements of Sec.  63.772(e)(3) to demonstrate
that the control device achieves the applicable performance
requirements specified in Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1),
then the minimum operating parameter value or the maximum operating
parameter value shall be established 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.
    (B) If the owner or operator uses a condenser design analysis in
accordance with the requirements of Sec.  63.772(e)(4) to demonstrate
that the control device achieves the applicable performance
requirements specified in Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1),
then the minimum operating parameter value or the maximum operating
parameter value shall be established based on the condenser design
analysis and may be supplemented by the condenser manufacturer's
recommendations.
    (C) If the owner or operator operates a control device where the
performance test requirement was met under Sec.  63.772(h) to
demonstrate that the control device achieves the applicable performance
requirements specified in Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1),
then the maximum inlet gas flow rate shall be established based on the
performance test and supplemented, as necessary, by the manufacturer
recommendations.
    (ii) * * *
    (A) If the owner or operator conducts a performance test in
accordance with the requirements of Sec.  63.772(e)(3) to demonstrate
that the condenser achieves the applicable performance requirements in
Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1), then the condenser
performance curve shall 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.
    (B) If the owner or operator uses a control device design analysis
in accordance with the requirements of Sec.  63.772(e)(4)(i) to
demonstrate that the condenser achieves the applicable performance
requirements specified in Sec.  63.771(d)(1), (e)(3)(ii) or (f)(1),
then the condenser performance curve shall be based on the condenser
design analysis and may be supplemented by the control device
manufacturer's recommendations.
    (C) As an alternative to paragraph (d)(5)(ii)(B) of this section,
the 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-GLYCalc\TM\, Version 3.0 or higher, to generate a condenser
performance curve.
* * * * *
    (6) * * *
    (ii) For sources meeting Sec.  63.771(d)(1)(ii), an excursion
occurs when the 365-day average condenser efficiency calculated
according to the requirements specified in Sec.  63.772(g)(2)(iii) is
less than 95.0 percent. For sources meeting Sec.  63.771(f)(1), an
excursion occurs when the 365-day average condenser efficiency
calculated according to the requirements specified in Sec.
63.772(g)(2)(iii) is less than 95.0 percent of the identified 365-day
required percent reduction.
    (iii) For sources meeting Sec.  63.771(d)(1)(ii), if an owner or
operator has less than 365 days of data, an excursion occurs when the
average condenser efficiency calculated according to the procedures
specified in Sec.  63.772(g)(2)(iii)(A) or (B) is less than 90.0
percent. For sources meeting Sec.  63.771(d)(1)(ii), an excursion
occurs when the 365-day average condenser efficiency calculated
according to the requirements specified in Sec.  63.772(g)(2)(iii) is
less than the identified 365-day required percent reduction.
* * * * *
    (vi) For control device whose model is tested under Sec.  63.772(h)
an excursion occurs when:
    (A) The inlet gas flow rate exceeds the maximum established during
the test conducted under Sec.  63.772(h).
    (B) Failure of the monthly visible emissions test conducted under
Sec.  63.772(i)(3) occurs.
* * * * *
    (8) * * *
    (i) * * *
    (A) During a malfunction when the affected facility is operated
during such

period in accordance with Sec.  63.6(e)(1); or
* * * * *
    (ii) For each control device, or combinations of control devices
installed on the same emissions unit, one excused excursion is allowed
per semiannual period for any reason. The initial semiannual period is
the 6-month reporting period addressed by the first Periodic Report
submitted by the owner or operator in accordance with Sec.  63.775(e)
of this subpart.
* * * * *
    20. Section 63.774 is amended by:
    a. Revising paragraph (b)(3) introductory text;
    b. Removing and reserving paragraph (b)(3)(ii);
    c. Revising paragraph (b)(4)(ii) introductory text;
    d. Adding paragraph (b)(4)(ii)(C);
    e. Adding paragraph (b)(7)(ix); and
    f. Adding paragraphs (g) through (i) to read as follows:

Sec.  63.774  Recordkeeping requirements.

* * * * *
    (b) * * *
    (3) Records specified in Sec.  63.10(c) for each monitoring system
operated by the owner or operator in accordance with the requirements
of Sec.  63.773(d). Notwithstanding the requirements of Sec.  63.10(c),
monitoring data recorded during periods identified in paragraphs
(b)(3)(i) through (b)(3)(iv) of this section shall not be included in
any average or percent leak rate computed under this subpart. Records
shall be kept of the times and durations of all such periods and any
other periods during process or control device operation when monitors
are not operating or failed to collect required data.
* * * * *
    (ii) [Reserved]
* * * * *
    (4) * * *
    (ii) Records of the daily average value of each continuously
monitored parameter for each operating day determined according to the
procedures specified in Sec.  63.773(d)(4) of this subpart, except as
specified in paragraphs (b)(4)(ii)(A) through (C) of this section.
* * * * *
    (C) For control device whose model is tested under Sec.  63.772(h),
the records required in paragraph (h) of this section.
* * * * *
    (7) * * *
    (ix) Records identifying the carbon replacement schedule under
Sec.  63.771(d)(5) and records of each carbon replacement.
* * * * *
    (g) The owner or operator of an affected source subject to this
subpart shall maintain records of the occurrence and duration of each
malfunction of operation (i.e., process equipment) or the air pollution
control equipment and monitoring equipment. The owner or operator shall
maintain records of actions taken during periods of malfunction to
minimize emissions in accordance with Sec.  63.764(a), including
corrective actions to restore malfunctioning process and air pollution
control and monitoring equipment to its normal or usual manner of
operation.
    (h) Record the following when using a control device whose model is
tested under Sec.  63.772(h) to comply with Sec.  63.771(d), (e)(3)(ii)
and (f)(1):
    (1) All visible emission readings and flowrate measurements made
during the compliance determination required by Sec.  63.772(i); and
    (2) All hourly records and other recorded periods when the pilot
flame is absent.
    (i) The date the semi-annual maintenance inspection required under
Sec.  63.773(b) is performed. Include a list of any modifications or
repairs made to the control device during the inspection and other
maintenance performed such as cleaning of the fuel nozzles.
    21. Section 63.775 is amended by:
    a. Revising paragraph (b)(1);
    b. Revising paragraph (b)(6);
    c. Removing and reserving paragraph (b)(7);
    d. Revising paragraph (c)(1);
    e. Revising paragraph (c)(6);
    f. Revising paragraph (c)(7)(i);
    g. Revising paragraph (d)(1)(i);
    h. Revising paragraph (d)(1)(ii) introductory text;