\55\ WRI CAIT Climate Data Explorer. http://cait.wri.org/.
Accessed March 30, 2016.
    \56\ Ibid.
---------------------------------------------------------------------------

4. Global GHG Emissions

Table 7--Comparisons of United States Oil and Natural Gas Production and
  Natural Gas Processing and Transmission CH4 Emissions to Total Global
                    Greenhouse Gas Emissions in 2012
------------------------------------------------------------------------
                                                   Total U.S. oil and
                                                 natural gas production
                                2012 (MMT CO2        and natural gas
                                     Eq.)            processing and
                                                 transmission share  (%)
------------------------------------------------------------------------
Total Global GHG Emissions...          44,816                       0.5
------------------------------------------------------------------------

    As illustrated by the domestic and global GHG comparison data
summarized above, the collective GHG emissions from the oil and natural
gas source category are significant, whether the comparison is domestic
(where this sector is the largest source of methane emissions,
accounting for 32 percent of United States methane and 3.4 percent of
total United States emissions of all GHG), global (where this sector,
while accounting for 0.5 percent of all global GHG emissions, emits
more than the total national emissions of over 150 countries, and
combined emissions of over 50 countries), or when both the domestic and
global GHG emissions comparisons are viewed in combination.
Consideration of the global context is important. GHG emissions from
United States oil and natural gas production and natural gas processing
and transmission will become globally well-mixed in the atmosphere, and
thus will have an effect on the United States regional climate, as well
as the global climate as a whole for years and indeed many decades to
come.
    As was the case in 2009, no single GHG source category dominates on
the global scale. While the oil and natural gas source category, like
many (if not all) individual GHG source categories, could appear small
in comparison to total emissions, in fact, it is a very important
contributor in terms of both absolute emissions, and in comparison to
other source categories globally or within the United States.
5. VOC Emissions
    The EPA National Emissions Inventory (NEI) estimated total VOC
emissions from the oil and natural gas sector to be 2,729,942 tons in
2011. This ranks second of all the sectors estimated by the NEI and
first of all the anthropogenic sectors in the NEI. These facts only
serve to further the notion that emissions from the oil and natural gas
sector contribute significantly to harmful air pollution.
6. SO2 Emissions
    The NEI estimated total SO2 emissions from the oil and
natural gas sector to be 74,266 tons in 2011. This ranks 13th of the
sectors estimated by the NEI. Again, it is clear that emissions from
the oil and natural gas sector contribute significantly to dangerous
air pollution.
7. Conclusion
    In summary, the 1979 Priority List broadly covers the oil and
natural gas industry, including the production, processing,
transmission, and storage of natural gas. As such, the 1979 Priority
List covers all segments that we are regulating in this rule. To the
extent that there is any ambiguity in the prior listing, the EPA hereby
finalizes as an alternative its proposed revision of the category
listing to broadly include the oil and natural gas industry. As
revised, the listed oil and natural gas source category includes oil
\57\ and natural gas production, processing, transmission, and storage.
Pursuant to CAA section 111(b)(1)(A), the Administrator has determined
that, in her judgment, this source category, as defined above,
contributes significantly to air pollution that may reasonably be
anticipated to endanger public health or welfare. In support, the EPA
notes its previous determination under CAA section 111(b)(1)(A) for the
oil and natural gas source category. In addition, the EPA provides in
this section information and analyses detailing the public health and
welfare impacts of GHG, VOC and SO2 emissions and the amount
of these emission from the oil and natural gas source category (in
particular from the various segments of the natural gas industry).
Although the EPA does not believe the revision to the category listing
is required for the standards we are promulgating in this action, even
assuming it is, the revision is well justified.
---------------------------------------------------------------------------

    \57\ For the oil industry, the listing includes production, as
explained above in footnote 27.
---------------------------------------------------------------------------

D. Establishing GHG Standards in the Form of Limitations on Methane
Emissions

    A petition for reconsideration of the 2012 NSPS urged that ``EPA
must reconsider its failure to adopt standards for the methane
pollution released by the oil and gas sector.'' \58\ Upon reconsidering
the issue, and with the benefit of additional information now available
to us, the EPA is establishing GHG standards, in the form of
limitations on methane emissions, throughout the oil and natural gas
source category.
---------------------------------------------------------------------------

    \58\ Sierra Club et al., Petition for Reconsideration, In the
Matter of: Final Rule Published at 77 FR 49490 (August 16, 2012),
titled ``Oil and Gas Sector: New Source Performance Standards and
National Emission Standards for Hazardous Air Pollutants Reviews;
Final Rule,'' Docket ID No. EPA-HQ-OAR-2010-0505, RIN 2060-AP76
(2012).
---------------------------------------------------------------------------

    During the 2012 oil and natural gas NSPS rulemaking, we had a
considerable amount of data and a good understanding of VOC emissions
from the oil and natural gas industry and the available control
options, but data on methane emissions were just emerging at that time.
In light of the rapid expansion of this industry and the growing
concern with the associated emissions, the EPA proceeded to establish a
number of VOC standards in the 2012 NSPS, while indicating in the 2012
rulemaking an intent to revisit methane at a later date when additional
information was available from the GHGRP.
    We have since received and evaluated considerable additional data,
which confirms that the oil and natural gas industry is one of the
largest emitters of methane in the United States. As

discussed in more detail in section IV.C of this preamble above, the
current methane emissions from this industry contribute substantially
to nationwide GHG emissions. And these emissions are expected to
increase as a result of the rapid growth of this industry.
    While the controls used to meet the VOC standards in the 2012 NSPS
also reduce methane emissions incidentally, in light of the current and
projected future GHG emissions from the oil and natural gas industry,
reducing GHG emissions from this source category should not be treated
simply as an incidental benefit to VOC reduction; rather, it is
something that should be directly addressed through GHG standards in
the form of limits on methane emissions under CAA section 111(b) based
on direct evaluation of the extent and impact of GHG emissions from
this source category and the emission reductions that can be achieved
through the best system for their reduction. The standards detailed in
this final action will achieve meaningful GHG reductions and will be an
important step towards mitigating the impact of GHG emissions on
climate change.
    In addition, while many of the currently regulated emission sources
are equipment used throughout the oil and natural gas industry (e.g.,
pneumatic controllers, compressors) that emit both VOCs and methane,
the VOC standards established in the 2012 NSPS apply only to the
equipment located in the production and processing segments. As
explained in the 2012 final rule, while our analysis suggested that the
remaining pieces of equipment (i.e., those in the transmission and
storage segments) are also important to regulate, given the large
number of these pieces of equipment and the relatively low level of VOC
from individual equipment, the EPA decided that further evaluation is
appropriate before taking final action. 77 FR 49490, 49521-2 (August
16, 2012). Based on its analyses in the current rulemaking, the EPA is
taking final action to regulate VOC emitted from these remaining pieces
of equipment. In addition, the EPA is setting GHG standards (by setting
limitations on methane) for these pieces of equipment across the
industry. As shown in the TSD, there are cost-effective controls that
can simultaneously reduce both methane and VOC emissions from these
equipment across the industry, and in many instances, they are cost
effective even if all the costs are attributed to methane
reduction.\59\ Moreover, in addition to the reductions to be achieved,
establishing both GHG and VOC standards for equipment across the
industry will also promote consistency by providing the same regulatory
regime for this equipment throughout the oil and natural gas source
category for both VOC and GHG, thereby facilitating implementation and
enforcement.\60\ Therefore, based on the EPA's evaluation of methane
reduction to address the impact of GHGs on climate change in
conjunction with VOC reduction, the oil and gas NSPS, as finalized in
this action, includes both VOC and GHG standards (in the form of
limitations on methane) for a number of equipment across the oil and
natural gas industry. It also includes VOC and GHG standards for a
number of previously unregulated sources (i.e., oil well completions,
fugitive emissions at well sites and compressor stations, and pneumatic
pumps).
---------------------------------------------------------------------------

    \59\ In this action, we evaluated the controls under different
approaches, including a single pollutant approach and a multi-
pollutant approach, which are described in detail in the preamble to
the proposed rule and the final TSD. Under a single pollutant
approach, we attribute all costs to one pollutant and zero to the
other.
    \60\ While this final rule will result in additional reductions,
as specified in sections II and IX of this preamble, the EPA often
revises standards even where the revision will not lead to any
additional reductions of a pollutant because another standard
regulates a different pollutant using the same control equipment.
For example, in 2014, the EPA revised the Kraft Pulp Mill NSPS in 40
CFR part 60 subpart BB published at 70 FR 18952 (April 4, 2014) to
align the NSPS standards with the National Emission Standards for
Hazardous Air Pollutants (NESHAP) standards for those sources in 40
CFR part 63, subpart S. Although no previously unregulated sources
were added to the Kraft Pulp Mill NSPS, several emission limits were
adjusted downward. The revised NSPS did not achieve additional
reductions beyond those achieved by the NESHAP, but aligning the
NSPS with the NEHSAP eased the compliance burden for the sources.
---------------------------------------------------------------------------

    With respect to the GHG standards contained in this final rule, the
EPA identifies the air pollutant as the pollutant GHGs. However, the
standards in this rule that are specific to GHGs are expressed in the
form of limits on emissions of methane, and not the other constituent
gases of the air pollutant GHGs.\61\ In this action, we are not
establishing a limit on aggregate GHGs or separate emission limits for
other GHGs that are not methane. This rule focuses on methane because,
among other reasons, it is a GHG that is emitted in large quantities
from the oil and gas industry, as explained above in section IV.C of
this preamble. Notwithstanding this form of the standard, consistent
with other EPA regulations addressing GHGs, the air pollutant regulated
in this rule is GHGs; methane is limited as a constituent of the
regulated pollutant, GHGs, not as a separate pollutant. This approach
is consistent with the approach EPA followed in setting limits for new
electric generating units.\62\ Additional regulatory language has been
added to 40 CFR 60.5360a to clarify and confirm that GHGs is the
regulated pollutant.
---------------------------------------------------------------------------

    \61\ In the 2009 GHG Endangerment Finding, the EPA defined the
relevant ``air pollution'' as the atmospheric mix of six long-lived
and directly emitted GHGs: CO2, CH4,
N2O, HFCs, PFCs, and SF6. 74 FR 66497,
December 15, 2009.
    \62\ See 80 FR 64510 (October 23, 2015).
---------------------------------------------------------------------------

    The EPA's authority for regulating GHGs in this rule is CAA section
111(b)(1). As discussed above, under the statutory structure of CAA
section 111(b), the Administrator first lists source categories
pursuant to CAA section 111(b)(1)(A), and then promulgates, under CAA
section 111(b)(1)(B), ``standards of performance for new sources within
such category.''
    In this rule, the EPA is establishing standards under CAA section
111(b)(1)(B) for a source category that it has previously listed and
regulated for other pollutants and which now is being regulated for an
additional pollutant.\63\ Because of this, there are two aspects of CAA
section 111(b)(1) that warrant particular discussion.
---------------------------------------------------------------------------

    \63\ As explained in more detail in section IV.A of this
preamble, the EPA interprets the 1979 category listing to broadly
cover the oil and natural gas industry. Thus, this discussion
focuses on EPA's authority to regulate an additional pollutant
(specifically GHG) emitted from a previously listed source category.
However, to the extent that any ambiguity exists in the 1979
listing, and as also explained above, EPA is finalizing its
alternative proposal to revise the category listing to broadly cover
the oil and natural gas industry. In support, the Administrator has
determined in this action, pursuant to CAA section 111(b)(1)(A),
that the listed source category, as defined in the revision,
contributes significantly to air pollution which may reasonably be
anticipated to endanger public health or welfare. Therefore, the
category listing and the Administrator's determination (to the
extent they are necessary) provide authority for standards we are
promulgating in this final rule, including the standards for GHG.
---------------------------------------------------------------------------

    First, because the EPA is not listing a new source category in this
rule,\64\ the EPA is not required to make a new endangerment finding
with regard to the oil and natural gas source category in order to
establish standards of performance for an additional pollutant from
those sources. Under the plain language of CAA section 111(b)(1)(A), an
endangerment finding is required only to list a source category. Though
the endangerment finding is based on determinations as to the health or
welfare impacts of the pollution to which the source category's
pollutants contribute, and as to the significance of the amount of such
contribution, the statute is clear that the endangerment

finding is made with respect to the source category; CAA section
111(b)(1)(A) does not provide that an endangerment finding is made as
to specific pollutants. This contrasts with other CAA provisions that
do require the EPA to make endangerment findings for each particular
pollutant that the EPA regulates under those provisions (e.g., CAA
sections 202(a)(1), 211(c)(1), 231(a)(2)(A). See American Electric
Power v. Connecticut, 131 S. Ct. 2527, 2539 (2011) (``the Clean Air Act
directs EPA to establish emissions standards for categories of
stationary sources that, `in [the Administrator's] judgment,' `caus[e],
or contribut[e] significantly to, air pollution which may reasonably be
anticipated to endanger public health or welfare.' Sec.
7411(b)(1)(A).'') (emphasis added).
---------------------------------------------------------------------------

    \64\ See section IV.A of this preamble.
---------------------------------------------------------------------------

    Second, once a source category is listed, the CAA does not specify
what pollutants should be the subject of standards from that source
category. The statute, in CAA section 111(b)(1)(B) simply directs the
EPA to propose and then promulgate regulations ``establishing Federal
standards of performance for new sources within such category.'' In the
absence of specific direction or enumerated criteria in the statute
concerning what pollutants from a given source category should be the
subject of standards, it is appropriate for the EPA to exercise its
authority to adopt a reasonable interpretation of this provision.
Chevron U.S.A. Inc. v. NRDC, 467 U.S. 837, 843-44 (1984).\65\
---------------------------------------------------------------------------

    \65\ In Chevron, the United States Supreme Court held that an
agency must, at Step 1, determine whether Congress's intent as to
the specific matter at issue is clear, and, if so, the agency must
give effect to that intent. If Congressional intent is not clear,
then, at Step 2, the agency has discretion to fashion an
interpretation that is a reasonable construction of the statute.
---------------------------------------------------------------------------

    The EPA has previously interpreted this provision as granting it
the discretion to determine which pollutants should be regulated. See
Standards of Performance for Petroleum Refineries, 73 FR 35838, 35858
(June 24, 2008) (concluding the statute provides ``the Administrator
with significant flexibility in determining which pollutants are
appropriate for regulation under section 111(b)(1)(B)'' and citing
cases). Further, in directing the Administrator to propose and
promulgate regulations under CAA section 111(b)(1)(B), Congress
provided that the Administrator should take comment and then finalize
the standards with such modifications ``as [s]he deems appropriate.''
The D.C. Circuit has considered similar statutory phrasing from CAA
section 231(a)(3) and concluded that ``[t]his delegation of authority
is both explicit and extraordinarily broad.'' National Assoc. of Clean
Air Agencies v. EPA, 489 F.3d 1221, 1229 (D.C. Cir. 2007).
    In exercising its discretion with respect to which pollutants are
appropriate for regulation under CAA section 111(b)(1)(B), the EPA has
in the past provided a rational basis for its decisions. See National
Lime Assoc. v. EPA, 627 F.2d 416, 426 & n.27 (D.C. Cir. 1980) (court
discussed, but did not review, the EPA's reasons for not promulgating
standards for NOX, SO2, and CO from lime plants);
Standards of Performance for Petroleum Refineries, 73 FR 35859-60 (June
24, 2008) (providing reasons why the EPA was not promulgating GHG
standards for petroleum refineries as part of that rule). Though these
previous examples involved the EPA providing a rational basis for not
setting standards for a given pollutant, a similar approach is
appropriate where the EPA determines that it should set a standard for
an additional pollutant for a source category that was previously
listed and regulated for other pollutants. The EPA took this approach
in setting limits for new electric generating units.\66\ The EPA
interprets CAA section 111(b)(1)(B) to provide authority to establish a
standard for performance for any pollutant emitted by that source
category as long as the EPA has a rational basis for setting a standard
for the pollutant. In making such determination, we have generally
considered a number of factors to help inform our decision. These
include the amount of the pollutant that is being emitted from the
source category, the availability of technically feasible control
options, and the costs of those control options.\67\
---------------------------------------------------------------------------

    \66\ 80 FR 64510, 64529-30, October 23, 2015.
    \67\ See 80 FR 56593, 56600-09, (section VI of the proposed
rule) and 56616-45, September 18, 2015 (section VIII of the proposed
rule).
---------------------------------------------------------------------------

    In this rulemaking, the EPA has a rational basis for concluding
that GHGs from the oil and natural gas source category, which is a
large category of sources of GHG emissions, merit regulation under CAA
section 111. In making this determination, the EPA focuses on methane
emissions from this category. The information summarized here and
discussed in other sections of this preamble provides the rational
basis for the GHG standards, expressed as limitations on methane,
established in this action.\68\
---------------------------------------------------------------------------

    \68\ Specifically, Sections IV.B and C, V, and VI of this final
rule.
---------------------------------------------------------------------------

    In 2009, the EPA made a finding that GHG air pollution may
reasonably be anticipated to endanger public health or welfare under
section 202(a) of the CAA \69\ and, in 2010, the EPA denied petitions
to reconsider that finding. The EPA extensively reviewed the available
science concerning GHG pollution and its impacts in taking those
actions. In 2012, the United States Court of Appeals for the District
of Columbia Circuit upheld the finding and the denial of petitions to
reconsider.\70\ In addition, assessments released by the
Intergovernmental Panel on Climate Change (IPCC), the USGCRP, and the
NRC, and other organizations published after 2010 lend further credence
to the validity of the 2009 Endangerment Finding. No information that
commenters have presented or that the EPA has reviewed provides a basis
for reaching a different conclusion for purposes of this action.
Indeed, current and evolving science discussed in detail in sections
IV.B and C of this preamble is confirming and enhancing our
understanding of the near- and longer-term impacts that elevated
concentrations of GHGs, including methane, are having on Earth's
climate and the adverse public health, welfare, and economic
consequences that are occurring and are projected to occur as a result.
---------------------------------------------------------------------------

    \69\ 74 FR 66496 (December 15, 2009).
    \70\ Coalition for Responsible Regulation v. EPA, 684 F.3d 102,
119-126 (D.C. Circuit 2012).
---------------------------------------------------------------------------

    Moreover, the high quantities of methane emissions from the oil and
natural gas source category demonstrate that it is rational for the EPA
to set methane limitations to regulate GHG emissions from this sector.
The oil and natural gas source category is the largest emitter of
methane in the United States, contributing about 29 percent of total
United States methane emissions. The methane that this source category
emits accounts for 3 percent of all United States GHG emissions. As
shown in Tables 4 and 5 in this preamble, oil and gas sources are very
large emitters of methane: In fact, GWP-weighted emissions of methane
from these sources are larger than emissions of all GHGs from about 150
countries. Methane is a GHG with a global warming potential 28 to 36
times greater than that of CO2.\71\ When considered in

total, the facts presented in sections IV.B and C of this preamble,
along with prior EPA analysis, including that found in the 2009
Endangerment Finding, provide a rational basis for regulating GHG
emissions from affected oil and gas sources by expressing GHG
limitations in the form of limits on methane emissions.
---------------------------------------------------------------------------

    \71\ IPCC, 2013: Climate Change 2013: The Physical Science
Basis. Contribution of Working Group I to the Fifth Assessment
Report of the Intergovernmental Panel on Climate Change [Stocker,
T.F., D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A.
Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge
University Press, Cambridge, United Kingdom and New York, NY, USA,
1535 pp. Note that for purposes of inventories and reporting, GWP
values from the 4th Assessment Report may be used. For the purposes
of calculating GHG emissions, the GWP value published on Table A-1
to subpart A of 40 CFR part 98 should still be used.
---------------------------------------------------------------------------

    To reiterate, the ``air pollution'' defined in the 2009
Endangerment Finding is the atmospheric mix of six long-lived and
directly emitted GHGs: CO2, CH4, N2O,
HFCs, PFCs, and SF6.\72\ This is the same pollutant that is
regulated by this rule. However, the standards of performance adopted
in the present rulemaking address only one constituent gas of this air
pollution: Methane. This is reasonable, given that methane is the
constituent gas emitted in the largest volume by the source category
and for which there are available controls that are technically
feasible and cost effective. There is no requirement that standards of
performance address each component of an air pollutant. Clean Air Act
section 111(b)(1)(B) requires the EPA to establish ``standards of
performance'' for listed source categories, and the definition of
``standard of performance'' in CAA section 111(a)(1) does not specify
which air pollutants must be controlled. So, while the limitations in
this rule are expressed as limits on methane, the pollutant regulated
is GHGs.
---------------------------------------------------------------------------

    \72\ See 74 FR 66496, 66497 (December 15, 2009).
---------------------------------------------------------------------------

    Some commenters have argued that the EPA is required to make a new
endangerment finding before it may set limitations for methane from the
oil and natural gas source category. We disagree, for the reasons
discussed above. Moreover, even if CAA section 111 required the EPA to
make an endangerment finding as a prerequisite for this rulemaking,
then, the information and conclusions described above in sections IV.B
and C of this preamble should be considered to constitute the requisite
finding (which includes a finding of endangerment as well as a cause-
or-contribute significantly finding). The same facts that support our
rational basis determination would support such a finding. The EPA's
rational basis for regulating GHGs, by setting methane limitations,
under CAA section 111 is based primarily on the analysis and
conclusions in the EPA's 2009 Endangerment Finding and 2010 denial of
petitions to reconsider that Finding, coupled with the subsequent
assessments from the IPCC, USGCRP, and NRC that describe scientific
developments since those EPA actions and other facts contained herein.
    More specifically, our approach here--reflected in the information
and conclusions described above--is substantially similar to that
reflected in the 2009 Endangerment Finding and the 2010 denial of
petitions to reconsider. The D.C. Circuit upheld that approach in
Coalition for Responsible Regulation v. EPA, 684 F.3d 102, 117-123
(D.C. Cir. 2012) (noting, among other things, the ``substantial . . .
body of scientific evidence marshaled by EPA in support of the
Endangerment Finding'' (id. at 120); the ``substantial record evidence
that anthropogenic emissions of greenhouse gases very likely caused
warming of the climate over the last several decades'' (id. at 121);
``substantial scientific evidence . . . that anthropogenically induced
climate change threatens both public health and public welfare . . .
[through] extreme weather events, changes in air quality, increases in
food- and water-borne pathogens, and increases in temperatures'' (id.);
and ``substantial evidence . . . that the warming resulting from the
greenhouse gas emissions could be expected to create risks to water
resources and in general to coastal areas. . . .'' (id.)). The facts,
unfortunately, have only grown stronger and the potential adverse
consequences of GHG to public health and the environment more dire in
the interim.\73 \The facts also demonstrate that the current methane
emissions from oil and natural gas production sources and natural gas
processing and transmission sources contribute substantially to
nationwide GHG emissions.
---------------------------------------------------------------------------

    \73 \ Nor does the EPA consider the cost of potential standards
of performance in making this finding. Like the endangerment finding
under section 202(a) at issue in State of Massachusetts v. EPA, 549
U.S. 497 (2007), the pertinent issue is a scientific inquiry as to
whether an endangerment to public health or welfare from the
relevant air pollution may reasonably be anticipated. Where, as
here, the scientific inquiry conducted by the EPA indicates that
these statutory criteria are met, the Administrator does not have
discretion to decline to make a positive endangerment finding to
serve other policy grounds. Id. at 532-35. In this regard, an
endangerment finding is analogous to setting national ambient air
quality standards under CAA section 109(b), which similarly call on
the Administrator to set standards that in her ``judgment'' are
``requisite to protect the public health''. The EPA is not permitted
to consider potential costs of implementation in setting these
standards. Whitman v. American Trucking Assn's, 531 U.S. 457, 466
(2001); see also Michigan v. EPA, U.S. (no. 14-46, June 29, 2015)
slip op. pp. 10-11 (reiterating Whitman holding). The EPA notes
further that section 111(b)(1) contains no terms such as ``necessary
and appropriate'' which could suggest (or, in some contexts,
require) that costs may be considered as part of the finding.
Compare CAA section 112(n)(1)(A); see State of Michigan, slip op.
pp. 7-8. The EPA, of course, must consider costs in determining
whether a best system of emission reduction is adequately
demonstrated and so can form the basis for a section 111(b) standard
of performance, and the EPA has carefully considered costs here and
found them to be reasonable. See sections V and VI below. The EPA
also has found that the rule's quantifiable benefits exceed
regulatory costs under a range of assumptions were new capacity to
be built. See RIA. Accordingly, this endangerment finding would be
justified if (against our view) it is both required, and (again,
against our view) costs are to be considered as part of the finding.
---------------------------------------------------------------------------

    The EPA also reviewed comments presenting other scientific
information to determine whether that information has any meaningful
impact on our analysis and conclusions. For both the rational basis
analysis and for any endangerment finding, assuming for the sake of
argument that one would be necessary for this final rule, the EPA
focused on public health and welfare impacts within the United States,
as it did in the 2009 Endangerment Finding. The impacts in other world
regions strengthen the case because impacts in other world regions can
in turn adversely affect the United States and its citizens.\74\
---------------------------------------------------------------------------

    \74\ See 74 FR 66514 and 66535, December 15, 2009.
---------------------------------------------------------------------------

    Lastly, EPA identified technically feasible and cost effective
controls that can be applied nationally to reduce methane emissions
and, thus, GHG emissions, from the oil and natural gas source category.
    The EPA considered whether the costs (e.g., capital costs,
operating costs) are reasonable considering the emission reductions
achieved through application of the controls required. For a detailed
discussion on how we evaluated control costs and our cost analysis for
individual emission sources, please see the proposal and the final TSD
in the public docket.

V. Summary of Final Standards

    This section presents a summary of the specific standards we are
finalizing for various types of equipment and emission points. More
details of the rationale for these standards and requirements,
including alternative compliance options and exemptions to the
standards, are provided in sections VI, VII, and VIII of this preamble,
the TSD, and the RTC document in the public docket.

A. Control of GHG and VOC Emissions in the Oil and Natural Gas Source
Category--Overview

    In this action, the EPA is finalizing emission standards for GHG,
in the form of limitations on methane, and VOC

emissions, for certain new, modified and reconstructed emission sources
across the oil and natural gas source category at subpart OOOOa. For
some of these sources, there are VOC requirements currently in place
that were established in the 2012 NSPS, and we are now establishing GHG
limitations for those emission points. For others, for which there are
no current requirements, we are finalizing both GHG and VOC standards.
We are also finalizing improvements to enhance implementation of the
current standards at subpart OOOO. For the reasons explained in the
previous section, the EPA believes that GHG standards, in the form of
limitations on methane, are warranted, even for those already subject
to VOC standards under the 2012 NSPS. Further, as shown in the final
TSD, there are cost effective controls that achieve simultaneous
reductions of GHG and VOC emissions.
    Pursuant to CAA section 111(b), we are both amending subpart OOOO
and adding a new subpart, OOOOa. We are amending subpart OOOO, which
applies to facilities constructed, modified or reconstructed after
August 23, 2011, (i.e., the original proposal date of subpart OOOO) and
on or before September 18, 2015 (i.e., the proposal date of the new
subpart OOOOa), and is amended only to include the revisions reflecting
implementation improvements in response to issues raised in petitions
for reconsideration. We are adding subpart OOOOa, which will apply to
facilities constructed, modified or reconstructed after September 18,
2015, to include current VOC requirements already provided in subpart
OOOO (as updated) as well as new provisions for GHGs and VOCs across
the oil and natural gas source category as highlighted below in this
section.
    As the purpose of this action is to control and limit emissions of
GHG and VOC, EPA seeks to confirm that all regulatory standards are
met. Any owner or operator claiming technical infeasibility,
nonapplicability, or exemption from the regulation has the burden to
demonstrate the claim is reasonable based on the relevant information.
In any subsequent review of a technical infeasibility or
nonapplicability determination, or a claimed exemption, EPA will
independently assess the basis for the claim to ensure flaring is
limited and emissions are minimized, in compliance with the rule. Well-
designed rules ensure fairness among industry competitors and are
essential to the success of future enforcement efforts.

B. Centrifugal Compressors

    We are finalizing amendments to the 2012 NSPS, and adding new
requirements to establish both VOC and GHG standards (in the form of
limitations on methane emissions) for new, modified or reconstructed
wet seal centrifugal compressors located across the oil and natural gas
source category. Specifically, the final rule adds GHG standards to the
current VOC standards for wet seal centrifugal compressors, as well as
establishing GHG and VOC standards for those that are currently
unregulated, with one exception. We are not establishing requirements
for centrifugal compressors at well sites. As finalized, the standards
require a 95 percent reduction of the emissions from each wet seal
centrifugal compressor affected facility. The standard can be achieved
by capturing and routing the emissions, using a cover and closed vent
system, to a control device that achieves an emission reduction of 95
percent, or routing to a process.

C. Reciprocating Compressors

    We are finalizing amendments to the 2012 NSPS and adding new
requirements to establish both VOC and GHG standards (in the form of
limitations on methane emissions) for new, modified, or reconstructed
reciprocating compressors located across the oil and natural gas source
category. Specifically, the final rule adds GHG standards to the
current VOC standards for reciprocating compressors, as well as
establishing GHG and VOC standards for those that are currently
unregulated, with one exception. We are not establishing requirements
for reciprocating compressors at well sites. The standards, which are
operational standards, require either replacement of the rod packing
based on usage or routing of rod packing emissions to a process via a
closed vent system under negative pressure. The owner or operator of a
reciprocating compressor affected facility is required to monitor the
duration (in hours) that the compressor is operated, beginning on the
date of initial startup of the reciprocating compressor affected
facility. On or before 26,000 hours of operation, the owner or operator
is required to change the rod packing. Owners or operators can elect to
change the rod packing every 36 months in lieu of monitoring compressor
operating hours. As an alternative to rod packing replacement, owners
and operators may route the rod packing emissions to a process via a
closed vent system operated at negative pressure.

D. Pneumatic Controllers

    We are finalizing amendments to the 2012 NSPS and adding new
requirements to establish both VOC and GHG standards (in the form of
limitations on methane emissions) for new, modified, or reconstructed
pneumatic controllers located across the oil and natural gas source
category. Specifically, the final rule adds GHG standards to the
current VOC standards for pneumatic controllers and establishes GHG and
VOC standards for those that are currently unregulated. We are
finalizing GHG (in the form of limitations on methane emissions) and
VOC standards to control emissions by requiring use of low-bleed
controllers in place of high-bleed controllers (i.e., natural gas bleed
rate not to exceed 6 standard cubic feet per hour (scfh)) at all
locations within the source category except for natural gas processing
plants. For natural gas processing plants, we are finalizing standards
to control GHG and VOC emissions by requiring that pneumatic
controllers have a zero natural gas bleed rate (i.e., they are operated
by means other than natural gas, such as being driven by compressed
instrument air). These standards apply to each newly installed,
modified or reconstructed pneumatic controller (including replacement
of an existing controller). The finalized standards provide exemptions
for certain critical applications based on functional considerations.

E. Pneumatic Pumps

    We are finalizing standards for natural gas-driven diaphragm
pumps.\75\ The standards require that GHGs (in the form of limitations
on methane emissions) and VOC emissions from new, modified and
reconstructed natural gas-driven diaphragm pumps located at well sites
be reduced by 95 percent if either a control device or the ability to
route to a process is already available onsite, unless it is
technically infeasible at sites other than new developments (i.e.,
greenfield sites). In setting this requirement, the EPA recognizes that
there may not be a control device or process available onsite. Our
analysis shows that it is not cost-effective to require the owner or
operator of a pneumatic pump affected facility to install a new control
device or process onsite to capture emissions. If a control device or
ability to route to a process is not available onsite, the pneumatic
pump affected facility is not

subject to the emission reduction provisions of the final rule. In
other instances, there may be a control device available onsite, but it
may not be capable of achieving a 95 percent reduction. In those cases,
we are not requiring the owner or operator to install a new control
device onsite or to retrofit the existing control device, however, we
are requiring the owner or operator of a pneumatic pump affected
facility at a well site to route the emissions to an existing control
device even it if achieves a level of emissions reduction less than 95
percent. In those instances, the owner or operator must maintain
records demonstrating the percentage reduction that the control device
is designed to achieve. In this way, the final rule will achieve
emission reductions with regard to pneumatic pump affected facilities
even if the only available control device cannot achieve a 95 percent
reduction. For pneumatic pumps located at natural gas processing
plants, the standards require that GHG and VOC emissions from natural
gas-driven diaphragm pumps be zero.
---------------------------------------------------------------------------

    \75\ A lean glycol circulation pump that relies on energy
exchange with the rich glycol from the contactor is not considered a
diaphragm pump. For more details, please see section VI.
---------------------------------------------------------------------------

F. Well Completions

    We are finalizing GHG standards (in the form of limiting methane
emissions) for well completions of hydraulically fractured (or
refractured) gas wells as well as GHG and VOC standards for well
completions of hydraulically fractured (or refractured) oil wells. As
explained in the proposal preamble, the BSER for these emission
reductions are the same as the BSER for reducing VOC emissions from
hydraulically fractured gas wells. Therefore, the operational standards
finalized in this action are essentially the same as the VOC standards
for hydraulically fractured gas wells promulgated in the 2012 NSPS. For
the reason stated above, the well completion standards in this final
rule apply to both gas and oil well completions.
    As with gas wells, for well completions of hydraulically fractured
(or refractured) oil wells, we identified two subcategories of
hydraulically fractured wells for which well completions are conducted:
(1) Non-wildcat and non-delineation wells (subcategory 1 wells); and
(2) wildcat and delineation wells (subcategory 2 wells). A wildcat
well, also referred to as an exploratory well, is a well drilled
outside known fields or is the first well drilled in an oil or gas
field where no other oil and gas production exists. A delineation well
is a well drilled to determine the boundary of a field or producing
reservoir.
    We are finalizing operational standards for subcategory 1 wells
that require a combination of reduced emissions completion (REC) and
combustion. Compared to combustion alone, the combination of REC and
combustion will maximize gas recovery and minimize venting to the
atmosphere. The finalized standards for subcategory 2 wells require
combustion.
    For subcategory 1 wells, we define the flowback period of a well
completion as consisting of two distinct stages, the ``initial flowback
stage'' and the ``separation flowback stage.'' The initial flowback
stage begins with the onset of flowback and ends when the flowback is
routed to a separator. Routing of the flowback to a separator is
required as soon as a separator is able to function (i.e., the operator
must route the flowback to a separator unless it is technically
infeasible for a separator to function). Any gas in the flowback prior
to the point at which a separator begins functioning is not subject to
control. The point at which the separator can function marks the
beginning of the separation flowback stage. During this stage, the
operator must do the following, unless technically infeasible to do so
as discussed below: (1) Route all salable quality gas from the
separator to a gas flow line or collection system; (2) re-inject the
gas into the well or another well; (3) use the gas as an onsite fuel
source; or (4) use the gas for another useful purpose that a purchased
fuel or raw material would serve. If the operator assesses all four
options for use of recovered gas, and still finds it technically
infeasible to route the gas as described, the operator must route the
gas to a completion combustion device with a continuous pilot flame and
document the technical infeasibility assessment according to Sec.
60.5420a(c) of this final rule, which describes the specific types of
information required to document that the operator has exercised due
diligence in making the assessment. No direct venting of gas is allowed
during the separation flowback stage unless combustion creates a fire
or safety hazard or can damage tundra, permafrost or waterways. The
separation flowback stage ends when the well is shut in and the
flowback equipment is permanently disconnected from the well or on
startup of production. This also marks the end of the flowback period.
    The operator has a general duty to safely maximize resource
recovery and minimize releases to the atmosphere over the duration of
the flowback period. For subcategory 1 wells (except for low gas to oil
ratio (GOR) and low pressure wells discussed below), the operator is
required to have a separator onsite during the entirety of the flowback
period. The operator is also required to document the stages of the
completion operation by maintaining records of (1) the date and time of
the onset of flowback; (2) the date and time of each attempt to route
flowback to the separator; (3) the date and time of each occurrence in
which the operator reverted to the initial flowback stage; (4) the date
and time of well shut in; and (5) the date and time that temporary
flowback equipment is disconnected. In addition, the operator must
document the total duration of venting, combustion and flaring over the
flowback period. All flowback liquids during the initial flowback
period and the separation flowback period must be routed to a well
completion vessel, a storage vessel or a collection system. Because the
BSER for oil wells and gas wells are the same, the final rule applies
these requirements to both oil and gas wells.
    For subcategory 2 wells, we are finalizing an operational standard
that requires either (1) routing all flowback directly to a completion
combustion device with a continuous pilot flame (which can include a
pit flare) or, at the option of the operator, (2) routing the flowback
to a well completion vessel and sending the flowback to a separator as
soon as a separator will function and then directing the separated gas
to a completion combustion device with a continuous pilot flame. For
option 2, any gas in the flowback prior to the point when the separator
will function is not subject to control. In either case, combustion is
not required if combustion creates a fire or safety hazard or can
damage tundra, permafrost or waterways. Operators are required to
maintain the same records described above for category 1 wells.
    As with gas wells, we similarly recognize the limitation of ``low
pressure'' oil wells from conducting REC. Therefore, consistent with
the 2012 NSPS, low pressure wells are affected facilities and have the
same requirements as subcategory 2 wells (wildcat and delineation
wells). We have revised the definition of a ``low pressure'' well in
response to comment.
    Further, wells with a GOR of less than 300 scf of gas per stock
tank barrel of oil produced are affected facilities, but have no well
completion requirements, providing the owner or operator maintains
records of the low GOR certification and a claim signed by the
certifying official.
    We are also retaining the provision from the 2012 NSPS, now at
Sec.  60.5365a(a)(1), that a well that is refractured, and for which
the well completion operation is conducted

according to the requirements of Sec.  60.5375a(a)(1) through (4), is
not considered a modified well and, therefore, does not become an
affected facility for purposes of the well completion standards. We
point out that such an exclusion of a ``well'' from applicability under
the NSPS has no effect on the affected facility status of the ``well
site'' for purposes of the fugitive emissions standards at Sec.
60.5397a.

G. Fugitive Emissions From Well Sites and Compressor Stations

    We are finalizing standards to control GHGs (in the form of
limitations on methane emissions) and VOC emissions from fugitive
emission components at well sites and compressor stations.
Specifically, we are finalizing semiannual monitoring and repair of
fugitive emission components at well sites and quarterly monitoring and
repair at compressor stations. Monitoring of the components must be
conducted using optical gas imaging (OGI), and repairs must be made if
any visible emissions are observed. Method 21 may be used as an
alternative monitoring method at a repair threshold level at 500 parts
per million (ppm). Repairs must be made within 30 days of finding
fugitive emissions and a resurvey of the repaired component must be
made within 30 days of the repair using OGI or Method 21 at a repair
threshold of 500 ppm. A monitoring plan that covers the collection of
fugitive emissions components at well sites or compressor stations
within a company-defined area must be developed and implemented.

H. Equipment Leaks at Natural Gas Processing Plants

    We are finalizing standards to control GHGs (in the form of
limitations on methane emissions) from equipment leaks at new, modified
or reconstructed natural gas processing plants. These requirements are
the same as the VOCs equipment leak requirements in the 2012 NSPS and
require the level of control established in NSPS part 60, subpart VVa,
including a detection level of 500 ppm for certain pieces of equipment,
as in the 2012 NSPS. As with VOC reduction, we believe that subpart VVa
level of control reflects the best system of emission reductions for
reducing methane emissions.

I. Liquids Unloading Operations

    The EPA stated in the proposal that we did not have sufficient
information to propose a national standard for liquids unloading.\76\
However, the EPA requested comment on nationally applicable
technologies and techniques that reduce GHG and VOC emissions from
these events. Although the EPA received valuable information from the
public comment process, the information was not sufficient to finalize
a national standard representing BSER for liquids unloading.
---------------------------------------------------------------------------

    \76\ See 80 FR 56614 and 80 FR 56644, September 18, 2015.
---------------------------------------------------------------------------

    Specifically, we requested data and information on the level of GHG
and VOC emissions per unloading event, the number of unloading events
per year, and the number of wells that perform liquids unloading. In
addition, we requested comment on (1) characteristics of the well that
play a role in the frequency of liquids unloading events and the level
of emissions; (2) demonstrated techniques to reduce the emissions from
liquids unloading events, including the use of smart automation and the
effectiveness and cost of these techniques; (3) whether there are
demonstrated techniques that can be employed on new wells that will
reduce the emissions from liquids unloading events in the future; and
(4) whether emissions from liquids unloading can be captured and routed
to a control device and whether this has been demonstrated in practice.
    The EPA received some information pertaining to our request for
information. Specifically, the EPA received information on the
frequency of unloading and on techniques to reduce emissions through
capture or flaring and learned of some operators that have been able to
achieve capture in practice. While we have gained better understanding
of the practice of liquids unloading, the EPA did not receive the
necessary information to identify an emission reduction technology that
can be applied across the category of sources. We also considered the
possibility of subcategorization. However, according to the information
received, the differences in liquids unloading events (with respect to
both frequency and emission level) are not due to differences in well
size or type of wells at which liquids unloading is performed, but
rather the specific conditions of a given well at the time the operator
determines that well production is impaired such that unloading must be
done. Operators select the technique to perform liquids unloading
operations based on the conditions of the well each time production is
impaired. Because well conditions change over time, each iteration of
unloading may require repeating a single technique or attempting a
different technique that may not have been appropriate under prior
conditions. Given the differences in conditions at different wells when
liquids unloading must be performed, the EPA did not receive
information about techniques, individually or as a group, that helped
us to identify a BSER under our CAA section 111(b) authority. The EPA
continues to search for better means to address emissions associated
with liquids unloading and is including this emissions source in the
upcoming information gathering effort.\77\ Please refer to the RTC for
additional discussion on liquids unloading.\78\
---------------------------------------------------------------------------

    \77\ See section III.E of this preamble for a discussion of the
upcoming information gathering effort.
    \78\ See RTC document in EPA Docket ID No. EPA-HQ-OAR-2010-0505.
---------------------------------------------------------------------------

J. Recordkeeping and Reporting

    We are finalizing recordkeeping and reporting requirements that are
consistent with those in the current NSPS. The final rule requires
owners or operators to submit initial notifications and annual reports,
in addition to retaining records to assist in documenting that they are
complying with the provisions of the NSPS.
    For new, modified, or reconstructed pneumatic controllers, owners
and operators are not required to submit an initial notification for
each piece of equipment; rather, they must report the installation of
these affected facilities in their first annual report following the
compliance period during which they were installed. Owners or operators
of well affected facilities (consistent with current requirements for
gas well affected facilities) are required to submit an initial
notification no later than two days prior to the commencement of each
well completion operation. This notification must include contact
information for the owner or operator, the United States Well Number
(formerly the American Petroleum Institute (API) well number), the
latitude and longitude coordinates for each well, and the planned date
of the beginning of flowback.
    In addition, initial annual reports are due no later than 90 days
after the end of the initial compliance period, which is established in
the rule. Subsequent annual reports are due no later than the same date
each year as the initial annual report. The annual reports include
information on all affected facilities that were constructed, modified
or reconstructed during the previous year. A single report may be
submitted covering multiple affected facilities,

provided that the report contains all the information required by Sec.
60.5420a(b). This information includes general information on the
company (e.g., company name), as well as information specific to
individual affected facilities, such as the well ID associated with the
affected facility (e.g., storage vessels) and the facility site name
(e.g., ``Compressor Station XYZ'' or ``Tank Battery 123'') and the
address of the affected facility.
    For well affected facilities, the information required in the
annual report includes the location of the well, the United States well
number, the date and time of the onset of flowback following hydraulic
fracturing or refracturing, the date and time of each attempt to direct
flowback to a separator, the date and time of each occurrence of
returning to the initial flowback stage, and the date and time that the
well was shut in and the flowback equipment was permanently
disconnected or the startup of production, the duration of flowback,
the duration of recovery to the flow line, duration of the recovery of
gas for another useful purpose, duration of combustion, duration of
venting, and specific reasons for venting in lieu of capture or
combustion. For each well for which a technical infeasibility exemption
is claimed, to route the recovered gas to any of the four options
specified in Sec.  60.5375a(a)(1)(ii), the report includes the reasons
for the claim of technical infeasibility with respect to all four
options provided in that subparagraph.
    For each well for which an exemption is claimed the owner or
operator must maintain records of the low GOR certification and submit
a claim signed by the certifying official in the annual report. For
each well for which an exemption is claimed for conditions in which
combustion may result in a fire hazard or explosion, or where high heat
emissions from a completion combustion device may negatively impact
tundra, permafrost or waterways, the report should include the location
of the well, the United States Well Number, the specific exception
claimed, the starting date and ending date for the period the well
operated under the exception, and an explanation of why the well meets
the claimed exception. The annual report must also include records of
deviations where well completions were not conducted according to the
applicable standards.
    For centrifugal compressor affected facilities, information in the
annual report must include an identification of each centrifugal
compressor using a wet seal system constructed, modified or
reconstructed during the reporting period, as well as records of
deviations in cases where the centrifugal compressor was not operated
in compliance with the applicable standards.
    For reciprocating compressors, information in the annual report
must include the cumulative number of hours of operation or the number
of months since initial startup or the previous reciprocating
compressor rod packing replacement, whichever is later, or a statement
that emissions from the rod packing are being routed to a process
through a closed vent system under negative pressure.
    Information in the annual report for pneumatic controller affected
facilities includes location and documentation of manufacturer
specifications of the natural gas bleed rate of each pneumatic
controller installed during the reporting period. For pneumatic
controllers for which the owner is claiming an exemption from the
standards, the annual report includes documentation that the use of a
pneumatic controller with a natural gas bleed rate greater than 6 scfh
is required and the reasons why. The annual report also includes
records of deviations from the applicable standards.
    For pneumatic pump affected facilities, information in the annual
report includes an identification of each pneumatic pump constructed,
modified or reconstructed during the compliance period; if applicable,
a certification that no control was available onsite and that there is
no ability to route to a process; an identification of any sites that
contain pneumatic pumps and installed a control device during the
reporting period, where there was previously no control device or
ability to route to a process at a site; and records of deviations in
cases where the pneumatic pump was not operated in compliance with the
applicable standards.
    The final rule includes new requirements for monitoring and
repairing sources of fugitive emissions at well sites and compressor
stations. An owner or operator must submit an annual report, which
covers the collection of fugitive emissions components at well sites
and compressor stations within an area defined by the company. The
report must include the date and time of the surveys completed during
the reporting year, the name of the operator performing the survey; the
ambient temperature, sky conditions, and maximum wind during the
survey; the type of monitoring instrument used; the number and type of
components that were found to have fugitive emissions; the number and
type of components that were not repaired during the monitoring survey;
the number and type of difficult-to-monitor and unsafe-to-monitor
components that were monitored; the date of the successful repair of
the fugitive emissions component if it was not repaired during the
survey; the number and type of fugitive emission components that were
placed on delay of repair and the explanation of why the component
could not be repaired and was placed on delay of repair; and the type
of monitoring instrument used to resurvey a repaired component that
could not be repaired during the initial monitoring survey. If an owner
or operator chooses to use Method 21 to conduct the monitoring survey,
they are required to keep records that include the type of monitoring
instrument used and the fugitive emissions component identification.
The owner or operator is required to keep a log for each affected
facility. The log must include the date the monitoring survey was
performed, the technology used to perform the survey, the number and
types of equipment found to have fugitive emissions, a digital
photograph or video of the monitoring survey when an OGI instrument is
used to perform the monitoring survey, the date or dates of first
attempt to repair the source of fugitive emissions, the date of repair
of each source of fugitive emissions that could not be repaired during
the initial monitoring survey, any source of fugitive emissions found
to be technically infeasible or unsafe to repair and an explanation of
why the component was placed on delay of repair, a list of the fugitive
emissions components that were tagged as a result of not being repaired
during the initial monitoring survey, and a digital photograph or video
of each untagged fugitive emissions component that could not be
repaired during the monitoring survey when the fugitive emissions were
initially found. These digital photographs and logs must be available
at the affected facility or the field office.
    Consistent with the current requirements of subpart OOOO, records
must be retained for 5 years and generally consist of the same
information required in the initial notification and annual reports.
The records may be maintained either onsite or at the nearest field
office.

K. Reconsideration Issues Being Addressed

    The EPA is finalizing numerous items in subpart OOOO on which we
granted reconsideration and proposed changes with some further
adjustments as a

result of public comment. To the extent that these items relate to
subpart OOOOa, we are also finalizing the same provisions for purposes
of consistency between the two rules. First, we are finalizing
corrections to the storage vessel control device monitoring and testing
provisions related to in-field performance testing of enclosed
combustors, initial and ongoing performance testing for any enclosed
combustors used to comply with the emissions standard for an affected
facility, and consistent requirements for monitoring of visible
emissions for all enclosed combustion units. We are also finalizing
clarified applicability requirements for storage vessel affected
facilities. Next, we are finalizing amendments to include initial
compliance requirements for bypass devices and certain closed vent
systems and provide an alternative in subpart OOOO. Specifically, the
rule allows for either an alarm at the bypass device or a remote alarm.
The EPA is not finalizing our proposal to require both forms of alarm
under subpart OOOO to avoid retroactive requirements.
    Additionally, the EPA is finalizing recordkeeping requirements for
repair logs for control devices failing a visible emissions test. We
are clarifying the due date for the initial annual report and
finalizing that flares used to comply with subpart OOOO are subject to
the design and operation requirements in the general provisions. Next,
we clarify that the monitoring provisions of subpart VVa applicable to
affected units of subpart OOOO do not extend to open-ended valves or
lines. We are finalizing clarification to the initial compliance
requirement specifically to identify that the 2012 rule already
includes a provision similar to subpart KKK. The EPA is finalizing the
exemption from the notification required for reconstruction to affected
facility pneumatic controllers, centrifugal compressors, and storage
vessels in subpart OOOOa. The EPA is finalizing provisions for
management of waste from spent carbon canisters. The EPA is finalizing
a definition of the term ``capital expenditure'' in subpart OOOO. The
EPA is finalizing an exemption for certain water recycling vessels that
EPA did not intend to be affected facility storage vessels under
subparts OOOO or OOOOa. By exempting such vessels, EPA will address a
disincentive for recycling of water for hydraulic fracturing. Lastly,
the EPA is not finalizing continuous control device monitoring
requirements for storage vessels and centrifugal compressor affected
facilities in subpart OOOO. For additional discussion of these issues,
please refer to section VI of this preamble and the RTC.

L. Technical Corrections and Clarifications

    We discovered 22 drafting errors in the proposal and have corrected
these errors in the final rule. Please see section VI for a complete
list of technical corrections and clarifications.

M. Prevention of Significant Deterioration and Title V Permitting

    In the proposed rule, we stated that the pollutant we were
proposing to regulate was GHGs, not methane as a separately regulated
pollutant. 80 FR 56593, 56600-01 (Sept. 18, 2015). As explained in
section VII of this preamble, we are adding provisions to the final
rule, analogous to what was included in Standards of Performance for
Greenhouse Gas Emissions from New, Modified, and Reconstructed
Stationary Sources: Electric Utility Generating Units, 80 FR 64509
(Oct. 23 2015), to make clear in the regulatory text that the pollutant
regulated by this rule is GHGs.

N. Final Standards Reflecting Next Generation Compliance and Rule
Effectiveness

    In making decisions on the final requirements for this rule, we
have emphasized the value of requirements that reflect principles of
Next Generation Compliance and Rule Effectiveness. EPA's Next
Generation Compliance strategy includes designing rules that promote
improved compliance and better environmental outcomes. Specifically, we
are finalizing standards with the following Next Generation Compliance
strategies: (1) Electronic reporting via the EPA's Central Data
Exchange (CDX), (2) clear applicability criteria (e.g., modification
criteria), (3) incentives for intrinsically lower emitting equipment
(e.g., solar pumps at gas plants are not affected facilities), (4) OGI
technology for monitoring fugitive emissions, (5) digital picture
reporting as an alternative for well completions (``REC PIX'') and
manufacturer installed control devices, (6) qualified professional
engineer certification of technical infeasibility to connect a
pneumatic pump to an existing control device, and (7) qualified
professional engineer certification of closed vent system design. These
requirements, or options for compliance, provide opportunities for
owners and operators to reduce obligations by making particular
choices, reduce the burden for both the regulated industry and the
agencies providing oversight, and provide greater transparency for all
parties, including the public.

VI. Significant Changes Since Proposal

    This section identifies significant changes in this rule from the
proposed rule. These changes reflect the EPA's consideration of over
900,000 comments submitted on the proposal and other information
received since the proposal, while preserving the aims underlying the
proposal. The final rule protects human health and the environment by
improving the existing NSPS and adding emission reduction standards for
additional significant sources of GHGs and VOCs, consistent with the
CAA. The EPA sought to achieve this important goal by endeavoring,
where possible, to consistently expand the 2012 NSPS requirements
across the oil and natural gas sector while also accounting for the
unique characteristics of each type of source in setting emission
reduction requirements. In this section, we discuss the significant
changes since proposal by source category and the broad background for
those changes. More specific information regarding comments and our
responses appears in section VIII and in materials available in the
docket.

A. Centrifugal Compressors

    For centrifugal compressors, comments and information available led
us to finalize the standards as proposed. In the proposed rule, we
proposed to require 95 percent reduction of emissions from each
centrifugal compressor affected facility. The standard can be achieved
by capturing and routing the emissions using a cover and closed vent
system to a control device (i.e., combustion control device) that
achieves an emission reduction of 95 percent, or by routing the
captured emissions to a process. For additional details, please refer
to section VIII, the TSD, and the RTC supporting documentation in the
public docket.

B. Reciprocating Compressors

    For the reciprocating compressors requirements, we are finalizing
the standards as proposed, except with a slight modification to the
definition of reciprocating compressor rod packing. In the proposed
rule, we proposed to require replacement of rod packing on or before
26,000 hours or 3 years of operation, or alternatively to route
emissions via a closed vent system under negative pressure. To account
for segments of the industry in which reciprocating compressors operate
in a pressurized mode for a fraction of the

calendar year, the standard is based on the determination that 26,000
hours of operation are comparable to 3 years of continuous operation.
    In the final rule, we revised the definition of reciprocating
compressor rod packing. The EPA received comment that the definition of
rod packing should be included in the rule to clarify the intent to
replace any component of the rod packing that was contributing to
emissions from the rod packing assembly. Because we agree that this
clarification is useful, we have revised the definition of
reciprocating compressor rod packing in the final rule to mean a series
of flexible rings in machined metal cups that fit around the
reciprocating compressor piston rod to create a seal limiting the
amount of compressed natural gas that escapes from the compressor, or
any other mechanism that provides the same function of limiting the
amount of compressed natural gas that escapes from the compressor. For
additional details, please refer to section VIII, the TSD, and the RTC
supporting documentation in the public docket.

C. Pneumatic Controllers

    For pneumatic controllers, comments and information available led
us to finalize the standards as proposed. We proposed to require the
use of low-bleed controllers in place of high-bleed controllers (i.e.,
natural gas bleed rate not to exceed 6 scfh) \79\ at all locations
within the source category, except for natural gas processing plants.
For natural gas processing plants, the standards require control of GHG
and VOC emissions by requiring that pneumatic controllers have a zero
natural gas bleed rate (i.e., they are operated by means other than
natural gas, such as being driven by compressed instrument air).
---------------------------------------------------------------------------

    \79\ Low-bleed controllers are not affected facilities under
this final rule.
---------------------------------------------------------------------------

    The final rule provides that certain pneumatic controllers,
reflecting the particular functions they perform, have only tagging and
recordkeeping and reporting requirements. As discussed in the proposal,
the EPA identified situations where high-bleed controllers (i.e.,
controllers with a natural gas bleed rate greater than 6 scfh) are
necessary because of functional requirements, such as positive
actuation or rapid actuation. An example would be controllers used on
large emergency shutdown valves on pipelines entering or exiting
compressor stations. The 2012 NSPS accounts for this by providing an
exemption to pneumatic controllers for which compliance would pose a
functional limitation due to their actuation response time or other
operating characteristics. The EPA is finalizing the same exemption for
all pneumatic controllers across the source category. For additional
details, please refer to section VIII, the TSD, and the RTC supporting
documentation in the public docket.

D. Pneumatic Pumps

    In the final rule, the EPA is finalizing requirements for pneumatic
pumps that use control devices or processes that are already available
onsite. At natural gas processing plants, the EPA proposed to require
reductions of 100 percent of GHG (in the form of methane) and VOC
emissions from all diaphragm pneumatic pumps. For locations other than
natural gas processing plants, the EPA proposed to require reductions
of 95 percent of GHG (in the form of methane) and VOC emissions from
all natural gas-driven diaphragm pumps, if an existing control or
process was available.
    The public comment process helped us to identify aspects of the
proposed requirements that may not be practical or feasible in all
cases, and commenters submitted additional information for us to
analyze. In this final rule, based on our consideration of the comments
received and other relevant information, we have made certain changes
to the proposed standards for pneumatic pumps. The final standards
require the GHG (in the form of a limitation on methane) and VOC
emissions from new, modified, or reconstructed natural gas-driven
diaphragm pumps located at well sites to be routed to an available
control device or process onsite, unless such routing is technically
infeasible at non-greenfield sites. We are not finalizing a technical
infeasibility exemption at greenfield sites, where circumstances that
could otherwise make control of a pneumatic pump technically infeasible
at an existing location can be addressed in the site's design and
construction. For pneumatic pumps located at a natural gas processing
plant, the final rule requires the GHG (in the form of a limitation on
methane) and VOC emissions from natural gas-driven diaphragm pumps to
be zero.
    While we acknowledge that solar-powered, electrically-powered, and
air-driven pumps cannot be employed in all applications, we encourage
operators to use pumps other than natural gas-driven pneumatic pumps
where their use is technically feasible. To incentivize the use of
these alternatives, the final rule's definition of ``pneumatic pump
affected facility'' described in Sec.  60.5365a(h) only includes
natural gas-driven pumps. Pumps that are driven by means other than
natural gas are not affected facilities subject to the pneumatic pump
provisions of the NSPS and are not subject to any requirements under
the final rule.
    Provided below are the significant changes since proposal that
result from the information in the record and the comments that we
received and our rationale for these changes. For additional details,
please refer to section VIII, the TSD, and the RTC supporting
documentation in the public docket.
1. Piston Pumps
    The EPA received several comments concerning the level of GHG and
VOC emissions from natural gas-driven pneumatic piston pumps. The
comments focused on the small volume of gas discharged by these pumps
and the intermittent nature of their use. Other commenters suggested
that the EPA treat pneumatic pumps consistently with pneumatic
controllers. The commenters state that the same bleed rate
considerations should be applied to pneumatic pumps because they are
similar devices. Other commenters discussed the technical infeasibility
of controlling emissions from piston pumps due to the inability to move
such a small and intermittent gas flow through a duct or pipe to a
control device.
    We agree with commenters that pneumatic controller bleed rate
considerations can serve as a useful guide in considering emission
reduction requirements for pneumatic pumps. In response to these
comments, we further evaluated the natural gas flow rate of pneumatic
pumps and agree that piston pumps are inherently low-emitting because
of their small size, design, and usage patterns. As discussed in the
TSD to the proposed rule, we used natural gas emission rates between
2.2 to 2.5 scf/hr during operation of piston pumps. We determined these
emission rates based on a joint report from the EPA and the Gas
Research Institute on methane emissions from the natural gas industry.
Our analysis of the currently available data, the information in the
record, and consideration of public comments lead us to the conclusion
that we should exclude piston pumps from coverage under the NSPS based
on their inherently low emission rates. This approach is consistent
with the manner in which we addressed low-bleed pneumatic controllers.
After considering the inherently low emission rates of low-bleed
pneumatic controllers, we determined that they should not be subject to
the final rule requirements. Similarly, based upon the information

that we have on the low emission rates of piston pumps, we are not
establishing requirements for them in this final rule.
    We note that our best available emissions data for diaphragm pumps,
as discussed in the TSD, indicates that the emission rate ranges from
about 20 to 22 scf/hr during operation of a diaphragm pump. Based on
our analysis of this data, we do not believe exclusion of diaphragm
pumps from the definition of a pneumatic pump affected facility is
warranted. As a result, we are retaining requirements for diaphragm
pumps in the final rule.
2. Pneumatic Pumps Located in the Gathering and Boosting and
Transmission and Storage Segments
    We received comment that pneumatic pumps located in the
transmission and storage segment generally have very low emissions.
Similar to the arguments presented above for piston pumps, commenters
contend that these low emission rate pumps should not be subjected to
the final rule. In response to these comments, we reviewed our
available information used in the proposed rule TSD to estimate the
number of pneumatic pumps and the emission rates of these pumps in all
segments of the oil and natural gas sector. In the TSD for the final
rule, we noted that neither the GHGRP nor the GHG Inventory include
data about pneumatic pumps or their emission rates in the natural gas
transmission and storage segment. Because we currently have no reliable
source of information indicating the prevalence of use of pneumatic
pumps in this segment, nor what their emission rates would be if they
are used, we are not finalizing pneumatic pump requirements for the
transmission and storage segment at this time.
    We also reviewed the available GHGRP and GHG Inventory data for
pneumatic pumps, which was limited to the production segment. We
consider the production segment to include both well sites and the
gathering and boosting segment. Our available data indicate that
pneumatic pumps are used at well sites as well as emission data for
those pumps, but are silent on the prevalence of use of pneumatic pumps
in the gathering and boosting segment, and what their emission rates
would be if they are used. As with pneumatic pumps in the transmission
and storage segment, we are not finalizing pneumatic pump requirements
for the gathering and boosting segments at this time because of the
lack of information in the record to support finalizing requirements
for these pumps.
    We note that the EPA is currently conducting a formal process to
gather additional data on existing sources in the oil and natural gas
sector. We believe that this data collection effort will provide
additional information on the use and emissions of pneumatic pumps in
the transmission and storage segment and gathering and boosting
segment. Once we have obtained and analyzed these data, we will be
better equipped to determine whether regulation of pneumatic pumps in
the transmission and storage segment and gathering and boosting segment
is warranted. See section III.E for more detail regarding the EPA's
information collection request for existing sources.
3. Technical Infeasibility
    We agree with comments that there may be circumstances, such as
insufficient pressure or control device capacity, where it is
technically infeasible to capture and route pneumatic pump emissions to
a control device or process, and we have made changes in the final rule
to include an exemption for these instances. The owner or operator must
maintain records of an engineering evaluation and certification
providing the basis for the determination that it is technically
infeasible to meet the rule requirements. The rule does not allow the
operator to claim the technical infeasibility exemption for a pneumatic
pump affected facility at a greenfield site (defined as a site, other
than a natural gas processing plant, which is entirely new
construction), where circumstances that could otherwise make control of
a pneumatic pump technically infeasible at an existing location can be
addressed in the site's design and construction.
4. Efficiency of Existing Control Devices
    As noted above, we are finalizing emission standards for new,
modified, and reconstructed natural gas-driven diaphragm pumps located
at well sites requiring emissions be reduced by 95 percent if either a
control device or the ability to route to a process is already
available onsite. In setting this requirement, the EPA recognizes that
there may not be a control device or process available onsite. Our
analysis shows that it is not cost-effective to require the owner or
operator of a pneumatic pump affected facility to install a new control
device or process onsite to capture emissions. In those instances, the
pneumatic pump affected facility is not subject to the emission
reduction provisions of the final rule.
    Commenters have also raised concerns, and we agree, that the
control device available onsite may not be able to achieve a 95 percent
emission reduction. We evaluated whether this requirement should only
be triggered when a NSPS subpart OOOO or OOOOa compliant control device
was onsite, which would alleviate the control efficiency concern raised
by commenters. However, the EPA is concerned that significant emissions
reductions would be lost as a result of limiting the required type of
equipment that must be used to control pneumatic pump emissions to only
those that are designed to achieve 95 percent emission reductions. We
are not requiring the owner or operator to install a new control device
on site that is capable of meeting a 95 percent reduction nor are we
requiring that the existing control device be retrofitted to enable it
to meet the 95 percent reduction requirement. However, we are requiring
that the owner or operator of a pneumatic pump affected facility at
well sites to route the emissions to an existing control device even if
it achieves a level of emissions reduction less than 95 percent. In
those instances, the owner or operator must maintain records
demonstrating the percentage reduction that the control device is
designed to achieve. In this way, the final rule will achieve emission
reductions with regard to pneumatic pump affected facilities even if
the only available control device on site cannot achieve a 95 percent
reduction.
5. Compliance Requirements
    In response to concerns about applicability of subpart OOOO or
OOOOa compliance requirements, the EPA has clarified our intent in the
final rule that existing control devices that are not already subject
to subparts OOOO or OOOOa compliance requirements (i.e., control
devices that are subject to other federal or state compliance
requirements) are not subject to the performance specifications,
performance testing, and monitoring requirements in this rule solely
because they are controlling pneumatic pump emissions. We believe that
control devices covered by other federal, state, or other regulations
would be subject to compliance requirements under those provisions and,
therefore, we have reasonable assurance that the devices will perform
adequately, and we do not need to include existing controls that are
not already covered by subparts OOOO and OOOOa under the compliance
requirements for these subparts.
6. Cost Analysis
    In response to commenters' concerns that the costs were
underestimated for compliance with the pneumatic pump

requirements, we revised the cost analysis using the average of our
annualized costs and two additional annualized cost estimates provided
by commenters.\80\ Commenters' cost estimate methodologies and inputs
varied from EPA's cost estimate which prevented us from conducting a
side-by-side comparison with our cost estimate, nor could we directly
compare the commenters' estimates with one another. However, in order
to take into account the cost estimates provided by the commenters, we
revised our cost analysis using the average of our annualized costs and
the two additional annualized cost estimates provided by commenters.
This is the same approach we would have taken had we obtained cost
quotes from three separate vendors to install the closed vent system,
and which we believe is the most equitable procedure when there is
insufficient information to distinguish between the three cost
estimates. One commenter gave an estimated capital cost of $5,800 which
is annualized to be $826. A second commenter gave an estimated capital
cost of $8,500 which annualized to be $1,210. The proposed capital cost
to route emissions through a closed vent system was $2,000 which when
annualized is $285. Based on our revised cost analysis, the capital
cost for routing the emissions to an existing control device or process
is $5,433, and the annualized cost is $774. We more fully discuss our
cost estimate analysis in the TSD.
---------------------------------------------------------------------------

    \80\ See EPA docket ID No. EPA-HQ-OAR-2010-0505.
---------------------------------------------------------------------------

    We evaluated the cost of control for routing emissions to an
existing combustion device or process where we assign the cost equally
to methane and VOC. For diaphragm pumps at well sites, the cost of
reducing methane emissions is $235 per ton and the cost of reducing VOC
emissions is $847 per ton, using the single-pollutant approach. Based
on this revised cost analysis using additional cost information, we
find that the cost of control for reducing methane emissions remains
reasonable.
7. Affected Facility Definition
    The EPA received comment that there was contradictory language in
the proposal preamble and regulatory text regarding recordkeeping
requirements for pneumatic pumps where no control device was on site.
This lack of clarity was the result of the affected facility definition
for pneumatic pumps. In the final rule, we have revised the definition
to clarify that coverage under this rule is independent of availability
of a control device on site. Specifically, all natural gas-driven
diaphragm pumps at natural gas processing plants or well sites are
affected facilities, except for pumps at well sites that operate less
than 90 days per calendar year. The EPA has revised the final
regulatory text to make clear that all pneumatic pumps affected
facilities must be reported on the annual report and records maintained
as applicable to control status of the pump.
8. Timing of Initial Compliance
    The EPA is also finalizing requirements for pneumatic pump affected
facilities at natural gas processing plants. The EPA is finalizing GHG
and VOC emissions control requirements for pneumatic pump affected
facilities at well sites if there is a control device or ability to
route to a process available on site or subsequently installed on site.
We are also finalizing a technical infeasibility exception when it is
infeasible to route the pneumatic pump to the control device (or route
to a process) at non-greenfield sites. An owner or operator applying
this exemption must obtain a professional engineering assessment
demonstrating the reasons for the exemption.
    As pointed out by commenters, the technical infeasibility exemption
may be based on safety concerns that could arise when a control device
is not designed to handle the additional stream from the pneumatic
pump. Commenters also expressed concern about safety issues related to
increased pressure on the rest of the closed vent system connected to
the control device. In light of these comments, we believe that the
proposed 60-day compliance period may be insufficient to identify a
qualified professional engineer, obtain the necessary design documents
for the existing control device and associated ductwork, evaluate the
design documents in light of the increased flow from the pneumatic
pump, make an assessment of the technical feasibility of routing the
pneumatic pump to the control device, and issue the required
certification. Therefore, we are finalizing the compliance period to
begin on November 30, 2016 to allow sufficient time for these necessary
tasks to be completed.

E. Well Completions

    For the well completion requirements, we proposed to require RECs,
when technically feasible and in combination with a completion
combustion device, for subcategory 1 wells. For subcategory 2 wells, we
proposed an operational standard that would require minimization of
venting of gas and hydrocarbon vapors during the completion operation
through the use of a completion combustion device, with provisions for
venting in lieu of combustion for situations in which combustion would
present safety hazards. The proposed rule identified challenging issues
for which we solicited comment in order to obtain additional
information.
    The public comment process helped us to identify aspects of the
proposed requirements that in practice may not be practical in all
cases, and commenters submitted additional information for us to
analyze. In this final rule, based on our consideration of the comments
received and other relevant information, we have made certain changes
to the proposed standards for well completions. The final rule refines
the well completion requirements to reduce emissions and provide
clarity for both operators and regulators. The EPA is finalizing well
completion standards for hydraulically fractured or refractured
wells.\81\ The final standards require a combination of REC and
combustion at subcategory 1 wells and combustion at subcategory 2 wells
and low pressure wells. Provided below are the significant changes
since proposal that result from the comments we received and our
rationale for these changes. For additional details, please refer to
section VIII, the TSD, and the RTC supporting documentation in the
public docket.
---------------------------------------------------------------------------

    \81\ As noted earlier in section IV, in 2012 EPA promulgated VOC
standards for completions of hydraulically fractured or refractured
gas wells. Today's action establishes GHG standards for gas well
completions, as well as GHG and VOC standards for hydraulically
fractured and refractured oil well completions.
---------------------------------------------------------------------------

1. Separator Function
    The EPA solicited comment on the use of a separator during flowback
and whether a separator can be employed for every well completion. We
received several comments identifying situations where a separator
cannot function. Specifically, commenters noted instances where a
separator cannot function due to very low gas flow from the well,
contaminated gas flow, or low reservoir pressure requiring artificial
lift techniques. Commenters indicate that because of these scenarios
there can be a complete absence of a separation flowback stage during
the well completion (which, according to the commenters, can be
particularly common in some basins and fields). Commenters asserted
that many of these circumstances can be anticipated prior to the onset
of flowback. Furthermore, commenters stated that the requirement to
have a separator onsite would likely

cause the operator to incur a cost with no environmental benefit
derived.
    We believe that commenters have presented legitimate situations
where it would be technically infeasible to use a separator, which is
required for performing a REC. The challenge is, however, that the
factors that lead to technical infeasibility of a separator to function
may not be apparent until the time the well completion occurs, at which
time it is too late to provide the equipment and, as a result, the well
completion will go forward without controls. Further, the commenters
did not provide data, and we do not have sufficient data to
consistently and accurately identify the subcategory or types of wells
for which these circumstances occur regularly or what criteria would be
used as the basis for an exemption to the REC requirement such that a
separator would not be required to be onsite for these specific well
completions. In order to accommodate these concerns raised by
commenters, the final rule requires a separator to be onsite during the
entire flowback period for subcategory 1 wells (i.e., non-exploratory
or non-delineation wells, also known as development wells), but does
not require performance of REC where a separator cannot function. 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. For the reason stated above, we do not believe that
requiring a separator onsite would incur cost with no environmental
benefit.
    However, unlike subcategory 1 wells, subcategory 2 wells are in
areas where gas composition is likely unknown and, therefore, there is
less certainty that a separator can work at these wells. If the
separator does not work, there are unlikely subcategory 1 wells nearby
that can put the separator to use. For the reasons stated above, we are
not requiring that a separator be onsite for the well completion of
subcategory 2 wells.
    The EPA had proposed that, for subcategory 2 wells and low pressure
wells, operators would be required to route flowback to a completion
combustion device as soon as the separator was able to function. We had
based the proposed requirement for these wells on our determination
that BSER was combustion, and efficient combustion using traditional
combustion devices could be achieved through separation of the gas from
the liquid and solid flowback materials prior to routing to the
completion combustion device.
    As discussed in the 2015 proposal, traditional combustion devices
(e.g., flares or enclosed combustors) cannot work initially because the
flowback following hydraulic fracturing consists for liquids, gases and
sand in high-volume, multiphase slug flow. As a result, these devices
can work only after a separator can function. While pit flares can be
installed and used from the start, considering the makeup of the
initial flowback, we believe there is little gas to be burned, and so
we assume there is not an appreciable difference between the amount of
emissions reductions between a traditional combustion device and a pit
flare. In addition, we believe that pit flares have increased potential
for secondary impacts compared to traditional flares, due to the
potential for the incomplete combustion of natural gas across the pit
flare plume.
    Although not required, some owners and operators may choose to
separate the gas from the other flowback materials for water management
or other purposes. If a separator is used, any separated gas can be
routed to combustion. In light of all of the above, we are providing in
the final rule two options for completions of subcategory 2 wells: (1)
Route all flowback directly to a completion combustion device (in that
case a pit flare); or (2) should an owner or operator choose to use a
separator, route the separated gas to a completion combustion device as
soon as a separator is able to operate.
    We are providing the same two options for low pressure wells. We
believe that wells cannot perform a REC if there is not sufficient well
pressure or gas content during the well completion to operate the
surface equipment required for a REC, and low pressure gas could
prevent proper operation of the separator. Alternatively, when
feasible, some owners and operators may choose to separate the gas from
the other flowback materials for water management or other purposes. If
a separator is used, any separated gas must be routed to combustion.
2. REC Feasibility
    The second instance for potential technical infeasibility occurs
during the separation flowback stage, where operators cannot perform a
REC and, therefore, must combust. The EPA received comment that
additional requirements are necessary to ensure that flaring of the
recovered gas during the separation flowback stage is limited to
scenarios where all options included in our definition for REC--(1)
route the recovered gas from the separator into a gas flow line or
collection system, (2) re-inject the recovered gas into the well or
another well, (3) use the recovered gas as an onsite fuel source, or
(4) use the recovered gas for another useful purpose that a purchased
fuel or raw material would serve--have been pursued and their technical
infeasibility documented.\82\ Commenters identified factors such as the
availability and capacity of gathering lines, right of way issues, the
quality of gas, and ownership issues that could impact the ability of
operators to capture and use gas. Commenters stated that the provision
for technical infeasibility for operators to use the recovered gas is
vague and runs counter to the improvements the EPA seeks to establish
within the oil and gas industry. Other commenters urged the EPA to
allow flaring only as a last resort by requiring advanced notification
and detailed documentation of the technical infeasibility of capturing
and using salable quality gas. Commenters further stated that flaring
should be very rarely necessary, as the EPA has identified four
separate options for using recovered gas. The commenter recommends that
EPA add additional notification and reporting requirements to ensure
that all four options have been pursued and their technical
infeasibility documented. The EPA agrees that the exemption from REC
due to technical infeasibility should be limited. However, as
illustrated by the comments received, the circumstances under which a
REC is technically infeasible are varied. It is, therefore, difficult
to provide one definition that can address all scenarios.
---------------------------------------------------------------------------

    \82\ This definition is the same as the definition for REC in
subpart OOOO which, in response to public comment, included options
in addition to routing to a gas line.
---------------------------------------------------------------------------

    The EPA considered, but declined to require, advanced notification
for the following reasons. Technical infeasibility can be an after-the-
fact occurrence (i.e., gas was contaminated and not of salable quality
or had characteristics prohibiting other beneficial use and, therefore,
the gas was combusted); therefore, advanced notification may not always
be possible. A case-by-case advance evaluation by a regulatory agency
is also not feasible considering the large number of completions, the
wide geographic dispersion of the completions and the remote location
of many well sites. For these reasons, we are not requiring prior
notification of the claim of the technical infeasibility exemption.
    Rather we have expanded recordkeeping requirements in the final

rule to include: (1) Detailed documentation of the reasons for the
claim of technical infeasibility with respect to all four options
provided in section 60.5375a(a)(1)(ii), including but not limited to,
names and locations of the nearest gathering line; capture, re-
injection, and reuse technologies considered; aspects of gas or
equipment prohibiting use of recovered gas as a fuel onsite; and (2)
technical considerations prohibiting any other beneficial use of
recovered gas onsite. We emphasize that the exemption is limited to
``technical'' infeasibility (e.g., lack of infrastructure, engineering
issues, safety concerns).
    In addition to the detailed documentation and recordkeeping
requirement, the final rule requires that a separator be onsite during
the entirety of the flowback period at subcategory 1 (developmental)
wells, as described earlier. We believe these additional provisions
will support a more diligent and transparent application of the intent
of the technical infeasibility exemption from the REC requirement in
the final rule. This information must be included in the annual report
made available to the public 30 days after submission through the
Compliance and Emissions Data Reporting Interface (CEDRI), allowing for
public review of best practices and periodic auditing to ensure flaring
is limited and emissions are minimized.
3. Gas to Oil Ratio (GOR) Exclusion
    We are not finalizing the proposed exclusion of wells with low GOR
from the definition of a well affected facility. However, in the final
rule, low GOR wells are not subject to REC or combustion requirements.
In order to ensure that low GOR claims are not being made without
sufficient analysis and oversight, the final rule requires that records
used to make the GOR determination must be retained and a certifying
official must sign the low GOR determination.
    The EPA proposed that wells with a GOR of less than 300 scf of gas
per barrel of oil produced would not be affected facilities subject to
the well completion provisions of the NSPS.\83\ The reason for the
proposed threshold GOR of 300 is that separators typically do not
operate at a GOR less than 300, which is based on industry experience
rather than a vetted technical specification for separator performance.
Though in theory any amount of free gas could be separated from the
liquid, in reality this is not practical given the design and operating
parameters of separation units operating in the field.
---------------------------------------------------------------------------

    \83\ On February 24, 2015, API submitted a comment to the EPA
stating that oil wells with GOR values less than 300 do not have
sufficient gas to operate a separator. http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2014-0831-0137.
---------------------------------------------------------------------------

    The EPA also solicited comment on how operators could identify low
GOR wells (i.e., those with a GOR of less than 300 scf of gas per stock
tank barrel of oil produced) prior to well completion, specifically the
question of whether the GOR of nearby wells would be a reliable
indicator in determining the GOR of a new or modified well. The EPA
received comment stating that wells in the same area or reservoir could
be used to indicate GOR prior to well completion. In light of the
comments received and, upon further consideration, the EPA concludes
that GOR of a well can be determined in advance. The EPA, therefore,
does not believe that it is appropriate to prescribe in the final rule
any specific way to determine the GOR for purposes of exempting low GOR
wells from performing REC or combustion. However, to ensure that only
those that, in fact, have GOR of less than 300 are exempt from the REC
or combustion requirement; these wells remain affected facilities under
the final rule. To ensure that their GORs are accurately determined,
the final rule requires detailed documentation of their GOR
determination as well as annual reporting and recordkeeping
requirements. However, they are not subject to the REC or combustion
requirement.
4. Low Pressure Wells
    We have revised the low pressure well definition in the final rule.
In the 2012 NSPS, the EPA recognized that certain wells, which the EPA
called ``low pressure gas wells,'' cannot implement a REC because of a
lack of necessary reservoir pressure to flow gas at rates appropriate
for the transportation of solids and liquids from a hydraulically
fractured gas well against additional back pressure that would be
caused by the REC equipment, thereby making a REC infeasible. The 2012
NSPS exempts these wells from REC and instead requires combustion of
the recovered gas.
    In the EPA's proposed rule (80 FR 56611, September 18, 2015), in
which we proposed to also regulate VOC and GHG emissions from oil
wells, we proposed to amend the current requirements for low pressure
gas wells to apply to all low pressure wells. We proposed to change the
term ``low pressure gas well'' to ``low pressure well'' but keep the
definition the same. The substance of the definition at proposal for
``low pressure well'' is the same as the currently codified definition
for ``low pressure gas well'' in the 2012 NSPS. We solicited comment on
whether this definition appropriately defined hydraulically fractured
wells for which conducting a REC would be technologically infeasible or
whether the definition should be revised to better characterize the
criteria for all low pressure wells.
    In our proposed definition, the pressure of the flowback fluid
(oil, gas, and water) immediately before it enters the flow line is
calculated by equation (1) below:

PL (psia) = 0.445 [middot] PR (psia) - 0.038 [middot] L(ft) + 67.578
Equation (1)

Where:

PL (psia) is the pressure of flowback fluid immediately before it
enters the flow line;
PR (psia) is the pressure of the reservoir containing oil, gas, and
water; and
L(ft) is the depth of the well.

    The EPA proposed that if the pressure of flowback fluid immediately
before it enters the flow line, PL, calculated using the above equation
is less than the available line pressure, the well would be considered
a low pressure well. Such a well would not be required to do a REC
during flowback (i.e., collect and send the associated gas to the flow
line). Instead, such a well would only be required to combust the gas
in a completion combustion device.
    Commenters asked the EPA to provide a new definition of ``low
pressure oil well'' to differentiate oil wells from gas wells. They
stated that the definition of ``low pressure well'' set out in proposed
section 60.5430a and taken from the definition of ``low pressure gas
well'' in subpart OOOO (section 60.5430) is not appropriate for a low
pressure oil well, because the surface and back pressure for oil wells
is higher than that for gas wells. They further state that ``. . . once
the hydraulic fracture load stops coming back, a gas well will
typically have much less liquids in the production tubing, making the
surface pressure actually higher for the gas well vs. an oil well. This
difference would be reflected in the 0.038 number which represents the
gas gradient in the well, which would impart a back pressure. For oil
wells this back pressure would be higher . . .'' In response to these
comments, the EPA modified the existing low pressure gas well equation
(equation (1) above) to add pressure drop resulting from flow of oil
and water in a well.
    The EPA's evaluation of the steady flow of petroleum fluid (gas and
oil) during flowback in wells resulted in the following modified
equation, hereafter

referred to as the low pressure well equation (equation 2 below):
[GRAPHIC] [TIFF OMITTED] TR03JN16.000

Where:

PL is the pressure of flowback fluid immediately before it enters
the flow line, expressed in psia;
PR is the pressure of the reservoir containing oil, gas, and water,
expressed in psia;
L is the true vertical depth of the well, expressed in feet;
qo, qg, qw are the flow rates of oil, gas, and water, respectively,
in the well, expressed in cubic feet/second; and
[rho]o is the density of oil in the well, expressed in pounds per
cubic feet.

    EPA's low pressure well equation is used to predict the pressure of
the flowback fluid (oil, gas, and water) immediately before it enters
the flow line. The low pressure well equation uses inputs similar to
those required for the gas well definition and for which information is
understood to be available before well completion activity starts at a
well site. These inputs include reservoir (or formation) pressure; true
vertical depth of the well; flow rates of oil, gas, and water in the
well; and the density of oil in the well.
    As oil-gas-water mixture flows upwards in a well to a lower
pressure location, oil and gas volumes change and some of the dissolved
gas evolves out of solution in oil. These phenomena result in oil and
gas densities and volumetric flows changing with well depth. Therefore,
oil density, [rho]o, and volumetric flow rate, qo, for use in equation
(2) are calculated using the known value of oil API gravity at a well
site and the widely used correlations provided in Vasquez and Beggs
(1980).\84\ The gas volumetric flow, qg, is calculated using widely
used correlations provided in Guo and Ghalambor (2005).\85\ Details on
using equation (2) to calculate the pressure of flowback fluid
immediately before it enters the flow line, PL, can be found in the TSD
in the public docket.
---------------------------------------------------------------------------

    \84\ Vasquez, M. and Beggs, H.D., ``Correlations for fluid
physical property prediction,'' JPT, 1980.
    \85\ Guo, B. and Ghalambor, A., ``Natural Gas Engineering
Handbook,'' Gulf Publishing Company, 2005.
---------------------------------------------------------------------------

    As noted above, equation (2) is the low pressure well equation for
all wells in the final rule. This equation predicts the pressure, PL,
of the flowback fluid (oil, gas, and water) immediately before it
enters the flow line during the separation flowback period. In response
to comments, the EPA's final regulations require that this pressure be
compared to the actual flow line pressure available at the well site.
Wells with insufficient predicted pressure to produce into the flow
line are required to combust the gas in a control device. Wells with
sufficient pressure to produce into the flow line are required to
capture the gas and produce it into the flow line.
    EPA further notes that equation (2) is a modification of equation
(1) and adds pressure drop resulting from flows of oil and water. When
characterizing a well with conditions of gas flow only (i.e.,
qo = qw = 0), equation (2) reduces to equation
(1), the equation for gas wells. Also note that equation (2) for line
pressure is derived using a vertical well. It is known that inclined
wells exist in the field, which will experience a somewhat higher
frictional drop due to longer flow length. Nonetheless, it is expected
that equation (2) would be able to account for minor increases in
pressure drop due to increased frictional drop at inclined wells
because the frictional pressure drop component contributes a small
amount to the total pressure drop (about 1 percent on average) and
conservative assumptions were used in deriving equation (2)--notably,
bottom hole pressure equals one-half of formation pressure.
    In addition to the revised low pressure well equation, we are
providing, in the final definition of low pressure well, other
characteristics of the well that would indicate that a well is a low
pressure well. We believe that if the static pressure (i.e., pressure
with the well shut in and not flowing) at the wellhead following
hydraulic fracturing, and prior to the onset of flowback, is less than
the flow line pressure at the sales meter, the well is a low pressure
well without having to demonstrate that it is such by using the low
pressure well equation in the final rule.
    Instead of using the equation, under the final rule, operators who
suspect that a well may be a low pressure well have the option, for
screening purposes, of performing a wellhead static pressure (i.e.,
pressure with the well shut in and not flowing) check following
fracturing and prior to the onset of flowback. If the static pressure
at the wellhead was less than the flow line pressure at the sales
meter, then the well would be a low pressure well. We believe that such
a comparison would be conservative because, for a given well, the
static pressure (i.e., with no fluid movement through the well) would
be higher than the dynamic pressure (i.e., with the well flowing)
because there would be no pressure losses brought about by friction
caused by material movement in the tubing string. For some wells, use
of this method could eliminate the need for the detailed calculations
provided in the low pressure well equation discussed above. For other
wells (i.e., those wells where the static pressure was greater than the
flow line pressure), it would be necessary for the operator to use the
low pressure well equation.
    Commenters asserted that many oil reservoirs have pressure that is
insufficient for wells to naturally flow even after hydraulic
fracturing. The commenters stated that this can be evidenced by the
prevalence of artificial lift equipment such as rod pumps visible
across the landscape of many oil producing areas. The commenters cited
examples of reservoirs such as the Permian Basin, where horizontal
drilling is used to extend the life of existing producing formations.
The commenters explained that many oil wells that are hydraulically
fractured do not have sufficient reservoir pressure to flowback
fracture fluids. One company estimated that 30 percent of its
hydraulically fractured horizontal wells and 80 percent of its
hydraulically fractured vertical wells in the Permian Basin require
artificial lift to flowback. In these cases, the commenter explained,
rod pumps are installed on the wells to artificially lift the fracture
fluids to the surface. In light of the comments received, the EPA
believes that wells that require artificial lift equipment for flowback
of fracture fluids should be classified as low pressure wells, as we
believe that

performing a REC is technically infeasible for these wells.
    To meet the definition of low pressure well, the well must satisfy
any of the criteria above. We have revised the definition in the
regulatory text to reflect this change. Section VIII, the RTC document,
the TSD, and other materials available in the docket provide more
discussion of these topics.
5. Timing of Initial Compliance
    The EPA proposed the well completion requirements that, if
finalized, would apply to both oil and gas well completions using
hydraulic fracturing. In the 2012 NSPS, we provided a phase-in approach
in the gas well completion requirements due to the concern with
insufficient REC and trained personnel if REC were required immediately
for all gas well completions. However, we did not provide the same in
this proposal on the assumption that the supplies of REC equipment and
trained personnel have caught up with the demand and, therefore, are no
longer an issue. While some commenters agreed, other commenters
indicated that the proposed rule, which would dramatically increase the
number of well completions subject to the NSPS, would lead to REC
equipment shortages. One commenter estimated that it would take at
least 6 months to obtain the necessary equipment, while another
commenter estimated that it would take 24 months. One commenter noted
that owners and operators have been drilling wells, but delaying
completion, due to the current economic conditions affecting the
industry, causing a suppressed equipment demand. Finally, one state
regulatory agency recommended extending the compliance period to 120
days to allow sufficient time to contract for the necessary completion
equipment.
    After reviewing the comments, we agree that some owners and
operators may have difficulty complying with the REC requirements in
the final rule in the near term due to the unavailability of REC
equipment. Although REC equipment suppliers have increased production
to meet the demand for gas well completions under subpart OOOO, the
affected facility under subpart OOOOa includes both gas and oil wells
and will more than double the number of wells requiring REC equipment
over subpart OOOO. We believe this demand will likely lead to a short-
term shortage of REC equipment. However, based on the prior experience,
we believe that suppliers have both the capability and incentive to
catch up with the demand quickly, as opposed to the longer terms
suggested by the commenters; they likely already stepped up production
since this rule was proposed last year in anticipation of the impending
increase in demand. In light of the above, the final rule provides a
phase-in approach that would allow a quick build-up of the REC supplies
in the near term. Specifically, for subcategory 1 oil wells, the final
rule requires combustion for well completions conducted before November
30, 2016 and REC if technically feasible for well completions conducted
thereafter. For subcategory 2 and low pressure oil wells, the final
rule requires combustion during well completion, which is the same as
that required for completion of subcategory 2 and low pressure gas well
in the 2012 NSPS. For gas well completions, which are already subject
to well completion requirements in the 2012 NSPS, the requirements
remain the same.

F. Fugitive Emissions From Well Sites and Compressor Stations

    For fugitive emissions requirements for the source category, three
principles or aims directed our efforts. The first aim was to produce a
consistent and accountable program for a source to use to identify and
repair fugitive emissions at well sites and compressor stations. A
second aim was to provide an opportunity for companies to design and
implement their own fugitive emissions monitoring and repair programs.
The third aim was to focus the fugitive emissions monitoring and repair
program on components from which we expected the greatest emissions,
with consideration of appropriate exemptions. The fourth aim was to
establish a program that would complement other programs currently in
place. With these principles in mind, we proposed a detailed monitoring
plan; semiannual requirements using OGI technology for monitoring to
find and repair sources of fugitive emissions, which we had identified
as the BSER; a shifting monitoring schedule based on performance; a 15-
day timeframe for repairing and resurveying leaks; and an exemption for
low production wells.
    The public comment process helped us to identify additional
information to consider and provided an opportunity to refine the
standards proposed. Commenters specifically identified concerns with
the definition of modification for well sites and compressor stations,
the monitoring plan, the fluctuating survey frequency, the overlap with
state and federal requirements, use of emerging monitoring
technologies, the initial compliance timeframe, and the relationship
between production level and fugitive emissions.
    In this final rule, based on our consideration of the comments
received and other relevant information, we have made changes to the
proposed standards for fugitive emissions from well sites and
compressor stations. The final rule refines the monitoring program
requirements while still achieving the main goals. Below we describe
the significant changes since proposal for specific topics related to
fugitive emissions and our rationale for these changes. For additional
details, please refer to section VIII, the TSD, and the RTC supporting
documentation in the public docket.
1. Fugitive Emissions From Well Sites
a. Monitoring Frequency
    In conjunction with semiannual monitoring, the EPA co-proposed
annual monitoring and solicited comment on the availability of trained
OGI contractors and OGI instrumentation. 80 FR 56637, September 18,
2015. Commenters provided numerous comments and data regarding annual,
semiannual and quarterly monitoring surveys. These comments largely
focused on the cost, effectiveness, and feasibility of the different
program frequencies. The EPA evaluated these comments and information,
as well as certain production segment equipment counts from the 2016
public review draft GHG Inventory, which were developed from the data
reported to the GHGRP. Based on the above information, the EPA updated
its proposal assumptions on equipment counts per well site to use data
from the 2016 public review draft update. This resulted in changes to
the well site model plant. Specifically, the equipment count for
meters/piping at a gas well site increased from 1 to 3, which tripled
the component counts from meters/piping at these sites. In addition,
the EPA developed a third model plant to represent associated gas well
sites. This category includes wells with GOR between 300 and 100,000
standard cubic feet per barrel (scf/bbl), and the model plant is
assumed to have the same component counts as the model oil well site,
as well as components associated with meters/piping. The EPA used this
information to re-evaluate the control options for annual, semiannual
and quarterly monitoring. As shown in the TSD, the control cost, using
OGI, based on quarterly monitoring is not cost-effective, while both
semiannual and annual monitoring remain cost-effective for reducing GHG
(in the form of

methane) and VOC emissions. Because control costs for both semiannual
and annual monitoring are cost-effective, we evaluated the difference
in emissions reductions between the two monitoring frequencies and
concluded that semiannual monitoring would achieve greater emissions
reductions. Therefore, the EPA is finalizing the proposed semiannual
monitoring frequency. Please see the RTC document in the public docket
for further discussion.\86\ Even though the EPA has determined that
semi-annual surveys for well sites is the BSER under this NSPS, this
does not preclude the EPA from taking a different approach in the
future, including requiring more frequent monitoring (e.g., quarterly).
---------------------------------------------------------------------------

    \86\ See EPA docket ID No. EPA-HQ-OAR-2010-0505.
---------------------------------------------------------------------------

b. Low Production Well Sites
    The EPA proposed to exclude low production well sites (i.e., well
sites where the average combined oil and natural gas production is less
than 15 barrels of oil equivalent (boe) per day averaged over the first
30 days of production) from the fugitive emissions monitoring and
repair requirements for well sites. As we explained in the preamble to
the proposed rule, we believed that these wells are mostly owned by
small businesses and that fugitive emissions associated with these
wells are generally low. 80 FR 56639, September 18, 2015. We were
concerned about the burden on small businesses, in particular, where
there may be little emission reduction to be achieved. Id. We
specifically requested comment on the proposed exclusion and the
appropriateness of the 15 boe per day threshold. We also requested data
that would confirm that low production sites have low GHG and VOC
fugitive emissions.
    Several commenters indicated that low production well sites should
be exempt from fugitive emissions monitoring and that the 15 boe per
day threshold averaged over the first 30 days of production is
appropriate for the exemption, however, commenters did not provide
data. Other commenters indicated that the low production well sites
exemption would not benefit small businesses since these types of wells
would not be economical to operate and few operators, if any, would
operate new well sites that average 15 boe per day.
    Several commenters stated that the EPA should not exempt low
production well sites because they are still a part of the cumulative
emissions that would impact the environment. One commenter indicated
that low production well sites have the potential to emit high fugitive
emissions. Another commenter stated that low production well sites
should be required to perform fugitive emissions monitoring at a
quarterly or monthly frequency. One commenter provided an estimate of
low producing gas and oil wells that indicated that a significant
number of wells would be excluded from fugitive emissions monitoring.
    Based on the data from DrillingInfo, 30 percent of natural gas
wells are low production wells, and 43 percent of all oil wells are low
production wells. The EPA believes that low production well sites have
the same type of equipment (e.g., separators, storage vessels) and
components (e.g., valves, flanges) as production well sites with
production greater than 15 boe per day. Because we did not receive
additional data on equipment or component counts for low production
wells, we believe that a low production well model plant would have the
same equipment and component counts as a non-low production well site.