information, we have concluded that semiannual monitoring is not
feasible for well sites located on the Alaskan North Slope, therefore,
conducting three quarterly monitoring events is likewise not feasible
for compressor stations. Therefore, we are proposing amendments to the
fugitive emissions requirements in the 2016 NSPS OOOOa as they apply to
compressor stations located on the Alaskan North Slope.
---------------------------------------------------------------------------

    \67\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
    \68\ See Docket ID No. EPA-HQ-OAR-2010-0505-12434.
    \69\ See FLIR Systems, Inc. product specifications for GF300/320
model OGI cameras at http://www.flir.com/ogi/display/?id=55671.
    \70\ See Thermo Fisher Scientific product specification for TVA-
2020 at https://assets.thermofisher.com/TFS-Assets/LSG/Specification-Sheets/EPM-TVA2020.pdf.
    \71\ See information on average hourly temperatures from January
2010 to January 2018 at the weather station located at Deadhorse
Alpine Airstrip, Alaska. Obtained from the National Oceanic and
Atmospheric Administration (NOAA)'s National Centers for
Environmental Information and summarized in Docket ID No. EPA-HQ-
OAR-2010-0505-12505.
---------------------------------------------------------------------------

    We are proposing to establish separate fugitive monitoring
requirements for compressor stations located on the Alaskan North Slope
because of the technical infeasibility issues with the operations of
the monitoring instruments discussed above. Similar to well sites
located on the Alaskan North Slope, we are proposing that new
compressor stations that startup between September and March must
conduct initial monitoring within 6 months of startup, or by June 30,
whichever is later. Similarly, we are proposing that modified
compressor stations located on the Alaskan North Slope that become
modified between September and March must conduct initial monitoring
within 6 months of the modification, or by June 30, whichever is later.
Compressor stations that startup or are modified between April and
August would meet the 60-day initial monitoring requirement in the 2016
NSPS OOOOa. However, as discussed in section VI.B.3, we are soliciting
comment on extending the time frame for conducting the initial
monitoring for all well site and compressor station fugitive emissions
components subject to the 2016 NSPS OOOOa, including those located on
the Alaskan North Slope. Further, we are proposing that all compressor
stations located on the Alaskan North Slope that are subject to the
fugitive emissions requirements must conduct annual monitoring.
Subsequent annual monitoring must be conducted at least 9 months apart,
but no more than 13 months apart.
    As discussed in section VI.B.3 of this preamble (Initial Monitoring
for Well Sites and Compressor Stations), the EPA is soliciting comment
on whether to extend the period for conducting initial monitoring for
well sites and compressor stations because additional time is needed to
complete installation of equipment. For the same reason, the EPA is
soliciting comment on whether to extend the time frame for initial
monitoring for well sites that start up production and compressor
stations that start up between April and August, and for those that are
modified during this period. Further discussion on this topic is
included in section VI.B.3 of this preamble, which describes the
concerns raised and the timeframes suggested by petitioners (180 days)
and the EPA (90 days) to address such concerns. In addition to the
information specified in that subsection, we are soliciting comments
and information specific to the well sites and compressor stations
located on the Alaskan North Slope regarding allowing additional time
for the initial monitoring. Upon receiving and reviewing the relevant
information, the EPA may conclude that amendment to extend the
timeframe for conducting the initial monitoring is necessary for all or
some well site and compressor station fugitive emissions components
subject to the 2016 NSPS OOOOa, including those located on the Alaskan
North Slope.
    One petitioner \72\ requested that the EPA exempt well sites and
compressor stations located on the Alaskan North Slope from fugitive
emissions monitoring, similar to the exemptions from LDAR at natural
gas processing plants provided in the 2012 NSPS OOOO and the 2016 NSPS
OOOOa. The petitioner stated the reasons for applying an exemption to
natural gas processing plants are also valid for well sites and
compressor stations.
---------------------------------------------------------------------------

    \72\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
---------------------------------------------------------------------------

    The EPA exempted natural gas processing plants from LDAR
requirements when issuing 40 CFR part 60, subpart KKK, in 1985 (1985
NSPS KKK). At that time, we acknowledged ``that there are several
unique aspects to the operation of natural gas processing plants north
of the Arctic Circle. Because of the unique aspects of natural gas
processing plants north of the Arctic Circle, the increased costs to
perform routine leak detection and repair may result in an unreasonable
cost effectiveness.'' \73\ We currently do not have sufficient
information to suggest that the cost-effectiveness of the fugitive
emissions requirements specific to well sites and compressor stations
located on the Alaskan North Slope differ from the cost-effectiveness
of the program generally. The information we do have related to the
initial monitoring suggests that the average initial percentage of
identified fugitive emissions for a well site located on the Alaskan
North Slope is 2.38 percent.\74\ Additionally, this information
represents some of the highest reported percentages of identified
fugitive emissions from the data set are from well sites located on the
Alaskan North Slope. Therefore, we are not proposing to exempt well
sites located on the Alaskan North Slope from the fugitive emissions
requirements. However, we are soliciting data to support an analysis of
the cost-effectiveness of fugitive emissions monitoring programs for
well sites and compressor stations located on the Alaskan North Slope,
including the cost associated with performing annual fugitive emissions
monitoring and repairs. Specific information that distinguishes
differences in cost realized by sites located on the Alaskan North
Slope from our model plant estimates would be useful.
---------------------------------------------------------------------------

    \73\ ``Equipment Leaks of VOC in Natural Gas Production
Industry--Background Information for Promulgated Standards,'' EPA-
450/3-82-024b, May 1985.
    \74\ See memorandum EPA Analysis of Well Site Fugitive Emissions
Monitoring Data Provided by API located at Docket ID No. EPA-HQ-OAR-
2017-0483. April 17, 2018.
---------------------------------------------------------------------------

2. Modification -Name: pb -Payroll No: 09854 -Folios: 66-69 -Date: 10/
10/18[FEDREG][VOL]*[/VOL][NO]*[/NO][DATE]*[/
DATE][PRORULES][PRORULE][PREAMB][AGENCY]*[/AGENCY][SUBJECT]*[/
SUBJECT][/PREAMB][SUPLINF][HED]*[/HED]?>
    Modification of Well Sites. For the purposes of fugitive emissions
components at a well site, a modification is defined in 40 CFR
60.5365a(i)(3) as (i) drilling a new well at an existing well site,
(ii) hydraulically fracturing a well at an existing well site, or (iii)
hydraulically refracturing a well at an existing well site. As the EPA
explained in that rulemaking, these three activities, which are
conducted to increase production, increase fugitive emissions at well
sites in two ways. First, increased production will ``generate
additional emissions at the well sites. Some of these additional
emissions will pass through leaking fugitive emission components at the
well sites (in addition to the emissions already leaking from those
components).'' 81 FR 35881. Second, additional fugitive emissions can
also result from installation of additional equipment. As the EPA
observed, ``it is not uncommon that an increase in production would
require additional equipment and, therefore, additional fugitive
emission components at the well sites.'' Id.
    As previously mentioned, in a letter dated April 18, 2017, the
Administrator granted reconsideration of several

aspects of the 2016 NSPS OOOOa, including its application of the
fugitive emissions requirements at 40 CFR 60.5397a to low production
well sites.\75\ The petitioner who raised this issue for
reconsideration identified in its petition a perceived inconsistency
between the EPA's justification for not exempting low production well
sites from the fugitive emissions requirements and the EPA's rationale
for the definition of modification for purposes of those same
requirements.\76\ This petitioner observed that it appeared the EPA
relied on data indicating the same equipment counts are present at all
well sites, regardless of production levels, to justify regulating
fugitive emissions at low production well sites, while defining
modification by events that increase production (i.e., drilling a new
well, hydraulic fracturing, or hydraulic refracturing), which the EPA
concludes will increase emissions whether or not there is change in
component counts. The petitioner then stated that:
---------------------------------------------------------------------------

    \75\ See Docket ID No. EPA-HQ-OAR-2010-0505-7730.
    \76\ See Docket ID No. EPA-HQ-OAR-2010-0505-7685.

    EPA's rationale, that fugitive emissions are a function of the
number and types of equipment, and not operating parameters such as
pressure and volume, is inconsistent with EPA's justification for
what constitutes a `modification' for an existing well site. EPA
assumes that fracturing or refracturing an existing well will
increase emissions because of the additional production, i.e., the
additional pressure and volume. EPA cannot ignore the laws of
physics to the detriment of low production wells in one instance and
then `honor' them in another context to eliminate an `emissions
increase' requirement in the traditional definition of
`modification.' \77\
---------------------------------------------------------------------------

    \77\ See Docket ID No. EPA-HQ-OAR-2010-0505-7685, page 6.

    In addition to the issues raised regarding an inconsistency with
our treatment of fugitive emissions from low production well sites and
what constitutes a modification (as discussed in section VI.B.1),
several petitioners stated that hydraulically refracturing a well alone
would not increase emissions from the fugitive emissions components and
suggested that emissions would increase from a refractured well only if
additional permanent equipment is also installed.\78\ According to one
petitioner,
---------------------------------------------------------------------------

    \78\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.

[a] well that is refractured typically does not require additional
production equipment and does not typically operate at a pressure
higher than before the refracturing since that pressure is set by
the gas gathering system pressure. Therefore, as long as a
significant piece of process equipment is not constructed along with
the refracture, there is no emissions increase and there is no
`modification' as defined in CFR part 60.2. \79\
---------------------------------------------------------------------------

    \79\ Docket ID No. EPA-HQ-OAR-2010-0505-7682, p. 16.

    In light of the above, the EPA has provided a more detailed
explanation below for the definition of modification of fugitive
emissions components at well sites, including how an increase in
production can increase fugitive emissions at well sites even without
the addition of equipment, and therefore no addition of fugitive
emissions components. The EPA has also re-evaluated its treatment of
low production well sites, which is discussed in section VI.B.1 of this
preamble.
    There is no dispute that an addition of processing equipment, and
attendant fugitive emissions components, in conjunction with
refracturing a well will result in a modification. Further, as
explained in the 2016 NSPS OOOOa and in more detail below, an increase
in the number of components is not the sole reason for an increase in
fugitive emissions when there is an increase in production.
    A well is refractured for the purpose of increasing production
rates. An increase in the production rate necessitates, by definition,
an increase in the molar flow rate. An increase in molar flow rate can
be accomplished through an increase in operating pressure (and
attendant mass per unit of volume) and/or volumetric flow rate. An
increase in volumetric flow rate can be accomplished through an
increase to the velocity of flow, an increase to cross-sectional area
of the flow path, or, if flow is intermittent, an increase to the time
duration of flow (e.g., duration of flow events or frequency of flow
events). Increasing velocity of flow of production fluids through
process equipment can only be accomplished through an increase in the
pressure drop across the system. Where increased production throughput
is routed through a system of production equipment that is not
physically changed, the cross-sectional area of the flow path through
the equipment does not change. Therefore, the increase in production
rate requires an increase to either the operating pressure and/or the
duration or frequency of flow events. Where operating pressure is
increased, the pressure increase will increase the molar flow rate of
fugitive emissions from leaking fugitive emission components. These
increased emissions on components with existing fugitive emissions will
occur even if the increased operating pressure does not result in
additional components with fugitive emissions at existing design stress
points, which is an additional source of potential fugitive emissions
increases. Increasing duration or frequency of flow events will not be
an option unless flow is intermittent. Where flow is intermittent in
the process and flow event duration or frequency is increased (e.g.,
through longer dump events or more frequent dump events), additional
molar flow rate will pass through components with fugitive emissions
due to increased periods of flow through that component at the same
pressure. Therefore, as was stated in the 2016 NSPS OOOOa preamble
language, increased production will result in ``[s]ome of these
additional emissions [passing] through leaking fugitive emission
components at the well sites (in addition to the emissions already
leaking from those components).'' 81 FR 35881.
    There is also a third instance in which increased production from
modification of a well site could cause an increase in emissions from
fugitive emissions components without additional equipment, and
therefore, without additional fugitive emissions components. Absent
additional stages of separation or an otherwise-accomplished decrease
in the pressure at the final stage of separation prior to the storage
vessels, increased production throughput to storage vessels increases
the flash emissions at those storage vessels. Where storage vessels are
affected facilities for purposes of this rule, the rule contains
separate requirements for storage vessel covers and CVS to be designed
and operated to route all emissions to a control device. However, where
controlled storage vessels are not affected facilities because legally
and practically enforceable permits limit the potential VOC emissions
to below 6 tpy, the covers and CVS are included in the fugitives
monitoring program for the well site as a fugitive emissions component.
In either scenario, it is possible for increased throughput to these
controlled storage vessels at a well site to exceed the design capacity
of the vapor control system, which may result in additional emissions
from storage vessel thief hatches or other openings.
    For the reasons stated above, we propose to maintain our conclusion
that refracturing of an existing well will increase fugitive emissions.
We solicit comments on our rationale described above. Specifically, we
solicit comments and data on whether emissions from fugitive emissions
components will

increase following a refracture even if the equipment counts and
operating pressures remain the same. Further, we are soliciting
comments and data about how changes in production may influence the
operating pressures of the well site. Additionally, we are soliciting
comment and data on whether an increase in pressure alone (without
additional equipment) would result in more fugitive emissions (e.g.,
cause new fugitive emissions that were not otherwise present or would
result in an increase in the fugitive emissions from an already leaking
fugitive emissions component). Finally, we are soliciting comment and
information on other factors, such as changes in the gas gathering
system, that may influence the operating pressures of the well site.
    During the implementation of the 2016 NSPS OOOOa, several questions
were raised regarding the modification of a separate tank battery for
the purposes of fugitive emissions monitoring. The definition of well
site in 40 CFR 60.5430a states, ``For purposes of the fugitive
emissions standards at Sec.  60.5397a, well site also means a separate
tank battery surface site collecting crude oil, condensate,
intermediate hydrocarbon liquids, or produced water from wells not
located at the well site (e.g., centralized tank batteries).''
Stakeholders have commented to the EPA that there is confusion
regarding when a modification of fugitive emissions components has
occurred at a separate tank battery. Similar to the information from
petitioners regarding modifications without a change in equipment or
component counts at a well site, stakeholders have also claimed that
sending process fluids from a new well or existing hydraulically
fractured or refractured well that is not located at the separate tank
battery will not necessarily increase the emissions from the fugitive
emissions components at the separate tank battery. Instead,
stakeholders have suggested that emissions increase only when
additional processing equipment, such as storage vessels, separators,
or compressors, is installed in conjunction with the introduction of
additional process fluids received from these off-site wells.
    The EPA is proposing a clarification to address modifications of
the collection of fugitive emissions components at well sites when the
well site is a separate tank battery with no wells located at the tank
battery. While the regulatory text is clear about what constitutes a
modification when a well is located at the separate tank battery, the
regulatory text is less clear when there are no wells at the tank
battery. To clarify the definition of modifications for separate tank
batteries, we are proposing specific amendments to clarify when a
modification occurs at a well site, including a well site that is a
separate tank battery. We are proposing to amend the language in 40 CFR
60.5365a(i) to add two additional instances to clarify when there is a
modification to the collection of fugitive emissions components located
at a separate tank battery, such as a centralized tank battery (which
itself is a well site as defined in 40 CFR 60.5430a). First, when
production from a new, hydraulically fractured, or hydraulically
refractured well is sent to an existing separate tank battery, the
collection of fugitive emissions components at the separate tank
battery has been modified. Second, when a well site that is subject to
fugitive emissions requirements removes the major production and
processing equipment, such that it becomes a well head only well site,
and sends the production to an existing separate tank battery, the
collection of fugitive components at that separate tank battery has
modified. In both instances, a physical or operational change occurs at
an existing separate tank battery because additional production from a
well site is sent to that separate tank battery, and this change
results in an increase in fugitive emissions at that tank battery. We
are soliciting comment on these proposed amendments to the definition
of modification of the collection of fugitive emissions components
located at a well site, including the treatment of separate tank
batteries as well sites for the purposes of fugitive emissions
requirements. Additionally, we are soliciting comment on other options
for modifications of a separate tank battery for purposes of fugitive
emissions monitoring. For example, we are soliciting comment on whether
we should define a separate tank battery as a separate affected
facility, instead of defining this source as a well site. Further, we
are soliciting comment on what would constitute a modification of a
separate tank battery affected facility, or other options for a
modification if the definition remains as currently proposed. Finally,
the EPA is soliciting information related to the permitting of such
separate tank batteries and information related to how states have
regulated these sources when a well is not located at the site.
    Modification of Compressor Stations. For the purposes of fugitive
emissions components at a compressor station, a modification is defined
in 40 CFR 60.5365a(j) as (1) the installation of an additional
compressor at an existing compressor station or (2) the replacement of
one or more compressors at an existing compressor station that results
in a net increase in the total horsepower to drive the compressor(s)
that are replaced at the compressor station. We are not proposing any
changes to this definition; however, we are soliciting comment on
whether the engine horsepower is the correct measure of increased
emissions from the collection of fugitive emissions components.
    Further, the EPA is clarifying the type of compressors that would
trigger a modification for the purposes of fugitive emissions at a
compressor station. In the preamble to the 2016 NSPS OOOOa, the EPA
clarified that this definition refers to instances where ``the design
capacity and potential emissions of the compressor station would
increase.'' 81 FR 35864. Therefore, it is possible that the addition of
a compressor would not be considered a modification where the overall
design capacity of the compressor station is not increased. For
example, the addition of a vapor recovery unit (VRU) compressor, such
as a screw or vane compressor, would not be a modification for purposes
of the compressor station fugitive emissions standards. Adding a VRU
compressor does not increase the overall design capacity of the
compressor station for the following reasons. VRU compressors are
installed to recover methane and VOC emissions; they are not designed
to ``move natural gas at increased pressure through gathering or
transmission pipelines, or into or out of storage.'' Therefore, the
addition of a VRU compressor does not increase the overall design
capacity of a compressor station, and does not result in a modification
of the compressor station for the purposes of fugitive emissions
monitoring. The EPA is not proposing a definition for compressor in
this action because the explanation provided above related to the
definition of compressor station does not support the need for a
definition, and because the 2016 NSPS OOOOa already contains
definitions of centrifugal and reciprocating compressors, which are the
only compressor affected facilities.
3. Initial Monitoring for Well Sites and Compressor Stations
    The 2016 NSPS OOOOa requires completion of initial monitoring for
well sites and compressor stations by June 3, 2017, or 60 days after
startup, whichever is later. For well sites, the startup of production
marks the beginning of the initial monitoring

survey period for the collection of fugitive emissions components at a
well site. Similarly, for compressor stations, the startup of the
compressor station marks the beginning of the initial monitoring survey
period.
    Petitioners on the 2016 NSPS OOOOa have requested that the timing
of fugitive emissions initial monitoring surveys be revised to allow
for integration into existing monitoring programs.\80\ One petitioner
asserted that there are numerous challenges to setting up and
implementing a fugitive monitoring program. The petitioner reported
that even with the EPA's one-year phase-in allowance, there are initial
inspection timing challenges (e.g., because of the significant
distances between oil and gas sites). Petitioners requested that the
EPA consider allowing 180 days for the initial survey. According to the
petitioners, allowing for 180 days would not result in significantly
more emissions and that, on average, half of the sites would likely
conduct their initial survey in less than 90 days and half would likely
conduct their initial survey between 90 and 180 days.
---------------------------------------------------------------------------

    \80\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-10791.
---------------------------------------------------------------------------

    Between proposal and promulgation of the 2016 NSPS OOOOa, several
industry comments recommended a 90-day time period (in lieu of the 30-
day time period we initially proposed) to complete the initial survey
to (1) address time and logistical capacities of oil and gas field
crews and potential limited availability of monitoring contractors, (2)
be consistent with the Ohio Environmental Protection Agency's General
Air Permit for Oil and Gas Well Site Production Operations (General
Permit 12.2), and (3) provide a more realistic time frame to perform an
initial survey without potentially resulting in safety issues while
initial oil and gas production and completion activities are taking
place on the well pad.\81\ Other industry comments were received
requesting that the EPA allow the initial fugitive survey to occur
within 180 days from startup of a new well site or compressor station
to (1) be consistent with similar LDAR programs, such as NSPS KKK and
NSPS OOOO (where leak detection is currently imposed at natural gas
processing plants), and (2) allow owners or operators time to do a
thorough check of all new equipment installations before the
survey.\82\ One of the commenters (also a petitioner) reported that 180
days is needed to prepare for monitoring of the new or modified well
site and ensure that such monitoring is conducted during the next
scheduled monitoring period that would include all the well sites in
the area.\83\ They asserted that hiring third-party contractors to
monitor one remote well site is inefficient and costly.
---------------------------------------------------------------------------

    \81\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-6808, EPA-HQ-OAR-
2010-0505-6935 and EPA-HQ-OAR-2010-0505-6960.
    \82\ See Docket ID EPA-HQ-OAR-2010-0505-6857.
    \83\ See Docket ID EPA-HQ-OAR-2010-0505-6884.
---------------------------------------------------------------------------

    We have not received data indicating that initial monitoring cannot
be completed within the currently required 60-day timeframe. We propose
to maintain our conclusion that, in light of the need to complete
initial monitoring in a timely manner after startup of production for
well sites and the startup or modification for compressor stations to
verify the proper installation of equipment, waiting 180 days for
initial monitoring is too long after the installation of equipment to
verify its proper installation. However, we are soliciting data that
supports or refutes the claims by the petitioner that 180 days are
necessary for proper installation of equipment before conducting
initial monitoring would not result in significantly more emissions.
Assuming we receive information that supports extending the initial
monitoring deadline to give more time for installing equipment, we
think it is possible these tasks may be nevertheless completed in a
shorter time frame than the suggested 180 days discussed above. We are,
therefore, soliciting comment and supporting data for changing the
initial monitoring deadline to 90 days from 60 days after the startup
of production for well sites and the startup or modification for
compressor stations. Specific data would need to outline the
difficulties with completing initial monitoring within the 60 days
required in the 2016 NSPS OOOOa. In summary, while we are proposing to
maintain the 60-day requirement, we solicit comment and information
regarding the request to extend to 180 days, as well as an intermediate
90-day requirement.
    We recognize that the 2016 NSPS OOOOa includes a waiver from
quarterly monitoring at compressor stations after recognizing there are
areas of the country that may experience temperatures below 0[deg] for
a period of 60 days. However, as discussed in detail in section VI.B.4,
we are not sure where any areas of the country would utilize this
waiver. The EPA is soliciting comment on how cold weather may impact
the ability to comply with the 60-day initial monitoring deadline for
well sites and compressor stations.
4. Low Temperature Waivers
    In the 2016 NSPS OOOOa, owners and operators are granted a waiver
from one quarterly monitoring event at compressor stations if the
average temperature is below 0[deg] for two consecutive quarters. 40
CFR 60.5397a(g)(5). In the preamble to the 2016 NSPS OOOOa we stated
that the waiver was included for two reasons: (1) There were concerns
raised by commenters that extreme winter weather created risk for the
safety of monitoring survey personnel and (2) the manufacturer
specifications indicate that OGI cameras may not reliably operate at
temperatures below 0[deg]. 80 FR 56668. In light of the proposed
changes to monitoring frequencies discussed in section VI.B.1 of this
preamble, we are proposing to remove the low temperature waiver because
it is no longer relevant. The EPA is soliciting comment and supporting
data that would indicate a need to maintain the waiver.
5. Repair Requirements
    Repair. After detection of fugitive emissions, the 2016 NSPS OOOOa
requires repair of these components within 30 days of detection of the
fugitive emissions. Further, the owner or operator must resurvey the
component within 30 days of the repair in order to verify successful
repair. 40 CFR 60.5397a(h)(1) and (3).
    Several questions were raised during implementation that required
reconsideration of the repair requirements. Specifically, stakeholders
asked about the situation where repairs were completed during the 30-
day required timeframe but the resurvey identified the presence of
fugitive emissions, indicating unsuccessful repair.
    The EPA recognizes the requirements in the 2016 NSPS OOOOa may
create an unintended noncompliance issue with the repair requirements.
Therefore, we are proposing to amend the repair requirements to require
a ``first attempt at repair'' within 30 days of detection of fugitive
emissions, followed by a requirement that identified fugitive emissions
be ``repaired'' within 60 days of detection. We are proposing
definitions for ``repaired'' and ``first attempt at repair'' as related
to the fugitive emissions requirements. The EPA is proposing to define
``repaired,'' for purposes of fugitive emissions monitoring, as
``fugitive emissions components are adjusted, replaced, or otherwise
altered, in order to eliminate fugitive emissions as defined in 40 CFR
60.5397a of this subpart and is

resurveyed as specified in 40 CFR 60.5397a(h)(4) and it is verified
that emissions from the fugitive emissions components are below the
applicable fugitive emissions definition.'' Additionally, we are
proposing the definition for ``first attempt at repair'' for the
purposes of fugitive emissions monitoring as ``an action taken for the
purpose of stopping or reducing fugitive emissions of methane or VOC to
the atmosphere. First attempts at repair include, but are not limited
to, the following practices where practicable and appropriate:
Tightening bonnet bolts; replacing bonnet bolts; tightening packing
gland nuts; ensuring the thief hatch is properly seated or injecting
lubricant into lubricated packing.'' These proposed definitions for
``repaired'' and ``first attempt at repair'' are specific to the
fugitive emissions requirements and would not replace the definitions
for ``repaired'' or ``first attempt at repair'' within the requirements
for equipment leaks at onshore natural gas processing plants referenced
in 40 CFR part 60, subpart VVa. We are soliciting comment on these
proposed repair requirements and definitions.
    Delay of Repair. As amended on March 12, 2018, the 2016 NSPS OOOOa
allows for delay of repair if the repair is technically infeasible;
requires a vent blowdown, a compressor station shutdown, a well
shutdown, or well shut-in; or would be unsafe to repair during
operation of the unit. Repairs meeting one of these criteria must be
completed during the next scheduled compressor station shutdown, well
shutdown, or well shut-in; after a planned vent blowdown; or within 2
years, whichever is earlier. The amendment addressed the concerns
associated with requiring repair during unscheduled or emergency events
by removing such a requirement.
    In addition to concerns with requiring repair during unscheduled or
emergency events, several petitioners raised additional concerns with
the provisions regarding the delay of repair for fugitive emissions
components at well sites and compressor stations.\84\ One petitioner
stated that the 2-year delay should be reevaluated because no specific
data was provided to support that deadline.\85\ Further, other
petitioners stated that blowdowns, shutdowns, and well shut-ins might
not always involve depressurizing the specific equipment that needs
repair. The EPA is soliciting comment on instances when equipment
cannot be isolated during vent blowdowns, compressor station shutdowns,
well shutdowns, and well shut-ins to allow for repair of components
with fugitive emissions. Further, the EPA is soliciting comment and
supporting information on the instances where delayed repairs cannot be
conducted during any of the events listed in the rule and under what
event or time frame delayed repairs can be conducted for those
instances.
---------------------------------------------------------------------------

    \84\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7683, and EPA-HQ-OAR-2010-0505-7686.
    \85\ See Docket ID No. EPA-HQ-OAR-2010-0505-7683.
---------------------------------------------------------------------------

    Finally, we are clarifying when a repair can be delayed. There are
three circumstances when repair can be delayed: (1) When the repair is
technically infeasible, (2) when the repair requires a vent blowdown, a
compressor station shutdown, a well shut-in, or a well shutdown, and
(3) when the repair is unsafe during operation of the unit.\86\ The
2016 NSPS OOOOa requires an explanation of each repair that is delayed
as well.\87\ As discussed in section VI.B.1, we have added 1 controlled
storage vessel per model plant because when the controlled storage
vessel is not subject to the control requirements in 40 CFR 60.5395a,
the thief hatch and other openings are subject to fugitive emissions
requirements, per the definition of fugitive emissions components in 40
CFR 60.5430a. The EPA believes that thief hatches on controlled storage
vessels which are part of the fugitive emissions program would not be
subject to delay of repair under any of these circumstances; however,
we are soliciting comment for any instance when delaying repair on a
thief hatch may be necessary. The EPA acknowledges that questions may
arise as to whether opening a thief hatch is considered a vent
blowdown. While we do not consider this to constitute a vent blowdown,
we are soliciting comment on whether clarification within the
regulatory text is necessary for this point. We are also soliciting
comment on the 2-year deadline for completion of delayed repairs.
---------------------------------------------------------------------------

    \86\ See 40 CFR 60.5397a(h)(2).
    \87\ See 40 CFR 60.5420a(b)(7)(ii)(J).
---------------------------------------------------------------------------

6. Definitions Related to Fugitive Emissions at Well Sites and
Compressor Stations
    Third-party equipment. In the 2016 NSPS OOOOa, all fugitive
emissions components located at a well site, regardless of ownership,
are subject to the monitoring and repair requirements for fugitive
emissions in the 2016 NSPS OOOOa. As defined in 40 CFR 60.5430a, the
term `fugitive emissions component' means ``any component that has the
potential to emit fugitive emissions of methane or VOC at a well site
or compressor station, including, but not limited to valves,
connectors, pressure relief devices, open-ended lines, flanges, covers
and closed vent systems not subject to Sec.  60.5411a, thief hatches or
other openings on a controlled storage vessel not subject to Sec.
60.5395a, compressors, instruments, and meters'' and the term `well
site' means ``one or more surface sites that are constructed for the
drilling and subsequent operation of any oil well, natural gas well, or
injection well.'' Several petitioners raised concerns that these
definitions are too broad and requested that the EPA should exclude
equipment that is owned and operated by a third-party.\88\
---------------------------------------------------------------------------

    \88\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-7684.
---------------------------------------------------------------------------

    First, petitioners requested an exemption for equipment owned and
operated by midstream companies because that equipment is owned by
legally distinct entities, and applicability of the standards to
midstream assets would be based solely on the actions of the upstream
producers. Second, petitioners stated that the EPA is incorrect in
suggesting that contractual agreements between upstream producers and
midstream owners and operators would be appropriate for managing
fugitive emissions monitoring and repair(s) at the well site. The
petitioners stated that, due to the complexity of contractual
agreements between different owners and operators at a well site, each
individual owner or operator may need to develop and implement separate
fugitive emissions monitoring programs. The petitioner further stated
that doing so would add significant and unnecessary costs that the EPA
did not consider.\89\
---------------------------------------------------------------------------

    \89\ See Docket ID No. EPA-HQ-OAR-2010-0505-7684.
---------------------------------------------------------------------------

    In the response to comment document for the 2016 NSPS OOOOa we
stated that cooperative agreements could be used to resolve any
fugitive emissions identified during surveys, but we acknowledged in
the 2017 NODA that confusion remained over the applicability of the
fugitive emissions requirements as they relate to ancillary midstream
assets that are owned by companies that are legally distinct from the
well site owner and operator and that could have limited emissions. 82
FR 51798. In their comments on the 2017 NODA, one petitioner noted that
since the components associated with the gas gathering and metering
systems

serve the ``crucial commercial purpose in calculating gas accepted by
the gathering company and the related revenue accounting,'' the
midstream operators could not allow the production operators to access
this equipment.\90\ This petitioner further clarified that due to this
limitation, the midstream operator would need to implement a separate
fugitive emissions program for a limited number of components.
Additionally, the petitioner stated there are significant practical
issues with renegotiating contracts, especially as well sites are
modified over time. We did not consider this issue during development
of the 2016 NSPS OOOOa.
---------------------------------------------------------------------------

    \90\ See Docket ID No. EPA-HQ-OAR-2010-0505-13436.
---------------------------------------------------------------------------

    In light of the concerns raised by the petitioners, the EPA is
proposing to amend the definition of ``well site,'' for the purposes of
fugitive emissions monitoring, to exclude the flange upstream of the
custody meter assembly, and fugitive emissions components located
downstream of this flange. The EPA understands this custody meter is
used effectively as the cash register for the well site and provides a
clear separation for the equipment associated with production of the
well site, and the equipment associated with putting the gas into the
gas gathering system. Additionally, the proposed definition would
exclude only a small number of fugitive emissions components, and we do
not believe it would be cost-effective to require a separate fugitive
emissions program for these components. We are also proposing a
definition for the custody meter as ``the meter where natural gas or
hydrocarbon liquids are measured for sales, transfers, and/or royalty
determination,'' and the custody meter assembly as ``an assembly of
fugitive emissions components, including the custody meter, valves,
flanges, and connectors necessary for the proper operation of the
custody meter.'' We are limiting the exemption within the definition of
a well site to the flange upstream of the custody meter because we are
not aware of similar issues with monitoring other third-party equipment
at a well site. The EPA is soliciting comment on this proposed change
to the ``well site'' definition, the proposed definition of ``custody
meter,'' the proposed definition of ``custody meter assembly,'' and
suggestions for other ways which provide a clear separation to
distinguish the third-party equipment described above at a well site,
for the purposes of fugitive emissions monitoring.
    Applicability to Saltwater Disposal Wells. In addition to concerns
about the definition of a ``well site'' as it relates to third party
equipment, the EPA received feedback from industry seeking confirmation
that a saltwater disposal well is not an injection well as the term is
used in the definition for well site and, therefore, not subject to the
fugitive emission standards at 40 CFR 60.5397a. They asserted that
disposal wells are not injection wells and that the disposed liquid
consists of water with insignificant amounts of stabilized skim oil
that is never in vapor state at normal or elevated conditions. The
commenters were concerned that, although they did not believe it was
the EPA's intent to require fugitive emissions monitoring of saltwater
disposal wells, they will nevertheless have to comply with those
requirements because, as written, the definition of ``well site'' is
ambiguous with respect to the status of saltwater disposal wells.
    Deposits of oil and natural gas can be found in porous rocks and
shale, where saltwater is also found. Oil and gas pumped out of the
earth that is not pure enough for distribution because of saltwater and
other chemicals/impurities go through a separation phase or are treated
with chemicals that extract the impurities. After the oil or gas is
treated, the water that remains (referred to as ``saltwater'') is
subject to handling requirements.\91\ Saltwater, or produced water,
that results from bringing the oil and gas up to the surface (ejected
from the well) during production operations is generally (1) recycled,
(2) returned to the reservoir for fluid reinjection or (3) injected
into underground porous rock formations not productive of oil or gas,
and sealed above and below by unbroken, impermeable strata.\92\ The
third option is considered saltwater disposal (or oilfield wastewater
disposal). Regulations for the disposal of this water vary from state
to state, but the EPA monitors disposal to ensure ground water is not
contaminated through Underground Injection Control (UIC) programs under
the federal Safe Drinking Water Act for surface and groundwater
protection. The EPA had not considered these UIC Class II oilfield
wastewater disposal wells during the development of the fugitive
emissions standards in the 2016 NSPS OOOOa.
---------------------------------------------------------------------------

    \91\ http://www.tech-flo.net/salt-water-disposal.html.
    \92\ Barnett Shale Energy Education Council. What are Saltwater
Disposal Wells? Air and Water Quality. http://www.bseec.org/what_are_saltwater_disposal_wells.
---------------------------------------------------------------------------

    For the reasons stated below, we are proposing to exclude UIC Class
II oilfield wastewater disposal wells from the well site definition and
are proposing a definition for a UIC Class II oilfield wastewater
disposal well to distinguish them from injection wells subject to the
rule. It is our understanding that the storage vessels located at these
disposal facilities have low methane and VOC emissions, and thus are
not subject to the control requirements for storage vessels found in 40
CFR 60.5395a, do not require controls for permitting purposes, and
would not be subject to fugitive emissions monitoring because they are
uncontrolled. Further, it is our understanding that the number of
fugitive emissions components at these facilities are typically low,
including water pumps and a limited number of valves or connectors,
which are expected to have negligible if any fugitive emissions. These
proposed changes clarify the universe of well sites subject to the
fugitive emissions standards. Our proposed definition for a ``UIC Class
II oilfield disposal well'' is ``a well with a UIC Class II permit
where wastewater resulting from oil and natural gas production
operations is injected into underground porous rock formations not
productive of oil or gas, and sealed above and below by unbroken,
impermeable strata.'' Further, we are proposing that UIC Class II
disposal facilities without wells that produce oil or natural gas are
not considered well sites for the purposes of fugitive emissions
requirements. We are soliciting comment on this proposed definition and
on the proposed exemption for UIC Class II wastewater disposal wells
and disposal facilities from fugitive emissions monitoring and repair,
including data to support or refute our understanding that these sites
have limited fugitive emissions components.
    Definition of well site. As discussed in the sections regarding
third-party equipment and saltwater disposal wells, the EPA is
proposing to amend the definition of well site as follows:

    Well site means one or more surface sites that are constructed
for the drilling and subsequent operation of any oil well, natural
gas well, or injection well. For purposes of fugitive emission
standards at Sec.  60.5397a, a well site also means a separate tank
battery surface site collection crude oil, condensate, intermediate
hydrocarbon liquids, or produced water from wells not located at the
well site (e.g., centralized tank batteries). Also for the purposes
of the fugitive emissions standards at Sec.  60.5397a, a well site
does not include (1) UIC Class II oilfield disposal wells and
disposal facilities and (2) the flange upstream of the custody meter

assembly and equipment, including fugitive emissions components,
located downstream of this flange.

    Startup of Production. The EPA defines the ``startup of
production'' in the 2016 NSPS OOOOa as the ``beginning of initial flow
following the end of flowback when there is continuous recovery of
salable quality gas and separation and recovery of any crude oil,
condensate or produced water.'' 40 CFR 60.5430a. For purposes of the
fugitive emissions requirements in 40 CFR 60.5397a, the initial
monitoring survey follows the startup of production. We received
questions from stakeholders that suggested this definition would limit
the fugitive emissions requirements to well sites with hydraulically
fractured wells and not those with conventional wells. While the first
trigger for modification is based on the drilling of a new well,
regardless if it is hydraulically fractured or not, the definition of
startup of production is linked to flowback, which is inherently an
effect following hydraulic fracturing.
    We are proposing to amend the definition of ``startup of
production'' in this proposal to address how it relates to the fugitive
emissions requirements. Specifically, we are proposing that, for the
purposes of the fugitive monitoring requirements, startup of production
means ``the beginning of the continuous recovery of salable quality gas
and separation and recovery of any crude oil, condensate or produced
water.'' We are soliciting comment on this proposed definition change
as it relates to wells that are not hydraulically fractured.
7. Fugitive Emissions Monitoring Plan
    The 2016 NSPS OOOOa requires that each fugitive emissions
monitoring plan include a sitemap and a defined observation path.\93\
As we are clarifying in this proposed action, these requirements were
meant to apply only to owners and operators using OGI for monitoring
surveys, not to owners and operators using Method 21. In addition to
clarifying this intent, we are also proposing options that owners and
operators using OGI for monitoring surveys can comply with in lieu of
the observation path requirement.
---------------------------------------------------------------------------

    \93\ See 40 CFR 60.5397a(d)(1) and (2).
---------------------------------------------------------------------------

    As we discussed in the preamble to the 2016 NSPS OOOOa, the purpose
of the observation path is to ensure that the OGI operator visualizes
all of the components that must be monitored. In a traditional
monitoring scenario using Method 21, the owner or operator tags all of
the equipment that must be monitored, and when the 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 that requires close
contact with each component, whereas with OGI, the operator can be away
from the components and still monitor several components
simultaneously. The observation path \94\ was intended to offer owners
and operators an alternative to the traditional tagging approach while
still providing assurance that the owner or operator has met the
obligation to monitor all components. 81 FR 35860.
---------------------------------------------------------------------------

    \94\ In the preamble to the 2016 NSPS OOOOa, we also noted that
the purpose of using the term ``observation path'' was to clarify
that the emphasis is on the field of view of the OGI instrument, not
the physical location of the OGI operator. 81 FR 35860.
---------------------------------------------------------------------------

    Petitions received on the 2016 NSPS OOOOa assert that there is no
added benefit to including the sitemap and defined observation path in
the fugitive emissions monitoring plan and that they should be
removed.\95\ Industry representatives report that, in many cases,
sitemaps do not exist. They further report that there are significant
added costs associated with the requirement to develop site-specific
details for a sitemap and a defined observation path for each site and
that there may be hundreds to thousands of different sites. These
representatives express concern that sitemaps could also change,
subjecting them to additional costs associated with revising the
fugitive emissions monitoring plan without any added benefit. While we
do think that it is necessary to revise monitoring plans when equipment
at the site changes,\96\ we generally expected these to be one-time
requirements, unless additional equipment is added to the site. 81 FR
35860. The EPA is specifically seeking comment on whether this
assumption is incorrect and, if not, we solicit information on the cost
to develop and revise the sitemap, including the cost to document an
observation path, the cost to revise a sitemap and observation path,
and the frequency with which the sitemap and observation path need to
be updated. We are also clarifying that plot plans can be substituted
for sitemaps, as these two items serve the same function, i.e., to
provide information on the locations of equipment on site.
---------------------------------------------------------------------------

    \95\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7686 and EPA-HQ-
OAR-2010-0505-10791.
    \96\ As we stated in the preamble to the 2016 NSPS OOOOa, 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. 81 FR 35860.
---------------------------------------------------------------------------

    Industry representatives have also expressed concern that the
fugitive emissions monitoring plan as written in 40 CFR 60.5397a(d) may
cause enforcement issues in cases where the fugitive emissions
monitoring plan is not followed exactly (specifically related to the
defined observation path), even when the deviation is not critical and
the monitoring plan is still effective. In response to public comments
on the 2016 NSPS OOOOa, we stated that the elements required in the
monitoring plan are necessary to judge the quality of the fugitive
emissions survey, in light of the fact that the EPA does not have a
standard method for use of OGI, but that we fully expected a trained
and experienced camera operator to know when deviations from the
standard monitoring plan are necessary and to make these
deviations.\97\ However, while deviations may not impact the camera's
detection ability and can actually improve the detection ability, this
does not mean that deviations from the monitoring plan should not be
noted because this record provides valuable information to air agency
reviewers on how surveys are conducted and whether the deviations from
the monitoring plan are adequate and warranted. We note that deviations
from the monitoring plan are not necessarily deviations from the
requirements of the rule.
---------------------------------------------------------------------------

    \97\ See Docket ID No. EPA-HQ-OAR-2010-0505-7632, Chapter 4,
page 4-708.
---------------------------------------------------------------------------

    While we are not proposing to remove the sitemap and observation
path elements from the fugitive emissions monitoring plan, we are
proposing two alternatives to address petitioner/industry
representative concerns. First, in lieu of the defined observation
path, we are proposing to add language to 40 CFR 60.5397a(d) that
allows an owner or operator to describe how each type of equipment will
be effectively monitored, including a description and location of the
fugitive emissions components located on the equipment. The sitemap
would include the locations of the pieces of equipment when complying
with this option. Second, in lieu of meeting the sitemap and defined
observation path requirements, we are proposing to add language to 40
CFR 60.5397a(d) to extend the inventory requirement that is currently
in 40 CFR 60.5397a(d)(3) for when an owner or operator chooses to
perform a survey with Method 21 as an option for owners and operators
who perform surveys with OGI. We believe

that both of these options provide assurances similar to the
observation path that the owner or operator meets the requirement to
visualize all components.
    In summary, the EPA is retaining the requirements for the sitemap
and observation path in the fugitive monitoring plan, but is also
proposing two alternatives to these requirements. The EPA is soliciting
comment on these proposed alternatives. Additionally, we are soliciting
comment on other potential options that would serve the same functions
as an observation path and sitemap. We are particularly interested in
potential options that provide assurance that all regulated components
have been monitored, how this information can be documented, and the
costs of such alternative approaches.

C. Professional Engineer Certifications

    The 2016 NSPS OOOOa requires that CVS used for routing emissions
from centrifugal compressor wet seal fluid degassing systems,
reciprocating compressors, pneumatic pumps, and storage vessels must
have sufficient design and capacity to ensure that all emissions are
routed to the control device. 40 CFR 60.5411a(d). This is accomplished
through a design evaluation that must be certified by a ``qualified
professional engineer'' (PE). Several petitioners requested
reconsideration of the PE certification requirement because the EPA did
not provide an evaluation of the costs associated with the
certification.\98\ Additionally, petitioners requested that the EPA
allow alternatives to PE certification, such as engineering design
reviews not necessarily conducted by a licensed PE.
---------------------------------------------------------------------------

    \98\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
---------------------------------------------------------------------------

    The 2016 NSPS OOOOa also includes a technical infeasibility
provision allowing an exemption from the well site pneumatic pump
requirements. However, the rule requires that such technical
infeasibility be determined and certified by a ``qualified professional
engineer.'' 40 CFR 60.5393a(b)(5)(i). Petitioners objected to this
additional certification, stating it results in additional costs and
project delays, with no environmental benefits. Additionally,
petitioners questioned the value of this requirement, claiming it is
duplicative with the existing general duty obligations and requirement
to provide a certifying official's acknowledgment. Petitioners also
stated that few companies have a sufficient number of in-house PEs, and
requested that this requirement be broadened to allow alternatives to
PE certification, including requiring engineering review and approval
of all designs.
    In the 2017 NODA, we requested information related to the
availability of PEs to provide these certifications. Seven commenters
provided information. Three commenters stated that there should be no
limitation related to the availability of licensed PEs because in 2016
over 400,000 resident licenses were issued, and over 400,000 non-
resident licenses were issued (a PE can hold both types of
licenses).\99\ One commenter cited a similar requirement in Colorado's
regulation and stated that in response to the same concerns from the
industry, Colorado found there was no basis for the claims about a lack
of availability of PEs.\100\ In contrast, four commenters stated
difficulties with locating a PE willing to provide the certification,
citing multiple concerns, including the certification statement
included in the 2016 NSPS OOOOa and the certification of a portion of a
system when the PE did not design the entire system.\101\
---------------------------------------------------------------------------

    \99\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-12386, EPA-HQ-OAR-
2010-0505-12441, and EPA-HQ-OAR-2010-0505-12469.
    \100\ See Docket ID No. EPA-HQ-OAR-2010-0505-12469.
    \101\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-12422, EPA-HQ-OAR-
2010-0505-12424, EPA-HQ-OAR-2010-0505-12437, and EPA-HQ-OAR-2010-
0505-12446.
---------------------------------------------------------------------------

    We have evaluated the concerns raised by petitioners regarding the
additional burden of the PE certification for CVS design and pneumatic
pump technical infeasibility. Further, the EPA agrees with commenters
that in-house engineers may be more knowledgeable about site design and
operation for both CVS and pneumatic pumps. In addition, the EPA
acknowledges that, in the 2016 NSPS OOOOa, we did not analyze the costs
associated with the PE certification requirement or evaluate whether
the improved environmental performance this requirement may achieve
justifies the associated costs and other compliance burden. In this
action, the EPA evaluated the costs associated with PE certification
and certification by an in-house engineer. We estimated costs based on
two scenarios: (1) Requiring a PE certify the design and (2) allowing
either a PE or an in-house engineer certify the design. We estimate
that each PE certification would cost $547, while allowing use of in-
house engineers would cost $358.\102\ The EPA is soliciting comment on
this cost estimate.
---------------------------------------------------------------------------

    \102\ See the TSD for additional discussion of certification
cost.
---------------------------------------------------------------------------

    After reconsideration of these costs, the EPA is proposing to amend
the certification requirements for CVS design and technical
infeasibility for pneumatic pumps. Specifically, we are proposing to
allow certification by either a PE or an in-house engineer with
expertise on the design and operation of the CVS or pneumatic pump. We
believe that an in-house engineer with knowledge of the design and
operation of the CVS is capable of performing these certifications,
regardless of licensure; however, we are soliciting comment on the use
of other engineers with knowledge of the design and operation of the
CVS that may be appropriate for this certification, such as third-party
or other qualified engineers. We continue to have a concern regarding
the use of undersized or under designed CVS, which can result in
pressure relief events from thief hatches and PRVs on the controlled
storage vessels or CVS, thus allowing emissions to escape to the
atmosphere uncontrolled. As stated in the 2013 NSPS OOOO Oil and
Natural Gas Sector: Reconsideration of Certain Provisions of New Source
Performance Standards, ``Improper design or operation of the storage
vessel and its control system can result in occurrences where peak flow
overwhelms the storage vessel and its capture systems, resulting in
emissions that do not reach the control device, effectively reducing
the control efficiency. We believe that it is essential that operators
employ properly designed, sized, and operated storage vessels to
achieve effective emissions control.'' 78 FR 22136. This proposed
amendment will still ensure these systems are evaluated and certified
by engineers with expert knowledge of their operation.

D. Alternative Means of Emission Limitation (AMEL)

    The 2016 NSPS OOOOa contains provisions for owners and operators to
request an AMEL for specific work practice standards in the rule,
covering well completions, reciprocating compressors, and the
collection of fugitive emissions components at well sites and
compressor stations. An owner or operator can request an AMEL by
submitting data that demonstrate the alternative will achieve at least
equivalent emission reductions as the requirements in the rule, among
other requirements such as initial and on-going compliance monitoring.
The specific requirements for this request are outlined in 40 CFR
60.5398a. For the 2016 NSPS OOOOa, these alternatives

could be based on emerging technologies (e.g., for fugitive emissions,
technologies other than OGI or Method 21) or requirements under state
or local programs.
    We are proposing to amend the language in 40 CFR 60.5398a for
incorporation of emerging technologies, and to add a separate section
at 40 CFR 60.5399a to take into account existing state programs as
discussed in further detail in the sections below.
1. Incorporating Emerging Technologies
    As discussed in the 2016 NSPS OOOOa, the EPA recognizes that new
technologies are expected to enter the market in the near future that
will locate the source of emissions sooner and at lower levels than
current technology. While the EPA established a foundation for
approving the use of emerging technologies in the final rule, several
stakeholders have identified a need to streamline the process for
requesting and approving an AMEL for individual affected sources, such
as well completions, compressors, and the collection of fugitive
emissions components located at a well site or at a compressor station.
As promulgated in the 2016 NSPS OOOOa, each AMEL request must be
submitted using site-specific information, which could result in the
same owner or operator submitting identical requests for multiple
affected facilities. We are clarifying that an individual application
may include the same technology for multiple sites, provided the
required information is provided for each site and any site-specific
variations to the procedures are addressed in the application. The
application must provide a demonstration of equivalency and the
emission reductions achieved for each site included in the application.
The EPA is also proposing specific changes to the AMEL process as it
relates to emerging technologies to address this issue. Specifically,
we are proposing to allow owners or operators to apply for an AMEL, on
their own or in conjunction with manufacturers or vendors, and trade
associations, that incorporates the use of alternative technologies,
techniques, or processes, along with compliance monitoring provisions
to ensure continuous compliance other than those identified in the 2016
NSPS OOOOa work practice standards. We are not changing the requirement
that AMELs must be site-specific because we are aware of the
variability of this sector and are concerned that the procedures for a
specific technology may need to be adjusted based on site-specific
conditions (e.g., gas compositions, allowable emissions, or landscape).
Therefore, we expect that applications for these AMEL will include
site-specific procedures for ensuring continuous compliance of the
emission reductions to be demonstrated as equivalent. For this reason,
we are not proposing to allow a manufacturer, vendor, or trade
association to apply for an AMEL without an owner or operator. However,
we are soliciting comment on whether groups of sites within a specific
area (e.g., basin-specific) that are operated by the same operator
could be grouped under a single AMEL. Additionally, we are proposing
that field data can be supplemented with test data, modeling analyses
and other documentation, provided the field data still provides
information related to seasonal variations. For the purposes of
fugitive emissions requirements, the application must demonstrate that
the technology is able to detect emissions beyond those allowed, such
as pneumatic controllers. We are soliciting comment on the proposed
revisions to the application requirements for technology-based AMEL.
2. Incorporating State Programs
    In addition to recognizing potential emerging technologies, the EPA
evaluated existing state and local fugitive emissions programs during
the development of the 2016 NSPS OOOOa for purposes of establishing
AMEL. The EPA was unable to conclude that any state program as a whole
would reflect what we identified as BSER in the 2016 NSPS OOOOa due to
the differences in the sources covered and the specific requirements.
However, the 2016 NSPS OOOOa allowed owners and operators to use the
AMEL process to allow use of existing state or local programs. 81 FR
35871. Petitioners and states have raised specific questions about the
practicality of the AMEL process as it relates to the incorporation of
state programs.\103\ For instance, one state has notified the EPA that
since the ability to make an AMEL request is limited to owners and
operators at the individual site level, it is possible that the EPA
would have over 300 identical applications from various owners and
operators wanting to use the same state program at their affected
facilities. Believing that there may be opportunities to streamline the
process, ensure compliance, and reduce regulatory burdens, the EPA
continued its evaluation of existing state fugitive emissions programs
after promulgating the 2016 NSPS OOOOa. Based on this evaluation, the
EPA is proposing certain existing state requirements as alternatives to
specified aspects (e.g., monitoring, repair, and recordkeeping) of the
fugitive emissions requirements for well sites and compressor stations.
---------------------------------------------------------------------------

    \103\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
---------------------------------------------------------------------------

    To date, the EPA has evaluated 14 existing state programs for
comparable or equivalent standards related to the fugitive emissions
requirements in 40 CFR 60.5397a and the specific amendments in this
proposal. For this evaluation, we compared the fugitive emissions
components covered by the state programs, monitoring instruments, leak
or fugitive emissions definitions, monitoring frequencies, repair
requirements, and recordkeeping to the fugitive emissions requirements
proposed in this action.\104\ We did not include an evaluation of
monitoring plans or reporting requirements because we are not proposing
any alternative standards for these aspects of the fugitive emissions
requirements. Through this evaluation, we have identified aspects of
certain existing state fugitive emissions programs that we propose to
find to be at least equivalent to the proposed amendments in this
action.\105\ For instance, we have evaluated the lists of affected
fugitive components, monitoring instrument(s), fugitive definition(s),
monitoring frequency, repair deadlines, delay of repair provisions, and
recordkeeping of the programs reviewed. In most of the programs, the
affected fugitive components were different than our definition of
fugitive emissions component. Therefore, we are proposing alternative
standards that also require the owner or operator to survey our entire
list of fugitive emissions components, regardless of whether they are
affected components in the state program. Additionally, we evaluated
monitoring instruments, frequencies, and fugitive definitions in
conjunction with each other. Where monitoring is more frequent, we are
proposing that a different fugitive definition could be appropriate.
For instance, the standards in the California Code of Regulations,
title 17, sections 95665-95667 require quarterly monitoring using
Method 21 with a fugitive definition of 1,000 ppm while this proposal
requires annual or stepped monitoring with a fugitive definition of 500
ppm if Method 21 is the chosen monitoring instrument. The

EPA believes that more frequent monitoring warrants allowance of a
higher fugitive definition because larger fugitive emissions will be
found faster and repaired sooner, thus reducing the overall length of
the emission event. Additional information related to the specific
evaluation of programs is available in the memorandum Equivalency of
State Fugitive Emissions Programs for Well Sites and Compressor
Stations to Proposed Standards at 40 CFR part 60, subpart OOOOa,
located at Docket ID No. EPA-HQ-OAR-2017-0483.
---------------------------------------------------------------------------

    \104\ See memorandum Equivalency of State Fugitive Emissions
Programs for Well Sites and Compressor Stations to Proposed
Standards at 40 CFR part 60, subpart OOOOa located at Docket ID No.
EPA-HQ-OAR-2017-0483. April 12, 2018.
    \105\ Specifically, we propose to make this finding with respect
to state programs in California, Colorado, Ohio, Pennsylvania,
Texas, and Utah.
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    Based on this evaluation, we are proposing combining those aspects
of the state requirements to formulate alternatives to the relevant
portions of the fugitive emissions standards for the collection of
fugitive emissions components located at either well sites or
compressor stations. The specific states for which we are proposing
alternative standards are California, Colorado, Ohio, and Pennsylvania
for both well sites and compressor stations, and Texas and Utah for
well sites only. We have not determined whether Pennsylvania's
Exemption No. 38 for well sites should be included in the alternative
standards. While we evaluated the current consent decree \106\ that the
state of North Dakota has developed for well sites, we are not
proposing alternative standards related to those requirements because
by their nature, consent decrees are negotiated terms for non-
compliance and contain an expiration date, after which sources return
to compliance with the underlying regulatory provisions, permit terms,
etc. Further, inclusion of settlement terms from a consent decree as an
alternative standard would essentially endorse regulation through
enforcement as a pathway to establishment of alternative standards. For
all of these reasons, the EPA believes that evaluation of settlement
agreement terms reached through negotiated resolution to an enforcement
action would be an inappropriate basis from which to establish
alternative standards for regulations promulgated through notice and
comment rulemaking. Additionally, we are identifying the specific
effective date of the individual state programs to specify which
version of the state programs is being proposed as alternative
standards because the state programs may change over time, and our
evaluation is only valid for the current version of these programs. If
in the future any of these programs are amended, the states can utilize
the proposed application procedure discussed below.
---------------------------------------------------------------------------

    \106\ See North Dakota Consent Decree 10.19.16, attachment to
the memorandum Equivalency of State Fugitive Emissions Programs for
Well Sites and Compressor Stations to Proposed Standards at 40 CFR
part 60, subpart OOOOa. April 12, 2018, in Docket ID No. EPA-HQ-OAR-
2017-0483.
---------------------------------------------------------------------------

    The proposed alternative fugitive emissions standards include
alternatives for monitoring frequencies, repair deadlines, and
recordkeeping. The requirements for the monitoring plan found in 40 CFR
60.5397a(c) and (d) would still apply. In fact, the owner or operator
would indicate through this monitoring plan that they have elected the
alternative and would base the monitoring plan on the specific
requirements from the state, local, or tribal program that is being
adopted. Compliance would be evaluated against the specified
requirements in the alternative fugitive emissions standards as
incorporated in the monitoring plan. Further, we are proposing to
require notification that the owner or operator has elected to comply
with the applicable alternative fugitive emissions standards for the
state in which the well site or compressor station is located. We are
proposing that this notification is made at least 90 days prior to
adopting an alternative fugitive emissions standard. We are soliciting
comment on the requirements necessary to document that an owner or
operator is following an alternative state, local or tribal program and
on the notification requirement, including the appropriateness of the
use of the requirement of 90 days' notice prior to adoption of the
alternative standards.
    In this action we are proposing a new section, in proposed 40 CFR
60.5399a, to include these state requirements that qualify as
alternative fugitive emissions standards. The proposed section also
includes a framework for the application and inclusion of additional
existing state fugitive emissions standards as alternatives to the
fugitive emissions requirements or future revisions to programs already
proposed as alternative standards. Under our proposal, such applicants
would include, but not be limited to, individuals, corporations,
partnerships, associations, states, or municipalities. The proposed
requirements for the application include specific information about the
monitoring instrument (including monitoring procedures), monitoring
frequency, leak or fugitive emissions definition, and repair
requirements. We are soliciting comment on the proposed application
requirements, the proposed alternative fugitive emissions standards
(including compliance monitoring), and information to support the
inclusion of additional alternative fugitive emissions standards.

E. Other Reconsideration Issues Being Addressed

1. Well Completions
    Location of a Separator During Flowback. The 2016 NSPS OOOOa
requires the owner or operator to have a separator onsite during the
entirety of the flowback period. 40 CFR 60.5375a(a)(1)(iii). However,
several petitioners indicated that it is not clear whether the term
``onsite'' refers to the specific well site where the well completion
is taking place.\107\ Our intent was that the separator be located in
close enough proximity to the well that it could be utilized as soon as
sufficient flowback is present for the separator to function. Close
proximity could be either onsite or nearby, as we explained in the
preamble to the 2016 NSPS OOOOa, ``We anticipate a subcategory 1 well
to be producing or near other producing wells. We therefore anticipate
REC equipment (including separators) to be onsite or nearby, or that
any separator brought onsite or nearby can be put to use.'' 81 FR
35852. Thus, our intent was that the separator may be located at the
well site or near to the well site so that it is able to commence
separation flowback, as required by the rule. Locations ``near'' or
``nearby'' may include a centralized facility or well pad that services
the well which is used to conduct the completion of the well affected
facility. In order to alleviate concerns that the separator must be
located on the well site, we are proposing to amend 40 CFR
60.5375a(a)(1)(iii) to clarify the location of the separator.
---------------------------------------------------------------------------

    \107\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-7686.
---------------------------------------------------------------------------

    Screenouts and Coil Tubing Cleanouts. Petitioners requested
clarification as to whether screenouts and coil tubing cleanouts are
regulated as part of flowback. Petitioners asserted that these are
necessary processes performed during hydraulic fracturing that are not
associated with flowback.\108\ In November 2016, the EPA responded to a
letter from API seeking clarification on this issue, stating, ``any
releases of gas or vapor during `screenouts' and `coil tubing
cleanouts,' which occur during the initial flowback stage are not
subject to control under section 60.5375a.\109\ However, we have
further assessed this topic and believe that the guidance we issued was
incorrect. In the

preamble to the final 2014 amendments, we stated regarding flowback:
``. . . the first stage would begin with the first flowback from the
well following hydraulic fracturing or refracturing, and would be
characterized by high volumetric flow . . .'' 79 FR 79024. In some
situations, screenouts or coil tubing cleanouts may be necessary in
order to remove proppant (sand) from the well so that high volumetric
flow can occur, marking the beginning of the initial flowback stage.
Therefore, screenouts and coil tubing cleanouts are not a part of
flowback; rather, they are functional processes that allow for flowback
to begin. It should be noted that this is consistent with the
definition of hydraulic fracturing, which we stated requires high rate,
extended flowback to expel fracture fluids and solids during
completions. 40 CFR 60.5430a. For the reasons stated above, the
November 2016 letter incorrectly states that screenouts and coil tubing
cleanouts occur during the initial flowback stage. To clarify this
point, we are proposing to revise the definition of flowback to
expressly exclude these processes to avoid any future confusion. In
addition, we are proposing definitions for these processes. A screenout
is the first attempt to clear proppant from the wellbore. It involves
flowing the well to a fracture tank in order to achieve maximum
velocity and carry the proppant out of the well. If a screenout is
unsuccessful in clearing the proppant from the wellbore, then a coil
tubing cleanout is conducted. This involves running a string of coil
tubing to the packed proppant and jetting the well to dislodge the
proppant and provide sufficient lift energy to flow it to the surface.
It is after these processes that flowback begins and, subsequently,
production. The EPA solicits comment on the proposed definitions for
these processes.
---------------------------------------------------------------------------

    \108\ See Docket ID No. EPA-HQ-OAR-2010-0505-7682.
    \109\ See Docket ID No. EPA-HQ-OAR-2010-0505-7722.
---------------------------------------------------------------------------

    Plug Drill-Outs. A plug drill-out is the removal of a plug (or
plugs) that was used to conduct hydraulic fracturing in different
sections of the well. Plug drill-outs are also functional processes
that are necessary in order for flowback to begin. Therefore, the EPA
is similarly proposing to exclude these processes from the definition
of flowback.
    Flowback Routed Through Permanent Separators. The EPA is proposing
to streamline reporting and recordkeeping requirements for flowback
routed through permanent separators to reduce burden on the regulated
community. We consider a permanent separator to be one that handles
flowback from a well or wells beginning when the flowback period begins
and continuing to the startup of production. When routing flowback
through permanent separators, some reporting and recordkeeping elements
associated with well completions (e.g., information about when a
separator is hooked up or disconnected) become unnecessary because the
separator is already connected to the well at the onset of flowback. In
these situations, there is no initial flowback stage, and the
separation flowback stage begins. Therefore, the EPA is proposing that
operators do not need to record or report the date and time of each
attempt to direct flowback to a separator for these situations.
However, these streamlined recordkeeping and reporting requirements
would not apply in situations where flowback is not routed through a
permanent separator; in those cases, operators would be required to
report the date and time of each attempt to direct flowback to a
separator. The EPA is soliciting comments on these proposed revisions
and additional ways to streamline reporting and recordkeeping.
2. Onshore Natural Gas Processing Plants
    Capital Expenditure. We are proposing to correct the definition of
``capital expenditure'' promulgated at 40 CFR 60.5430a by replacing the
reference to the year 2011 with the year 2015 in the formula in
paragraph (2) of the definition. The definition of ``capital
expenditure'' was among the issues related to 40 CFR part 60, subpart
OOOO that the EPA reconsidered and addressed in the 2016 NSPS OOOOa.
That definition is relevant to the equipment leaks standards for
onshore natural gas processing plants that were originally promulgated
in 1985 in 40 CFR part 60, subpart KKK, updated in 2012 in 40 CFR part
60, subpart OOOO, and carried over in 2016 in 40 CFR part 60, subpart
OOOOa. As explained in the memorandum Alternative Method for
Determining Capital Expenditures (Thomas W. Rhoads to Docket A-80-44,
July 21, 1983), located at Docket ID No. EPA-HQ-OAR-2017-0483, this
method was developed to allow a facility to approximate the original
costs of the facility using the replacement costs and the inflation
index and therefore, providing an alternative method to the definition
of ``capital expenditure'' in 40 CFR part 60, subpart A (``General
Provisions'').\110\ The value for ``Y'' (the percent of replacement
cost) is designed to take into account the age of the facility.
Therefore, the replacement cost for a new facility should be the same
as the original cost, or the value of ``Y'' should be closer to 1 for
new facilities. Because the 2016 NSPS OOOOa applies to new sources
constructed, reconstructed, or modified after September 18, 2015, the
base year of 2015 is the correct year to reflect the age of the
facility in this calculation.
---------------------------------------------------------------------------

    \110\ See also Equipment Leaks of VOC in Natural Gas Production
Industry--Background for Promulgated Standards, EPA-450/3-82-024b,
May 1985, at 9-1.
---------------------------------------------------------------------------

    However, for sources that commenced construction between January 1,
2015, and September 18, 2015, when the value of ``2015'' is used it
results in a ``zero'' value for ``X'' for which there is no logarithmic
solution. This is a result that the EPA did not intend in its revision
of the calculation in the 2016 rulemaking. The EPA is, therefore,
amending the definition so that the value of ``Y'' equals 1 if the
affected process unit was constructed in 2015. The proposed amendment
would address the mathematical issue for affected sources constructed
in 2015 whiling leaving the calculation method intact for other
affected sources. We are soliciting comment on the proposed amendment
to the equation.
    Notwithstanding this proposed amendment, as indicated above, the
equation was developed as an alternative to the General Provisions
definition of ``capital expenditure.'' Since the General Provisions
definition also applies, if calculation issues arise when applying the
2016 NSPS OOOOa equation, facilities should use the General Provisions
to calculate capital expenditure. Facilities can also contact the EPA
for guidance on how to apply the General Provisions definition for
``capital expenditure'' evaluations if necessary by utilizing 40 CFR
60.5 (Determination of construction or modification).
    In addition, the EPA is soliciting comment and information to help
inform us whether the current capital expenditure definition should be
revised based on a ratio of consumer price indices (CPI), as requested
by two petitioners.\111\ Petitioners indicated that calculation of
``capital expenditure'' was designed to account for inflation. In
supporting documentation provided from one petitioner \112\ a plot of
values prior to 1982 demonstrates a logarithmic function, which
directly correlates to the CPI for the years 1950 through 1982. This
was the information on which the ``capital expenditure'' equation was
based. However, as described by the

petitioners, the CPI takes a more linear function post-1982, while the
``capital expenditure'' equation remains with a logarithmic function.
In practice, this could mean that the ``P'' value would be lower using
the ``capital expenditure'' equation, thus resulting in modifications
at lower expenditures than if the CPI were used. While we are proposing
to update the existing equation with the corrected base year date of
2015, we are also soliciting comment on changing the calculation for
the value of ``Y'' using the CPI. Specifically, we are soliciting
comment on the petitioner's suggestion that the value for ``Y'' should
be calculated using the CPI of the date of construction or
reconstruction divided by the CPI of the date of component price data,
or ``CPIN/CPIPD''.
---------------------------------------------------------------------------

    \111\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682 and EPA-HQ-
OAR-2010-0505-7684.
    \112\ See GPA Midstream New Source Performance Standards
(``NSPS'') Subpart OOOOa Petition for Review Technical Issues
located at Docket ID No. EPA-HQ-OAR-2010-0505-12361. March 1, 2017.
---------------------------------------------------------------------------

3. Closed Vent Systems (CVS) and Storage Vessel Thief Hatches
    The requirements for CVS are specific to the type of affected
facility that is associated with the CVS (i.e., ``routes to'' the CVS).
CVS receiving emissions from centrifugal compressor, reciprocating
compressor, and pneumatic pump affected facilities must be (a)
initially and annually inspected visually for defects and (b) initially
and annually monitored using Method 21 to verify operation at no
detectable emissions (i.e., an instrument reading less than 500 ppm
above background concentration). In contrast, no instrument monitoring
is required for CVS receiving emissions from storage vessel affected
facilities and monthly auditory, visual, and olfactory (AVO)
inspections must be performed. 40 CFR 60.5416a. Several petitioners
have stated that the requirements for CVS associated with pneumatic
pumps should be aligned with the requirements for CVS associated with
storage vessels instead of the CVS requirements for centrifugal or
reciprocating compressors.\113\ In addition, these petitioners stated,
though incorrectly, that pneumatic pumps are subject to OGI monitoring
under the fugitive emissions requirements as well as the annual Method
21 requirement; the petitioners, therefore, assert that the Method 21
requirement is duplicative and burdensome. Pneumatic pumps are not
fugitive emissions components because they vent as part of normal
operation. Finally, stakeholders have requested streamlined and
standardized requirements for all CVS, in place of equipment-specific
requirements currently in the 2016 NSPS OOOOa. Specifically, the
requirements are spread over multiple sections of the rule and vary
based on the affected facility associated with the CVS as stated above,
which the stakeholders have indicated creates confusion regarding
compliance.
---------------------------------------------------------------------------

    \113\ See Docket ID Nos. EPA-HQ-OAR-2010-0505-7682, EPA-HQ-OAR-
2010-0505-7685 and EPA-HQ-OAR-2010-0505-7686.
---------------------------------------------------------------------------

    The EPA has received information from various stakeholders that
overlapping requirements for these CVS and openings on controlled
storage vessels may still exist due to state program requirements.
Specifically, two stakeholders have informed us they are required to
perform quarterly OGI monitoring on the CVS located at well sites under
their state program in addition to the annual Method 21 requirement on
the same CVS for their affected facility pneumatic pumps as required by
the 2016 NSPS OOOOa. We agree with the stakeholders that amendments are
appropriate for the CVS requirements for pneumatic pumps.
    We are proposing to align the CVS monitoring requirements for
affected facility pneumatic pumps with the CVS monitoring requirements
for affected facility storage vessels. As stated by the petitioners, we
agree that pneumatic pumps and storage vessels are commonly located at
well sites and agree that having separate monitoring requirements for
potentially shared CVS is overly burdensome and duplicative. This
proposed amendment effectively requires monthly AVO monitoring for the
CVS located at well sites because there are no affected facility
reciprocating or centrifugal compressors located at well sites. We are
soliciting comment on this proposed amendment for CVS on affected
facility pneumatic pumps. Additionally, we are soliciting comment on
other methods that could be employed as an alternative to the monthly
AVO monitoring to ensure the CVS is operated with no detectable
emissions.
    Further, we are soliciting comment regarding the requirements for
covers, thief hatches and other openings on storage vessel affected
facilities. As specified in 40 CFR 60.5411a(b)(2), each opening on the
storage vessel cover should be secured in a closed and sealed position
except during periods where opening the cover is necessary (e.g., to
inspect or sample material in the storage vessel). Under 40 CFR
60.5416a(c)(2), each cover is also subject to monthly AVO monitoring
for defects that could result in air emissions. It has come to our
attention, however, that there may be confusion related to how the
cover and openings on the cover relate to the CVS and the no detectable
emissions requirement. We have observed fugitive emissions using OGI on
thief hatches, even where the CVS has been properly designed and
certified, and the thief hatch is properly weighted and closed.\114\
Given this information, we acknowledge there are concerns about an
interpretation of 40 CFR 60.5411a(c)(2) under which thief hatches are
subject to the no detectable emissions limit. We recognize that this
limit is traditionally required for components that we do not expect to
leak (e.g., valves with no external actuating shaft in contact with
process fluid). However, as noted here, we continue to observe fugitive
emissions from thief hatches that are properly weighted and closed.
Root cause analysis has demonstrated that deteriorated gaskets are one
cause of such emissions. While these sources might still be able to
meet the sensory monitoring limit, we are soliciting comment on whether
covers and openings on the cover should be viewed as part of the CVS
and thus subject to the no detectable emissions limit. In addition, we
are soliciting comment on whether other methods are available to more
reliably identify fugitive emissions from the CVS and thief hatches or
other openings on storage vessel affected facilities than the currently
required monthly AVO and to better assure compliance with the 95% VOC
emissions control requirement for storage vessel affected facilities.
We are also soliciting comment on whether a work practice standard
would be more effective at assuring compliance than subjecting thief
hatches to a no detectable emissions standard as determined through
monthly AVO. Finally, we are not proposing any changes to the CVS
requirements for affected facility centrifugal compressors or
reciprocating compressors.
---------------------------------------------------------------------------

    \114\ Analysis of Consent Decree Reports from Noble Energy, Inc.
as to Emissions Observations from Thief Hatches or Other Openings on
Controlled Storage Vessels; Oil and Natural Gas Sector: Emission
Standards for New, Reconstructed and Modified Sources
Reconsideration--SAN 5719.8 located at Docket ID No. EPA-HQ-OAR-
2017-0483.
---------------------------------------------------------------------------

VII. Implementation Improvements

    Following publication of the 2016 NSPS OOOOa, we subsequently
determined, following review of petitions and discussions with affected
parties, that the final rule warrants correction and clarification in
certain areas in addition to those discussed above. Each of these areas
is discussed below.

A. Reciprocating Compressors

    The 2016 NSPS OOOOa includes an alternative to the work practice
standards for reciprocating compressors. Operators may choose to gather
rod packing emissions using a collection system that operates under
negative pressure and then route emissions to a process via a CVS, as
opposed to replacing the rod packing every 26,000 hours or 36 months.
During the comment period for the proposal for the 2016 NSPS OOOOa, the
EPA received feedback from various stakeholders, who noted that there
were safety concerns with requiring the rod packing emissions to be
collected under negative pressure. Specifically, commenters stated that
operating the collection system under negative pressure may
inadvertently introduce oxygen into the system.\115\ In response to
comments, the EPA stated that operation of the collection system under
negative pressure was necessary in order to appropriately capture
emissions.\116\ The EPA is soliciting comment and supporting data on
capture systems which are at least equivalent to the current systems
and which could negate the necessity to capture emissions under
negative pressure.
---------------------------------------------------------------------------

    \115\ See Docket ID No. EPA-HQ-OAR-2010-0505-6884.
    \116\ See Docket ID No. EPA-HQ-OAR-2010-0505-7632, Chapter 7,
page 7-37.
---------------------------------------------------------------------------

B. Storage Vessels

    Pursuant to 40 CFR 60.5365a(e), owners and operators must calculate
potential emissions from storage vessels in order to determine if
control requirements apply. This calculation is based on the ``maximum
average daily throughput.'' During implementation of the 2016 NSPS
OOOOa, several stakeholders requested clarification regarding this
calculation. Specifically, the stakeholders have expressed confusion
about what value constitutes the ``maximum average daily throughput.''
This value was intended to represent the maximum of the average daily
production rates in the first 30-day period to each individual storage
vessel. The EPA stated in its Response to Comments on the 2013
amendments to the 2012 NSPS OOOO, ``we believe that the estimate of
potential VOC emissions should be determined based on maximum emissions
during the 30-day period rather than average emissions over that
period''.\117\ While the EPA was clear that emissions are not to be
averaged over the 30-day period, we were less clear at the time as to
what averaging was allowed when we used the term ``maximum average
daily throughput.'' Therefore, we propose to further clarify in this
notice when and how daily production may be averaged in determining
daily throughput.
---------------------------------------------------------------------------

    \117\ See Docket ID No. EPA-HQ-OAR-2010-0505-4639.
---------------------------------------------------------------------------

    We are proposing to revise the definition to clarify that the
maximum average daily throughput refers to the maximum average daily
throughput for an individual storage vessel over the days that
production is routed to that storage vessel during the 30-day
evaluation period. This average over the days that production is routed
to a storage vessel represents the maximum average daily throughput for
that single storage vessel because the determination takes place during
the first 30-day evaluation period when production throughput will be
the greatest due to the decline curve for production from oil and
natural gas wells. Further, by clarifying that production to a single
storage vessel must be averaged over the number of days production was
actually sent to that storage vessel, rather than over the entire 30
days (where the storage vessel receives no production on some days), we
are ensuring that the determination of potential for VOC emissions to
that individual storage vessel does not presume that production will be
split evenly across storage vessels where there is no legally and
practically enforceable limit requiring operation in that manner. A
more detailed discussion regarding the issue of averaging across a tank
battery is provided below. We are soliciting comment on this
clarification. Additionally, we are soliciting comment on whether a
different term would better describe this value than the currently used
``maximum average daily throughput.''
    Where a storage vessel has automated gauging, the operator may
directly determine the average daily throughput for each day that
production is routed to that storage vessel. The average daily
throughput for each day of production to that storage vessel would then
be averaged to determine the maximum average daily throughput for the
30-day evaluation period. For example, if a storage vessel receives
production on 22 of the 30 days in the evaluation period, then the
maximum average daily throughput is calculated by averaging the daily
throughput that was calculated for each of those 22 days. We recognize
that this approach averages the daily throughputs for the days that a
storage vessel receives production; however, recognizing that
production declines, we are clarifying that this calculation, based on
the days of production to the storage vessel during the first 30-days
of production, represents the potential emissions. We are soliciting
comment on this clarification.
    We understand that some storage vessels may not have daily
throughput measurements because they are not equipped with automated
level gauging and do not have daily manually gauged readings. In such
circumstances, we believe that the liquid height, and therefore volume,
in the storage vessel would be measured at a minimum at the start and
completion of loadout of liquids from the storage vessel. Frequency of
loadout from each storage vessel (i.e., ``turnover rate'') will vary
depending on company or site-specific operations. Therefore, it is
possible that a storage vessel could have multiple turnovers during the
first 30-days of production, and therefore multiple production periods.
Where this occurs, you must determine the average daily throughput for
each of those production periods, which can be done by dividing the
volumetric throughput calculated from the change in liquid height for
that production period over the number of days in the production
period, and use the maximum of those production period average daily
throughput values to calculate the potential emissions from the
individual storage vessel. A production period begins when production
begins to be routed to a storage vessel and ends either when throughput
is routed away from that storage vessel or when a loadout occurs from
that storage vessel, whichever happens first. We recognize that
calculating daily throughput based on liquid level measurements at the
beginning and end of a production period will necessarily average
production throughput to the individual storage vessel over the number
of days it was receiving production in the turnover period. However,
recognizing that production declines, we are clarifying that this
calculation, based on the first 30-days of production, represents the
potential emissions. We are soliciting comment on this clarification.
    Finally, inspection data and compliance reports for the 2016 NSPS
OOOOa indicate that many operators determined that few or no storage
vessels are affected facilities under the 2016 NSPS OOOOa. For example,
review of the 2016 NSPS OOOOa compliance reports and the fewer than
expected number of reported storage vessel affected facilities
indicates that some operators may be incorrectly averaging emissions
across storage tanks in tank batteries when determining the potential
for VOC emissions. Both the

2012 NSPS OOOO and 2016 NSPS OOOOa specify that a storage vessel
affected facility is ``a single storage vessel'' that ``has the
potential for VOC emissions equal to or greater than 6 tpy.'' 40 CFR
60.5365(e) and 60.5365a(e). In prior rulemakings, the EPA explained
that storage vessel emission estimation methods for the potential for
VOC emissions generally require information on both the composition and
volumetric rate of the liquid entering the storage vessel, where the
volumetric throughput is frequently calculated by recording the volume
of liquid collected from the receiving vessel(s) over time. 79 FR
79026. Because the 2012 NSPS OOOO and 2016 NSPS OOOOa define the
affected facility as ``a single storage vessel,'' the determination of
the potential for VOC emissions must be based on the liquid throughput
of each ``single storage vessel,'' even where the storage vessel is
part of a tank battery. Operators should ensure that the determination
of the potential for VOC emissions reflects each storage vessel's
actual configuration and operational characteristics. Similarly, the
EPA notes that affected facility determinations are allowed to account
for legally and practically enforceable limits in determining the
potential for VOC emissions for a storage vessel. However, only limits
that meet certain enforceability criteria may be used to restrict a
source's potential to emit, and the permit or requirement must include
sufficient compliance assurance terms and conditions such that the
source cannot lawfully exceed the limit. Given the potential for
recurring emissions from controlled storage vessel thief hatches or
other opening owing to operation and maintenance performance even where
adequate design has been verified,\118\ any limit on capture and
control efficiency from storage vessels must include sufficient
monitoring to timely identify and repair emissions from storage vessels
to ensure the limit on capture and control efficiency is consistently
achieved.
---------------------------------------------------------------------------

    \118\ Analysis of Consent Decree Reports from Noble Energy, Inc.
as to Emissions Observations from Thief Hatches or Other Openings on
Controlled Storage Vessels; Oil and Natural Gas Sector: Emission
Standards for New, Reconstructed and Modified Sources
Reconsideration--SAN 5719.8 located at Docket ID No. EPA-HQ-OAR-
2017-0483.
---------------------------------------------------------------------------

    Where a storage vessel is part of a tank battery, some operators
appear to derive the maximum average daily throughput of a storage
vessel in a battery by using the throughput to the entire battery (by
using records of liquids collected from the battery over time) and
dividing that figure by the number of storage vessels in the battery.
This approach for determining a storage vessel's maximum average daily
throughput is incorrect for certain operational configurations. For
instance, where a tank battery is operated such that all pressurized
liquids from the separator initially flow to only one storage vessel,
and then overflow to the next, and so on (i.e., in series or series
flow), the first individual storage vessel's throughput would be the
entire battery's throughput, not the entire battery's throughput
apportioned evenly among the storage vessels. Dividing an entire
battery's throughput by the number of storage vessels in the battery
would greatly underestimate flash emissions from the first storage
vessel connected in series, which is where liquid pressure drops from
separator pressure to atmospheric pressure. However, such division
could be appropriate where all liquids flow through a splitter system
in a common header that ensures that all liquids initially flow in
equal amounts to all storage vessels in a tank battery at all times
since the liquid pressure drop would occur equally in each storage
vessel in the battery. The EPA is soliciting comment and suggestions
for how to clarify or simplify the calculation for application by
stakeholders such that the potential emissions from storage vessels may
be determined.
    Finally, records of each VOC emissions determination for each
storage vessel affected facility are required in 40 CFR
60.5420a(c)(5)(ii). Given the proposed clarification discussed above,
we are soliciting comment on specific recordkeeping requirements that
would support the applicability determination for each individual
storage vessel regardless of whether that storage vessel is determined
to be an affected facility. This is because recordkeeping is necessary
to be able to verify that rule applicability was appropriately
determined in accordance with the regulatory requirements. We are
soliciting comment on the type of records that would be maintained to
demonstrate how the calculations of the maximum average daily
throughput and the potential for VOC emissions were performed. For
example, information related to how the throughput to the individual
storage vessel was determined (i.e., daily measurements or liquid
height measurements at the start and end of a production period) and
the start and end dates for each production period, along with the
number of days production was routed to that storage vessel, are key
elements that we would expect to have recorded. Where automated
readings from gauges or meters are available, we expect that a data
historian could automatically record and store some or all of this
information. Where automated readings are not available, load slips may
be able to provide some or all of this information (i.e., liquid height
in a storage vessel at the beginning and end of each load out and the
date of the load out, traceable to the storage vessel). We are also
soliciting comment on records that would be available to document the
operational configuration of a tank battery, where applicable,
including to which storage vessel(s) production was routed for each day
in the 30-day evaluation period. For calculation of potential for VOC
emissions, we expect that identification of the model or calculation
methodology used would be documented with the calculation itself. In
addition to the type of information that should be recorded, we are
also soliciting comment on the associated recordkeeping burden.

C. Definition of Certifying Official

    In response to petitions on NSPS OOOO, the EPA amended the
definition of `responsible official' in order to remove potential
confusion in the regulated community and to clarify that the
requirements of the NSPS were not associated with a permitting
program.\119\ Because the terms `responsible official' and `permitting
authority' were similar to terms used in the Title V permitting
program, the EPA changed the term `responsible official' to `certifying
official' and replaced the term `permitting authority' used in the
definition with `Administrator.' '' \120\ This amended definition of
`certifying official' was carried forward into the 2015 NSPS OOOOa
proposal. 80 FR 56694. The EPA received comments that the term
`certifying official' still includes references to permitting programs
and is inconsistent with way the NSPS program operates.\121\ In
response to this comment, the EPA stated that the change made in the
2014 amendments ``remove[d] any confusion.'' \122\ Upon further
evaluation of this issue, the EPA recognizes that continuing to include
the language ``facilities applying for or subject to a permit'' in the
definition of `certifying

official' is inappropriate for the NSPS program. Therefore, the EPA is
proposing to amend this definition to remove the reference to permits.
The EPA solicits comment on this proposed change.
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    \119\ 79 FR 79023-4.
    \120\ Id.
    \121\ See Docket ID No. EPA-HQ-OAR-2010-0505-6881.
    \122\ See Docket ID No. EPA-HQ-OAR-2010-0505-7632, Chapter 15,
page 15-284.
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D. Equipment in VOC Service Less Than 300 Hours/Year

    In this action, the EPA is proposing to amend the requirements for
equipment leaks at onshore natural gas processing plants. Specifically,
we are proposing to include an exemption from monitoring for certain
equipment that an owner or operator designates as being in VOC service
less than 300 hr/yr.
    When the 2007 requirements were promulgated, the EPA concluded that
an exemption for certain equipment that is in VOC service less than 300
hr/yr was appropriate. In response to public comments on the 2006 NSPS
VV/VVa proposal, we stated that such exemption was appropriate for
equipment that is used only during emergencies, used as a backup, or
that is in service only during startup and shutdown.\123\ In these
situations, the operating schedule of the equipment is unpredictable
and likely at widely spaced and varying intervals. Planning for
monitoring is more challenging and the effort outweighs the limited
potential gain in emissions. The EPA is proposing to include this same
exemption for equipment at onshore natural gas processing plants that
is used only during emergencies, used as a backup, or that is in
service only during startup and shutdown.
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    \123\ See Docket ID No. EPA-HQ-OAR-2006-0699-0094.
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E. Reporting and Recordkeeping

    The EPA is proposing to streamline certain reporting and
recordkeeping requirements to reduce burden on the regulated industry.
The proposed changes can be seen in section 60.5420a. Additionally, the
proposed reporting elements can be seen in the draft electronic
reporting template, located at Docket ID No. EPA-HQ-OAR-2017-0483. We
solicit comment on these proposed revisions; the content, layout, and
overall design of the reporting template; and additional ways to
streamline reporting and recordkeeping.
    We are also proposing revisions to accommodate the submittal of CBI
data in annual reports, as well as additional clarifications for
reporting requirements during outages of the Compliance and Emissions
Data Reporting Interface (CEDRI) or the EPA's Central Data Exchange
(CDX) systems, or during a force majeure event. These proposed changes
can be seen in section 60.5420a.

F. Technical Corrections and Clarifications

    We are proposing to revise the 2016 NSPS OOOOa to include the
following technical corrections and clarifications.
     Revise paragraphs 60.5385a(a)(1), 60.5410a(c)(1),
60.5415a(c)(1), 60.5420a(b)(4)(i), and 60.5420a(c)(3)(i) to clarify
that hours or months of operation at reciprocating compressor
facilities should be measured beginning with the later of initial
startup, the effective date of the requirement (August 2, 2016), or the
last rod packing replacement.
     Revise paragraph 60.5393a(b)(3)(ii) to correctly cross-
reference to paragraph (b)(3)(i) of that section.
     Revise paragraph 60.5397a(c)(8) to clarify the calibration
requirements when Method 21 of Appendix A-7 to Part 60 is used for
fugitive emission monitoring.
     Revise paragraph 60.5397a(d)(3) to correctly cross-
reference paragraphs (g)(3) and (g)(4) of that section.
     Revise paragraph 60.5401a(e) to remove the word
``routine'' to clarify that pumps in light liquid service, valves in
gas/vapor service and light liquid service, and pressure relief devices
in gas/vapor service within a process unit at an onshore natural gas
processing plant located on the Alaskan North Slope are not subject to
any monitoring requirements.
     Revise paragraph 60.5410a(e) to correctly reference
pneumatic pump affected facilities located at a well site as opposed to
pneumatic pump affected facilities not located at a natural gas
processing plant. This proposed revision reflects that the 2016 NSPS
OOOOa did not finalize requirements for pneumatic pumps in the
gathering and boosting and transmission and storage segments. 81 FR
35850.
     Revise paragraph 60.5411a(a)(1) to remove the reference to
paragraphs 60.5412a(a) and (c) for reciprocating compressor affected
facilities.
     Revise paragraph 60.5411a(d)(1) to remove the reference to
storage vessels, as this paragraph applies to all the sources lists in
paragraph 60.5411a(d), not only storage vessels.
     Revise paragraphs 60.5412a(a)(1), 60.5412a(a)(1)(iv),
60.5412a(d)(1)(iv), and 60.5412a(d)(1)(iv)(D) to clarify that all
boilers and process heaters must introduce the vent stream into the
flame zone and that the performance requirement option for combustion
control devices on centrifugal compressors and storage vessels is to
introduce the vent stream with the primary fuel or as the primary fuel.
This is consistent with the performance testing exemption in section
60.5413a and continuous monitoring exemption in section 60.5417a for
boilers and process heaters that introduce the vent stream with the
primary fuel or as the primary fuel.
     Revise paragraph 60.5412a(c) to correctly reference both
paragraphs (c)(1) and (c)(2) of that section, for managing carbon in a
carbon adsorption system.
     Revise paragraph 60.5413a(d)(5)(i) to reference fused
silica-coated stainless steel evacuated canisters instead a specific
name brand product.
     Revise paragraph 60.5413a(d)(9)(iii) to clarify the basis
for the total hydrocarbon span for the alternative range is propane,
just as the basis for the recommended total hydrocarbon span is
propane.
     Revise paragraph 60.5413a(d)(12) to clarify that all data
elements must be submitted for each test run.
     Revise paragraph 60.5415a(b)(3) to reference all the
applicable reporting and recordkeeping requirements.
     Revise paragraph 60.5416a(a)(4) to correctly cross-
reference paragraph 60.5411a(a)(3)(ii).
     Revise paragraph 60.5417a(a) to clarify requirements for
controls not specifically listed in paragraph (d) of that section.
     Revise paragraph 60.5422a(b) to correctly cross-reference
paragraphs 60.487a(b)(1) through (3) and (b)(5).
     Revise paragraph 60.5422a(c) to correctly cross-reference
paragraph 60.487a(c)(2)(i) through (iv) and (c)(2)(vii) through (viii).
     Revise paragraph 60.5423a(b) to simplify the reporting
language and clarify what data is required in the report of excess
emissions for sweetening unit affected facilities.
     Revise paragraph 60.5430a to remove the phrase ``including
but not limited to'' from the ``fugitive emissions component''
definition. This proposed revision reflects that in the response to
comments document for the 2016 NSPS OOOOa we stated we were removing
this phrase.\124\
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    \124\ See Docket ID No. EPA-HQ-OAR-2010-0505-7632, Chapter 4,
page 4-319.
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     Revise paragraph 60.5430a to remove the phrase ``at the
sales meter'' from the ``low pressure well'' definition. When
determining the low pressure status of a well, pressure is measured
within the flow line, rather than at the sales meter.
     Revise Table 3 to correctly indicate that the performance
tests in section 60.8 do not apply to pneumatic pump affected
facilities.

     Revise Table 3 to include the collection of fugitive
emissions components at a well site and the collection of fugitive
emissions components at a compressor station in the list of exclusions
for notification of reconstruction.
     Revise paragraphs 60.5393a(f), 60.5410a(e)(8),
60.5411a(e), 60.5415a(b), 60.5415a(b)(4), 60.5416a(d), 60.5420a(b),
60.5420a(b)(13), and introductory text in 60.5411a and 60.5416a to
remove the language added in the ``Oil and Natural Gas Sector: Emission
Standards for New, Reconstructed, and Modified Sources; Grant of
Reconsideration and Partial Stay'' (June 5, 2017), which was vacated by
the U.S. Court of Appeals for the D.C. Circuit on July 3, 2017.

VIII. Impacts of This Proposed Rule

A. What are the air impacts?

    For this action, the EPA estimated the change in emissions that
will occur due to the implementation of the proposed NSPS
reconsideration for the analysis years of 2019 through 2025. We
estimate impacts beginning in 2019 to reflect the year implementation
of this reconsideration will begin, assuming it is finalized within the
next year. We estimate impacts through 2025 to illustrate the continued
compound effect of this rule over a longer period. We do not estimate
impacts after 2025 for reasons including limited information, as
explained in the RIA (Regulatory Impact Analysis). The regulatory
impact estimates for 2025 include sources newly affected in 2025 as
well as the accumulation of affected sources from 2016 to 2024 that are
also assumed to be in continued operation in 2025, thus incurring
compliance costs and emissions reductions in 2025.
    We have estimated that, over the 2019 through 2025 timeframe,
assuming semiannual monitoring at compressor stations, the proposed
NSPS reconsideration would increase methane emissions by about 380,000
short tons, and VOC emissions by about 100,000 tons from facilities
affected by this reconsideration compared to emissions under the 2018
updated baseline, as described in the RIA. The proposed reconsideration
is also expected to concurrently increase hazardous air pollutant (HAP)
emissions by about 3,800 tons from 2019 through 2025. Section 2 of the
RIA contains an analysis of the increase in emissions as a result of
this proposed reconsideration under the co-proposed option of annual
monitoring at compressor stations. As seen in section 2.5.2 of the RIA,
the co-proposed option of annual fugitive emissions monitoring results
in greater total emissions than those under the co-proposed option of
semiannual fugitive emissions monitoring at compressor stations outside
of the Alaskan North Slope. Over 2019 through 2025, fugitive emissions
under the co-proposed option assuming annual monitoring are about
100,000 short tons greater for methane, 24,000 tons greater for VOC,
and 890 tons greater for HAP than those under the co-proposed option
assuming semiannual fugitive emissions monitoring.
    As described in the TSD and RIA for this rule, the EPA projected
affected facilities using a combination of historical data from the
United States GHG Inventory, projected activity levels taken from the
Energy Information Administration (EIA's) Annual Energy Outlook (AEO),
and oil and natural gas production information from DrillingInfo, a
private company that provides information and analysis to the energy
sector. The EPA also considered state regulations with similar
requirements to the proposed NSPS in projecting affected sources for
impacts analyses supporting this rule.

B. What are the energy impacts?

    Energy impacts in this section are those energy requirements
associated with the operation of emission control devices. Potential
impacts on the national energy economy from the rule are discussed in
the economic impacts section. There would be little change in the
national energy demand from the operation of any of the environmental
controls proposed in this action. The proposed NSPS reconsideration
continues to encourage the use of emission controls that recover
hydrocarbon products that can be used on-site as fuel or reprocessed
within the production process for sale.

C. What are the compliance cost savings?

    Assuming the co-proposed option of semiannual monitoring at
compressor stations, the EPA estimates the PV of compliance cost
savings of the proposed reconsideration over 2019-2025, discounted back
to 2016, will be $429 million (in 2016 dollars) under a 7 percent
discount rate, and $546 million under a 3 percent discount rate, not
including the forgone producer revenues associated with the decrease in
the recovery of saleable natural gas. The EAV of these cost savings are
$74 million per year using a 7 percent discount rate and $85 million
per year using a 3 percent discount rate. In this analysis, we use the
2018 AEO projection of natural gas prices to estimate the value of the
change in the recovered gas at the wellhead. After accounting for the
change in these revenues, the estimate of the PV of compliance cost
savings of the proposed reconsideration over 2019-2025, discounted back
to 2016, are estimated to be $380 million under a 7 percent discount
rate, and $484 million under a 3 percent discount rate; the
corresponding estimates of the EAV of cost savings after accounting for
the forgone revenues are $66 million per year under a 7 percent
discount rate, and $75 million per year under a 3 percent discount
rate.
    Compared to the estimated cost savings of the co-proposed option
under semiannual fugitive emissions monitoring at compressor stations,
the co-proposed option assuming annual monitoring results in greater
cost savings. Assuming a 7 percent discount rate, and including the
forgone value of product recovery, the PV of the total cost savings
from 2019 through 2025 are about $43 million greater under annual
monitoring than under semiannual monitoring. This is associated with an
increase in the EAV of total cost savings of about $7.5 million per
year in comparison to the co-proposed option under semiannual
monitoring. A summary of the cost savings and forgone emission
reductions associated with the co-proposed option of annual fugitive
emissions monitoring at compressor stations is located in section 2.5.2
of the RIA.

D. What are the economic and employment impacts?

    The EPA used the National Energy Modeling System (NEMS) to estimate
the impacts of the 2016 NSPS OOOOa on the United States energy system.
The NEMS is a publicly-available model of the United States energy
economy developed and maintained by the EIA and is used to produce the
AEO, a reference publication that provides detailed forecasts of the
United States energy economy.
    The EPA estimated small impacts of that rule over the 2020 to 2025
period relative to the baseline for that rule. The proposed
reconsideration is estimated to result in a decrease in total costs
compared to the updated 2018 baseline, and the 2016 NSPS OOOOa, with
the change in costs affecting a subset of the total costs estimated for
the 2016 NSPS OOOOa. Therefore, the EPA expects that this deregulatory
action, if finalized, would partially ameliorate the impacts estimated
for the final NSPS in the 2016 RIA.
    Executive Order 13563 directs federal agencies to consider the
effect of regulations on job creation and

employment. According to the Executive Order, ``our regulatory system
must protect public health, welfare, safety, and our environment while
promoting economic growth, innovation, competitiveness, and job
creation. It must be based on the best available science.'' (Executive
Order 13563, 2011.) While a standalone analysis of employment impacts