section 111, the EPA has concluded that it is appropriate to adopt
language in 40 CFR 60.5360a, language that is substantially similar to
language found in 40 CFR 60.5515 (subpart TTTT).
    While most of the Tailoring Rule limitations are no longer needed
to avoid triggering the requirement to obtain a PSD permit based on
GHGs alone, the limitation in 40 CFR 51.166(b)(48)(iv) and 40 CFR
52.21(b)(49)(iv) will remain important to provide an interim
applicability level for the GHG BACT requirement in ``anyway source''
PSD permits. Thus, there continues to be a need to ensure that the
regulation of GHGs under CAA section 111 does not make this BACT
applicability level for ``anyway sources'' effectively inoperable. The
language in 40 CFR 60.5360a is necessary to avoid this result in light
of the judicial actions described above.

C. Implications for Title V Program

    Under the Title V program, certain stationary sources, including
``major sources'' are required to obtain an operating permit. This
permit includes all of the CAA requirements applicable to the source,
including adequate monitoring, recordkeeping, and reporting
requirements to ensure sources' compliance. These permits are generally
issued through EPA-approved state Title V programs.
    In the proposal for this rulemaking, the EPA indicated that ``the
air pollutant that it propose[d] to regulate [was] the pollutant GHGs
(which consist of the six well-mixed gases), consistent with other
actions the EPA has taken under the CAA, although only methane will be
reduced directly by the proposed standards.'' 80 FR 56600-56601 (Sept.
18, 2015).
    Similar to the comments received on PSD permitting, the EPA
received several comments asking for clarification to make clear that
this rule did not directly regulate methane as a separate pollutant
from GHG and that it would not cause sources to be considered a major
source under the Title V permitting program based solely on having
methane emissions above the major source threshold. Several of these
comments suggested that this issue could be addressed by adding
provisions similar to those that appear in 40 CFR 60.5515 (subpart
TTTT).
    The immediately preceding section provides some general background
about the application of the PSD and Title V permitting programs to GHG
emissions. With respect to Title V, the definition of major source
includes, in relevant part, a stationary source that ``directly emits
or has the potential to emit, 100 tpy or more of any air pollutant
subject to regulation.'' 40 CFR 70.2, 71.2 (definition of ``major
source''). In the Tailoring Rule, a GHG threshold was incorporated into
the definition of ``subject to regulation'' under 40 CFR 70.2 and 71.2,
such that those definitions specify that GHGs are not subject to
regulation, unless, as of July 1, 2011, the emissions of GHGs are from
a source emitting or having the potential to emit 100,000 tpy of GHGs
on a CO2 Eq. basis. 40 CFR 70.2, 71.2 (definition of ``subject to
regulation''); see also 75 FR 31583, June 3, 2010. However, there is
not a similar threshold for methane as a separately regulated air
pollutant. Some comments reflected a concern that if methane were to be
subject to regulation as a separate air pollutant, sources that emitted
or had the potential to emit 100 tpy or more of methane would trigger
major source status under Title V and any related requirements under
the Title V permitting program.
    In consideration of these comments and for purposes of clarity, the
EPA has concluded that it is appropriate to adopt language in 40 CFR
60.5360a that is substantially similar to language found in 40 CFR
60.5515 (subpart TTTT). Consistent with the statement quoted above from
the proposal, that provision along with the explanation in this
preamble clarifies that the GHG standard established in this rulemaking
regulates the air pollutant GHGs, although the standard is expressed in
the form of a limitation on emission of methane. Accordingly, the air
pollutant that is subject to regulation under this standard for Title V
purposes is GHGs.
    As noted above, on June 23, 2014, the United States Supreme Court
issued its opinion in UARG v. EPA, 134 S.Ct. 2427 (June 23, 2014) and,
in accordance with that decision, the D.C. Circuit subsequently issued
an amended judgment in Coalition for Responsible Regulation, Inc. v.
Environmental Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-
1167 (D.C. Cir., April 10, 2015). With respect to Title V, the Supreme
Court said in UARG v. EPA that the EPA may not treat GHGs as an air
pollutant for purposes of determining whether a source is a major
source required to obtain a Title V operating permit. In accordance
with that decision, the D.C. Circuit's amended judgment in Coalition
for Responsible Regulation, Inc. v. Environmental Protection Agency,
vacated the Title V regulations under review in that case to the extent
that they require a stationary source to obtain a Title V permit solely
because the source emits or has the potential to emit GHGs above the
applicable major source thresholds. The D.C. Circuit also directed the
EPA to consider whether any further revisions to its regulations

are appropriate in light of UARG v. EPA, and, if so, to undertake to
make such revisions. These court decisions make clear that promulgation
of CAA section 111 requirements for GHGs will not result in the EPA
imposing a requirement that stationary sources obtain a Title V permit
solely because such sources emit or have the potential to emit GHGs
above the applicable major source thresholds.\98\
---------------------------------------------------------------------------

    \98\ The EPA intends to propose revisions to the Title V
regulations in a future rulemaking action to respond to the Supreme
Court decision and the D.C. Circuit's amended judgment. To the
extent there are any issues related to the potential interaction
between the promulgation of CAA section 111 requirements for GHGs
and Title V applicability based on emissions above major source
thresholds, the EPA anticipates there would be an opportunity to
consider those during that rulemaking.
---------------------------------------------------------------------------

    To be clear, however, unless exempted by the Administrator through
regulation under CAA section 502(a), any source, including an area
source (a ``non-major source''), subject to an NSPS is required to
apply for, and operate pursuant to, a Title V permit that ensures
compliance with all applicable CAA requirements for the source,
including any GHG-related applicable requirements. This aspect of the
Title V program is not affected by UARG v. EPA, as the EPA does not
read that decision to affect either the grounds other than those
described above on which a Title V permit may be required or the
applicable requirements that must be addressed in Title V permits.\99\
For the source category in this rule, there is an exemption in 40 CFR
60.5370a from the obligation to obtain a Title V permit for sources
that are not otherwise required by law to obtain a permit under 40 CFR
70.3(a) or 40 CFR 71.3(a). However, sources that are subject to the CAA
section 111 standards promulgated in this rule and that are otherwise
required to obtain a Title V permit under 40 CFR 70.3(a) or 40 CFR
71.3(a) will be required to apply for, and operate pursuant to, a Title
V permit that ensures compliance with all applicable CAA requirements,
including any GHG-related applicable requirements.
---------------------------------------------------------------------------

    \99\ See Memorandum from Janet G. McCabe, Acting Assistant
Administrator, Office of Air and Radiation, and Cynthia Giles,
Assistant Administrator, Office of Enforcement and Compliance
Assurance, to Regional Administrators, Regions 1-10, Next Steps and
Preliminary Views on the Application of Clean Air Act Permitting
Programs to Greenhouse Gases Following the Supreme Court's Decision
in Utility Regulatory Group v. Environmental Protection Agency (July
24, 2014) at 5.
---------------------------------------------------------------------------

VIII. Summary of Significant Comments and Responses

    This section summarizes the significant comments on our proposed
amendments and our response to those comments.

A. Major Comments Concerning Listing of the Oil and Natural Gas Source
Category

    As previously explained, the EPA interprets the 1979 listing of
this source category to cover the oil and natural gas industry broadly.
To the extent there is any uncertainty, EPA proposed, as an alternative
in the 2015 proposal, to revise the listing of this source category to
include oil production and natural gas production, processing, and
transmission and storage. We received several comments regarding the
EPA's interpretation of the 1979 category listing and its alternative
proposal to revise that listing. Provided below is one such comment and
the EPA's response. Other comments on this subject and the EPA's
responses thereto can be found in the RTC.
    Comment: One commenter argues that, in the proposed rule, the EPA
seeks to unlawfully expand the scope of the oil and natural gas sector
source category, even beyond the expansion that the EPA undertook in
2012 with subpart OOOO, which the commenter had also opposed as
unlawful. The commenter asserts that the EPA's attempt here to expand
even further the types of emissions sources that would be subject to
the NSPS is likewise unlawful. The commenter notes that, in this
proposal, several types of never before regulated emissions sources
would be regulated under NSPS, specifically, hydraulically fractured
oil well completions, pneumatic pumps and fugitive emissions from well
sites and compressor stations, and that some source types would also be
regulated more generally for methane and VOC emissions, as only a small
subset are currently regulated for VOC: Pneumatic controllers,
centrifugal compressors and reciprocating compressors (except for
compressors at well sites).
    The commenter notes that the EPA's proposed NSPS would cover an
even greater number of very small source types in the EPA's broadly
defined ``oil and natural gas source category,'' which, according to
the EPA, includes production, processing, transmission and storage. The
commenter notes that the EPA again maintains, as it did in the original
subpart OOOO rulemaking, that all emissions sources proposed for
regulation are covered by its 1979 listing of the oil and natural gas
category.
    The commenter claims that the EPA is incorrect that the 1979
original source category determination can be read to include the
numerous smaller emissions points covered by this proposal. According
to the commenter, the 1979 listing was focused on major emitting
operations and cannot be reasonably construed as encompassing small,
discrete sources that exist separate and apart from a large facility,
like a processing plant.
    The commenter claims that the EPA made clear in the 1979 listing
notice that the category was listed to satisfy section 111(f) of the
Clean Air Act. According to the commenter, that section required the
EPA to create a list of ``categories of major stationary sources'' that
had not been listed as of August 7, 1977, under section 111(b)(1)(A) of
the Act, and to promulgate NSPS for the listed categories according to
a set schedule. The commenter asserts that the EPA explained in the
listing rule that its list included ``major source categories,'' which
the EPA defined to include ``those categories for which an average size
plant has the potential to emit 100 tons or more per year of any one
pollutant.''
    Although the commenter notes that the EPA provided no further
explanation in its original 1979 listing decision as to what facilities
it intended to regulate under the ``crude oil and natural gas
production'' source category, the commenter claims that ``there can be
no doubt that the category originally included `stationary sources'
(i.e., `plants') that typically have a potential to emit at least 100
tons per year of a regulated pollutant.'' \100\ The commenter argues
that this communicates two important limitations on the original
listing decision: First, the EPA was focused on discrete ``plants'' or
``stationary sources''; and second, the EPA was focused on large
emitting plants or stationary sources. The commenter argues that, as a
result, the original listing decision cannot reasonably be interpreted
to extend to the types of sources the EPA seeks to regulate in the
proposal and that the additional source types that the EPA seeks to
regulate in this proposal could not plausibly be considered part and
parcel of major emitting plants.
---------------------------------------------------------------------------

    \100\ API Comments on the Proposed Rulemaking--Standards of
Performance for New Stationary Sources: Oil and Natural Gas
Production and Natural Gas Transmission and Distribution, at 2
(December 4, 2015).
---------------------------------------------------------------------------

    The commenter notes that the EPA interpreted the 1979 listing to be
broader than the ``production source segment'' because the EPA
evaluated equipment that is used in various segments of the natural gas
industry, such as stationary pipeline compressor engines. 80 FR 56600,
September 18, 2015. The commenter argues that this

does not evince an intent to regulate non-major source types, but only
that the Agency evaluated equipment located at what it perceived to be
major facilities.
    The commenter further notes that, in the preamble to the proposed
NSPS for natural gas processing plants, the EPA described the major
emission points of this source category to include process, storage and
equipment leaks. However, the commenter argues that this does not
support what the commenter claims as ``broad regulation of even the
smallest sources in the oil and natural gas industry.'' \101\ The
commenter notes that the emissions points regulated in that
rulemaking--process units and compressors--were located at gas
processing plants. The commenter argues that it is telling that the
Agency decided to regulate only natural gas processing plants--the
closest thing to a major emitting plant that can be found in this
sector--in that NSPS.
---------------------------------------------------------------------------

    \101\ Id.
---------------------------------------------------------------------------

    Response: In 1979, the EPA published a list of source categories,
including ``oil and natural gas production,'' pursuant to a new section
111(f) in the Clean Air Act amendment of 1977, which directed the EPA
to list under 111(b)(1)(A) ``categories of major stationary sources''
and establish standards of performance for the listed source
categories. As explained in the September 2015 proposal preamble and
earlier in section IV.A of this preamble, the EPA interprets the 1979
listing to broadly cover the oil and natural gas industry. The
commenter claims that the EPA's interpretation is incorrect because the
1979 listing included only large emitting plants or stationary sources.
However, the commenter's interpretation fails for the following
reasons.
    The commenter's claim relies in large part on the EPA's definition
of a ``major source category'' in the 1979 listing action, which was
defined as ``an average size plant that has the potential to emit 100
tons or more per year of any one pollutant,'' 44 FR 49222 (August 21,
1979). However, despite the definition above, the EPA provided notice
in the listing action that ``certain new sources of smaller than
average size within these categories may have less than a 100 ton per
year emission potential.'' 43 FR 38872, 38873 (August 31, 1978). The
EPA thus made clear that the 1979 listing did not include only those
meeting the major source threshold. The EPA's contemporaneous
explanation indicates that, while the 1979 action focused on large
emitting sources, the EPA recognized at the time that there are smaller
sources that may warrant regulation.
    The commenter next argues that the 1979 listing included only large
plants because it included only ``stationary sources.'' However,
``stationary sources,'' as defined in section 111(a)(2), include not
only buildings, structures and facilities (e.g., plants) but also
installations, such as equipment, that emit or may emit any pollutant.
Moreover, this definition contains no size limitation.
    The commenter cites to the EPA's initial NSPS promulgation in 1985,
which regulated only natural gas processing plants, as evidence that
the 1979 listing included only large emitting stationary sources and,
in the case of the oil and natural gas source category, only natural
gas processing plants. However, the fact that the EPA regulated only
natural gas processing plants in the 1985 NSPS does not establish that
the listed oil and natural gas source category consists of only large
natural gas processing plants. On the contrary, this argument ignores
that the category, as listed, also includes crude oil production.
Further, such narrow view is inconsistent with the EPA's clarification
of the 1979 listing and the statutory definition of ``stationary
sources,'' neither of which limits a listed category of stationary
sources under section 111 only to large plants such as natural gas
processing plants, as explained above.
    The commenter's assertion is also refuted by the EPA's statements
during the development of the 1985 NSPS. Specifically, in the preamble
to the proposed rule for equipment leaks at natural gas processing
plants, the EPA described the major emission points of this source
category to include process, storage and equipment leaks, which can be
found in various segments of the oil and natural gas industry. Further,
as mentioned earlier, the EPA described the listed oil and natural gas
source category to include emission points that the EPA did not
regulate at that time, such as ``well systems field oil and gas
separators, wash tanks, settling tanks and other sources.'' 49 FR at
2637. The EPA explained in that action that it could not address these
emission at that time because ``best demonstrated control technology
has not been identified.''
    In light of the above, EPA reasonably interprets the 1979 listing
to include the sources regulated under the 2012 oil and gas NSPS as
well as those subject to today's action. The EPA established well
completion performances standards for hydraulically fractured gas wells
in the 2012 NSPS and for oil wells in today's action. These standards
address some of the above mentioned well system emissions that the EPA
could not regulate previously due to the lack of data. In addition, as
mentioned above, the EPA had previously identified equipment leaks as a
major emission point from this listed source category and established
leaks standards for natural gas processing plants. Today's action
further reduces emissions from equipment leaks by establishing work
practice standards to detect and repair fugitive emissions at well
sites and compressor stations. Emissions from equipment do not result
only from leaks but also from normal operations that, if uncontrolled,
are vented into the atmosphere. Therefore, both the 2012 NSPS and
today's rule include performance standards for certain equipment used
throughout the oil and natural gas industry, such as storage vessels,
pneumatic controllers, pneumatic pumps, and compressors. Because these
equipment are widely used across this industry, they contribute
significant amount of emissions even if emissions from an individual
piece of equipment may not be big.\102\
---------------------------------------------------------------------------

    \102\ For example, based on industry wide estimate, high-bleed
pneumatic controllers (from production through transmission and
storage) emit in total of 87,285 tons of VOC and 350,000 tons of
methane (8.7 million metric tons of CO2e).
---------------------------------------------------------------------------

    The commenter's main concern appears to be with the EPA regulating
what the commenter claims to be ``very small emission sources'' and,
therefore, unreasonable. However, section 111(b)(1)(A) requires that
the EPA list source categories, not emission sources. In listing a
source category, the EPA is not required to identify specific emission
points within that source category. However, having listed a source
category, the EPA is then required under section 111(b)(1)(B) to
establish through rulemaking performance standards that reflect the
best system of emission reductions, which would entail evaluation of
emissions, control options, and other considerations (including their
costs) for the sources to be regulated. Therefore, specific concerns
with regulation of certain emission sources can be addressed during the
rulemaking to establish such performance standards, where a commenter
can argue that controlling a specific type of source is unreasonable
under 111(b)(1)(B).
    For the reasons stated above, the commenter fails to support its
claim that the EPA's interpretation of the 1979 listing is unlawful.
The commenter also fails to support its interpretation of the 1979
listing. The EPA's interpretation of

the 1979 listing therefore remains unchanged.
    Comment: The commenter claims that the EPA fails to make the
required statutory findings under section 111(b)(1)(A) to support its
proposed revision to the 1979 listing. The commenter asserts that,
under section 111(b)(1)(A), the EPA is authorized to regulate
additional source types if and only if it: (1) Defines a discrete
``category'' of stationary sources; and (2) determines that emissions
from the source category cause or significantly contribute to
endangerment to health or the environment.
    The commenter claims that the EPA makes no effort whatsoever to
demonstrate that emissions from the particular additionally-regulated
sources in subpart OOOOa cause or contribute to endangerment to health
or the environment. Instead, the Agency simply asserts general public
health effects associated with GHGs, VOC, and SO2 and then
evaluates emissions from oil and natural gas sources generally. See 80
FR 56601-08, September 18, 2015. For methane, the EPA merely breaks
down emissions into four general ``segments'' (natural gas production,
natural gas processing, natural gas transmission and storage, and
petroleum production), but does not evaluate particular source type
emissions within those segments. The EPA does nothing to break down its
evaluation of emissions even by sector segment for SO2 and
VOC. This failure to investigate the key statutory listing criteria is
patently arbitrary and plainly violates the requirement in section
307(d)(3) of the Clean Air Act to clearly set forth the basis and
purpose of the proposal.
    The commenter claims that under the EPA's logic, as long as certain
types of stationary sources in a category, or segment of a category,
cause or significantly contribute to endangerment to health or the
environment, the Agency can lump together in the defined source
category (or segment of a source category) all manner of ancillary
equipment and operations, even if those ancillary equipment and
operations do not in and of themselves significantly contribute to the
previously identified endangerment. See 80 FR 56601, September 18,
2015. This is not a reasonable interpretation of section 111(b)(1)(A)
because such an interpretation would bestow virtually unlimited
regulatory authority upon the EPA, allowing the EPA to evade the
express listing criteria by creating loose associations of nominally
related sources in a sector.
    Response: The commenter claims that the EPA must separately list
and make the required findings under CAA section 111(b)(1)(A) for the
``additional source types'' from the oil and natural gas industry that
were not covered by the 1979 listing. First of all, the EPA disagrees
that there are such ``additional source types'' because, for the
reasons stated in section IV.A of this preamble and the response to
comment immediately above, the EPA interprets the 1979 listing to
broadly cover the oil and natural gas industry. To the extent there is
any uncertainty, the EPA rejects the commenter's claim that the 1979
listing covers only natural gas processing plants. But, more
importantly, the EPA rejects this comment because it is contrary to the
law.
    CAA section 111(b)(1)(A) requires that the EPA list a category of
sources ``if in [the Administrator's] judgment it causes, or
contributes significantly to, air pollution which may reasonably be
anticipated to endanger public health and welfare.'' \103\ The
provision is clear that the listing and endangerment findings
requirements are to be made for source categories, not specific
emission sources within the source category. The provision also does
not require that the EPA identify all emission points within a source
category when listing that category.
---------------------------------------------------------------------------

    \103\ As previously mentioned, the required findings under
section 111(b)(1)(A) is commonly referred to as the ``endangerment
findings.''
---------------------------------------------------------------------------

    The commenter's claim that the EPA must separately list and make
findings for particular emission source types within individual
segments of the natural gas industry clearly contradicts with the plain
language of section 111(b)(1)(A) which, as discussed above, is stated
in terms of source category, not emission source types. Regardless, the
EPA has satisfied the two criteria the commenter has identified as
required by section 111(b)(1)(A): (1) Define a discrete category of
stationary sources; and (2) determine that emissions from the source
category cause or significantly contribute to endangerment to health or
the environment. Although the EPA does not believe that revision to the
1979 category listing to be necessary for today's action, the EPA is
finalizing as an alternative its proposed revision of the category
listing to broadly include the oil and natural gas industry. In support
of the revision, the final rule includes the Administrator's
determination under section 111(b)(1)(A) that, in her judgment, this
source category, as defined in this revision, contributes significantly
to air pollution which may reasonably be anticipated to endanger public
health or welfare.
    The commenter also appears to claim that the EPA cannot revise the
scope of a listed source category, but must instead separately list and
make findings for what the commenter considers as ``additional source
types'' within an already listed source category. The commenter offers
no legal basis to support its claim because there is none. On the
contrary, as explained below, the commenter claim impermissibly
restricts the EPA's authority under section 111(b)(1)(A).
    Section 111(b)(1)(A) requires that the EPA revise the category
listing from time to time; it does not limit such revision to simply
adding new source categories. The only criteria that section
111(b)(1)(A) states for the EPA to apply to category listing revision
are the same as those for the initial category listing: That the
category ``causes, or contributes significantly to, air pollution which
may reasonably be anticipated to endanger public health and welfare.''
Thus, the statute leaves the EPA with the discretion to determine how
to carry out such task, and that gives the EPA the flexibility to list
and revise the list, including redefining the scope of a previously
listed category, as long as long as the EPA meets the above criteria
with the requisite endangerment findings for the source category as a
whole. It allows the EPA to revise a category listing to include
sources that, though not included in the initial listing (e.g., the EPA
might now have known about it at the time), reasonably belong in a
listed source category. The commenter provides no compelling reason
that such emission sources need a separate category listing and
endangerment finding. In light of the above, the commenter's claim for
a separate category listing and endangerment finding is not only
unsupported by the statute, it unreasonably curtails the discretion
section 111(b)(1)(A) provides the EPA in executing its category listing
and revision authority under that provision. For the reasons stated
above, the EPA disagrees with this comment.

B. Major Comments Concerning EPA's Authority To Establish GHG Standards
in the Form of Limitations on Methane Emissions

    As previously explained in section IV.D, the EPA's authority for
regulating GHGs in this rule is CAA section 111. The standards in this
rule that are specific to GHGs are expressed in the form of limitations
on emissions of methane, and not the other constituent gases of the air
pollutant GHGs. We

received several comments regarding the EPA's interpretation of CAA
section 111. Provided below is a summary of such comments and the EPA's
response. Other comments on this subject and the EPA's responses
thereto can be found in the RTC document.
    Comment: Several commenters argued that the EPA cannot rely on the
2009 Endangerment Finding for GHG to justify the limitations of methane
in this rule. The commenters made several arguments.
    First, some commenters asserted that the EPA cannot regulate
methane alone or specifically without a new Endangerment and Cause or
Contribute Finding for the individual gas, because the original 2009
Finding defined the pollutant as the six well-mixed greenhouse gases.
One commenter further stated that it is unlawful for the EPA to
regulate only methane based on an endangerment finding that is largely
attributable to other pollutants and that, of the six greenhouse gases,
carbon dioxide is emitted in vastly greater quantities (even on a
carbon dioxide equivalent basis) than methane.
    Second, some commenters argue that a new endangerment finding is
necessary for each pollutant regulated in a given source category. One
commenter claims that section 111(b)(1)(A) of the CAA requires the EPA
to list a category of stationary sources if, in the Administrator's
judgment, the category causes, or contributes significantly to, air
pollution which may reasonably be anticipated to endanger public health
or welfare. The commenter further argues that this CAA section
unambiguously requires the EPA to list and regulate according to
endangerment and significant contribution findings for particular
pollutants. The commenter goes to state that it is unreasonable for the
EPA to use a cause-or-contribute finding made for one pollutant thirty
years ago in order to justify controlling a different pollutant today.
The commenter asserts that a ``rational basis test'' is insufficient
justification, and that the term ``rational basis'' is not found in
section 111.
    Third, some commenters argue that methane does not endanger human
health or welfare. One commenter states that methane is naturally
occurring and is non-toxic, that it does not accumulate in the body,
that the only real risks that it poses are that it is flammable when
present in high concentrations, and that inhaling high levels can cause
oxygen deprivation. Another commenter claims that recent science
supports a weakening of the case for human-caused global warming.
    Finally, some commenters state that the impacts of the rule will be
very small. One commenter argues that ``the oil and gas sector do [sic]
not significantly cause or contribute to climate change'' because
methane emissions from that sector ``account for only 3 percent of
total United States domestic GHG emissions, just over 2 percent of the
total United States GHG Inventory, and 0.3 percent of Global GHG
emissions'' and transmission and storage is only a third of that total.
    Response: As a general matter, commenters on this issue
consistently mischaracterize the EPA's actions. The standards in this
rule that are specific to GHGs are expressed in the form of limitations
on emissions of methane. For these standards, GHG is the regulated
pollutant. An endangerment finding is only required when the EPA lists
a source category under section 111(b)(1)(A). Nothing in section 111
requires that the EPA make further endangerment findings with respect
to each pollutant that it regulates under section 111(b)(1)(B). By
considering whether there is a rational basis to regulate a given
pollutant from a listed source category, the EPA ensures that it
regulates pollutants that warrant regulation.
    For purposes of this final rule, the EPA's rational basis is
supported, in part, by the analysis that supported the 2009
Endangerment Finding. If, as commenters argue, the EPA is required to
make additional findings of endangerment and cause-or-contribute for
this final rule, then the analysis that supported the 2009 Endangerment
Finding, along with other facts presented herein, including the
information in sections IV.B and C, would be sufficient to make these
findings.
    While the 2009 Endangerment Finding defined the pollutant as the
``aggregate group of the well-mixed greenhouse gases'' the finding was
also clear that a given source category does not have to emit every
single one of these gases in order to contribute to the pollution in
question. See 74 FR 66496-99 and 66541 (December 15, 2009).
Specifically, as we explained in the 2009 Endangerment Finding, two of
the six pollutants (PFCs and SF6) are not emitted by motor
vehicles, the source category in question in the 2009 Endangerment
Finding. Moreover, while motor vehicles contribute to emissions of HFC-
134a, there are many other HFCs which are not emitted by that source.
Just as the GHG emissions from motor vehicles do not need to contain
all six gases in order to be regulated, the GHG emissions from the oil
and gas sector do not need to contain all six gases. Therefore, the EPA
does not need to make an endangerment finding for methane alone: The
2009 Endangerment Finding that defines the aggregate group of six well-
mixed gases as the air pollution addresses emissions of any individual
component of that aggregate group and, therefore, supports the rational
basis for this final rule.
    Next, the assertion that methane has no risks beyond flammability
is false. While methane is indeed produced from natural sources, the
health and welfare risks of elevated concentrations of greenhouse gases
(including methane) was detailed in the 2009 Endangerment Finding.
Moreover, methane is a precursor to tropospheric ozone formation, which
also impacts human health. As further context, according to the IPCC,
historical methane emissions contribute the second most warming today
of all the greenhouse gases, after carbon dioxide. This makes methane
emission reductions an important contribution to reducing the
atmospheric concentrations of the six well-mixed greenhouse gases.
    Lastly, the climate benefits anticipated from the implementation of
this rule are consequential in terms of the quantity of methane
reduced, particularly in light of the potency of methane as a GHG. The
reductions are additionally important as the United States oil and
natural gas sector emits about 32 percent of United States methane
emissions and about 3.4 percent of all United States GHGs. The final
standards are expected to reduce methane emissions annually by about
6.9 million metric tons CO2 Eq. in 2020 and by about 11
million metric tons CO2 Eq. in 2025. To gives a sense of the
magnitude of these reductions, the methane reductions expected in 2020
are equivalent to about 2.8 percent of the methane emissions for this
sector reported in the United States GHG Inventory for 2014. Expected
reductions in 2025 are equivalent to around 4.7 percent of 2014
emissions. As discussed in section IX.E, the estimated monetized
benefits of methane emission reductions resulting from this rule are
$160 million to approximately $950 million for reduced emissions in
2020, and $320 million to $1.8 billion for reduced emissions in 2025,
depending on the discount rate used. The magnitude of these benefits
estimates demonstrates that the methane reductions are consequential
from an economic perspective, as well as physical perspective.

C. Major Comments Concerning Compressors

1. Wet Seal Centrifugal Compressors With Emission Rates Equal to or
Lower Than Dry Seal Centrifugal Compressors
    Comment: The EPA received several comments asserting that there are
many wet seal centrifugal compressors that have emissions that are
equal to, or lower than, dry seal compressors. One commenter notes that
the EPA cites 6 standard cubic feet per minute (scfm) as the emission
rate for dry seals and that a wide variety of wet seal systems are in
use with varying rates of de-gas emissions and that if wet seal system
can meet an emissions performance specification on par with dry seals
(i.e., 6 scfm), they should be exempt from the 95 percent reduction
requirement. One commenter states that data indicate that a well-
maintained wet seal will have a methane emission rate comparable to or
lesser than dry seals and that the emission rate for commenter's
compressors is significantly lower than the average rate identified in
the EPA's National Emissions Inventory for this kind of source.
    Response: The emissions factor used in our BSER analysis is an
average factor calculated from available emissions information. As
such, there are some wet seal centrifugal compressors that have a lower
emission rate than the average emission rate. However, we have not been
provided, nor do we have, any data indicating that there is a specific
type or significant population of wet seal centrifugal compressors that
have emission rates that are equal to or lower than dry seal
compressors. We acknowledge that a well-maintained wet seal compressor
may have lower emissions; however, as noted, the rule is based on an
average emission factor derived from the best available information on
a population of wet seal compressors. We have no data on which to base
an exemption or different requirement for a subcategory of merely
presumed low-emitting wet seal centrifugal compressors.
2. Regulation of Centrifugal and Reciprocating Compressors at Well
Sites
    Comment: The EPA received several comments opposing the exemption
of centrifugal and reciprocating compressors located at well heads from
the requirements of the rule. The commenters state that there are
thousands of well head reciprocating compressors across the nation as
well as some centrifugal compressors at well heads, and they pose a
significant source of emissions unless properly controlled. The
commenters contend that the reason the EPA claims to exclude these
compressors is based on EPA data that show no centrifugal compressors
located at well heads and on the determination that it is not cost
effective to regulate these reciprocating compressors. Commenters state
that the GHGRP data shows that there are centrifugal compressors
located at well heads and that they should be regulated under the rule.
Further, commenters assert that the EPA's cost effectiveness
determination for reciprocating compressors is arbitrary because it was
based on outdated emission factors and that if updated, the revised
emissions would render the control for the well head compressors as
cost-effective. Commenters suggest that the EPA should have relied on
updated emission factors to estimate emissions from well-site
compressors as it did to estimate emissions from gathering sector
compressors, or at least explained why it failed to rely on updated
emissions data to estimate emissions from well-site compressors.
    Response: The emissions estimates presented in the proposal were
based on the most robust data available at the time of their
development. The EPA began collecting data through GHGRP on centrifugal
compressors in the onshore petroleum and natural gas production segment
in 2011. However, reporting of input data for compressors, including
the count of centrifugal compressors at a facility, in onshore
production was deferred until 2015 and published for the first time in
October 2015. As a result, data on the number of centrifugal
compressors were not available through GHGRP at the time of the
development of the NSPS OOOOa proposal.
    The EPA agrees with the commenter that the newly available data
from GHGRP show the presence of centrifugal compressors in the onshore
production segment, but the EPA disagrees with the commenter that it
should cover these sources under the final rule. Although GHGRP data
shows that 15 reporters indicated 69 centrifugal compressors at
production facilities, the data do not provide a method to determine
the number of centrifugal compressors with wet seals in onshore
production. The GHGRP does not collect data on seal type (wet seal and
dry seal) for onshore production. The EPA is not aware of other data
sets on wet seals in the onshore production segment. Based on available
data on the number of centrifugal compressors in onshore production, it
is unlikely that there is a large population of centrifugal compressors
with wet seals in onshore production.
    With respect to emission factors for reciprocating compressors at
well sites, the EPA proposed to exempt these compressors from the
standards because we found that the cost of control for reciprocating
compressors at well sites is not reasonable. Commenters on the 2014 Oil
and Gas White Papers and on the subpart OOOOa proposal did not provide
new data available for development of emission factors for
reciprocating compressors at well sites. The EPA has not identified
additional data sources for development of emission factors for
reciprocating compressors at well sites and, therefore, has not updated
its emissions estimate for this source. We continue to believe the cost
of control for reciprocating compressors at well sites remains
unreasonable. The final rule exempts centrifugal and reciprocating
compressors at well sites.
3. Condition-Based Maintenance
    Comment: The EPA solicited comment on an alternative to the
proposed requirements which consists of monitoring of rod packing
leakage to identify when the rate of rod packing leakage indicates that
packing replacement is needed. Under such a condition-based maintenance
provision, rod packing would be inspected or monitored based on a
prescribed method and frequency and rod packing replacement, or repair
would be required once a prescribed leak rate was observed. We
requested additional information on the technical details of this
condition-based concept.
    Several commenters state that the rule should include an
alternative maintenance program and allow operators flexibility to use
a condition-based maintenance approach to reduce emissions rather than
a prescribed maintenance schedule as currently included in the rule. In
addition to controlling emissions, commenters assert that a condition-
based maintenance may extend the operation of functional rod packing,
eliminate premature and wasteful rod packing maintenance/replacement
and, possibly, where rod packing leakage increases quicker than is
typical, condition-based maintenance can result in earlier maintenance
than EPA's proposed prescribed maintenance schedule. Commenters note
that condition-based maintenance has been a proven successful technique
for reducing methane emissions through the Natural Gas STAR program,
where rod packing leaks were periodically monitored and the value of
the incremental leaked gas (relative to leak rates for ``new'' packing)
was compared to the rod packing

maintenance cost. When the incremental lost gas value exceeded the
maintenance/replacement cost, the rod packing maintenance was
determined to be cost-effective.
    Other commenters noted that because operators in transmission and
storage segment do not own the gas, a different performance metric
could be used and recommended a metric based on a defined leak rate or
change in leak rate over time. Commenters recommended possibly setting
a threshold at a leak rate above 2 scfm, combined with annual
monitoring, which would require rod packing maintenance/replacement
within nine months or during the next unit shutdown, whichever is
sooner and which is consistent with a draft California Air Resources
Board (CARB) regulation for oil and gas operations.
    Response: The EPA disagrees with the commenters that the rule
should include an alternative maintenance program and allow operators
flexibility to use condition-based maintenance approach to reduce
emissions rather than a prescribed maintenance schedule. While we
received comment supporting the addition of a threshold-based or
condition-based maintenance provision, we did not receive sufficient
technical details to properly evaluate this alternative for inclusion
in the rule. Although condition-based maintenance has been shown to be
effective under the Natural Gas STAR program, the criteria on which
rule requirements could be based would require significantly more data
and analysis. Specifically, in order to evaluate such a provision for
the rule, we would need to determine an appropriate leak-rate threshold
which would trigger rod packing replacement. Commenters suggested 2
scfm demonstrated acceptable rod packing leakage; however, the
commenters provided no substantive data as to the reason for this
threshold. Commenters also recommended that we model the provision
after the California Air Resources Board proposed regulation which was
based on input from rod packing vendors. Although some valuable
information was provided, the level of technical data and information
necessary to analyze all aspects of such a provision were not provided.
Therefore, we are unable to evaluate the condition-based maintenance
provision for inclusion in the rule at this time.

D. Major Comments Concerning Pneumatic Controllers

1. Studies That Indicate Emission Rates for Low-Bleed Pneumatic
Controllers That Are Higher Than the EPA Estimates
    Comment: The EPA received comment that several recent studies
report that pneumatic controllers emit more than they are designed to
emit and that their emission rate is higher than the currently
estimated EPA emission rate for pneumatic controllers. Specifically,
the commenters noted that studies indicated that controllers were
observed to have emissions inconsistent with the manufacturer's design
and were likely operating incorrectly due to maintenance or equipment
issues. Low-bleed pneumatic controllers were observed to have emission
rates that were 270 percent higher than the EPA's emission factor for
these devices, in some cases approaching the emission rate of high-
bleed controllers.
    Response: The emissions estimates presented in the proposal were
based on the most robust data available at the time of their
development. The EPA is familiar with the studies discussed in the
comments summarized here and several of those studies were discussed in
the EPA's Oil and Gas White Paper. The EPA has reviewed available data;
because of the lack of emissions data that are straightforward to use
in assessment of emissions from specific bleed rate categories (i.e.,
high-bleed and low-bleed), the EPA has retained the emission factors
for pneumatic controllers used in the proposal analysis and has
retained the requirements for pneumatic controllers.
2. Capture and Control of Emissions From Pneumatic Controllers
    Comment: The EPA received comment that pneumatic controllers should
be required to capture emissions through a closed vent system and route
the captured emissions to a process or a control device, similar to the
approach the EPA has taken in its proposed standards for pneumatic
pumps and compressors. The commenters cite recent Wyoming proposed
rules for existing pneumatic controllers that allow operators of
existing high-bleed controllers to route emissions to a process and the
California Air Resources Board (CARB) proposed rules which requires
that operators capture emissions and route to a process or control
device. Commenters state that this approach would work for all types of
pneumatic controllers and that this approach would be cost effective
based on the costs identified for pneumatic pumps in the TSD.
    Response: The EPA disagrees with the commenters that capturing and
routing emissions from pneumatic controllers to a process or control
device is a viable control option under our BSER analysis. While the
commenter stated that a few permits in Wyoming indicate that a facility
is capturing emissions from controllers and routing to a control
device, we believe that there is insufficient information and data
available for the EPA to establish the control option as the BSER. For
more information, please see the RTC.

E. Major Comments Concerning Pneumatic Pumps

1. Compliance Date
    Comment: Commenters stated that the EPA requires that new or
modified pneumatic pumps at a site that currently lack an emission
control device will become an affected facility if a control device is
later installed; and, the facility must be in compliance within 30 days
of installation of the new control device. One commenter states that 30
days does not provide such sources sufficient time to come into
compliance. The commenter suggests that the rule be revised to require
compliance within 30 days of startup of the control device so that the
operator can ensure that the control device is properly tested after
installation without concern over triggering non-compliance for
pneumatic pump controls.
    Response: We agree that additional time is appropriate for
designing connections and testing after control device installation.
Therefore, we have revised the compliance date in the final rule with
respect to control devices that are installed on site after
installation of the pneumatic pump affected facility. In the final
rule, the compliance date for pneumatic pump affected facilities to be
routed to a newly installed onsite control device 30 days after startup
of the control device.
2. Subsequent Removal of Control Device
    Comment: Several commenters expressed concern that the rule did not
provide a way to remove control equipment from a site when it is no
longer needed for the purpose for which it was installed. Further, they
requested that the EPA clarify that a source ceases to be an affected
facility if the control device is no longer needed for other equipment.
The commenters cite an example where the exiting control device onsite
is installed for a subpart OOOO storage vessel and subsequently

the storage vessel's potential to emit falls below 6 tpy. If this were
to occur, the storage vessel would no longer be subject to regulation
and the control device would no longer be necessary.
    Response: The EPA agrees that the intent of the proposal was not to
require existing control devices that are no longer required for their
original purposes to remain at a site only to control pneumatic pump
affected facility emissions. Therefore, the final rule clarifies that
subsequent to the removal of a control device and provided that there
is no ability to route to a process, a pneumatic pump affected facility
is no longer required to comply with Sec.  60.5393a(b)(1) or (2).
However, these units will continue to be affected facilities and we are
requiring pneumatic pump affected facilities to continue following the
relevant recordkeeping requirements of Sec.  60.5420a even after an
existing control device is removed.
3. Limited-Use Pneumatic Pumps
    Comment: Commenters state that there are natural gas-driven
pneumatic pumps which are used intermittently to transfer bulk liquids.
These limited use pumps may be manually operated as needed or may be
triggered by a level controller or other sensor. Specific examples
provided by the commenters include engine skid sump pumps, pipeline
sump pumps, tank bottom pumps, flare knockout drum pumps, and separator
knockout drum pumps that are used to pump liquids from one place to
another. The commenters contend that these pumps do not run
continuously or even seasonally for long periods but only run
periodically as needed. Thus, these pumps do not exhaust large volumes
of gas in the aggregate. For this reason, the commenters requested that
the final rule include an exemption for limited-use pneumatic pumps.
    Response: In the TSDs to the proposed and final rule, the emission
factors we used for pneumatic pumps assumed that the pumps operated 40
percent of the time. While we understood that pneumatic pumps typically
do not run continuously, we did assume that the 40 percent usage was
distributed evenly throughout the year. However, based upon the
comments we received, the usage of some pneumatic pumps is much more
limited than we previously determined and not spread evenly throughout
the year. We did not intend to regulate these limited-use pneumatic
pumps and are not including limited-use pneumatic pumps in the
definition of pneumatic pump affected facilities that are located at
well sites. Specifically, if a pump located at a well site operates for
any period of time each day for less than a total of 90 days per year,
this limited-use pneumatic pump is not an affected facility under this
rule. We believe this requirement is sufficient to address the
commenters' concerns for both intermittent use and temporary use
pneumatic pumps.
    Because we believe there are multiple viable alternatives available
at natural gas processing plants that are not available at well sites,
we do not believe it is necessary to exclude limited-use pneumatic
pumps located at natural gas processing plants from the definition of
pneumatic pump affected facility. Based on our best available
information, both instrument air and electricity are readily available
at natural gas processing plants. We believe owners and operators will
choose instrument air over natural gas-driven pumps since their other
pumps will be air powered. We also believe owners and operators can
utilize electric pumps for intermittent activities cited by the
commenters such as sump pumps and transfer pumps where it is safe to
use an electric pump. Given these options, we conclude that it is not
necessary to exclude limited-use pneumatic pumps located at natural gas
processing plants from the definition of pneumatic pump affected
facility in the final rule.
4. Removal of Tagging Requirements
    Comment: Several commenters requested that the EPA remove the
tagging requirement for pneumatic pump affected facilities. As written,
the proposed rule required that operators tag pumps that are affected
facilities and those that are not affected facilities. The commenters
contend that the tagging requirement appears to add little value and is
confusing. Commenters suggest operators should only be required to
maintain a list of make, model, and serial number, rather than
individual tags and that a list of make, model, and serial number will
achieve the same results desired by the EPA, without presenting the
unnecessary operational hurdles associated with individual tagging and
recordkeeping.
    Response: The EPA has reviewed the proposed tagging requirements
and agrees with the commenters that the recordkeeping in lieu of
tagging for pneumatic pumps affected facilities is sufficient.
Therefore, the EPA has removed the tagging requirements for pneumatic
pump affected facilities in the final rule.
5. Lean Glycol Circulation Pumps
    Comment: The EPA solicited comments on the level of uncontrolled
emissions from lean glycol circulation pumps and how they are vented
through the dehydrator system. We received comments corroborating our
understanding at proposal and in the white papers that emissions from
these pumps are vented through the rich glycol separator vent or the
reboiler still vent and are already regulated under 40 CFR part 63
subparts HH and HHH.
    Response: The EPA's understanding during the proposal was that the
lean glycol pumps are integral to the operation of the dehydrator, and
as such, emissions from glycol dehydrator pumps are not separately
quantified because these emissions are released from the same stack as
the rest of the emissions from the dehydrator system, including HAP
emission that are being controlled to meet the standards under the
National Emission Standards for Hazardous Air Pollutants (NESHAP) at 40
CFR part 63 subparts HH and HHH. It is also our understanding from
white paper commenters that replacing the natural gas in gas-assisted
lean glycol pumps with instrument air is not feasible and would create
significant safety concerns. Commenters on the white paper stated that
the only option for these types of pumps are to replace them with
electric motor driven pumps; however, solar and battery systems large
enough to power these types of pumps are not currently feasible.
Therefore, we have clarified that lean glycol circulation pumps are not
affected facilities under the final pneumatic pumps standards.

F. Major Comments Concerning Well Completions

1. Request for a Limited Use of Combustion
    Comment: Several commenters support the requirements for reducing
completion emissions at oil wells; however, they express concern that
the proposed rule does not go far enough in establishing a hierarchy of
preference for the beneficial use options provided in the rule (i.e.,
routing the recovered gas from the separator into a gas flow line or
collection system, re-injecting the recovered gas into the well or
another well, use of the recovered gas as an onsite fuel source or use
of the recovered gas for another useful purpose that a purchased fuel
or raw material would serve) over what the commenters perceive to be
the least-preferable option to route the emission to a combustion
control device. Further, one commenter states that the technical

infeasibility exemption in the rule is vague and could detract
significantly from the overall value of this standard if not narrowly
limited in application. The commenter notes that because of the swiftly
increasing production of oil (along with associated natural gas) in the
United States which produces very high initial rates of oil and
associated gas, it is vital that the rule's requirements apply
rigorously.
    Response: The EPA agrees that REC should be preferred over
combustion due to the secondary environmental impact from combustion.
The final rule reflects such preference by requiring REC unless it is
technically infeasible, in which event the recovered gas is to be
routed to a completion combustion device. Further, to ensure that the
exemption from REC due to technical infeasibility is limited to those
situations where the operator can demonstrate that each of the options
to capture and use gas beneficially is not feasible and why, 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 Sec.
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 on site.
    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 CEDRI and WebFIRE,
allowing for public review of best practices and periodic auditing to
ensure flaring is limited and emissions are minimized.

G. Major Comments Concerning Fugitive Emissions From Well Sites and
Compressor Stations

1. Modification Definitions for Well Sites
    Comment: Several commenters assert that the definition of
``modification'' of a well site under the proposed rule in Sec.
60.5365a(i) is overly broad because it would bring many existing well
sites under the Rule's requirements. The commenters believe that
drilling a new well or hydraulically fracturing an existing well does
not increase the probability of a leak from an individual component and
no new components result from these activities, thus the potential
emissions rate does not change and should not be consider a
modification.
    Response: The EPA believes the addition of a new well or the
hydraulically fracturing or refracturing of an existing well will
increase emissions from the well site for the following reasons. These
events are followed by production from these wells which generate
additional emissions at the well sites. Some of these additional
emissions will pass through leaking fugitive emission components at the
well sites (in addition to the emissions already leaking from those
components). Further, it is not uncommon that an increase in production
would require additional equipment and, therefore, additional fugitive
emission components at the well sites. We also believe that defining
``modification'' to include these two events, rather than requiring
complex case-by-case analysis to determine whether there is emission
increase in each event, will ease implementation burden for owners and
operators. For the reasons stated above, EPA is finalizing the
definition of ``modification'' of a well site, as proposed.
2. Monitoring Plan
    Comment: Commenters expressed concerns about the elements of the
proposed monitoring plans and encouraged the EPA to consult with the
oil and gas industry and states to adopt requirements that would meet
their specific needs. Commenters suggested that an area-wide monitoring
plan should be allowed instead of a corporate-wide or site specific
plan. The area plan would allow owners to write a plan that covers
various areas for each specific region since operators may rely on
contractors in one area due to location while company-owned monitoring
equipment may be used within another area.
    Response: The EPA participated in numerous meetings with industry,
environmental and state stakeholders to discuss the proposed rule.
During these meetings industry stakeholders further explained why a
corporate-wide monitoring plan would be difficult to develop due to
their corporate structures, well site locations, basin characteristics
and many other factors. They also indicated that a site-specific plan
would be redundant since many well sites within a district or field
office are similar and would utilize the same personnel, contractors or
monitoring equipment. The industry stakeholders provided input on
specific elements of the monitoring plan, such as the walking path
requirement. Based on the comments that we received and subsequent
stakeholder meetings, we have made changes to the monitoring plan and
have further explained our intent for the walking path. We have also
modified the digital photograph recordkeeping requirements for sources
of fugitive emissions. See section VI.f.1.h of this preamble for
further discussion.

H. Major Comments Concerning Final Standards Reflecting Next Generation
Compliance and Rule Effectiveness Strategies

1. Electronic Reporting
    Comment: While some commenters express support, several commenters
oppose electronic reporting of compliance-related records. Some of the
commenters state that they have an obligation under the rule to
maintain these records and make them available to the regulatory agency
upon request, and this should be sufficient. Providing all the records
requested under the proposed rule would likely cause a backlog of
correspondence between the regulatory agency and the industry. Other
commenters expressed concern that sensitive company information could
be present in the records, and other parties could use a FOIA request
to obtain the records.
    Additional commenters pointed out that the EPA should not require
electronic reporting until CEDRI is modified to accommodate the unique
nature of the oil and natural gas production industry. As the
commenters understand the operational characteristics of CEDRI, the
system links reports for each affected facility to the site at which
they are located. Under subparts OOOO and OOOOa, there is no unique
site identifier. This would result in owners and operators having to
deconstruct the annual report in order to obtain the affected facility
level data needed for CEDRI. The EPA did not account for this burden
and cost. The commenters request that should electronic reporting be
required, that CEDRI be revised to accept the annual reports as
currently specified in the proposed rule as a pdf file or hardcopy
until these issues can be resolved. Commenters also request that CEDRI
be modified to accept area-wide reports rather than site-level reports.
Additionally, commenters noted that the definition of ``certifying
official'' under CEDRI is different than in the proposed rule.
    Finally, since the EPA did not propose regulatory language for
these

requirements, some commenters believe that the EPA cannot finalize
these requirements without first proposing the regulatory language.
    Response: The EPA notes that regulatory language for the electronic
reporting requirements was available in Sec.  60.5420a, Sec.  60.5422a
and Sec.  60.5423a of the proposed rule.
    The EPA thanks the commenters for the support for electronic
reporting. Electronic reporting is in ever-increasing use and is
universally considered to be faster, more efficient and more accurate
for all parties once the initial systems have been established and
start-up costs completed. Electronic reporting of environmental data is
already common practice in many media offices at the EPA; programs such
as the Toxics Release Inventory (TRI), the Greenhouse Gas Reporting
Program, Acid Rain and NOX Budget Trading Programs and the
Toxic Substances Control Act (TSCA) New Chemicals Program all require
electronic submissions to the EPA. The EPA has previously implemented
similar electronic reporting requirements in over 50 different subparts
within parts 60 and 63. WebFIRE, the public access site for these data,
currently houses over 5000 reports that have been submitted to the EPA
via CEDRI.
    The EPA notes that reporting is an essential element in compliance
assurance, and this is especially true in this sector. Because of the
large number of sites and the remoteness of sites, it is unlikely that
the delegated agencies will be able to visit all sites. By providing
reports electronically in a standardized format, the system benefits
air agencies by streamlining review of data, facilitating large scale
data analysis, providing access to reports and providing cost savings
through a reduction in storage costs. The narrative and upload fields
within the CEDRI forms can even be used to provide information to
satisfy extra reporting requirements that state and local air agencies
may impose.
    The EPA is sensitive to the complexity of the oil and gas
regulations and the unique challenges presented by this sector. CEDRI
forms are designed to be consistent with the requirements of the
underlying subparts and are unique to each regulation. The forms are
reviewed multiple times before being finalized, and they are subjected
to a beta testing period that allows end-users to provide feedback on
issues with the forms prior to requiring their use. Also, if a form has
not yet been completed by the time the rule is effective, affected
facilities will not be required to use CEDRI until the form has been
available for at least 90 days. The EPA notes that we have recently
developed a bulk upload feature for several subparts within CEDRI. The
bulk upload feature allows users to enter data for sites across the
country in a single file instead of having to submit individual reports
for each site. This feature should alleviate some of the commenters'
concerns.
    The EPA is aware that facility personnel must learn the new
reporting system, but the savings realized by simplified data entry
outweighs the initial period of learning the system. Electronic
reporting can eliminate paper-based, manual processes, thereby saving
time and resources, simplifying data entry, eliminating redundancies,
minimizing data reporting errors and providing data quickly and
accurately. Reporting form standardization can also lead to cost
savings by laying out the data elements specified by the regulations in
a step-by-step process, thereby helping to ensure completeness of the
data and allowing for accurate assessment of data quality.
Additionally, the EPA's electronic reporting system will be able to
access existing information in previously submitted reports and data
stored in other EPA databases. These data can be incorporated into new
reports, which will lead to reporting burden reduction through labor
savings.
    In 2011, in response to Executive Order 13563, the EPA developed a
plan to periodically review its regulations to determine if they should
be modified, streamlined, expanded, or repealed in an effort to make
regulations more effective and less burdensome.\104\ The plan includes
replacing outdated paper reporting with electronic reporting. In
keeping with this plan and the White House's Digital Government
Strategy,\105\ in 2013 the EPA issued an agency-wide policy specifying
that EPA will start with the assumption that reporting will be
electronic and not paper. The EPA believes that the electronic
submittal of the reports addressed in this rulemaking increases the
usefulness of the data contained in those reports, is in keeping with
current trends in data availability, further assists in the protection
of public health and the environment and will ultimately result in less
burden on the regulated community. Therefore, the EPA is retaining the
requirement to report these data electronically.
---------------------------------------------------------------------------

    \104\ EPA's Final Plan for Periodic Retrospective Reviews,
August 2011. Available at: http://www.epa.gov/regdarrt/retrospective/documents/eparetroreviewplan-aug2011.pdf.
    \105\ Digital Government: Building a 21st Century Platform to
Better Serve the American People, May 2012. Available at: https://www.whitehouse.gov/sites/default/files/omb/egov/digital-government/digital-government-strategy.pdf.
---------------------------------------------------------------------------

2. Third-Party Verification for Closed Vent Systems
    Comment: Several commenters express opposition to a third-party
verification system for the design of closed vent systems. Some of the
commenters explain that they design their closed vent system using in-
house staff. Many of the details regarding actual flow volumes and gas
composition are unknown at the initial design stage, so it would not be
possible to certify the design's effectiveness prior to construction.
Also, storage vessels are designed to have some level of losses, so it
would also not be possible to certify that the closed vent system
routes all emissions to the control device.
    Several of the commenters also express concern that the
verification process discussed in the preamble to the proposed rule
would create a complex bureaucratic scheme with no measurable benefits.
Many of the commenters believe such a verification process would add a
significant labor and cost burden that the EPA has not quantified. The
EPA's contention that third-party verification ``may'' improve
compliance is presented without any analysis or support and does not
justify the costs of such a program.
    Concerning the impartiality requirements outlined by the EPA, some
of the commenters believe that it would be impossible to find someone
who is qualified to do verification that could pass those requirements
due to the interrelationship between the production and support
companies over decades of working with one another. Some commenters
contend that the EPA overestimates the availability of qualified third-
party consultants, assuming that an impartial one could be found, that
understands the industry well enough to competently review designs for
closed vent systems.
    Some of the commenters remind the EPA of the conclusions the Agency
reached after proposing a similar third-party verification system for
the Greenhouse Gas Reporting Program, in which the EPA expressed
concerns about establishing third-party verification protocols,
developing a system to accredit third-party verifiers, and developing a
system to ensure impartiality.
    Response: The EPA continues to believe that independent third party
verification can furnish more, and sometimes better, data about
regulatory compliance. With better data about compliance, regulatory
agencies, including the EPA, would have more

information to determine what types of regulations are effective and
how to spend their resources. A critical element to independent third
party verification is to ensure third-party verifiers are truly
independent from their clients and perform competently. We continue to
believe that this model best limits the risk of bias or ``capture'' due
to the third-party verifier identifying or aligning his interests too
closely with those of the client. However, in other rulemakings, we
have explored and implemented an alternative to the independent third
party verification, where engineering design is the element we wish to
ensure is examined and implemented without bias. This is the
``qualified professional engineer'' model. In the ``Resource
Conservation and Recovery Act (RCRA) Burden Reduction Initiative''
(Burden Reduction Rule) (71 FR 16826, April 4, 2006) and the ``Oil
Pollution Prevention and Response; Non-Transportation-Related Onshore
and Offshore Facilities rule (67 FR 47042, July 17, 2002), the Agency
came to similar conclusions. First, that professional engineers,
whether independent or employees of a facility, being professionals,
will uphold the integrity of their profession and only certify
documents that meet the prescribed regulatory requirements and that the
integrity of both the professional engineer and the professional
oversight of boards licensing professional engineers are sufficient to
prevent any abuses. And second, that in-house professional engineers
may be the persons most familiar with the design and operation of the
facility and that a restriction on in-house professional certifications
might place an undue and unnecessary financial burden on owners or
operators of facilities by forcing them to hire an outside engineer.
Also in the ``Burden Reduction Rule'' the Agency concluded that a
professional engineer is able to give fair and technical review because
of the oversight programs established by the state licensing boards
that will subject the professional engineer to penalties, including the
loss of license and potential fines if certifications are provided when
the facts do not warrant it. A qualified professional engineer
maintains the most important components of any certification
requirement: (1) That the engineer be qualified to perform the task
based on training and experience; and (2) that she or he be a
professional engineer licensed to practice engineering under the title
Professional Engineer which requires following a code of ethics with
the potential of losing his/her license for negligence (see 71 FR
16868, April 4, 2006). The personal liability of the professional
engineer provides strong support for both the requirement that
certifications must be performed by licensed professional engineers.
The Agency is convinced that an employee of a facility, who is a
qualified professional engineer and who has been licensed by a state
licensing board, would be no more likely to be biased than a qualified
professional engineer who is not an employee of the owner or operator.
The EPA has concluded that the programs established by state licensing
boards provide sufficient guarantees that a professional engineer,
regardless of whether he/she is ``independent'' of the facility, will
give a fair technical review. As an additional protection, the Agency
has re-evaluated the design criteria for closed vent systems to ensure
that the requirements are sufficiently objective and technically
precise, while providing site specific flexibility, that a qualified
professional engineer will be able to certify that they have been met.
    It is important to reiterate that state licensing boards can
investigate complaints of negligence or incompetence on the part of
professional engineers and may impose fines and other disciplinary
actions, such as cease-and-desist orders or license revocation. (See 71
FR 16868.) In light of the third party oversight provided by the state
licensing boards in combination with the numerous recordkeeping and
recording requirements established in this rule, the Agency is
confident that abuses of the certification requirements will be minimal
and that human health and the environment will be protected.
    In other rulemakings, which have allowed for a qualified
professional engineer in lieu of an independent reviewer, the Agency
has required that the professional engineer be licensed in the state in
which the facility is located. (See ``Hazardous and Solid Waste
Management System; Disposal of Coal Combustion Residuals from Electric
Utilities; Final Rule'' (Coal Ash Rule) (80 FR 21302, April 17, 2015)).
The Agency has made this decision, in that rule, for a number of
reasons, but primarily because state licensing boards can provide the
necessary oversight on the actions of the professional engineer and
investigate complaints of negligence or incompetence as well as impose
fines and other disciplinary actions such as cease-and-desist orders or
license revocation. The Agency concluded that oversight may not be as
rigorous if the professional engineer is operating under a license
issued from another state. While we believe this is the appropriate
outcome for the Coal Ash Rule, in part due to the regional and
geological conditions specific to the landfill design, we do not
believe that we need to provide this restriction for the closed vent
system design under this rulemaking. Closed vent system design elements
are not predicated on regional characteristics but instead follow
generally and widely understood engineering analysis such as volumetric
flow, back pressure and pressure drops. We do believe that the
professional engineer should be licensed in a minimum of one of the
states in which the certifying official does business.
    Whether to specify independent third-party reporting, some other
type of third-party or self-reporting, or a Professional Engineer is a
case-specific decision that will vary depending on the nature of the
rule, the characteristics of the sector(s) and regulated entities, and
the applicable regulatory requirements. Based on all relevant factors
for this rule, the EPA has determined that a qualified Professional
Engineer approach is appropriate and that it is unnecessary to require
the individual making certifications under this rule to be
``independent third parties.'' Thus the final rule does not prohibit an
employee of the facility from making the certification, provided they
are a professional engineer that is licensed by a state licensing
board.
3. The EPA's Authority and Costs for Standards Reflecting Next
Generation Compliance and Rule Effectiveness
    Comment: Several commenters believe that standards reflecting Next
Generation Compliance and rule effectiveness strategies discussed in
the preamble to the proposed rule are not legal and represent an
overreach of its authority. While the EPA has authority to require
reasonable recordkeeping, reporting and monitoring under the CAA, there
is nothing in the CAA that can be construed to authorize the EPA to
force the regulated community to hire a third-party contractor to do
the EPA's work. The commenters point out that the EPA admitted in the
preamble to the 2011 proposal of subpart OOOO that ensuring compliance
with the well completion requirements would be very difficult and
burdensome for regulatory agencies. The commenters believe that the EPA
is using the requirements to relieve the regulatory agencies of some of
this burden. One commenter stated that the requirements amount to an
unfunded enforcement mandate on the facilities it is supposed to be
regulating.
    The commenters also state that the compliance requirements would
violate

the Anti-Deficiency Act because the third-party verification
requirements would circumvent budget appropriations for EPA enforcement
activities (see 31 U.S.C. 1341(a)(1)(A)).
    Some of the commenters also object to the EPA justifying increased
monitoring, recordkeeping and reporting requirements on consent decrees
in enforcement actions. The commenters point out that consent decrees
impose more stringent requirements on facilities that have been found
to be in violation of a regulatory requirement; therefore, consent
decree requirements would be inappropriate for generally applicable
regulations. The commenters state that the EPA has provided no
justification for imposing heightened requirements on all facilities
regardless of their compliance history.
    Several commenters also state that the EPA must propose the
regulatory language for all of the compliance provisions reflecting
Next Generation Compliance and rule effectiveness strategies before
they can be finalized and doing otherwise would raise a notice and
comment issue. One commenter added that the EPA's intent is to apply
such compliance requirements to more industries than just oil and
natural gas production. Therefore, the EPA must separately propose the
compliance requirements in their entirety, including estimated costs
and benefits, before using them in any specific rulemakings.
    Many commenters believe the standards reflecting Next Generation
and rule effectiveness strategies will add significant labor and cost
burdens over and above the compliance costs that the EPA already
estimated for complying with the proposed rule. For example, one
commenter calculates that their company will have to generate 270,000
closed vent system monthly inspection reports in the first five years
of the rule if current requirements are finalized. Another commenter
estimates the cost of installing continuous pressure monitoring
equipment at a single site to be $20,000, resulting in potential
company-wide costs of about $15 million. One commenter adds, based on
their own experience with third-party auditors, the cost of an audit
can range from $8,000 to $15,000 per audit, per facility. In general,
the commenters state that the compliance requirements raise technical
and operational complexities which can only result in increased costs.
Some of the commenters note that these costs would be untenable for
small businesses.
    Some of the commenters also expressed concern about a lack of
necessary IT infrastructure, such as data acquisition hardware, data
management software, and appropriate software, at remote oil and
natural gas production and transmission facilities. The commenters also
point out the lack of electricity at these sites. The commenters point
out that dealing with these issues further increase the costs
associated with these compliance measures.
    Response: The EPA believes that the comment regarding our legal
authority may be based upon a misunderstanding of EPA's Next Generation
Compliance and rule effectiveness strategies. The EPA describes these
strategies as follows:
    ``Today's pollution challenges require a modern approach to
compliance, taking advantage of new tools and approaches while
strengthening vigorous enforcement of environmental laws. Next
Generation Compliance is EPA's integrated strategy to do that, designed
to bring together the best thinking from inside and outside EPA.''
\106\ Among the referenced modern approaches to compliance is to
``[d]esign regulations and permits that are easier to implement, with a
goal of improved compliance and environmental outcomes.''
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    \106\ USEPA; Next Generation Compliance Web page at https://www.epa.gov/compliance/next-generation-compliance.
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    Thus EPA's Next Generation Compliance and rule effectiveness
strategies, in and of themselves, impose no requirements or obligations
on the regulated community. The strategies establish no regulatory
terms for any sector or facility nor create rights or responsibilities
in any party. Rather, the strategies describe general compliance
assurance and regulatory design principles, approaches, and tools that
EPA may consider in conducting rulemaking, permitting, and compliance
assurance, and enforcement activities.
    Regarding comments that in order to avoid notice and comment issues
the EPA must propose regulatory language before finalizing any
regulatory language, the EPA disagrees. Section 307(d)(3) of the CAA
states that ``notice of proposed rulemaking shall be published in the
Federal Register, as provided under section 553(b) of title 5, United
States Code . . . .'' There is nothing in the remainder of section
307(d) that requires the EPA to publish the regulatory text. Similarly,
section 553(b) of the Administrative Procedure Act (APA) does not
require agencies to publish the actual regulatory text. See EMILY's
List v. FEC, 362 F. Supp. 2d 43, 53 (D.D.C. 2005), where ``[t]he Court
notes that section 553 itself does not require the Agency to publish
the text of a proposed rule, since the Agency is permitted to publish
'either the terms or substance of the proposed rule or a description of
the subjects and issues involved.' ''. For this rulemaking, the EPA has
provided notice and opportunity to comment for all of the specific
regulatory requirements applicable to the sector and facilities covered
by the rulemaking, either through proposed regulatory language or a
description in the preamble.
    The EPA notes that the proposal for independent third party
verification--replaced in the final rule with qualified Professional
Engineer requirements--reflects the responsibility of regulated
entities to comply with the new NSPS. CAA Section 111(a)(1) defines ``a
standard of performance'' as ``a standard for emissions of air
pollutants which reflects the degree of emission limitation achievable
through the application of the best system of emission reduction which
(taking into account the cost of achieving such reduction and any non-
air quality health and environmental impact and energy requirement) the
Administrator determines has been adequately demonstrated.'' Further,
in directing the Administrator to propose and promulgate regulations
under section 111(b)(1)(B), Congress provided that the Administrator
should take comment and then finalize the standards with such
modifications ``as 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 addition, the information to be collected for the proposed NSPS
is based on notification, performance tests, recordkeeping and
reporting requirements which will be mandatory for all operators
subject to the final standards. Recordkeeping and reporting
requirements are specifically authorized by section 114 of the CAA (42
U.S.C. 7414) which provides that for ``any standard of performance
under section 7411,'' the Administrator may require the sources to,
among other things, ``install, use, and maintain such monitoring
equipment, and use such audit procedures, or methods'' and submit
compliance certifications in accordance with subsection (a)(3) of this
section,'' as the Administrator may require. CAA section 114(a)(1)(A)-
(G).
    As discussed in section VI and in this section, the EPA has
determined that to comply with the new NSPS and meet its

emissions standard, regulated entities must obtain certifications from
qualified Professional Engineers to demonstrate technical infeasibility
to connect a pneumatic pump to an existing control device and to ensure
the proper closed vent system design. The EPA believes for the sources
covered by this rule, a professional engineer can furnish more, and
sometimes better, data about regulatory compliance, especially where
engineering design (e.g., closed vent system design) is the element we
want to ensure is examined and implemented without bias.
    The EPA notes that nothing in this rule relieves the EPA of any of
its responsibilities under the CAA or implies that the EPA will not
continue to use its enforcement authorities under the CAA or devote
resources to monitoring and enforcing this rule. This rule simply
ensures that regulated parties will have the tools available to assess
and ensure their own compliance.
    The EPA wishes to explain that unfunded mandates are typically
rules that impose significant obligations, without funding, on state,
local, or tribal governments.\107\ Interpreting this comment as
applying to the obligations this NSPS imposes on entities to which it
will apply, all rules, by definition, impose some obligations and
responsibilities on subject facilities. In this preamble, the EPA
explains the benefits, costs, and justification for each regulatory
requirement.
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    \107\ See USEPA, Rulemakings by Effect: Unfunded Mandates Web
site at https://yosemite.epa.gov/opei/rulegate.nsf/content/effectsunfunded.html?OpenDocument&Count=1000&ExpandView.
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    As discussed above, the EPA explains the emission standards in this
NSPS apply to the subject regulated entities. The EPA remains
responsible for ensuring and enforcing compliance with the rule. The
EPA notes that nothing in this rule relieves the EPA of any of its
responsibilities under the CAA to ensure and enforce regulatory
compliance.
    The EPA agrees, that if the EPA were to seek to apply the standards
in this rule--or any other regulatory standards, reflecting the
Agency's Next Generation Compliance and rule effectiveness strategies
or otherwise--to additional sectors beyond oil and natural gas
production, the EPA would need to separately propose and justify the
standards. As discussed above, however, the EPA's Next Generation
Compliance and rule effectiveness strategies, in and of themselves,
impose no requirements on the regulated community. The strategies
prescribe no specific regulatory terms for any sector or facility nor
do they create rights or responsibilities in any party. Rather, they
describe compliance assurance and regulatory design strategies and
approaches that the EPA will consider in conducting rulemaking,
permitting, and compliance assurance, and enforcement activities that
are inappropriate for notice and comment rulemaking. If the EPA
believes that these strategies and approaches should be applied in
other circumstances and to other industry sectors, the Agency will do
this through other regulatory actions.
    The EPA agrees with the commenters that certain of the Next
Generation and rule effectiveness strategies are the result of
information that the Agency has gained from implementation of past
consent decrees (e.g., closed vent system design and fugitives
monitoring program audit). It is not unusual for the Agency to require
additional monitoring practices, and recordkeeping and reporting
requirements through consent, as this provides us an opportunity to
identify the effectiveness of these standards from those companies that
have engaged in violative conduct. Furthermore, through our enforcement
efforts, when we see common and widespread compliance problems that can
be addressed through improved monitoring, reporting and recordkeeping
practices, it is our duty to include these tools in rulemaking,
resulting in greater environmental benefit. As discussed elsewhere in
this preamble, we are not requiring an ``independent third party''
verification of closed vent system design, nor are we requiring that
the fugitive emissions monitoring program be audited. However, because
of the widespread issues we have found with closed vent system design,
the Agency will require a certification by a qualified professional
engineer.
    Regarding the comment about necessary IT infrastructure, such as
data acquisition hardware, data management software, and appropriate
software, at remote oil and natural gas production and transmission
facilities and the lack of electricity at these sites, the Agency does
not believe that the next generation and rule effectiveness initiatives
we are proposing directly require IT infrastructure beyond that already
required by other aspects of the rule. Likewise, onsite electrical
availability for remote well sites is not an issue for the Next
Generation and Rule Effectiveness strategies that we are finalizing.

IX. Impacts of the Final Amendments

A. What are the air impacts?

    For this action, the EPA estimated the emission reductions that
will occur due to the implementation of the final emission limits. The
EPA estimated emission reductions based on the control technologies
proposed as the BSER. This analysis estimates regulatory impacts for
the analysis years of 2020 and 2025. The analysis of 2020 represents
the accumulation of new and modified sources from the first full year
of compliance, 2016, through 2020 to illustrate the near-term impacts
of the rule. The regulatory impact estimates for 2020 include sources
newly affected in 2020 as well as the accumulation of affected sources
from 2016 to 2019 that are also assumed to be in continued operation in
2020, thus incurring compliance costs and emissions reductions in 2020.
We also estimate impacts in 2025 to illustrate the continued compound
effect of this rule over a longer period. The regulatory impact
estimates for 2025 include sources newly affected in 2025 as well as
the accumulation of affected sources from 2016 to 2024 that are also
assumed to be in continued operation in 2025, thus incurring compliance
costs and emissions reductions in 2025.
    In 2020, we have estimated that the final NSPS would reduce about
300,000 tons of methane emissions and 150,000 tons of VOC emissions
from affected facilities. In 2025, we have estimated that the proposed
NSPS would reduce about 510,000 tons of methane emissions and 210,000
tons of VOC emissions from affected facilities. The NSPS is also
expected to concurrently reduce about 1,900 tons HAP in 2020 and 3,900
tons HAP in 2025.
    As described in the TSD and RIA for this rule, the EPA projected
affected facilities using a combination of historical data from the
United States GHG Inventory, and projected activity levels, taken from
the Energy Information Administration (EIA's) Annual Energy Outlook
(AEO). The EPA also considered state regulations with similar
requirements to the final NSPS in projecting affected sources for
impacts analyses supporting this rule.

B. What are the energy impacts?

    Energy impacts in this section are those energy requirements
associated with the operation of emission control devices. Potential
impacts on the national energy economy from the rule are discussed in
the economic impacts section. There would be little national energy
demand increase from the operation of any of the environmental

controls expected to be used for compliance with the final NSPS.
    The final NSPS encourages the use of emission controls that recover
hydrocarbon products, such as methane, that can be used onsite as fuel
or reprocessed within the production process for sale. We estimate that
the standards will result in a total cost of about $320 million in 2020
and $530 million in 2025 (in 2012 dollars).

C. What are the compliance costs?

    The EPA estimates the total capital cost of the final NSPS will be
$250 million in 2020 and $360 million in 2025. The estimate of total
annualized engineering costs of the final NSPS is $390 million in 2020
and $640 million in 2025. This annual cost estimate includes capital,
operating, maintenance, monitoring, reporting, and recordkeeping costs.
This estimated annual cost does not take into account any producer
revenues associated with the recovery of salable natural gas. The EPA
estimates that about 16 billion cubic feet in 2020 and 27 billion cubic
feet of natural gas in 2025 will be recovered by implementing the NSPS.
In the engineering cost analysis, we assume that producers are paid $4
per thousand cubic feet (Mcf) for the recovered gas at the wellhead.
After accounting for these revenues, the estimate of total annualized
engineering costs of the final NSPS are estimated to be $320 million in
2020 and $530 million in 2025.\108\ The price assumption is influential
on estimated annualized engineering costs. A simple sensitivity
analysis indicates $1/Mcf change in the wellhead price causes a change
in estimated engineering compliance costs of about $16 million in 2020
and $27 million in 2025.
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    \108\ To the extent that NSPS affected facilities would have
controlled emissions voluntarily through the Methane Challenge or
other initiatives, the estimated costs and benefits of the NSPS
would be lower than those included in the RIA analysis.
---------------------------------------------------------------------------

D. What are the economic and employment impacts?

    The EPA used the National Energy Modeling System (NEMS) to estimate
the impacts of the final rule on the United States energy system. The
NEMS is a publically-available model of the United States energy
economy developed and maintained by the EIA and is used to produce the
AEO, a reference publication that provides detailed forecasts of the
United States energy economy.
    The EPA estimate that natural gas and crude oil drilling levels
decline slightly over the 2020 to 2025 period relative to the baseline
(by about 0.17 percent for natural gas wells and about 0.02 percent for
crude oil wells). Natural gas production decreases slightly over the
2020 to 2025 period relative to the baseline (by about 0.03 percent),
while crude oil production does not vary appreciably. Crude oil
wellhead prices for onshore lower 48 production are not estimated to
change appreciably over the 2020 to 2025 period relative to the
baseline. However, wellhead natural gas prices for onshore lower 48
production are estimated to increase slightly over the 2020 to 2025
period relative to the baseline (about 0.20 percent). Net imports of
natural gas are estimated to increase slightly over the 2020 to 2025
period relative to the baseline (by about 0.11 percent). Crude oil net
imports are not estimated to change appreciably over the 2020 to 2025
period relative to the baseline.
    Executive Order 13563 directs federal agencies to consider the
effect of regulations on job creation and employment. According to the
Executive Order, ``our regulatory system must protect public health,
welfare, safety, and our environment while promoting economic growth,
innovation, competitiveness, and job creation. It must be based on the
best available science.'' (Executive Order 13563, 2011) While a
standalone analysis of employment impacts is not included in a standard
benefit-cost analysis, such an analysis is of particular concern in the
current economic climate given continued interest in the employment
impact of regulations such as this final rule.
    The EPA estimated the labor impacts due to the installation,
operation, and maintenance of control equipment, control activities,
and labor associated with new reporting and recordkeeping requirements.
We estimated up-front and continual, annual labor requirements by
estimating hours of labor required for compliance and converting this
number to full-time equivalents (FTEs) by dividing by 2,080 (40 hours
per week multiplied by 52 weeks). The up-front labor requirement to
comply with the proposed NSPS is estimated at about 270 FTEs in both
2020 and 2025. The annual labor requirement to comply with final NSPS
is estimated at about 1,100 FTEs in 2020 and 1,800 FTEs in 2025.
    We note that this type of FTE estimate cannot be used to identify
the specific number of employees involved or whether new jobs are
created for new employees versus displacing jobs from other sectors of
the economy.

E. What are the benefits of the final standards?

    The final rule is expected to result in significant reductions in
emissions. In 2020, the final rule is anticipated to reduce 300,000
short tons, or 280,000 metric tons, of methane (a GHG and a precursor
to tropospheric ozone formation), 150,000 tons of VOC (a precursor to
both PM (2.5 microns and less) (PM2.5) and ozone formation),
and 1,900 tons of HAP. In 2025, the final rule is anticipated to reduce
510,000 short tons (460,000 metric tons) of methane, 210,000 tons of
VOC, and 3,900 tons of HAP. These pollutants are associated with
substantial health effects, climate effects, and other welfare effects.
    The final standards are expected to reduce methane emissions
annually by about 6.9 million metric tons CO2 Eq. in 2020
and by about 11 million metric tons CO2 Eq. in 2025. It is
important to note that the emission reductions are based upon predicted
activities in 2020 and 2025; however, the EPA did not forecast sector-
level emissions in 2020 and 2025 for this rulemaking. To give a sense
of the magnitude of the reductions, the methane reductions expected in
2020 are equivalent to about 2.8 percent of the methane emissions for
this sector reported in the United States GHG Inventory for 2014 (about
232 million metric tons CO Eq. from petroleum and natural gas
production and gas processing, transmission, and storage). Expected
reductions in 2025 are equivalent to around 4.7 percent of 2014
emissions. As it is expected that emissions from this sector would
increase over time, the estimates compared against the 2014 emissions
would likely overestimate the percent of reductions from total
emissions in 2020 and 2025.
    Methane is a potent GHG that, once emitted into the atmosphere,
absorbs terrestrial infrared radiation that contributes to increased
global warming and continuing climate change. Methane reacts in the
atmosphere to form tropospheric ozone and stratospheric water vapor,
both of which also contribute to global warming. When accounting for
the impacts of changing methane, tropospheric ozone, and stratospheric
water vapor concentrations, the Intergovernmental Panel on Climate
Change (IPCC) 5th Assessment Report (2013) found that historical
emissions of methane accounted for about 30 percent of the total
current warming influence (radiative forcing) due to historical
emissions of GHGs. Methane is therefore a major contributor to the
climate

change impacts described previously. In 2013, total methane emissions
from the oil and natural gas industry represented nearly 29 percent of
the total methane emissions from all sources and account for about 3
percent of all CO2-equivalent emissions in the United
States, with the combined petroleum and natural gas systems being the
largest contributor to United States anthropogenic methane emissions.
    We calculated the global social benefits of methane emission
reductions expected from the final NSPS standards for oil and natural
gas sites using estimates of the social cost of methane (SC-
CH4), a metric that estimates the monetary value of impacts
associated with marginal changes in methane emissions in a given year.
The SC-CH4 estimates applied in this analysis were developed
by Marten et al. (2014) and are discussed in greater detail below.
    A similar metric, the social cost of CO2 (SC-
CO2), provides important context for understanding the
Marten et al. SC-CH4 estimates.\109\ The SC-CO2
is a metric that estimates the monetary value of impacts associated
with marginal changes in CO2 emissions in a given year.
Similar to the SC-CH4, it includes a wide range of
anticipated climate impacts, such as net changes in agricultural
productivity, property damage from increased flood risk, and changes in
energy system costs, such as reduced costs for heating and increased
costs for air conditioning. Estimates of the SC-CO2 have
been used by the EPA and other federal agencies to value the impacts of
CO2 emissions changes in benefit cost analysis for GHG-
related rulemakings since 2008.
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    \109\ Previous analyses have commonly referred to the social
cost of carbon dioxide emissions as the social cost of carbon or
SCC. To more easily facilitate the inclusion of non-CO2
GHGs in the discussion and analysis the more specific SC-
CO2 nomenclature is used to refer to the social cost of
CO2 emissions.
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    The SC-CO2 estimates were developed over many years,
using the best science available, and with input from the public.
Specifically, an interagency working group (IWG) that included the EPA
and other executive branch agencies and offices used three integrated
assessment models (IAMs) to develop the SC-CO2 estimates and
recommended four global values for use in regulatory analyses. The SC-
CO2 estimates were first released in February 2010 and
updated in 2013 using new versions of each IAM. The 2010 SC-
CO2 Technical Support Document (2010 TSD) provides a
complete discussion of the methods used to develop these estimates and
the current SC-CO2 TSD presents and discusses the 2013
update (including recent minor technical corrections to the
estimates).\110\
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    \110\ Both the 2010 SC-CO2 TSD and the current TSD
are available at: https://www.whitehouse.gov/omb/oira/social-cost-of-carbon.
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    The SC-CO2 TSDs discuss a number of limitations to the
SC-CO2 analysis, including the incomplete way in which the
IAMs capture catastrophic and non-catastrophic impacts, their
incomplete treatment of adaptation and technological change,
uncertainty in the extrapolation of damages to high temperatures, and
assumptions regarding risk aversion. Currently, IAMs do not assign
value to all of the important physical, ecological, and economic
impacts of climate change recognized in the climate change literature
due to a lack of precise information on the nature of damages and
because the science incorporated into these models understandably lags
behind the most recent research. Nonetheless, these estimates and the
discussion of their limitations represent the best available
information about the social benefits of CO2 reductions to
inform benefit-cost analysis. The EPA and other agencies continue to
engage in research on modeling and valuation of climate impacts with
the goal to improve these estimates and continue to consider feedback
on the SC-CO2 estimates from stakeholders through a range of
channels, including public comments on Agency rulemakings, a separate
Office of Management and Budget (OMB) public comment solicitation, and
through regular interactions with stakeholders and research analysts
implementing the SC-CO2 methodology. See the RIA of this
rule for additional details.
    A challenge particularly relevant to this rule is that the IWG did
not estimate the social costs of non-CO2 GHG emissions at
the time the SC-CO2 estimates were developed. In addition,
the directly modeled estimates of the social costs of non-
CO2 GHG emissions previously found in the published
literature were few in number and varied considerably in terms of the
models and input assumptions they employed \111\ (EPA 2012). In the
past, EPA has sought to understand the potential importance of
monetizing non-CO2 GHG emissions changes through sensitivity
analysis using an estimate of the GWP of methane to convert emission
impacts to CO2 equivalents, which can then be valued using
the SC-CO2 estimates. This approach approximates the social
cost of methane (SC-CH4) using estimates of the SC-
CO2 and the GWP of methane.\112\
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    \111\ U.S. EPA. 2012. Regulatory Impact Analysis Final New
Source Performance Standards and Amendments to the National
Emissions Standards for Hazardous Air Pollutants for the Oil and
Natural Gas Industry. Office of Air Quality Planning and Standards,
Health and Environmental Impacts Division. April. http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf. Accessed March 30, 2015.
    \112\ For example, see (1) U.S. EPA. (2012). ``Regulatory impact
analysis supporting the 2012 U.S. Environmental Protection Agency
final new source performance standards and amendments to the
national emission standards for hazardous air pollutants for the oil
and natural gas industry.'' Retrieved from http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf and (2)
U.S. EPA. (2012). ``Regulatory impact analysis: Final rulemaking for
2017-2025 light-duty vehicle greenhouse gas emission standards and
corporate average fuel economy standards.'' Retrieved from http://www.epa.gov/otaq/climate/documents/420r12016.pdf.
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    The published literature documents a variety of reasons that
directly modeled estimates of SC-CH4 are an analytical
improvement over the estimates from the GWP approximation approach.
Specifically, several recent studies found that GWP-weighted benefit
estimates for methane are likely to be lower than the estimates derived
using directly modeled social cost estimates for these gases.\113\ The
GWP reflects only the relative integrated radiative forcing of a gas
over 100 years in comparison to CO2. The directly modeled
social cost estimates differ from the GWP-scaled SC-CO2
because the relative differences in timing and magnitude of the warming
between gases are explicitly modeled, the non-linear effects of
temperature change on economic damages are included, and rather than
treating all impacts over a hundred years equally, the modeled damages
over the time horizon considered (300 years in this case) are
discounted to present value terms. A detailed discussion of the
limitations of the GWP approach can be found in the RIA.
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    \113\ See Waldhoff et al. (2011); Marten and Newbold (2012); and
Marten et al. (2014).
---------------------------------------------------------------------------

    In general, the commenters on previous rulemakings strongly
encouraged the EPA to incorporate the monetized value of non-
CO2 GHG impacts into the benefit cost analysis. However,
they noted the challenges associated with the GWP approach, as
discussed above, and encouraged the use of directly modeled estimates
of the SC-CH4 to overcome those challenges.
    Since then, a paper by Marten et al. (2014) has provided the first
set of published SC-CH4 estimates in the peer-reviewed
literature that are consistent with the modeling assumptions underlying
the SC-CO2 estimates.114 115

Specifically, the estimation approach of Marten et al. used the same
set of three IAMs, five socioeconomic and emissions scenarios,
equilibrium climate sensitivity distribution, three constant discount
rates, and aggregation approach used by the IWG to develop the SC-
CO2 estimates.
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    \114\ Marten et al. (2014) also provided the first set of SC-
N2O estimates that are consistent with the assumptions
underlying the IWG SC-CO2 estimates.
    \115\ Marten, A.L., E.A. Kopits, C.W. Griffiths, S.C. Newbold &
A. Wolverton (2014, online publication; 2015, print publication).
Incremental CH4 and N2O mitigation benefits
consistent with the United States Government's SC-CO2
estimates, Climate Policy, DOI: 10.1080/14693062.2014.912981.
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    The SC-CH4 estimates from Marten et al. (2014) are
presented below in Table 8. More detailed discussion of the SC-
CH4 estimation methodology, results and a comparison to
other published estimates can be found in the RIA and in Marten et al.

                                    Table 8--Social Cost of CH4, 2012-2050 a
                            [In 2012$ per metric ton] (Source: Marten et al., 2014 b)
----------------------------------------------------------------------------------------------------------------
                                                                            SC-CH4
                    Year                     -------------------------------------------------------------------
                                                5% Average      3% Average     2.5% Average   3% 95th percentile
----------------------------------------------------------------------------------------------------------------
2012........................................            $430           $1000           $1400               $2800
2015........................................             490            1100            1500                3000
2020........................................             580            1300            1700                3500
2025........................................             700            1500            1900                4000
2030........................................             820            1700            2200                4500
2035........................................             970            1900            2500                5300
2040........................................            1100            2200            2800                5900
2045........................................            1300            2500            3000                6600
2050........................................            1400            2700            3300                7200
----------------------------------------------------------------------------------------------------------------
Notes:
a There are four different estimates of the SC-CH4, each one emissions-year specific. The first three shown in
  the table are based on the average SC-CH4 from three integrated assessment models at discount rates of 5, 3,
  and 2.5 percent. The fourth estimate is the 95th percentile of the SC-CH4 across all three models at a 3
  percent discount rate. See RIA for details.
b The estimates in this table have been adjusted to reflect the minor technical corrections to the SC-CO2
  estimates described above. See the Corrigendum to Marten et al. (2014), http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550.

    The application of these directly modeled SC-CH4
estimates from Marten et al. (2014) in a benefit-cost analysis of a
regulatory action is analogous to the use of the SC-CO2
estimates. In addition, the limitations for the SC-CO2
estimates discussed above likewise apply to the SC-CH4
estimates, given the consistency in the methodology.
    In early 2015, the EPA conducted a peer review of the application
of the Marten et al. (2014) non-CO2 social cost estimates in
regulatory analysis and received responses that supported this
application. See the RIA for a detailed discussion.
    The EPA also carefully considered the full range of public comments
and associated technical issues on the Marten et al. SC-CH4
estimates received through this rulemaking. The comments addressed the
technical details of the SC-CO2 estimates and the Marten et
al. SC-CH4 estimates as well as their application to this
rulemaking analysis. The commenters also provided constructive
recommendations to improve the SC-CO2 and SC-CH4
estimates in the future. Based on the evaluation of the public comments
on this rulemaking, the favorable peer review of the Marten et al.
application, and past comments urging the EPA to value non-
CO2 GHG impacts in its rulemakings, the EPA concluded that
the estimates represent the best scientific information on the impacts
of climate change available in a form appropriate for incorporating the
damages from incremental methane emissions changes into regulatory
analysis. The EPA has included those benefits in the main benefits
analysis. See the RTC document for the complete response to comments
received on the SC-CH4 as part of this rulemaking.
    The methane benefits calculated using Marten et al. (2014) are
presented in Table 9 for years 2020 and 2025. Applying this approach to
the methane reductions estimated for the NSPS, the 2020 methane
benefits vary by discount rate and range from about $160 million to
approximately $960 million; the mean SC-CH4 at the 3-percent
discount rate results in an estimate of about $360 million in 2020. The
methane benefits increase in the 2025, ranging from $320 million to
$1.8 billion, depending on discount rate used; the mean SC-
CH4 at the 3-percent discount rate results in an estimate of
about $690 million in 2025.

        Table 9--Estimated Global Benefits of Methane Reductions
                          [In millions, 2012$]
------------------------------------------------------------------------
                                                       Year
       Discount rate and statistic       -------------------------------
                                               2020            2025
------------------------------------------------------------------------
Million metric tonnes of methane reduced            0.28            0.46
Million metric tonnes of CO2 Eq.........             6.9              11
    5% (average)........................            $160            $320
    3% (average)........................            $360            $690
    2.5% (average)......................            $480            $890
    3% (95th percentile)................            $960          $1,800
------------------------------------------------------------------------

    In addition to the limitation discussed above, and the referenced
documents, there are additional impacts of individual GHGs that are not
currently captured in the IAMs used in the directly modeled approach of
Marten et al. (2014) and, therefore, not quantified for the rule. For
example, in addition to being a GHG, methane is a precursor to ozone.
The ozone generated by methane has important non-climate impacts on
agriculture, ecosystems, and human health. The RIA describes the
specific impacts of methane as an ozone precursor in more detail and
discusses studies that have estimated monetized benefits of these
methane generated ozone effects. The EPA continues to monitor
developments in this area of research.
    With the data available, we are not able to provide credible health
benefit estimates for the reduction in exposure to HAP, ozone and
PM2.5 for these rules, due to the differences in the
locations of oil and natural gas emission points relative to existing
information and the highly localized nature of air quality responses
associated with HAP and VOC reductions. This is not to imply that there
are no benefits of the rules; rather, it is a reflection of the
difficulties in modeling the direct and indirect impacts of the
reductions in emissions for this industrial sector with the data
currently available.\116\ In addition to health improvements, there
will be improvements in visibility effects, ecosystem effects and
climate effects, as well as additional product recovery.
---------------------------------------------------------------------------

    \116\ Previous studies have estimated the monetized benefits-
per-ton of reducing VOC emissions associated with the effect that
those emissions have on ambient PM2.5 levels and the
health effects associated with PM2.5 exposure (Fann,
Fulcher, and Hubbell, 2009). While these ranges of benefit-per-ton
estimates can provide useful context, the geographic distribution of
VOC emissions from the oil and gas sector are not consistent with
emissions modeled in Fann, Fulcher, and Hubbell (2009). In addition,
the benefit-per-ton estimates for VOC emission reductions in that
study are derived from total VOC emissions across all sectors.
Coupled with the larger uncertainties about the relationship between
VOC emissions and PM2.5 and the highly localized nature
of air quality responses associated with HAP and VOC reductions,
these factors lead us to conclude that the available VOC benefit-
per-ton estimates are not appropriate to calculate monetized
benefits of these rules, even as a bounding exercise.
---------------------------------------------------------------------------

    Although we do not have sufficient information or modeling
available to provide quantitative estimates for this rulemaking, we
include a qualitative assessment of the health effects associated with
exposure to HAP, ozone and PM2.5 in the RIA for this rule.
These qualitative effects are briefly summarized below, but for more
detailed information, please refer to the RIA, which is available in
the docket. One of the HAP of concern from the oil and natural gas
sector is benzene, which is a known human carcinogen. VOC emissions are
precursors to both PM2.5 and ozone formation. As documented
in previous analyses (U.S. EPA, 2006 \117,\ U.S. EPA, 2010 \118\, and
U.S. EPA, 2014 \119\), exposure to PM2.5 and ozone is
associated with significant public health effects. PM2.5 is
associated with health effects, including premature mortality for
adults and infants, cardiovascular morbidity such as heart attacks, and
respiratory morbidity such as asthma attacks, acute bronchitis,
hospital admissions and emergency room visits, work loss days,
restricted activity days and respiratory symptoms, as well as
visibility impairment.\120\ Ozone is associated with health effects,
including hospital and emergency department visits, school loss days
and premature mortality, as well as injury to vegetation and climate
effects.\121\
---------------------------------------------------------------------------

    \117\ U.S. EPA. RIA. National Ambient Air Quality Standards for
Particulate Matter, Chapter 5. Office of Air Quality Planning and
Standards, Research Triangle Park, NC. October 2006. Available on
the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/
Chapter%205_Benefits.pdf.
    \118\ U.S. EPA. RIA. National Ambient Air Quality Standards for
Ozone. Office of Air Quality Planning and Standards, Research
Triangle Park, NC. January 2010. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/s1-supplemental_analysis_full.pdf.
    \119\ U.S. EPA. RIA. National Ambient Air Quality Standards for
Ozone. Office of Air Quality Planning and Standards, Research
Triangle Park, NC. December 2014. Available on the Internet at
http://www.epa.gov/ttnecas1/regdata/RIAs/20141125ria.pdf.
    \120\ U.S. EPA. Integrated Science Assessment for Particulate
Matter (Final Report). EPA-600-R-08-139F. National Center for
Environmental Assessment--RTP Division. December 2009. Available at
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
    \121\ U.S. EPA. Air Quality Criteria for Ozone and Related
Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. Washington,
DC: U.S. EPA. February 2006. Available on the Internet at http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
---------------------------------------------------------------------------

    Finally, the control techniques to meet the standards are
anticipated to have minor secondary emissions impacts, which may
partially offset the direct benefits of this rule. The magnitude of
these secondary air pollutant impacts is small relative to the direct
emission reductions anticipated from this rule.
    In particular, the EPA has estimated that an increase in flaring of
natural gas in response to this rule will produce a variety of
emissions, including about 1.0 million short tons of CO2 in
2020 and about 1.2 million short tons of CO2 in 2025. The
EPA has not estimated the monetized value of the secondary emissions of
CO2 because much of the VOCs and methane that would have
been released in the absence of the flare would have eventually
oxidized into CO2 in the atmosphere. Note that the
CO2 produced from the methane oxidizing in the atmosphere is
not included in the calculation of the SC-CH4.
    For VOC emissions, the oxidization period is relatively short, on
the order of a couple of weeks. However, for methane, the oxidization
period is longer, on the order of a decade, and the EPA recognizes that
because the growth rate of the SC-CO2 estimates are lower
than their associated discount rates, the estimated impact of
CO2 produced in the future via oxidized methane from fossil-
based emissions may be less than the estimated impact of CO2
released immediately from combustion. This would imply a small
disbenefit associated with the earlier release of CO2 during
combustion of the methane emissions.
    In the proposal, the EPA solicited comment on the appropriateness
of monetizing the impact of the earlier release of CO2 due
to combusting methane emissions from oil and gas sites and an
illustrative analysis that described a potential approach to
approximate this value using the SC-CO2. The EPA did not
receive any comments regarding the appropriate methodology for