This would indicate that the emissions from low production well sites
could be similar to that of non-low production well sites. We also
believe that this type of well may be developed for leasing purposes
but is typically unmanned and not visited as often as other well sites
that would allow fugitive emissions to go undetected. We did not
receive data showing that low production well sites have lower GHG
(principally as methane) or VOC emissions other than non-low production
well sites. In fact, the data that were provided indicated that the
potential emissions from these well sites could be as significant as
the emissions from non-low production well sites because the type of
equipment and the well pressures are more than likely the same. In
discussions with us, stakeholders indicated that well site fugitive
emissions are not correlated with levels of production, but rather
based on the number of pieces of equipment and components. Therefore,
we believe that the fugitive emissions from low production and non-low
production well sites are comparable.
    Based on these considerations and, in particular, the large number
of low production wells and the similarities between well sites with
production greater than 15 boe per day and low production well sites in
terms of the components that could leak and the associated emissions,
we are not exempting low production well sites from the fugitive
emissions monitoring program. Therefore, the collection of fugitive
emissions components at all new, modified or reconstructed well sites
is an affected facility and must meet the requirements of the fugitive
emissions monitoring program.
c. Monitoring Using Method 21
    The EPA's analysis for the proposed rule found OGI to be more cost-
effective at detecting fugitive emissions than the traditional protocol
for that purpose, Method 21, and the EPA, therefore, identified OGI as
the BSER for monitoring fugitive emissions at well sites. See 80 FR
56636, September 18, 2015. The EPA solicited comment on whether to
allow Method 21 as an alternative fugitive emissions monitoring method
to OGI. 80 FR 56638, September 18, 2015. We also solicited comment on
the repair threshold for components that are found to have fugitive
emissions using Method 21. Id.
    Numerous industry, state, and environmental commenters indicated
that Method 21 is preferred or should be allowed as an alternative to
OGI, citing availability, costs, and training associated with OGI.
    Several commenters indicated that the EPA should set the Method 21
fugitive emissions repair threshold at 10,000 ppm, the level at which
our recent work indicates that fugitive emissions are generally
detectable using OGI instrumentation provided that the right operating
conditions (e.g., wind speed and background temperature) are present.
80 FR 56635, September 18, 2015. Some commenters stated that the repair
threshold should be 500 ppm to achieve a high level of fugitive
emission reductions while other commenters state that a 500 ppm repair
threshold would target fugitive emissions that would not provide
meaningful reductions.
    The issue of the repair threshold when Method 21 is used is a
critical decision. As discussed in the preamble to the proposed rule,
Method 21, at an appropriate repair threshold, is capable of achieving
the same or better emission reductions as OGI. However, at proposal, we
determined that Method 21 was not cost-effective at a semiannual
monitoring frequency with a repair threshold of 500 ppm.
    While we agree with the importance of allowing the use of Method 21
as an alternative, we need to ensure that its use does not result in
fewer emissions reductions than what would otherwise be achieved using
OGI, which is the BSER based on our analysis. Available data show that
OGI can detect fugitive emissions at a concentration of at least 10,000
ppm when restricting its use during certain environmental conditions

such as high wind speeds. Due to the dynamic nature for the OGI
detection capabilities, OGI may also image emissions at a lower
concentration when environmental conditions are ideal. Because an OGI
instrument can only visualize emissions and not the corresponding
concentration, any components with visible emissions, including those
emissions that are less than 10,000 ppm, would be repaired. Method 21
is capable of detecting fugitive emissions at concentrations well below
10,000 ppm. However, if the repair threshold was set at 10,000 ppm, an
owner or operator would not have to repair any leaks that are less than
10,000 ppm, thereby foregoing the reductions that would otherwise be
achieved by using the OGI. For the reason outlined in this section,
10,000 ppm is not an appropriate repair threshold for Method 21.
    Using information provided by commenters, we evaluated the methane
and VOC emission reductions associated with the use of Method 21 at
repair thresholds of 10,000 ppm and 500 ppm, the two levels recommended
by the various commenters. We used AP-42 emission factors to determine
the emissions from fugitive emissions components that were found to be
leaking using a Method 21 instrument and concluded that emissions
reductions are lower than when OGI is used to survey the same
components. The lower emission reductions are due to fugitive emissions
with a concentration lower than 10,000 ppm not being found using the
Method 21 instrument when it is calibrated to detect emissions at a
threshold of 10,000 ppm or greater.
    We then calculated the emission reductions that result from using a
Method 21 instrument to conduct a monitoring survey at a repair
threshold of 500 ppm. At this threshold, the operator would have to
repair every component found to have fugitive emissions over 500 ppm
threshold. This results in emission reductions greater than the
emissions reductions that would be achieved if OGI were used instead.
For the reasons stated in this section, using Method 21 to conduct
monitoring surveys at a repair threshold of 500 ppm is better than, or
at least equivalent to, using OGI to conduct the same survey; we are
allowing it in the final rule as an alternative to the use of OGI. We
acknowledge that the cost of conducting a survey using Method 21 may be
more expensive than using OGI; however, some owners or operators may
still chose to use Method 21 for convenience or due to the lack of
availability of OGI instruments or trained personnel. Therefore, to
ensure that it achieves at least the level of emission reduction to be
achieved using the OGI, the final rule allows the use of Method 21 with
a repair threshold of 500 ppm.
    Based on interest in having Method 21 as an approved alternative,
we are finalizing it as an alternative to OGI. Allowing Method 21 as an
alternative will address some of the uncertainty expressed by small
entities that indicated a concern with needing to purchase an OGI
instrument or hire trained OGI contractors to perform their monitoring
surveys. We are finalizing Method 21 as an alternative to OGI for
monitoring fugitive emissions components at a repair threshold of an
instrument reading of 500 ppm or greater. We are also finalizing
specific recordkeeping and reporting requirements when Method 21 is
used to perform a monitoring survey.
d. Shifting of Monitoring Frequency Based on Performance
    The EPA proposed shifting monitoring frequencies (ranging from
annual to quarterly monitoring) based on the percentage of components
that are found to have fugitive emissions during a monitoring survey.
We solicited comment on the proposed monitoring approach, including the
proposed metrics of one percent and three percent to determine
monitoring frequency or whether the monitoring frequency thresholds
should be based on a specific number of components that are found to
have fugitive emissions. In addition, the EPA solicited comment on
whether a performance-based frequency or a fixed-frequency program was
more appropriate.
    Most commenters opposed performance-based monitoring frequency.
They raised specific concerns that performance-based monitoring and
shifting monitoring frequencies would be costly, time-consuming, and
impose a complex administrative burden for the industry and states. For
example, commenters pointed out that an owner may have hundreds or even
thousands of well sites and a potentially ever-changing survey schedule
for each of those sites would present an untenable logistical hurdle.
Most of the commenters stated that the EPA should finalize a fixed
monitoring frequency to provide a level of certainty to owners and
operators for planning future schedules of survey crews.
    The EPA considered these comments and agrees that imposing a
performance-based monitoring schedule would require operators to
develop an extensive administrative program to ensure compliance. Under
the performance-based monitoring, owners and operators would need to
count all of the components at the well sites, affix identification
tags on each component or develop detailed piping and instrument
diagram. During each monitoring survey, owners and operators would need
to calculate the percentage of leaking fugitive emissions components to
determine the next monitoring frequency schedule.
    We also agree that the shifting monitoring frequencies could cause
regulated entities additional administrative burden to determine
compliance since the monitoring frequencies could change each year, but
the correct frequency may not be reflected in the operating permit.
This could also result in fugitive emissions being undetected longer
due to less frequent monitoring. We believe that the potential for a
performance-based approach to encourage greater compliance is
outweighed in this case by these additional burdens and the complexity
it would add. Therefore, the EPA is finalizing a fixed-frequency
monitoring instead of performance-based monitoring.
e. Fugitive Emissions Components Repair and Resurvey
    The EPA proposed that components that are a source of fugitive
emissions must be repaired or replaced as soon as practicable and, in
any case, no later than 15 calendar days after detection of the
fugitive emissions. For sources of fugitive emissions that cannot be
repaired within 15 days of finding the emissions, due to technical
infeasibility or unsafe conditions, the EPA proposed that the
components could be placed on a delay of repair until the next
scheduled shutdown or within six months, whichever is earlier. We also
proposed that a repaired fugitive emissions component be resurveyed
within 15 days of the repair. The EPA solicited comment on all three
aspects.
    Commenters voiced various opinions regarding the requirements. Many
commenters shared concerns that the 15-day window for repairs is too
short, due to factors such as remoteness of equipment locations,
unsuccessful repair attempts, and multiple components needing repair.
Other commenters preferred the 15-day window, in the interest of
achieving immediate mitigation of health and safety risks and alignment
with standards in several states.
    Multiple commenters provided comments on the proposed delay of

repair standards, including concerns about delays lasting longer than
six months due to availability of supplies needed to complete repairs
and information regarding the frequency of delayed repairs. Some
commenters also indicated that in some cases, requiring prompt repairs
could lead to more emissions than if repairs were able to be delayed,
for example if a well shut-in or vent blow-down is required.
    Regarding the 15-day window to resurvey repairs to fugitive
emissions components, multiple commenters stated that the final rule
should allow 30 days for the resurvey, due to the potential need for
specialized personnel for the resurvey, while others considered 15 days
to be adequate. Regarding performance of the resurvey, many commenters
also suggested that soap bubbles, as specified in section 8.3.3 of
Method 21, be allowed to determine if the components have been
repaired.
    After considering the comments above, the EPA agrees that repairs
for some sources of fugitive emissions at a well site may take multiple
attempts or require additional equipment that is not readily available
and may take longer than 15 days to repair. Well sites, unlike chemical
plants or refineries, may be located in remote areas and it is unlikely
that they would have warehouses or maintenance shops nearby where spare
equipment or tools are kept that would be needed to perform repairs
within 15 days. We also recognize that fugitive emissions must be
alleviated as soon as practicable. We believe that allowing an
additional 15 days for repair would give owners and operators enough
time to get the parts or the personnel needed to repair or replace the
components that could not be repaired during the initial monitoring
survey. Therefore, we are finalizing 30 days for the repair of fugitive
emissions sources. However, we do recognize that some state LDAR
programs require repairs to be made within 5 to 15 days of finding a
leak. We encourage operators to continue to fix leaks within that
timeframe, since the majority of leaks are fixed when they are found.
We do expect that the majority of components will not need the
additional 15 days for repair.
    The EPA agrees, based on our review of the comments, that only a
small percentage of components would not be able to be repaired during
that 30 day period. We also agree that a complete well shutdown or a
well shut-in may be necessary to repair certain components, such as
components on the wellhead, and this could result in greater emissions
than what would be emitted by the leaking component. The EPA does not
agree that unavailability of supplies or custom parts is a
justification for delaying repair (i.e., beyond the 30 days for repair
provided in this final rule) since the operator can plan for repair of
fugitive emission components by having stock readily accessible or
obtaining the parts within 30 days after finding the fugitive
emissions.
    Based on available information, it may be two years before a well
is shut-in or shutdown. Therefore, to avoid the excess emissions (and
cost) of prematurely forcing a shutdown, we are amending the rule to
allow 2 years to fix a leak where it is determined to be technically
infeasible to repair within 30 days; however, if an unscheduled or
emergency vent blowdown, compressor station shutdown, well shutdown, or
well shut-in occurs during the delay of repair period, the fugitive
emissions components would need to be fixed at that time. The owner or
operator will have to record the number and types of components that
are placed on delay of repair and record an explanation for each delay
of repair.
    Method 21 allows a user to spray a soap solution on components that
are operating under certain conditions (e.g., no continuous moving
parts or no surface temperatures above the boiling point or below the
freezing point of the soap solution) to determine if any soap bubbles
form. If no bubbles form, the components are deemed to be operating
with no detected emissions. We note that spraying soap solution to
confirm whether a component has been repaired may not work for all
fugitive emissions components, such as a leak found under the hood of
the thief hatch because it would be difficult to apply the soap
solution or observe bubbles. However, we believe that this alternative
will provide some owners and operators a simple, low cost way to
confirm that a fugitive emissions component has been repaired. This
would also allow the resurveys to be performed by the same personnel
that completed the repairs instead of other certified monitoring
personnel or hired contractors that would have to come back to verify
the repairs. Therefore, we are finalizing the use of the alternative
screening procedures specified in Section 8.3.3 of Method 21 for
resurveying repaired fugitive emissions components, where appropriate.
    For owners or operators that cannot use soap spray to verify
repairs, we are allowing an additional 30 days for resurvey of the
repaired fugitive emissions components, to allow time for contractors
or designated OGI personnel to perform the resurvey because they are
not typically the same personnel that would perform the repairs.
f. Definition of ``Fugitive Emission Component''
    As just discussed, we proposed monitoring, repair, and resurvey of
``fugitive emission components.'' The EPA solicited comment on the
proposed definition of fugitive emissions components. Commenters
indicated that, as proposed, the fugitive emissions component
definition is too broad and vague, because it contains both equipment
and component types, and suggested that the EPA modify the definition
to be more targeted and easier for states and other regulatory
authorities to determine compliance, and recommended other definitions,
such as that used by the state of Colorado.
    The EPA agrees with commenters that, as proposed, the fugitive
emissions component definition may cause confusion due to inclusion of
equipment types, such as uncontrolled storage vessels that are
potential sources of vented emissions (as opposed to fugitive
emissions), in the definition.
    Therefore, we are finalizing changes to the definition to remove
equipment types and identify specific components, such as valves and
flanges, that have the potential to be sources of fugitive emissions
and that, when surveyed and repaired, would significantly reduce GHG
and VOC emissions. This targeted list will remove the ambiguity of the
proposed definition and will allow owners and operators to consistently
identify fugitive emissions at well sites. We are finalizing the
definition for fugitive emissions components in Sec.  60.4530a of this
final rule.
    As finalized, the definition also aligns closely with other states'
and federal agencies' definitions of fugitive emissions components by
targeting similar components to the components in those definitions.
Owners and operators can therefore monitor one set of components while
complying with the requirements of this final rule and other state or
federal fugitive emissions monitoring programs.
g. Timing of the Initial Monitoring Survey
    The EPA proposed that the initial monitoring be conducted within 30
days after the initial startup of the first well completion or
modification of a well site. EPA solicited comment on whether the
proposal provides an appropriate amount of time to begin conducting
fugitive emissions monitoring. We received a wide variety of comments

and suggestions for the appropriate time for fugitive emissions
monitoring to begin.
    Several commenters indicated that initial monitoring should begin
after production starts, because time is needed to close out the
drilling activities. The commenters further stated that completion
activities and the transition from completion to production at well
sites is unpredictable and temporary completion equipment may still be
onsite 30 days after the ``initial startup of the first well
completion.'' One commenter indicated that production may not begin
immediately after a well completion, so initial monitoring should not
begin until after production starts.
    The EPA acknowledges that at the time of a well completion all of
the associated permanent equipment may not be present and conducting
the initial monitoring survey may not capture all of the fugitive
emissions components that would be in operation during production. In
addition, we believe it is important to conduct the initial survey soon
after the permanent equipment is in place to catch any improperly
installed or defective equipment that may have substantial fugitive
emissions immediately after installation. We believe that the permanent
equipment will be in place at the startup of production (i.e., the
initial flow following the end of the flowback when there is continuous
recovery of saleable quality gas). Therefore, the startup of production
more accurately reflects the start of normal operations and would
capture any fugitive emissions from the newly constructed or modified
components at the well site. Therefore, we are finalizing that the
startup of production marks the beginning of the initial monitoring
survey period for the collection of fugitive emissions components.
    Furthermore, based on the comments received, we are concerned that
the tasks required prior to conducting an initial survey would take
more than the 30 days we had proposed. Because each new or modified
well site must be covered by a monitoring plan for a company-defined
area, owners and operators must visit and assess each new or modified
well site in order to incorporate it into a newly developed or modified
monitoring plan for that area. They also need to secure certified
monitoring survey contractors or monitoring instruments. In addition,
they need to ensure that other compliance requirements will be met,
such as recordkeeping and reporting. In light of the activities
described above, the EPA is requiring in the final rule that the
initial survey be conducted within 60 days from the startup of
production.
    While 60 days from startup of production is sufficient time to
conduct the initial survey once the underlying program infrastructure
is established, we recognize that the initial establishment of the
required program's infrastructure and the initial round of monitoring
surveys will require additional time. Most importantly, additional time
is needed to secure the necessary equipment or trained personnel,
according to one OGI instrument manufacturer, which commented that they
would need to increase production of key components for the OGI
instrument to meet demand. The OGI manufacturer also indicated that
they would need to scale up the number of personnel needed to provide
OGI training and service of the equipment. We are concerned that
currently there is not sufficient equipment and trained personnel to
meet the demand imposed by this final rule in the near term.
Accordingly, it will be necessary to have a window of time for trained
personnel to work through this backlog. Furthermore, as previously
mentioned, an owner or operator will need to develop a monitoring plan
that would apply to each well site located within the company-defined
area, which requires an assessment of each well site. Therefore, before
a plan can be developed or modified, the owner or operator would need
time to visit each well site within the company-defined area. Based on
the information that we used to develop the model well site plants,
each company-defined area may consist of up to 22 well sites within a
70-mile radius of a central or district office. In light of the above,
the initial site visits and development of the monitoring plan would
require a significant amount of time. Time is also needed to secure
certified monitoring survey contractors or monitoring instruments. In
addition, owners and operators will need to plan the logistics of the
initial activities in order to comply with the requirements. This
includes time to set up recordkeeping systems and to train personnel to
manage the fugitive emissions monitoring program. These corporate
systems are critical for submitting the notification of initial and
subsequent annual compliance status.
    As noted above, once programs are established and equipment
supplies have caught up, well owners will be able to add additional
affected facilities to existing programs and, thus, this longer
timeline will not be needed. Therefore, in order to provide time for
owners and operators to establish the initial groundwork of their
fugitives program, we are requiring that the initial monitoring survey
must take place by June 3, 2017 or within 60 days of the startup of
production, whichever is later.\87\ We anticipate that sources will
begin to phase in these requirements as additional devices and trained
personnel become available. For additional discussion, please refer to
the materials in the docket.
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    \87\ For well site activities, such as the installation of a new
well, a hydraulically fractured or refractured well, which commenced
on or after September 18, 2015 are subject to this rule once it is
finalized.
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h. Monitoring Plan
    The EPA proposed that owners or operators develop a corporate-wide
fugitive emissions monitoring plan that specifies the measures for
locating sources and the detection technology to be used. We also
proposed that, in addition to the corporate-wide monitoring plan,
owners or operators develop a site-specific fugitive emissions
monitoring plan that specifies information such as the number of
fugitive emission components that pertains to that single site.\88\ The
EPA solicited comment on the required elements of the proposed
corporate-wide monitoring plan; specifically, the EPA asked for comment
on whether other techniques, such as visual inspections to help
identify indicators of potential leaks, should be included within the
monitoring plan.
---------------------------------------------------------------------------

    \88\ See 80 FR 56612 (September 18, 2015).
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    Some commenters agreed with the EPA's proposal to require a
corporate-wide fugitive monitoring plan but expressed concerns about
the elements of the plan, while others objected that the proposed plan
is overly prescriptive and costly, with particular concerns about
including requirements for a walking path and for digital photographs.
Other commenters suggested changing the scope of monitoring plans to
accommodate variations in locations of contractors and equipment.
    We considered these comments, and we have made the following
changes to the proposal in the final rule.
    First, the final rule requires owners or operators to develop a
fugitive emission monitoring plan for well sites within a company-
defined area instead of corporate-wide and site-specific monitoring
plans. This will give companies the flexibility to group well sites
that are located within close proximity, under common control within a
field or district, or that are

managed by a single group of personnel. This would also afford owners
and operators of well sites within different basins the ability to
tailor their plans for the specific elements within each basin (i.e.,
geography, well site characterization, emission profile). Information
we received indicates that, in many cases, several sites within a
specific geographic area may have similar equipment and would use the
same contractors, company-owned monitoring instruments, or company
personnel to perform the monitoring surveys. Based on a study conducted
for the city of Fort Worth, Texas, we estimate that, on average, there
are 22 well sites within a company's specific geographic region.\89\ In
this study, a total of 375 well pads were identified in the Fort Worth
area, and these well pads were owned and operated by 17 different
companies, or an average of 22 well pads per company. We believe these
data provide a reasonable estimate of the number of well sites operated
by a company in a specific geographic region. Therefore, we are
removing the proposed corporate-wide and site-specific monitoring plan
requirements and finalizing requirements that owners and operators
develop a fugitive emissions monitoring plan for each of the company-
defined areas that covers the collection of fugitive emissions
components at well sites. As a result, the final rule requires owners
and operators to develop a plan that describes the sites generally,
including descriptions of equipment, plans for how they will monitor,
etc., that apply to all similar sites. This will allow owners and
operators to develop a monitoring plan for groups of similar well sites
within an area for ease of implementation and compliance.
---------------------------------------------------------------------------

    \89\ ERG and Sage Environmental Consulting, LP. City of Fort
Worth Natural Gas Air Quality Study, Final Report. Prepared for the
City of Fort Worth, Texas. July 13, 2011. Available at http://fortworthtexas.gov/gaswells/default.aspx?id=87074.
---------------------------------------------------------------------------

    Second, we have made changes in the final rule to the proposed
digital photograph requirements. We believe concerns regarding the
burden of printing or transmitting digital pictures within the annual
report are the result of unclear language in the proposed rule. Our
intent was to require the owner or operator to include one or more
digital photographs of the survey being performed. However, we
inadvertently included that text within the requirement for each
fugitive emission. It was not our intent to require a digital
photograph of each fugitive emission in the annual report; instead we
wanted to ensure, through pictorial documentation, that the monitoring
survey had been performed. After consideration of the comments
received, we believe we can further streamline this requirement.
Because a source with fugitive emissions during the reporting period is
subject to other recordkeeping and reporting requirements, this
provides sufficient documentation that the survey was performed.
Therefore, we have removed the proposed requirement to provide a
digital photograph in the annual report for each required monitoring
survey. We are requiring owners and operators to retain a record of
each monitoring survey performed with optical gas imaging by keeping
one or more digital photographs or videos captured with the OGI
instrument. The photograph or video must either include the latitude
and longitude of the collection of fugitive emissions components
imbedded within the photograph or video or must consist of an image of
the monitoring survey being performed with a separately operating GPS
device within the same digital picture or video, provided that the
latitude and longitude output of the GPS unit can be clearly read in
the image.
    Third, with the allowance for Method 21 monitoring as an
alternative to OGI instrument monitoring, we are finalizing a
requirement that sources of fugitive emissions (e.g., a leaking
fugitive emissions component) that cannot be repaired during the
initial monitoring survey either be temporarily tagged for
identification for repair or be digitally photographed or video
recorded in a way that identifies the location of the fugitive
emissions component needing repair. If an owner or operator chooses to
digitally photograph the leaking component(s) instead of using
identification tags, the photograph will meet the requirement to take a
digital photograph during a monitoring survey, as long as the digital
photograph is taken with the OGI instrument and includes the latitude
and longitude either imbedded in the photograph or visible in the
picture.
    Fourth, we are finalizing the walking path requirement with minor
changes. We are revising the walking path terminology to observation
path in order to clarify that our intent is focused on the field of
view of the OGI instrument, not the physical location of the OGI
operator. We believe this terminology change will alleviate commenters'
concerns regarding the potentially overly prescriptive nature of the
defined walking path with transient interferences, environmental
obstructions, weather conditions and safety issues. This revision also
clarifies our intent to allow for the use of all types of OGI
instruments (e.g., mounted, handheld or remote controlled).
    The purpose of the observation path is to ensure that the OGI
operator visualizes all of the components that must be monitored, just
as a Method 21 operator in a traditional leak detection program surveys
all of the components. In the traditional scenario, the owner or
operator tags all of the equipment that must be monitored, and when the
Method 21 operator subsequently inspects the affected facility, the
operator scans each component's tag and notes the component's
instrument reading. The EPA realizes that this is a time-consuming
practice. Additionally, while the Method 21 operator must contact each
component with the probe of the Method 21 instrument and monitor it
individually, we recognize that with OGI, the operator can be away from
the components and still monitor several components simultaneously.
    Recognizing these aspects of traditional and OGI leak detection
methods, we want to offer owners and operators an alternative to the
traditional tagging approach. However, because we are no longer
requiring a traditional log of instrument readings, the rule must
provide another way to ensure that the compliance obligation to monitor
all equipment is met. We believe that the observation path requirement
effectively ensures that an operator looks at all of the required
components but reduces the burden of tagging and logging associated
with traditional Method 21 programs. Unlike the tagging and logging
requirement associated with traditional Method 21 programs, the
requirement to develop an observation path is a one-time requirement
(as long as the path does not need to change due to the addition of
components). We do not expect facilities to create overly detailed
process and instrumentation diagrams to describe the observation path.
The observation path description could be a simple schematic diagram of
the facility site or an aerial photograph of the facility site, as long
as such a photograph clearly shows locations of the components and the
OGI operator's walking path. As a result, we do not believe that the
requirement to document the observation path is burdensome.
i. Provision for Emerging Technology
    As the EPA noted in the 2015 proposal, fugitive emissions
monitoring is a field of emerging technology, and major advances are
expected in the near future. 80 FR at 56639. We are seeing a rapidly
growing push to develop and

produce low-cost monitoring technologies to find fugitive and direct
methane and VOC emissions sooner and at lower levels than current
technology allows, thus enhancing the ability of operators to detect
fugitive emissions. During the development of the proposed rule, the
EPA solicited comments and information on emerging technologies that
could potentially be used to detect fugitive emissions at well sites or
compressor stations and how these technologies could be used (e.g., as
standalone monitors or in conjunction with OGI). Several commenters
indicated that methane and VOC leak detection technology is undergoing
continuous and rapid development and innovation, potentially yielding,
for example, continuous emissions monitoring technologies, and urged
the EPA to allow emerging technology to be used for fugitive emissions
monitoring. The EPA agrees that continued development of these cost
effective technologies is important and that the final rule should
encourage and accommodate it to the extent possible.
    Fugitive emissions monitoring and repair is a work practice
standard, as allowed under section 111(h)(1) of the CAA. A work
practice standard is an emission limitation that is not necessarily in
a numeric format, such as the visualization of fugitive emissions using
OGI. As described in section 111(h)(3), the Administrator may approve
an alternative means of emission limitation for a work practice
standard if it can be proven that an equal reduction in emissions will
be achieved. To that end, pursuant to CAA section 111(h)(3), we are
establishing in the final rule a process for the agency to permit the
use of innovative technology for reducing fugitive emissions at well
sites and/or compressor stations. Specifically, under the final rule,
owners or operators may submit a request to the EPA for ``an
alternative means of emission limitation'' where a technology has been
demonstrated to achieve a reduction in emissions at least equivalent to
the reduction in emissions achieved under the work practice or
operational requirements for reducing fugitive emissions at well sites
and/or compressor stations in subpart OOOOa.
    To facilitate the application and review process, the final rule
includes information to be provided in the application that would be
needed for us to expeditiously evaluate the emerging technology. Such
information must include a description of the emerging technology and
the associated monitoring instrument or measurement technology; a
description of the method and data quality used to ensure the
effectiveness of the technology; a description of the method detection
limit of the technology and the action level at which fugitive
emissions would be detected; a description of the quality assurance and
control measures employed by the technology; field data that verify the
feasibility and detection capabilities of the technology; and any
restrictions for using the technology.
    This process will allow for the use of any currently emerging
technology or any technology that is developed in the future that is
capable of achieving methane and VOC emission reductions at levels that
are at least equivalent to reductions achieved when using OGI or Method
21 for fugitive emissions monitoring. This process will also allow for
the use of alternative fugitive emissions monitoring approaches such as
periodic, continuous, fixed, mobile, or a hybrid approach. Consistent
with section 111(h)(3), any application will be publicly noticed in the
Federal Register, which the EPA intends to provide within six months
after receiving a complete application, including all required
information for evaluation. The EPA will provide an opportunity for
public hearing and comment on the application and on intended action
the EPA might take. The EPA intends to make a final determination
within six months after the close of the public comment period. The EPA
will also publish its final determination in the Federal Register. If
final determination is a denial, the EPA will provide reasoning for
denial and recommendations for further development and evaluation of
the emerging technology, if appropriate.
j. Definition of Well Site
    In the proposed rule, we had defined ``well site,'' for purposes of
the fugitive emissions standards at Sec.  60.5397a, to include
separately located, centralized tank batteries. We received comments
that the definition was unclear and that there was concern that the
affected facility status of centralized tank batteries could
inadvertently pull into affected facility status those well sites that
only contain one or more wellheads, which were proposed to be excluded
from affected facility status. We agree that the proposed definition of
well site was somewhat unclear, and we have revised the definition in
the final rule. With regard to the affected facility status of
centralized tank batteries and its effect on well sites that only
contain one or more wellheads, our intent is not to have well sites
that only contain one or more wellheads subject to fugitive emissions
standards. To make this intent more explicit, we have added language to
Sec.  60.5365a(i)(2) to this effect.
2. Fugitive Emissions From Compressor Stations
    Based on our consideration of the comments received and other
relevant information, we have made several changes to the proposed
fugitive emissions standards for the compressor stations in this final
rule. The finalized fugitive emissions monitoring and repair
requirements for compressor stations are similar to the requirements
for well sites, so we streamlined this section by referencing our well
site discussion, where appropriate. Below we provide the significant
changes since proposal and our rationales for these changes.
a. Monitoring Frequency
    In conjunction with semiannual monitoring, the EPA co-proposed
annual monitoring, solicited comment on conducting monitoring surveys
on a quarterly basis, and solicited comment on the availability of
trained OGI contractors and OGI instrumentation. 80 FR at 56639.
    Some commenters supported quarterly monitoring on the belief that
it is more accurate and cost-effective than the monitoring frequencies
proposed by the EPA. Other commenters opposed quarterly monitoring,
alleging that it is not cost-effective and may be infeasible due to
weather or shortages associated with OGI, necessary for the surveys.
Also citing factors such as cost-effectiveness and questioning data
underlying the EPA's analysis, some commenters supported annual
monitoring or generally opposed semiannual monitoring.
    Based on the comments received, the EPA reviewed the type of
equipment and the associated components that were included in the model
plant used to determine emission reductions and costs for compressor
stations at proposal. The storage and transmission model plants
developed for the proposed rule had inadvertently included site
blowdown open-ended lines, which are not sources of fugitive emissions
but are vents. Therefore, the transmission and storage model plants
were revised for the final rule to remove these components from the
total component count.
    The EPA used information provided by commenters to re-evaluate the
control options for annual, semiannual and quarterly monitoring. As
shown in the TSD, the control costs for quarterly, semiannual, and
annual monitoring remain cost-effective for reducing GHG

(in the form of methane) and VOC emissions. Semiannual and quarterly
monitoring would provide greater emissions reductions than would annual
monitoring. However, as explained in the proposed rule, we were
concerned with compliance burden, in particular for small businesses,
associated with quarterly monitoring even though it was cost effective.
80 FR at 56641. Specifically, we were concerned that the limited
supplies of trained personnel for performing surveys might lead to
disadvantages for small businesses, which are more likely to hire
trained personnel. Id. However, certain changes we have made in the
final rule will help alleviate the concern. For example, the final rule
requires that the initial monitoring survey must take place by June 3,
2017 or within 60 days of the startup of production, whichever is
later. This allows additional time for owners and operators to
establish the requirement program's infrastructure at the initial
stage. Another example, in light of comments urging EPA to allow Method
21 as an alternative, and the fact that we know many companies already
own Method 21 instruments, offering Method 21 at a repair threshold of
500 ppm, as an alternative to conduct the monitoring surveys, will
alleviate some of the demand for OGI instruments and personnel.
Therefore, the EPA is finalizing quarterly monitoring frequency for the
collection of fugitive emissions components at compressor stations to
ensure the maximum amount of emission reductions. Please see the RTC
document in the public docket for further discussion.\90\
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    \90\ See EPA docket ID No. EPA-HQ-OAR-2010-0505.
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    Some commenters requested that fugitive emissions monitoring
exemptions be given to well sites and compressor stations that are
located in areas of the country that routinely experience extreme
weather. The commenters noted that these areas experience several
months of average temperatures below 0 [deg]F and long periods of snow
cover. The commenter also provided information from one of the OGI
instrument manufacturers which indicates that the instrument cannot
operate at temperatures below -4 [deg]F. The commenter also expressed
concerns about monitoring survey personnel's safety if they were to
attempt to conduct surveys in these weather conditions.
    We agree that there are areas within the United States that
regularly have extreme weather conditions such as three or more
consecutive months of average temperatures below 0 [deg]F. We also
obtained information from two OGI instrument manufacturers that confirm
that the minimum operating temperature of the OGI instruments is -4
[deg]F. As such, these prolonged subzero temperature conditions would
make performing fugitive emissions monitoring surveys impossible during
several months of the year. Additionally, while we believe that company
personnel may be accessing these sites for maintenance activities, it
may be difficult to transport OGI contractors to unmanned sites within
these areas during these periods, as outside access for OGI contractors
usually requires air travel to access these production sites.
    Based on these considerations, we are waiving quarterly fugitive
emissions monitoring surveys at compressor stations if, based on three
years of historical climatic data, two of the three consecutive months
within the quarter has an average temperature below 0 [deg]F. The
average temperatures must be determined by historical climatic data
from the National Oceanic and Atmospheric Administration or a source
approved by the EPA Administrator. This waiver may not be used for two
consecutive quarters and is not extended to well sites because we do
not believe that there will be any locations that have average monthly
temperatures below 0 [deg]F for six consecutive months. Owners and
operators will have to keep records of the waiver period, including the
three months within the quarterly monitoring period, the average
monthly temperatures and the source of the temperature information.
Owners and operators will also have to report this information in their
annual report.
b. Monitoring Using Method 21
    In performing analysis for the proposed rule, the EPA found OGI to
be more cost-effective than Method 21 and, therefore, identified OGI as
the BSER for monitoring fugitive emissions at compressor stations. See
80 FR 56641, September 18, 2015. As with well sites, discussed
previously in section VI.F.1.c, the EPA solicited comment on whether to
allow Method 21 as an alternative fugitive emissions monitoring method
to OGI and solicited comment on the repair threshold for components
that are found to have fugitive emissions using Method 21.
    The EPA received the same types of comments regarding allowing
Method 21 as an alternative to OGI for monitoring fugitive emissions at
compressor stations as for well sites, as discussed in section
VI.F.1.c. Likewise, for the same reasons as discussed earlier, we are
finalizing Method 21 as an alternative to OGI for monitoring fugitive
emissions components at compressor stations at a repair threshold of an
instrument reading of 500 ppm or greater. We are also finalizing
specific recordkeeping and reporting requirements when Method 21 is
used to perform a monitoring survey. See section V.J for more details
on the recordkeeping and reporting requirements.
c. Shifting of Monitoring Frequency Based on Performance
    The EPA proposed shifting monitoring frequencies (ranging from
annual to quarterly monitoring) based on the percentage of components
that are found to have fugitive emissions during a monitoring survey.
We solicited comment on the proposed monitoring scheme, including the
proposed metrics of one percent and three percent to determine
monitoring frequency or whether the monitoring frequency thresholds
should be based on a specific number of components that are found to
have fugitive emissions. In addition, the EPA solicited comment on
whether a performance-based frequency or a fixed-frequency was more
appropriate.
    The EPA received the same comments regarding frequency of
monitoring for compressor stations as for well sites, discussed in
section VI.F.1.d. Likewise, for the same reasons as discussed earlier,
the EPA is finalizing a fixed monitoring frequency instead of
performance based monitoring.
d. Fugitive Emissions Components Repair and Resurvey
    The EPA proposed that a source of fugitive emissions at compressor
stations must be repaired or replaced as soon as practicable, and, in
any case, no later than 15 calendar days after detection of the
fugitive emissions. The EPA solicited comment on whether 15 days is the
appropriate amount of time for repair of sources of fugitive emissions
from compressor stations. We also solicited comment on whether 15 days
is the appropriate amount of time needed to resurvey a component after
it has been repaired.
    The EPA received the same comments regarding the timeframe for
repairs, delay of repair, and resurveys for compressor stations as for
well sites, discussed in section VI.F.1.e. Likewise, for the same
reasons as discussed earlier, we are finalizing 30 days for the repair
of fugitive emissions sources and an additional 30 days for resurvey of
the repaired fugitive emissions components.

We also are finalizing revisions to the delay of repair requirements.
If a repair cannot be made due to a technical infeasibility that would
require a blowdown or shutdown of the compressor station, or would be
unsafe to repair by exposing personnel to immediate danger, the repair
can be delayed until the next scheduled or emergency blowdown or
station shutdown or within 2 years of finding the fugitive source of
emissions, whichever is earlier. We believe that the likelihood of an
emergency blowdown or a compressor station shutdown occurring within
six months of finding fugitive emissions from a component may be low;
however, it would be feasible to repair the component within a two-year
timeframe, since one of above described events is likely to occur
within that two-year timeframe. The owner or operator will also have to
record the number and types of components that are placed on delay of
repair and record an explanation for each delay of repair.
    Similarly with respect to well sites, and as discussed in section
VI.F.1.e, we are finalizing the use of the alternative screening
procedures specified in Section 8.3.3 of Method 21 for resurveying
repaired fugitive emissions components. Please see the RTC document in
the public docket for further discussion.
e. Definition of ``Fugitive Emission Component''
    As discussed earlier, we proposed monitoring, repair and resurvey
of ``fugitive emission components,'' that apply to both well sites and
compressor stations because the type of components are identical. We
solicited comment on the proposed definition. The EPA received the same
comments regarding the fugitive emissions component definition for
compressor stations as for well sites, discussed in section VI.F.1.f.
Likewise, for the same reasons as discussed earlier, we are finalizing
changes to the definition to identify specific components, such as
valves and flanges, that have the potential to be sources of fugitive
emissions and that, when surveyed and repaired, would significantly
reduce GHG and VOC emissions. This targeted list will remove the
ambiguity of the proposed definition and will allow owners and
operators to consistently identify fugitive emissions at compressor
stations.
f. Timing of the Initial Monitoring Survey
    The EPA proposed that the initial monitoring be conducted within 30
days after the initial startup of a new compressor station or
modification of an existing compressor station. The EPA solicited
comment on whether 30 days is an appropriate amount of time to begin
conducting fugitive emissions monitoring.
    Many commenters supported a longer timeframe for commencing
monitoring, citing time needed to complete well ties into a compressor
station that collects field gas, safety, and the relationship with
other regulations, while some commenters supported the timeframe
proposed. The EPA recognizes that at the time of startup of a
compressor station, additional gathering lines or well tie-ins may be
required. However, we also believe that, at the time of startup, the
associated collection of fugitive emissions components is operational
and initial monitoring can begin, even if the gathering lines or well
tie-ins are incomplete, which could take several months or longer.
Sources of fugitive emissions could go undetected for months if we were
to allow monitoring to begin after all of the gathering lines and tie-
ins were completed. Therefore, we are finalizing the proposed
requirement that initial monitoring will begin after the initial
startup of a compressor station instead of allowing all of the
gathering lines or tie-ins to be completed before monitoring begins.
    However, based on the comments received, we are concerned that the
tasks required prior to conducting an initial survey would take more
than the 30 days we had proposed. Because each new or modified
compressor station must be covered by a monitoring plan for a company-
defined area, owners and operators must visit and assess each new or
modified compressor station in order to incorporate it into a newly
developed or modified monitoring plan for that area. They also need to
secure certified monitoring survey contractors or monitoring
instruments. In addition, they need to ensure that other compliance
requirements will be met, such as recordkeeping and reporting. In light
of the activities described above, the EPA is requiring in the final
rule that the initial survey be conducted within 60 days from startup
or modification of a compressor station.
    While 60 days from startup or modification of a compressor station
is sufficient time to conduct the initial survey once the underlying
program infrastructure is established, we recognize that the initial
establishment of the required program's infrastructure and the initial
round of monitoring surveys will require additional time. Most
importantly, additional time is needed to secure the necessary
equipment or trained personnel according to one OGI instrument
manufacturer, which commented that they would need to increase
production of key components for the OGI instrument to meet demand. The
OGI manufacturer also indicated that they would need to scale up the
number of personnel needed to provide OGI training and service of the
equipment. We are concerned that currently there is not sufficient
equipment and trained personnel to meet the demand imposed by this
final rule in the near term. Accordingly, it will be necessary to have
a window of time for trained personnel to work through this backlog.
Furthermore, as previously mentioned, an owner or operator will need to
develop a monitoring plan that would apply to each compressor station
located within the company-defined area, which requires an assessment
of each compressor station. Therefore, before a plan can be developed
or modified, the owner or operator would need time to visit each
compressor station within the company-defined area. In light of the
above, the initial site visits and development of the monitoring plan
would require a significant amount of time. Time is also needed to
secure certified monitoring survey contractors or monitoring
instruments. In addition, owners and operators will need to plan the
logistics of the initial activities in order to comply with the
requirements. This includes time to set up recordkeeping systems and to
train personnel to manage the fugitive emissions monitoring program.
These corporate systems are critical for submitting the notification of
initial and subsequent annual compliance status.
    As noted above, once programs are established and equipment
supplies have caught up, well owners will be able to add additional
affected facilities to existing programs and, thus, this longer
timeline will not be needed. Therefore, in order to provide time for
owners and operators to establish the initial groundwork of their
fugitives program, we are requiring that the initial monitoring survey
must take place by June 3, 2017 or within 60 days of the startup or
modification of a compressor station, whichever is later. We anticipate
that sources will begin to phase in these requirements as additional
devices and trained personnel become available. For additional
discussion, please refer to the materials in the docket.
g. Monitoring Plan
    The EPA proposed that owners or operators develop a corporate-wide

emissions monitoring plan that specifies the measures for locating
sources and the detection technology to be used. The EPA also proposed
that owners or operators develop a separate site-specific fugitive
emissions monitoring plan that specifies information, such as the
number of fugitive emission components for that site and for each
affected facility. The EPA solicited comment on the required elements
of the proposed corporate-wide monitoring plan and specifically asked
for comment regarding whether the monitoring plan should include other
techniques, such as visual inspections to help identify indicators of
potential leaks.
    As with this topic in the context of well sites, and as discussed
in section VI.F.1.h, some commenters agreed with the EPA's proposal to
require a corporate fugitive monitoring plan, but expressed concerns
about the elements of the plan, while others objected that the proposed
plan is overly prescriptive and costly, with particular concerns about
including requirements for a walking path and for digital photographs.
Other commenters suggested changing the scope of monitoring plans to
accommodate variations in locations of contractors and equipment.
    Based on the comments that we received, we are revising the
fugitive emissions monitoring plan for compressor stations. We
acknowledge that developing and implementing a corporate-wide
monitoring plan that would be applicable to all compressor stations
within a company could be problematic because compressor station
configurations may differ across areas (i.e., basins, fields, or
districts) and what may be applicable in one area may not be relevant
in another area. This would mean that a company could have to design
and implement a site-specific plan for each compressor station.
    We also agree that developing a site-specific plan may be overly
burdensome because several gathering and boosting or transmission
compressor stations may exist in a specific geographic area and have
similar equipment. Using information from the Interstate Natural Gas
Association of America (INGAA) and the Energy Information
Administration (EIA), we estimated that, on average, compressor
stations are located 70 miles apart. We also assumed that a company
could monitor emissions from gathering and boosting or transmission
compressor stations within a 210-mile radius of a central location.
Using these assumptions, we estimated that a company could monitor
seven gathering and boosting or transmission compressor stations within
that company's specific geographic region. In such cases, companies
would benefit from having a plan to cover all of the compressor
stations within that area, as the monitoring will likely require use of
the same contractors, the same company-owned monitoring instruments, or
the same company personnel to perform the monitoring surveys. Allowing
companies to develop one fugitive emissions monitoring plan for all of
the compressors within a company-defined area would alleviate burden
and provide efficiency for owners and operators.
    Therefore, we are replacing the proposed corporate-wide and site-
specific monitoring plan requirements with a requirement for owners or
operators to develop a corporate monitoring plan for each of the
company-defined areas that would cover the collection of fugitive
emissions components at the compressor stations located within that
company-defined area. This will allow owners and operators flexibility
in developing monitoring plans for compressor stations by allowing
owners and operators to determine which company-defined area can be
covered under the specifications outlined in one monitoring plan, for
ease of implementation and compliance. See section VI.F.1.h of this
preamble for further discussion.
h. Modifications for Compressor Stations
    The EPA proposed that, for the purposes of the collection of
fugitive emissions monitoring and repair requirements, a compressor
station is modified when a new compressor is constructed at an existing
compressor station or when a physical change is made that causes an
increase in the compression capacity of an existing compressor station.
We received numerous comments on the compressor modification
definition.
    Several commenters stated that the compressor station modification
definition is too vague and broad because anytime a physical
modification occurred, a regulatory modification would be triggered
regardless of whether there were additional emissions. Commenters also
stated if a compressor station is not operating at full capacity,
addition of a compressor may not necessarily increase the compressor
station capacity, nor would addition of a compressor with greater
horsepower (thus adding capacity) necessarily increase emissions.
    At proposal, we attempted to identify distinct actions that we were
confident would result in an emissions increase and would clearly mark
for operators and regulators when a modification occurs. However, upon
reviewing the comments, we agree that certain triggering events
identified in the proposal may not result in an increase in emissions.
Specifically, EPA agrees that an addition of a compressor does not
result in an increase in emissions in all instances. For example, there
is no emission increase when a new compressor is being installed as a
replacement to an existing one. We have, therefore, made changes in the
final rule to clarify when an addition of a new compressor would
increase emission and therefore trigger the fugitive emission standards
(i.e., when it is installed as an additional compressor or if it is a
replacement that is of greater horsepower than the compressor or
compressors that it is replacing).
    The EPA agrees that an increase in the compression capacity that is
not due to the addition of a compressor that would result in an
increase of the overall design capacity of the compressor station is
not a modification. For example, a compressor station may have to
increase the operating throughput by bringing existing compressors on-
line to meet demand during peak seasons. In such a case, the
compressors' capacities are already accounted for in the overall design
capacity for the compressor station, and bringing them on-line would
not increase the overall design capacity nor would it increase the
potential emissions of the compressor station. Therefore, we are not
finalizing that an increase in compression capacity is a modification.
    Commenters also indicated that the addition of a new compressor at
an existing compressor station should not trigger a fugitive emissions
monitoring program for the entire compressor station but, should only
apply to the new compressor and its associated components. We disagree
that the addition of a compressor at an existing compressor station
should not trigger a fugitive emissions monitoring program for the
entire compressor station. We have clarified that the installation of a
compressor will only trigger the fugitive monitoring requirements if it
is installed as an additional compressor or if it is a replacement that
is of greater horsepower than the compressor or compressors that it is
replacing. In this case, the design capacity and potential emissions of
the compressor station would increase. Unlike the affected facilities
for purposes of standards for centrifugal and reciprocating compressors
themselves, the affected facility for purposes of the fugitive

emission requirements is the collection of fugitive emissions
components at a compressor station, not the fugitive emissions
components associated with a single compressor. Therefore, if a
compressor is added to an existing compressor station, the entire
compressor station is subject to the fugitive emissions monitoring
program.
    Therefore, we are finalizing a definition that we are confident
identifies actions that increase emissions and achieves our original
goal of having clearly identifiable criteria that can be easily
recognized by operators and regulators. We are finalizing that a
modification to a compressor station occurs when a compressor is added
to a compressor station or if one or more compressors is replaced with
one or more compressors with a greater total horsepower.
i. Provision for Emerging Technology
    Pursuant to CAA section 111(h)(3), we are establishing in the final
rule a process for the Agency to permit the use of innovative
technology for reducing fugitive emissions at well sites and/or
compressor stations. For a detailed discussion, please see section
VI.F.1.i.

G. Equipment Leaks at Natural Gas Processing Plants

    For equipment leaks at natural gas processing plants, the EPA
received a total of seven comments addressing issues such as the
definition of natural gas processing plant and whether OGI may be used
in place of Method 21. We reviewed the comments received and determined
to finalize the standard for equipment leaks at natural gas processing
plants as proposed. Specifically, the final rule requires NSPS part 60,
subpart VVa level of control, including a detection limitation of 500
ppm for certain pieces of equipment. Please see the TSD and RTC
documents in the public docket for further discussion.

H. Reconsideration Issues Being Addressed

    To address numerous items on which we granted reconsideration, we
proposed amendments to subpart OOOO and solicited comment on certain
topics that would also impact the new NSPS requirements. With some
revisions based on our consideration of public comment, the EPA is
finalizing certain reconsideration amendments. These amendments
address: Storage vessel control device monitoring and testing
provisions; initial compliance requirements for bypass devices;
recordkeeping requirements for repair logs for control devices failing
a visible emissions test; clarification of the due date for the initial
annual report under the 2012 NSPS; flare design and operation
standards; LDAR for open-ended valves or lines; compliance period for
LDAR for newly affected units; exemption to notification requirement
for reconstruction; disposal of carbon from control devices; the
definition of capital expenditure; and continuous control device
monitoring requirements for storage vessels and centrifugal compressor
affected facilities. This section identifies specifically what the EPA
proposed, identifies the regulatory text changes from proposal, and
states how the EPA is finalizing these provisions.\91\ Please see the
TSD and RTC documents in the public docket for further discussion.\92\
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    \91\ 80 FR 56645, September 18, 2015.
    \92\ See EPA docket ID No. EPA-HQ-OAR-2010-0505.
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1. Storage Vessel Control Device Monitoring and Testing Provisions
    The EPA proposed regulatory text changes to address performance
testing and monitoring of control devices used for new storage vessel
installations and centrifugal compressor emissions, specifically
relating to in-field performance testing of enclosed combustors. The
EPA specifically proposed to revise the limit for total organic carbon
(TOC) concentration in the exhaust gases at the outlet of the control
device from 20 ppmv to 600 ppmv as propane on a dry basis corrected to
3 percent oxygen, a value that more appropriately reflects 95 percent
control of VOC inflow to control devices. The EPA also proposed initial
and ongoing performance testing for any enclosed combustors used to
comply with the emissions standard for an affected facility and whose
make and model are not listed on the EPA Oil and Natural Gas Web site
(http://www.epa.gov/airquality/oilandgas/implement.html) as those
having already met a manufacturer's performance test demonstration. The
proposal stated that performance testing of combustors not listed at
the above Web site would be conducted on an ongoing basis, every 60
months of service, and monthly monitoring of visible emissions from
each unit would also be required.
    Additionally, the EPA proposed amendments to make the requirements
for monitoring visible emissions consistent for all enclosed combustion
units. Specifically, the EPA proposed to amend 40 CFR 60.5413(e)(3) to
require monthly 15-minute period observations using EPA Method 22.
    Based on information submitted through the public comment process,
the EPA has identified four necessary revisions for the final storage
vessel provisions. First, commenters provided information to the EPA
concerning the use of 600 ppmv as propane as appropriately reflecting
95 percent control of VOC inflow to control devices. After an
evaluation of the comments, we agreed that the EPA's assumption about
the ratio of fuel to combustion air was incorrect, making the proposed
600 ppmv as propane value incorrect. The 600 ppmv as propane value was
derived in the memorandum dated June 2, 2015,\93\ which discusses the
background for the Sec.  60.5412(a)(1)(ii) TOC exhaust gas standard for
combustion control devices to control VOC emissions from oil and gas
affected facilities. While this analysis reflects the destruction of
hydrocarbons compared to the concentration of hydrocarbon in the inlet
fuel, our analysis did not take into account any in-stack dilution
represented by the introduction of combustion air or the correction of
that air to 3 percent oxygen. Since hydrocarbon combustion requires
approximately a ratio of 12:1 input of combustion air to hydrocarbon,
the outlet concentration of TOC would be adjusted downward to 275 parts
per million by volume on a wet basis (ppmvw), as propane, at 3 percent
O2. The final rule corrects this concentration at Sec.
60.5412(a)(1)(ii), and the EPA has appended the memo in the public
docket with this adjustment.
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    \93\ See Docket ID No. EPA-HQ-OAR-2010-0505-4907.
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    Second, the EPA is finalizing amendments to make the requirements
for monitoring of visible emissions consistent for all enclosed
combustion units. Prior to the proposal, enclosed combustors that met
the manufacturer's performance test requirement were to conduct
quarterly observations for visible smoke emissions employing section 11
of EPA Method 22 for a 60-minute period. Petitioners suggested it would
ease implementation to adjust the frequency and duration to monthly 15-
minute EPA Method 22 tests, which is currently required for continuous
monitoring of enclosed combustors that are not manufacturer tested. The
EPA agrees with the petitioners. This revision will result in
consistent requirements to all enclosed combustors, which will make
compliance easier for owners and operators. Because both monitoring
requirements ensure compliance of the enclosed combustors, and having
the

same requirement would ease implementation burden, we are finalizing
amendments to Sec. Sec.  60.5413(e)(3) and 60.5415(b)(2)(vii)(B) to
require monthly 15-minute period observations using EPA Method 22 Test,
as suggested by the petitioner.
    The EPA proposed requirements for determining applicability for new
storage tanks that replace existing tanks. Commenters provided
alternative text indicating how the meaning of the regulation was
difficult to discern. The EPA considered the suggested text and agrees
that amending this section will make the requirements for compliance
easier to understand. The amended language has been finalized in Sec.
60.5365(e)(4).
    Fourth, the EPA received comments requesting removal of the
requirement that certain devices that route emissions to processes must
reduce emissions by 95 percent and instead be written to be consistent
with Sec.  60.5411a(c), which requires that process devices must
operate 95 percent of the year or greater. Upon further reflection, the
EPA determined that, because Sec.  60.5395a(a) clearly requires that
affected sources (except those with uncontrolled emissions below 4 tons
per year (tpy)) must reduce VOC emission by 95 percent, it is not
necessary to further prescribe the level of reduction to be achieved
when emissions are routed to a process. The EPA has therefore removed
such specification in Sec.  60.5395a(b)(1) in the final rule. As
finalized, this specific provision relative to control requirements is
the same for centrifugal compressors, pneumatic pumps, and storage
vessel affected facilities routing to a process.
2. Initial Compliance Requirements for Bypass Devices
    The EPA proposed to amend Sec.  60.5416(c)(3)(i) to include
notification via remote alarm to the nearest field office in order to
maintain consistency with previous amendments. The EPA proposed to
require both an alarm at the bypass device and a remote alarm. The EPA
proposed similar amendments to parallel requirements at Sec.
60.5411(a)(3)(i)(A) for closed vent systems used with reciprocating
compressors and centrifugal compressor wet seal degassing systems. At
proposal to amend subpart OOOO, EPA changed ``or'' to ``and'' under
subpart OOOO at Sec. Sec.  60.5411(a)(3)(i)(A) and 60.5411(c)(3)(i)(A),
which would have required that both an audible and remote alarm be
installed on a bypass device with the potential to vent to the
atmosphere. One commenter pointed out that the requirements would be
applied retroactively, as the EPA changed the requirements in subpart
OOOO as well as subpart OOOOa. The EPA agrees with the commenter that
our intent was not to create a retroactive requirement by revising
subpart OOOO. The EPA is therefore not finalizing the changes to
subpart OOOO, Sec.  60.5411(a)(3)(i)(A), or Sec.  60.5411(c)(3)(i)(A).
    Although we are not finalizing both audible and remote alarm
requirements in subpart OOOO, the EPA disagrees that the requirement
for remote notification is unreasonable and is therefore preserving the
option as an alternative to an audible alarm. The EPA notes that either
requirement is restricted to those bypass devices that vent to the
atmosphere, not bypass devices (such as some pressure relief devices)
that are required to be routed through closed vent systems to control
devices. The EPA proposed to require both types of notification in
subpart OOOOa because of the diverse nature of facilities that will use
them. While an audible alarm may be sufficient at facilities that have
personnel present on a continuous basis, not all affected facilities
are at continuously-manned locations. An audible alarm on a bypass at a
remote location that is visited only on a schedule by maintenance
personnel would likely alert no one authorized to take action on the
audible alarm until such time as the maintenance personnel arrive,
which according to industry, may be a considerable time. The EPA agrees
that the logistical requirements may need to be resolved in some
instances, and is therefore finalizing the requirements in subpart
OOOOa to be the same in substance as the requirements in subpart OOOO,
which allow for the operator to choose one form of alarm or the other.
Section 60.5416a(c)(3)(i) was revised to match the promulgated
regulatory language in Sec.  60.5416(c)(3)(i) of OOOO for consistency.
3. Recordkeeping Requirements for Repair Logs for Control Devices
Failing a Visible Emissions Test
    The EPA proposed that the recordkeeping requirements include the
repair logs for control devices failing a visible emissions test as
required by the rule. Petitioners noted that the recordkeeping
requirements of Sec.  60.5420(c) do not include the repair logs for
control devices failing a visible emissions test required by Sec.
60.5413(c). We agree that these recordkeeping requirements should be
listed and are finalizing them at Sec.  60.5420(c)(14).
4. Due Date for Initial Annual Report
    The EPA did not propose regulatory text to amend the rule; rather,
the EPA stated in the preamble to the proposed rule that we will
consider any initial annual report submitted no later than January 15,
2014 to be a timely submission. All subsequent annual reports must be
submitted by the correct date of January 13 of the year.
5. Flare Design and Operation Standards
    The EPA proposed to remove the provision of Table 3 in subpart OOOO
that exempts flares from complying with the requirements for the design
and operation of flares under 40 CFR 60.18 of the General Provisions.
By removing the exemption from the General Provisions of subpart OOOO,
this clarifies that flares used to comply with subpart OOOO are subject
to the design and operation requirements in the general provisions.
    Comments on our proposal focused on support for the use of
pressure-assisted flares. Pressure-assisted flares are designed to
operate with high velocities up to sonic velocity conditions (e.g., 700
to 1,400 feet per second for common hydrocarbon gases). In order to
evaluate the use of pressure-assisted flares by the oil and natural gas
industry and determine whether to develop operating parameters for
pressure-assisted flares for purposes of subparts OOOO and subpart
OOOOa, the EPA solicited comment on where in the source category, under
what conditions (e.g., maintenance), and how frequently pressure-
assisted flares are used to control emissions from an affected
facility, as defined within this subpart. From comments to our
proposal, the EPA understands that there may be affected facilities
that use pressure-assisted flares (e.g., sonic flares) to control
emissions from certain activities; however, the EPA now understands
that an affected facility storage vessel, pneumatic pump, or
centrifugal or reciprocating compressor would not use a pressure-
assisted flare for control. The affected facility could be routed by
closed vent system to a low pressure flare, which can comply with the
velocity requirements of 40 CFR 60.18. The EPA received information
showing that certain configurations have separate flare tips that
accommodate high pressure and low pressure. The EPA understands that a
flare configured this way would be able to meet Sec.  60.18 on the low
pressure side, which would be appropriate for compliance with these
standards. Given these facts, the EPA is finalizing the rule as
proposed, because no regulatory

amendment appears necessary for such flares to comply with the proposed
requirements.
6. Leak Detection and Repair (LDAR) for Open-Ended Valves or Lines
    In the preamble to the final 2012 rule, the EPA stated that subpart
VVa lowered the concentration limit defining a leak from 10,000 ppm to
500 ppm. The EPA's action did not revise subpart VVa, but rather
changed the application of leak detection and repair provisions by
making the LDAR standards of subpart VVa applicable to affected units
subject to LDAR under subpart OOOO if the concentration emanating from
a leak is 500 ppm or greater. The EPA further stated that monitoring
requirements from subpart VVa applied to pumps, pressure relief
devices, and open-ended valves or lines at units affected by LDAR under
subpart OOOO. Although the preamble may have obscured the issue, we
clarify here that the monitoring provisions of subpart VVa applicable
to affected units of subpart OOOO do not extend to open-ended valves or
lines. Given this clarification of preamble language, the EPA can
identify no need to modify the regulatory language in response to this
petition.
7. Compliance Period for LDAR for Newly Affected Units
    An issue was raised in an administrative petition that the EPA did
not adequately respond to a comment on the 2011 proposed NSPS regarding
the compliance period for the LDAR requirements for on-shore natural
gas processing plants. The commenter requested that the EPA include in
subpart OOOO a provision similar to subpart KKK, 40 CFR 60.632(a),
which allows a compliance period of up to 180 days after initial start-
up. The commenter was concerned that a modification at an existing
facility or a subpart KKK regulated facility could subject the facility
to subpart OOOO LDAR requirements without adequate time to bring the
whole process unit into compliance with the new regulation. We clarify
that subpart OOOO, as promulgated in 2012, already includes a provision
similar to subpart KKK, Sec.  60.632(a), as requested in the comment.
Therefore, the EPA has determined there is no need to modify the
current regulations.
8. Exemption to Notification Requirement for Reconstruction
    The EPA received an administrative petition that raised the issue
that notification of reconstruction requirements under Sec.  60.15(d)
is unnecessary for some affected facilities. After consideration, the
EPA agrees that some notifications are unnecessary because the EPA
specifies notification of reconstruction for affected unit pneumatic
controllers, centrifugal compressors, reciprocating compressors, and
storage vessels under Sec.  60.5410a and Sec.  60.5420a, in lieu of the
general notification requirement in Sec.  60.15(d). To make this change
effective, the EPA has noted this change in the explanatory comments in
Table 3 reflecting that Sec.  60.15(d) does not apply to affected
facility pneumatic controllers, centrifugal compressors, reciprocating
compressors and storage vessels in subpart OOOO. The EPA has determined
to finalize these amendments as proposed.
9. Disposal of Carbon From Control Devices
    The EPA re-proposed provisions for management of waste from spent
carbon canisters that were finalized in Sec.  60.5412(c)(2) of the 2012
NSPS to allow for comment. The EPA received no comment to the re-
proposal. The EPA has determined to finalize these amendments as
proposed.
10. The Definition of Capital Expenditure
    The EPA proposed to specifically define the term ``capital
expenditure'' in subpart OOOO. In this proposed definition, the EPA
updated the formula to reflect the calendar year that subpart OOOO was
proposed, as well as specified that the B value for subpart OOOO is
4.5. These updates are necessary for proper calculation of capital
expenditure under subpart OOOO. The EPA has determined to finalize
these amendments as proposed. Please refer to the RTC document in the
public docket for this rulemaking for further discussion.
11. Tanks Associated With Water Recycling Operations
    The EPA solicited comment in the proposed rule to remove tanks that
are used for water recycling from potential NSPS applicability and on
approaches that could be taken to amend the definition of ``storage
vessel.'' Commenters requested that the EPA remove water tanks that are
primarily used for water recycling from subpart OOOOa applicability.
Commenters discussed that large storage tanks encourage large scale
water recycling and are expected to reduce fresh water usage primarily
in the Permian Basin. After reviewing the public comments, the EPA
agrees that certain large water recycling vessels should be exempt from
affected facility status for storage vessels because EPA did not intend
such vessels to be affected facility storage vessels under subpart OOOO
or OOOOa. By exempting such vessels, EPA will not create a disincentive
for recycling of water for hydraulic fracturing. Therefore, the final
rule exempts water recycling vessels that receive water that has been
through separation, and are much larger than the storage vessels
generally intended to be regulated by subparts OOOO and OOOOa for VOC
emissions. The EPA has included the exemption language at Sec.
60.5365(e)(5) and Sec.  60.5365a(e)(5) in the final rule.
12. Continuous Control Device Monitoring
    The EPA proposed under Sec.  60.5417 to add continuous control
device monitoring requirements for storage vessels and centrifugal
compressor affected facilities. The EPA received comments indicating
that to impose this requirement on affected facilities under subpart
OOOO may make such requirements retroactive, given the time between the
original proposal for subpart OOOO and the proposal of the additional
requirements. To avoid this possibility, the EPA will not finalize the
change proposed to subpart OOOO, Sec.  60.5417(h)(4).

I. Technical Corrections and Clarifications

    The EPA is finalizing technical corrections and clarifications
intended to provide clarity, improve implementation, and update
procedures. This section identifies each correction and the rationale
for these changes. Please see the TSD and RTC documents in the public
docket for further discussion.\94\
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    \94\ See EPA docket I.D. No. EPA-HQ-OAR-2010-0505.
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    1. The EPA discovered drafting errors in Sec.
60.5412a(d)(1)(iv)(A), Sec.  60.5412a(d)(2) and Sec.  60.5415a(e)(3)
that required control of methane from storage vessels. As discussed in
the preamble and the TSD for the proposed rule, the EPA did not
consider reduction of methane emissions from storage vessels.
Therefore, the reference to controlling storage vessel methane
emissions in the proposed regulatory text in the above provisions was a
drafting error. In correction, the EPA is removing ``methane and'' from
these three provisions because methane control is not required for
storage vessels under subpart OOOOa.
    2. A commenter noted that EPA had omitted a clear deadline by which
newly constructed, reconstructed, or

modified storage vessels that receive liquids from sources other than
hydraulically fractured wells must make their potential to emit
determination, in Sec.  60.5365a(e)(1). The commenter presumed,
correctly, that the omission was inadvertent, stating that
``Presumably, EPA intends that such tanks with potential VOC emissions
greater than 6 tons per year would be subject to the rule.'' We have
more clearly specified the deadline.
    3. We removed the requirement in Sec.  60.5375a(a)(2) that all
salable gas recovered from a well completion be routed as soon as
practicable to a gathering line. This requirement was duplicative of
the provisions of paragraph (a)(1) of the same section.
    4. We revised Sec.  60.5420a(b)(4)(i) to include the provision that
gas recovered from reciprocating compressors could also be routed to a
process as an alternative to replacing rod packing no later than on or
before 26,000 hours of operation or 36 months. We additionally
corrected an error that identified a wrong initial startup period. This
correction consists of removing ``since [insert date 60 days after
publication of final rule in the Federal Register].'' This correction
was also made in Sec.  60.5420a(c)(3)(i) and Sec.  60.5415a(c)(1).
    5. We revised the requirements in Sec.  60.5417a for heat sensing
monitoring devices on pilot flames to clarify that these devices are
not subject to calibration, quality assurance and quality control
requirements. While we intended for these devices to monitor
continuously, we did not intend to place all of the requirements for
continuous parameter monitoring systems on these devices. We also
revised the language in Sec.  60.5417a(e) and Sec.  60.5417a(g) to
indicate that heat sensing is not a daily average and that a deviation
occurs when the device fails to indicate the presence of a pilot flame.
    6. We revised the language in Sec.  60.5417a(f)(1)(iii) for
monitoring inlet gas flow rate on control devices tested by the
manufacturer. We did not intend for owners or operators to have to
continuously achieve a minimum inlet gas flow rate. We have revised the
requirement to indicate that there is only a limit on the maximum gas
inlet flow rate to the device. We also revised the language in Sec.
60.5417a(d)(1)(viii)(A) to indicate that the accuracy requirement is at
the maximum flow rate.
    7. We revised the language in Sec.  60.5413a(d)(11)(iii) to
indicate that manufacturers must demonstrate a destruction efficiency
of 95 percent for total hydrocarbons (THC), as propane. This
requirement previously stated that the manufacturer must demonstrate a
destruction efficiency of 95 percent for VOC and methane. The revised
language aligns more accurately with the testing requirements in the
rule. Additionally, as these units are burning propene during the test,
it would be impossible to demonstrate a destruction efficiency of
methane. As methane is a one-carbon, single-bonded compound, it is more
easily destructed than propene, a double-bonded compound, and thus, the
destruction efficiency should be just as high or higher for methane
than for the THC measured during the performance test.
    8. We revised the testing language in Sec.  60.5413a(b) in order to
make it clearer for compliance purposes. The proposed language failed
to clearly identify the number of runs or the length of runs expected
for each performance test. Additionally, the calculations did not
properly align with the specified methods. Section 60.5412a(d)(1)(i)
has no subsections. The reference to ``percent reduction performance
requirement'' in the referring section 60.5413a(b)(3) indicates that
the cross reference should refer to section 60.5412a(d)(1)(iv)(A),
which contains the percent reduction required.
    9. We revised the language in Sec.  60.5395a(a) to clarify that
owners and operators must comply with the requirements of Sec.
60.5395a(a)(1). The proposed language could have been interpreted to
mean that compliance with Sec.  60.5395a(a)(1) was not required if
owners or operators complied with Sec.  60.5395a(a)(3); however, it
would be impossible to comply with Sec.  60.5395a(a)(3) without first
determining the potential for VOC emissions, as required by Sec.
60.5395a(a)(1). We also further clarified when owners and operators
must comply with the requirements of Sec.  60.5395a(a)(2) and when they
may comply with the requirements of Sec.  60.5395a(a)(3).
    10. We revised the language in Sec.  60.5420a(b)(9)(i), Sec.
60.5420a(b)(11), Sec.  60.5422a(a), and 60.5423a(b) to update the Web
site address for the Electronic Reporting Tool (ERT). We have also
clarified that if the CEDRI form is not available at the time that a
report is due, we do not intend for owners or operators to submit forms
electronically through CEDRI until the form has been available for 90
days. We are also clarifying that this only applies to subsequent
reports; owners or operators would not be required to enter previous
reports into CEDRI once the form is available. While similar language
was proposed, we realize that the previous language did not fully
capture our intent.
    11. We revised the language in Sec.  60.5412a(c)(2)(iii) to correct
a drafting error. The proposed language lists the types of units in
which owners or operators must regenerate or reactivate spent carbon.
The proposed language stated the unit must be operating emission
controls in accordance with an emissions standard for VOC under another
subpart in 40 CFR part 60 or this part, which is redundant. The
language has been revised to state part 63 or this part. We also
removed Sec.  60.5412a(c)(2)(ii), as we do not believe that owners or
operators would be able to regenerate or reactivate spent carbon in
accordance with this section, as there are no requirements in this
section for that activity. Finally, we removed the phrase ``thermal
treatment'' in front of unit in Sec.  60.5412a(c)(2)(i) and (iii) as
the phrase ``thermal treatment unit'' is not defined.
    12. We revised the language in Sec.  60.5412a(c)(2)(iv) through
(vii) and Sec.  60.5413a(a)(4) and (5) to reconcile the fact that most
hazardous waste combustion units are subject to the requirements of 40
CFR part 63 subpart EEE. While our intent was to encompass all
hazardous waste incinerators, boilers and industrial furnaces in these
requirements, referencing only 40 CFR parts 264, 265, 266 and 270 may
have inadvertently excluded units.
    13. We revised the language in Sec.  60.5413a(b)(5)(ii)(B) to more
clearly identify the continuing compliance obligations for units exempt
from periodic testing.
    14. We revised the TOC emission rate limit in Sec.
60.5412a(a)(1)(ii) and Sec.  60.5412a(d)(1)(iv)(B) to be consistent
with the changes to the limit in 40 CFR part 60 subpart OOOO. For more
explanation on this topic, see the discussion on reconsideration issues
in section VI.H of this preamble. We also revised the TOC limit to be
on a wet basis, as these units will be tested with Method 25A, which
provides measurement data on a wet basis. While we note that
compressors must control both VOCs and methane to at least 95 percent,
the calculated limit reflects 95 percent control of VOC inflow to
control devices. Because methane is the simplest carbon compound, it is
very easy to destroy through combustion. Ensuring 95 percent
destruction of VOCs will guarantee greater than 95 percent destruction
of methane.
    15. We revised the wording of Sec.  60.5365(e)(4) and
60.5365a(e)(4) at the request of commenters seeking clearer direction
on the applicability of standards to storage vessels returning to

service. Since the re-wording does not change the meaning or
requirements of the section, the revisions have been made to both
subparts OOOO and OOOOa for consistency.
    16. We corrected the cross reference in section 60.5415(c)(4) from
Sec.  60.5411(a) to section 60.5416(a) and (b), and in Sec.  60.5415a
paragraph (c)(4) from section 60.5411a(a) to Sec.  60.5416a(a) and (b).
    17. We corrected language in in Sec.  60.5420(c)(6) to include
reciprocating compressors.
    18. We adjusted the language in Sec.  60.5412(d)(1)(iv)(C), Sec.
60.5412a(a)(1)(iii) and Sec.  60.5412a(d)(1)(iv)(C). This language
allowed operation of the control device at a minimum temperature of
760[deg]Celsius, if the control device was able to demonstrate a
uniform combustion temperature during the performance test. In our
response to comments on the August 23, 2011 proposed rule, we agreed
with commenters that uniform combustion profiles are difficult to
obtain due to flame zone mixing and heat transfer. In response to that
comment, we revised the language in 40 CFR part 63 subpart HH. We have
now revised the language in 40 CFR part 60 subparts OOOO and OOOOa to
mimic the language in 40 CFR part 63 subpart HH. We believe that this
change is necessary as we do not believe that owners or operators will
be able to demonstrate a uniform combustion zone temperature, nor have
we defined what it means to have a uniform combustion zone temperature
(e.g., the number of measurement points necessary, the agreement
between points, etc.). Additionally, Sec.  60.5412(d)(1)(iv)(C), Sec.
60.5412a(a)(1)(iii) and Sec.  60.5412a(d)(1)(iv)(C) previously
referenced performance testing in accordance with Sec.  60.5413 and
Sec.  60.5413a, but it was unclear what the performance testing
obligations were. We believe the revised language will allow owners and
operators to more easily comply with this requirement.
    19. We added language to Sec.  60.5412(d) and Sec.  60.5412a(d) to
make our intent clear that flares are acceptable control devices for
storage vessels and to identify the design requirements for flares. We
also revised language in Sec.  60.5415a(b)(2)(vii) to clearly identify
the continuing compliance requirements for flares.
    20. We adjusted the language in Sec.  60.5413a(b)(5)(ii)(A) and
Sec.  60.5417a(d)(1)(viii) to add a second compliance option for
control device models tested under Sec.  60.5413a(d). We are allowing
owners and operators an option to retest these units every five years
in lieu of continuously monitoring the gas flow rate. Owners and
operators must still ensure they are not overwhelming the control
device by using a control device that can handle the maximum flow rate
at the site.
    21. We added language to Sec.  60.5417a(a) to identify the
continuing compliance requirements for enclosed combustion devices that
are not specifically identified in Sec.  60.5417a(d).
    22. In preparation of the final rule, EPA discovered an error in
both subpart OOOO and the proposed subpart OOOOa. Specifically, they
fail to include a general duty to minimize emissions. As the EPA
clarified during the 2012 NSPS rulemaking, ``[t]he general duty is
applicable to a source at all times.'' \95\ Therefore, the absence of
this provision in subpart OOOO and the proposed subpart OOOOa was an
error, which is being corrected in these final rules at Sec.  60.5370
and Sec.  60.5370a.
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    \95\ See RTC document in EPA Docket I.D. No. EPA-HQ-OAR-2010-
0505-4546.
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J. Final Standards Reflecting Next Generation Compliance and Rule
Effectiveness

    We are finalizing certain standards that are reflecting EPA's Next
Generation Compliance and rule effectiveness strategies. Based on our
consideration of the comments received, we are finalizing some aspects
as proposed while, for others, we have made a number of changes to the
proposed standards. We have the opportunity to expand transparency by
making the information we have more accessible and by making new
information, obtained from advanced emissions monitoring and electronic
reporting, publicly available. We are finalizing an electronic
reporting requirement, via the EPA's CDX.
    Other aspects of the final rule will maximize regulatory
compliance, such as clear applicability of the final rule (e.g., in
revisions to modification criteria) and provide incentives for
inherently low-emitting equipment (e.g., solar pumps at gas plants are
not affected facilities). Advances in technology additionally promote
compliance by enhancing a ``visibility'' factor; this rule builds on
such Next Generation strategies, by including measures involving the
use of digital picture reporting and OGI technology. In lieu of
independent third party verification for closed vent system design, we
are finalizing a qualified professional engineer certification for
certain issues. For example, as discussed in section VIII of this
preamble, in response to comment, we are providing that a pneumatic
pump that cannot be connected to an existing control device due to
technical infeasibility does not have to meet this requirement.
However, we will require that the source make this determination
through use of a professional engineer certification. We are finalizing
the use of OGI technology as a method for detecting fugitive emissions
at well sites and compressor station sites. With the exception of
``clear applicability'', ``incentives for inherently low-emitting
equipment'' and ``OGI technology for monitoring fugitive emissions'',
which are discussed elsewhere in this preamble, this section identifies
the rationale to the regulatory text changes from proposal and states
how the EPA is finalizing these provisions. For additional details,
please refer to section VIII, the TSD, and the RTC supporting
documentation in the public docket.
1. Electronic Reporting
    Through electronic reporting, or e-reporting, paper reporting is
replaced by standardized, Internet-based, electronic reporting to a
central repository using specifically developed forms, templates, and
tools. E-reporting is not simply a regulated entity emailing an
electronic copy of a document to the government but, also a means to
make collected information easily accessible to the public and other
stakeholders.
    On March 20, 2015, the EPA proposed the ``Electronic Reporting and
Recordkeeping Requirements for New Source Performance Standards'' (80
FR 15099, March 20, 2015). If adopted, the rule would revise the part
60 General Provisions and various NSPS subparts in part 60 of title 40
of the Code of Federal Regulations (CFR) to require affected facilities
to submit specified air emissions data reports to the EPA
electronically and to allow affected facilities to maintain electronic
records of these reports. This proposed rule focuses on the submission
of electronic reports to the EPA that provide direct measures of air
emissions data such as performance test reports, performance evaluation
reports, summary and excess emission reports and subpart specific
reports that are similar in nature to these reports.
    Subpart OOOO is one of the rules potentially affected by this
rulemaking. When promulgated, in addition to electronically reporting
the results of performance tests, which is already a requirement, a
requirement to report the annual reports required in Sec.  60.5420(b),
the semiannual reports required in Sec.  60.5422 and the excess
emissions reports required in Sec.  60.5423(b) would

be added to subpart OOOO. The owner or operator would be required to
use the appropriate electronic form in CEDRI for the subpart or an
alternate electronic file format consistent with the form's extensible
markup language (XML) schema. If the reporting form specific to the
subpart is not available at the time that the report is due, the owner
or operator would submit the report to the Administrator at the
appropriate address listed in Sec.  60.4 of the General Provisions. The
owner or operator would begin submitting reports electronically with
the next report that is due once the electronic form has been available
for at least 90 days. The EPA is currently working to develop the form
for subpart OOOO.
    In the proposal for subpart OOOOa, the EPA included the same
electronic reporting requirements for subpart OOOOa that were included
for subpart OOOO in the March 2015 proposal. The EPA is finalizing the
requirement to report certain performance test reports, excess emission
reports, annual reports and semiannual reports electronically through
the EPA's CDX using the CEDRI. The EPA believes that the electronic
submittal of the reports addressed in this rulemaking will increase the
usefulness of the data contained in those reports, is in keeping with
current trends in data availability, will further assist in the
protection of public health and the environment, and will ultimately
result in less burden on the regulated community. Electronic reporting
can also eliminate paper-based, manual processes, thereby saving time
and resources, simplifying data entry, eliminating redundancies,
minimizing data reporting errors, and providing data quickly and
accurately to the affected facilities, air agencies, the EPA and the
public.
    The EPA Web site that stores the submitted electronic data,
WebFIRE, will be easily accessible to everyone and will provide a user-
friendly interface that any stakeholder can access. By making the
records, data and reports addressed in this rulemaking readily
available, the EPA, the regulated community and the public will benefit
when the EPA conducts its CAA-required reviews. As a result of having
reports readily accessible, our ability to carry out comprehensive
reviews will be increased and achieved within a shorter period of time.
    The EPA anticipates fewer or less substantial information
collection requests (ICRs) in conjunction with prospective CAA-required
reviews may be needed, resulting in a decrease in time spent by
industry to respond to data collection requests. The EPA also expects
the ICRs to contain less extensive stack testing provisions, as we will
already have stack test data electronically. Reduced testing
requirements would be a cost savings to industry. The EPA should also
be able to conduct these required reviews more quickly. While the
regulated community may benefit from a reduced burden of ICRs, the
general public benefits from the Agency's ability to provide these
required reviews more quickly, resulting in increased public health and
environmental protection.
    Air agencies will benefit from more streamlined and automated
review of the electronically submitted data. Having reports and
associated data in electronic format will facilitate review through the
use of software ``search'' options, as well as the downloading and
analyzing of data in spreadsheet format. The ability to access and
review air emission report information electronically will assist air
agencies to more quickly and accurately determine compliance with the
applicable regulations, potentially allowing a faster response to
violations that could minimize harmful air emissions. This benefits
both air agencies and the general public.
    For a more thorough discussion of electronic reporting, see the
discussion in the preamble of the March 2015 proposal. In summary, in
addition to supporting regulation development, control strategy
development, and other air pollution control activities, having an
electronic database populated with performance test data will save
industry, air agencies, and the EPA significant time, money, and effort
while improving the quality of emission inventories, air quality
regulations, and enhancing the public's access to this important
information.
2. Digital Picture Reporting as an Alternative for Well Completions
(``REC PIX'') and Manufacturer Installed Control Devices
    The EPA is finalizing digital picture reporting as an alternative
for well completions and manufacturer installed control devices as
proposed. Specifically, the final rule allows digital picture reporting
as an alternative for well completions (``REC PIX'') and manufacturer
installed control devices. These alternative reporting options provide
flexibility for owners and operators, provide enhanced ``visibility''
for regulators, and take advantage of the advances of the digital age
with the ability to capture geospatial accuracy at any location.
    Digital picture reporting as an alternative for well completions
(``REC PIX'') reflects the 2012 NSPS. As with the 2012 NSPS, we
continue to promote an optional mechanism by which owners and operators
could streamline annual reporting of well completions by using a
digital camera to document that a well completion was performed in
compliance with subpart OOOOa. Although we understand that commenters
have concerns about the amount of electronic storage capability
necessary to store digital pictures, we believe that by allowing either
the REC PIX or the elements required under the recordkeeping
requirements for well completions, the owner or operator may determine
what is most advantageous for their company. Should an owner or
operator choose to submit the REC PIX, the REC PIX must consist of a
digital photograph of the REC equipment in use, with the date and
geospatial coordinates shown on the photographs. These photographs must
be submitted with the next annual report, along with a list of well
completions performed with identifying information for each well
completed.
    Digital picture reporting as an alternative for manufacturer
installed control devices provides further opportunity and flexibility
to owners and operators to advance data capture to ensure that
compliance practices are in effect. This alternative recordkeeping and
reporting option is allowed specifically for centrifugal compressors
and storage vessels routed to control devices, where the control device
used is one tested in accordance with the manufacturer testing
procedures in the rule and is posted to the EPA Oil and Gas page. In
lieu of a written record with the location of the centrifugal
compressor or storage vessel and its associated control device in
latitude and longitude, the digital picture alternative must have the
date the photograph was taken and the latitude and longitude of the
centrifugal compressor and control device or storage vessel and control
device imbedded within or stored with the digital file. As an
alternative to imbedded latitude and longitude within the digital
picture, the digital picture may consist of a photograph of the
centrifugal compressor and control device with a photograph of a
separately operating GPS device within the same digital picture,
provided the latitude and longitude output of the GPS unit can be
clearly read in the digital photograph. Furthermore, as discussed in
section VI.F of this preamble, digital pictures and frame captures will
help ensure that OGI for fugitive emissions is being performed
properly.

3. Certification of Technical Infeasibility of Connecting a Pneumatic
Pump to an Existing Control Device
    In response to comment, the final rule requires that a new,
modified, or reconstructed pneumatic pump be routed to an existing
control device or process onsite, unless the owner or operator obtains
a certification that it is technically infeasible to do so. The EPA
understands that some factors such as capacity of the existing control
device and back pressure on the exhaust of the pneumatic pump imposed
by the closed vent system and control device can contribute to
infeasibility of routing a pneumatic pump to an existing control device
onsite. Due to the various scenarios that could make routing a
pneumatic pump to an onsite control device or process technically
infeasible, we do not think we could prescribe a specific set of
criteria or factors that must be considered for making such
determination that could capture all such circumstances. However, we
want to ensure that the owner or operator has effectively assessed
these factors before making a claim of infeasibility. To that end, we
have included provisions in the final rule to require certification by
a qualified professional engineer of such technical infeasibility. In
addition, we are requiring that the owner or operator maintain records
of that certification for a period of five years.
4. Professional Engineer Design of Closed Vent Systems
    It is the EPA's experience, through site inspections and
interaction with the states, that closed vent systems and control
devices for storage vessels and other emission sources often suffer
from improper design or inadequate capacity that results in emissions
not reaching the control device and/or the control device being
overwhelmed by the volume of emissions. Either of these conditions can
seriously compromise emissions control and can render the system
ineffective. We also discussed the issue in the September 2015
Compliance Alert ``EPA Observes Air Emissions from Controlled Storage
Vessels at Onshore Oil and Natural Gas Production Facilities'' (See
https://www.epa.gov/sites/production/files/2015-09/documents/oilgascompliancealert.pdf).
    We believe it is important that owners and operators make real
efforts to provide for proper design of these systems to ensure that
all the emissions routed to the control device reach the control device
and that the control device is sized and operated to result in proper
control. As a result, we have included in the final rule provisions for
certification by a qualified professional engineer that the closed vent
system is properly designed to ensure that all emissions from the unit
being controlled in fact reach the control device and allow for proper
control.
    Although the final rule does not include requirements for specific
criteria for proper design, the EPA believes there are certain minimum
design criteria that should be considered to ensure that the closed
vent and control device system are designed to meet the requirements of
the rule; i.e., the closed vent system must be capable of routing all
gases, vapors, and fumes emitted from the affected facility to a
control device or to a process that meets the requirements of the rule.
    Furthermore, because other emissions may be collected into the
closed vent system and routed to the control device, these design
criteria include consideration of the contribution of these additional
emissions to ensure proper sizing and operation. The minimum design
elements include, but are not limited to, based on site-specific
considerations:
    1. Review of the Control Technologies to be Used to Comply with
Sec. Sec.  60.5380a and 60.5395a.
    2. Closed Vent System Considerations:
    a. Piping--
    i. Size (include all emissions, not just affected facility);
    ii. Back pressure, including low points which collect liquids;
    iii. Pressure losses; and
    iv. Bypasses and pressure release points.
    3. Affected Facility Considerations:
    a. Peak Flow from affected facility, including flash emissions, if
applicable; and
    b. Bypasses, pressure release points.
    4. Control Device Considerations:
    a. Maximum volumetric flow rate based on peak flow, and
    b. Ability to handle future gas flow.

K. Provision for Equivalency Determinations

    In recent years, certain states have developed programs to control
various oil and gas emission sources in their own states. Due to the
differences in the sources covered and the requirements, determining
equivalency through direct comparison of the various state programs
with the NSPS has proven to be difficult. We also did not find that any
state program as a whole would reflect what we have identified as the
BSERs for all emissions sources covered by the NSPS. In any event,
federal standards are necessary to ensure that emissions from the oil
and natural gas industry are controlled nationwide.
    However, depending on the applicable state requirements, certain
owners and operators may achieve equivalent or more emission reduction
from their affected source(s) than the required reduction under the
NSPS by complying with their state requirements. States may adopt and
enforce standards or limitations that are more stringent than the NSPS.
See CAA section 116 and the EPA's regulations at 40 CFR 60.10(a). For
states that are being proactive in addressing emissions from the oil
and natural gas industry, it is important that the NSPS complement such
effort. Therefore, in the final rule, through the process described in
section VI.F.1.i for emerging technology, owners and operators may also
submit an application requesting that the EPA approve certain state
requirement as ``alternative means of emission limitations'' under the
NSPS for their affected facilities. The application would include a
demonstration that emission reduction achieved under the state
requirement(s) is at least equivalent to the emission reduction
achieved under the NSPS standards for a given affected facility.
Consistent with section 111(h)(3), any application will be publicly
noticed, which the EPA intends to provide within six months after
receiving a complete application, including all required information
for evaluation. The EPA will provide an opportunity for public hearing
on the application and on intended action the EPA might take. The EPA
intends to make a final determination within six months after the close
of the public comment period. The EPA will also publish its
determination in the Federal Register.

VII. Prevention of Significant Deterioration and Title V Permitting

A. Overview

    This final rule will regulate GHGs under CAA section 111. In this
section, the EPA is addressing how regulation of GHGs under CAA section
111 could have implications for other EPA rules and for permits written
under the CAA Prevention of Significant Deterioration (PSD)
preconstruction permit program and the CAA Title V operating permit
program. The EPA is adopting provisions in the regulations that
explicitly address some of these potential implications based on our
review of the proposed regulatory text and comments received on the
proposal.
    For purposes of the PSD program, the EPA is finalizing provisions
in part 60

of its regulations and explaining in this preamble that the current
threshold for determining whether a PSD source must satisfy the best
available control technology (BACT) requirement for GHGs continues to
apply after promulgation of this rule. This rule does not require any
additional revisions to state implementation plans (SIPs). With respect
to the Title V operating permits program, we are finalizing provisions
in part 60 and explaining in this preamble that this rule does not
affect whether sources are subject to the requirement to obtain a Title
V operating permit based solely on emitting or having the potential to
emit GHGs above major source thresholds.

B. Applicability of Tailoring Rule Thresholds Under the PSD Program

    EPA received several comments asking for clarification or changes
to make clear that this rule did not directly regulate methane as a
separate pollutant from GHG and that it would not cause sources to
trigger PSD or Title V permitting requirements based solely on methane
emissions.\96\ This section discusses changes made in response to these
comments as well as clarification as to what, if any, impact this rule
has on PSD permitting. Section VII.C below addresses Title V-specific
issues.
---------------------------------------------------------------------------

    \96\ As is discussed elsewhere, the EPA has made clear that the
pollutant subject to regulation is GHG, in the form of methane.
Additional regulatory language in 40 CFR 60.5360a has been added to
provide additional clarity.
---------------------------------------------------------------------------

    Under the PSD program in part C of title I of the CAA, in areas
that are classified as attainment or unclassifiable for NAAQS
pollutants, a new or modified source that emits any air pollutant
subject to regulation at or above specified thresholds is required to
obtain a preconstruction permit. This permit ensures that the source
meets specific requirements, including application of BACT to each
pollutant subject to regulation under the CAA. Many states (and local
districts) are authorized by the EPA to administer the PSD program and
to issue PSD permits. If a state is not authorized, then the EPA issues
the PSD permits for facilities in that state.
    To identify the pollutants subject to the PSD permitting program,
EPA regulations contain a definition of the term ``regulated NSR
pollutant.'' 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition
contains four subparts, which cover pollutants regulated under various
parts of the CAA. The second subpart covers pollutants regulated under
section 111 of the CAA. The fourth subpart is a catch-all provision
that applies to ``[a]ny pollutant that is otherwise subject to
regulation under the Act.''
    This definition and the associated PSD permitting requirements
applied to GHGs for the first time on January 2, 2011, by virtue of the
EPA's regulation of GHG emissions from motor vehicles, which first took
effect on that same date. 75 FR 17004 (Apr. 2, 2010). GHGs became
subject to regulation under the CAA and the fourth subpart of the
``regulated NSR pollutant'' definition became applicable to GHGs.
    On June 3, 2010, the EPA issued a final rule, known as the
Tailoring Rule, which phased in permitting requirements for GHG
emissions from stationary sources under the CAA PSD and Title V
permitting programs (75 FR 31514). Under its understanding of the CAA
at the time, the EPA believed the Tailoring Rule was necessary to avoid
a sudden and unmanageable increase in the number of sources that would
be required to obtain PSD and Title V permits under the CAA because the
sources emitted GHGs in amounts over applicable major source and major
modification thresholds. In Step 1 of the Tailoring Rule, which began
on January 2, 2011, the EPA limited application of PSD or Title V
requirements to sources of GHG emissions only if the sources were
subject to PSD or Title V ``anyway'' due to their emissions of non-GHG
pollutants. These sources are referred to as ``anyway sources.'' In
Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA
applied the PSD and Title V permitting requirements under the CAA to
sources that were classified as major and, thus, required to obtain a
permit based solely on their potential GHG emissions and to
modifications of otherwise major sources that required a PSD permit
because they increased only GHG emissions above applicable levels in
the EPA regulations.
    In the PSD program, the EPA implemented the steps of the Tailoring
Rule by adopting a definition of the term ``subject to regulation.''
The limitations in Step 1 of the Tailoring Rule are reflected in 40 CFR
52.21(b)(49)(iv) and 40 CFR 51.166(b)(48)(iv). With respect to ``anyway
sources'' covered by PSD during Step 1, this provision established that
GHGs would not be subject to PSD requirements unless the source emitted
GHGs in the amount of 75,000 tons per year (tpy) of CO2 Eq. or more.
The primary practical effect of this paragraph is that the PSD BACT
requirement does not apply to GHG emissions from an ``anyway source''
unless the source emits GHGs at or above this threshold. The Tailoring
Rule Step 2 limitations are reflected in 40 CFR 52.21(b)(49)(v) and
51.166(b)(48)(v). These provisions contain thresholds that, when
applied through the definition of ``regulated NSR pollutant,'' function
to limit the scope of the terms ``major stationary source'' and ``major
modification'' that determine whether a source is required to obtain a
PSD permit. See e.g., 40 CFR 51.166(a)(7)(i) and (iii); 40 CFR
51.166(b)(1); 40 CFR 51.166(b)(2).
    On June 23, 2014, the United States Supreme Court, in Utility Air
Regulatory Group v. Environmental Protection Agency, issued a decision
addressing the application of PSD permitting requirements to GHG
emissions. The Supreme Court held that the EPA may not treat GHGs as an
air pollutant for purposes of determining whether a source is a major
source (or modification thereof) for the purpose of PSD applicability.
The Court also said that the EPA could continue to require that PSD
permits, otherwise required based on emissions of pollutants other than
GHGs, contain limitations on GHG emissions based on the application of
BACT. The Supreme Court decision effectively upheld PSD permitting
requirements for GHG emissions under Step 1 of the Tailoring Rule for
``anyway sources'' and invalidated application of PSD permitting
requirements to Step 2 sources based on GHG emissions. The Court also
recognized that, although the EPA had not yet done so, it could
``establish an appropriate de minimis threshold below which BACT is not
required for a source's greenhouse gas emissions.'' 134 S. Ct. at 2449.
    In accordance with the Supreme Court decision, on April 10, 2015,
the United States Court of Appeals for the District of Columbia Circuit
(the D.C. Circuit) issued an amended judgment vacating the regulations
that implemented Step 2 of the Tailoring Rule but not the regulations
that implement Step 1 of the Tailoring Rule. The court specifically
vacated 40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA's
regulations, but did not vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR
52.21(b)(48)(iv). The court also directed the EPA to consider whether
any further revisions to its regulations are appropriate in light of
UARG v. EPA and, if so, to undertake such revisions.
    The practical effect of the Supreme Court's clarification of the
reach of the CAA is that it eliminates the need for Step 2 of the
Tailoring Rule and subsequent steps of the GHG permitting phase-in that
the EPA had planned to consider under the Tailoring Rule. This also
eliminates the possibility that the

promulgation of GHG standards under section 111 could result in
additional sources becoming subject to PSD based solely on GHGs,
notwithstanding the limitations the EPA adopted in the Tailoring
Rule.\97\ However, for an interim period, the EPA and the states will
need to continue applying parts of the PSD definition of ``subject to
regulation'' to ensure that sources obtain PSD permits meeting the
requirements of the CAA.
---------------------------------------------------------------------------

    \97\ As discussed in other portions of this rulemaking, GHG are
the pollutant subject to regulation by this rule. The standards are
specific to GHGs expressed in the form of limitations on emissions
of methane. Changes, consistent with 40 CFR part 60, subpart TTTT as
suggested by several of the commenters, have been made in 40 CFR
60.5360a to make this clear.
---------------------------------------------------------------------------

    The CAA continues to require that PSD permits issued to ``anyway
sources'' satisfy the BACT requirement for GHGs. Based on the language
that remains applicable under 40 CFR 51.166(b)(48)(iv) and 40 CFR
52.21(b)(49)(iv), the EPA and states may continue to limit the
application of BACT to GHG emissions in those circumstances where a
source emits GHGs in the amount of at least 75,000 tpy on a CO2 Eq.
basis. The EPA's intention is for this to serve as an interim approach
while the EPA moves forward to propose a GHG significant emission rate
(SER) that would establish a de minimis threshold level for permitting
GHG emissions under PSD. Under this forthcoming rule, the EPA intends
to propose restructuring the GHG provisions in its PSD regulations so
that the de minimis threshold for GHGs will not reside within the
definition of ``subject to regulation.'' This restructuring will be
designed to make the PSD regulatory provisions on GHGs universally
applicable, without regard to the particular subparts of the definition
of ``regulated NSR pollutant'' that may cover GHGs. Upon promulgation
of this PSD rule, it will then provide a framework that states may use
when updating their SIPs consistent with the Supreme Court decision.
    While the PSD rulemaking described above is pending, the EPA and
approved state, local, and tribal permitting authorities will still
need to implement the BACT requirement for GHGs. In order to enable
permitting authorities to continue applying the 75,000 tpy CO2 Eq.
threshold to determine whether BACT applies to GHG emissions from an
``anyway source'' after GHGs are subject to regulation under CAA