aware that the captured gas is not always routed to a flare but in many
cases is routed back to the compressor suction or fuel system. Given
this information, the EPA has re-evaluated the costs for the
centrifugal compressor wet seal capture system and determined a system
of this type, in which the seal oil degassing vents are routed to fuel
gas, compressor suction or an existing flare would cost $22,000. The
estimated cost includes an intermediate pressure degassing drum, new
piping, gas demister/filter and a pressure regulator for the fuel line.
With this cost, the estimated VOC control cost effectiveness is $161/
ton of VOC for the processing segment. If savings are included, the
cost effectiveness for VOC control is -$2,408/ton of VOC.
    In light of the above, we have determined that the control option
described above is the BSER for wet seal compressors. Accordingly, the
final NSPS would require that wet seal compressors reduce emission by
95 percent. For dry seal compressors, the only emission control option
we have identified is the use of dry seal. Accordingly, there is no
requirement in the final rule for dry seal compressors, and dry seal
compressors are not affected facilities under the NSPS.
3. New Source Definition
    Comment: Several commenters oppose the proposal in 40 CFR
60.5365(b) and (c) that a reciprocating compressor be considered as
``commenced construction'' on the date of installation at a facility.
Commenters argue that the EPA was ``arbitrary and capricious'' in
proposing to apply the concept of ``commenced construction'' in the
NSPS context to a relocated compressor, because the agency had no
``reasoned explanation'' for making the change and that applying the
concept of ``commenced construction'' to a relocated compressor is
contrary to the plain language of the CAA.
    Response: The EPA traditionally defines the term ``commence
construction,'' as it applies to an equipment, to mean the time an
owner or operator has entered into a contractual obligation to acquire
the equipment. This is reflected in the definition of ``commenced'' in
the General Provisions at 40 CFR 60.2, as well as in the relevant NSPS
(see, e.g., 40 CFR 60.4230(a) of subpart JJJJ). We, therefore, agree
with the commenters that our proposed definition of ``commence
construction'' in 40 CFR 60.5365(b) and 40 CFR 60.5365(c) as the time
of installation is a deviation from our traditional view. Upon
reviewing the comments and re-evaluating the proposed definition, we
conclude that there is no discernible difference between the
compressors at issue and other equipment subject to NSPS that would
make such deviation necessary or appropriate in this case. We have,
therefore, removed these specific definitions of ``commence
construction'' in 40 CFR 60.5365(b) and 40 CFR 60.5365(c) in the final
rule.

    The NSPS also does not apply to relocated compressors. As provided
in the NSPS General Provisions at 40 CFR 60.14(e)(6), relocation of an
existing facility is not modification.

E. Major Comments Concerning Storage Vessels

1. Applicability Threshold Metric
    Comment: Numerous commenters objected to the EPA's proposed use of
liquid throughput to determine which storage vessels should be subject
to the standards, asserting that the high variability in volatility of
stored liquids and other parameters affecting emissions makes
throughput a poor indicator of VOC emissions. The commenters indicate
that, as a result, basing applicability on throughput would bring many
storage vessels with low VOC emissions (some less than 1 tpy) under the
standard and the required emission controls would not be cost-
effective. Some commenters point out that certain storage vessels with
high emissions might not be subject to the standards based on
throughput.
    Response: In its BSER analysis for storage vessels, the EPA
estimated the VOC emissions for storage vessels with various levels of
throughputs to determine the cost effectiveness of control. In that
analysis, the EPA estimated that storage vessels with throughput rates
of 1 barrel per day (bpd) of condensate or 20 bpd of crude oil are
equivalent to VOC emissions of 6 tpy and determined that control is
cost effective for these storage vessels. The EPA agrees with the
comments that throughput is not a good indicator of VOC emissions and,
therefore, not appropriate for determining the standards'
applicability. However, the EPA has received no comment contesting the
EPA's conclusion that regulating storage vessels emitting 6 tpy or more
of VOC is cost effective and appropriate (the basis of our proposed
throughput limit). Accordingly, in the final rule, the storage vessels
NSPS applies to those emitting 6 tpy or more of VOC. This change from
proposal would ensure that controls will be required only on those
storage vessels where they can be applied cost effectively. This
approach also allows for broader coverage across all types of storage
vessels, regardless of the fluid that is stored or where the storage
vessel may be located. The final rule reflects this change and has
established a VOC emissions threshold of 6 tpy for storage vessels to
require control. Based on our revised cost analysis, we determined that
storage vessels with VOC emissions equal to or greater than 6 tpy or
greater were cost effective to control at $3,400/ton of VOC. The final
rule requires each facility to determine its own emission factor and
calculate the estimated emissions from each storage vessel.
2. Definition of Affected Facility
    Comment: Numerous commenters commented on the definition of storage
vessel in 40 CFR part 60, subpart OOOO, calling for greater clarity and
consistency and requesting that certain activities or equipment be
included or excluded from the definition.
    Response: The EPA agrees with the commenters who assert that a more
specific and consistent definition of a storage vessel is needed. The
revised definition more clearly focuses on identifying which units are
considered storage vessels under this subpart and which units are not
and describes a storage vessel using terminology similar to that used
in 40 CFR part 63, subpart HH. We believe it is important to be
somewhat consistent in terminology because the NSPS and NESHAP both
apply to the oil and natural production segment where these tanks are
primarily located. We also removed the emissions threshold from the
definition and, instead, based the standard in 40 CFR 60.5395 on the
VOC emission rate of the storage vessel. In response to comments
requesting clarification on whether mobile units are considered storage
vessels, we have set a minimum amount of time (180 consecutive days)
that the storage vessel must be stationed at the same site before it is
subject to 40 CFR part 60, subpart OOOO. Our reasoning for setting this
minimum amount of time is discussed in the response to comment
immediately below. Additionally, we have not excluded wastewater
storage vessels, as the NSPS requires control for all storage vessels
emitting at least 6 tpy of VOC. Further, some wastewater tanks
containing significant amounts of organic compounds could exceed VOC
emissions of 6 tpy. Finally, the revised definition includes specific
exemptions for process vessels and pressure vessels to clarify that
these units are not considered storage vessels. Since the applicability
of subpart OOOO, as finalized, is not based on throughput, we believe
it is not necessary to specify which types of stored materials are
regulated and which are not, as suggested by commenters. If a stored
material is emitting at least 6 tpy of VOC, then the storage vessel
will need to reduce its VOC emissions by 95 percent.
    Comment: Some commenters assert that the EPA should limit
applicability to storage vessels that are stationary and should clarify
the meaning of ``stationary'' to include or exclude certain types of
storage vessels.
    Additionally, the EPA received comments requesting that the
stationary aspect of the ``storage vessel'' definition should be
consistent with other rules, while acknowledging the particular
scenarios unique to the oil and gas production segment. The commenter
notes that the stationary aspect of a storage vessel is typically
addressed by the EPA in terms of whether it is reasonably portable,
although the EPA sometimes addresses portability based on the size of
the vessel. The commenter states that another criterion specified by
the EPA in several regulations is that ``vessels permanently attached
to motor vehicles'' are not storage vessels, and the EPA has issued a
determination that this exemption extends to storage vessels ``equipped
with a permanently attached wheel assembly and a truck hitch'' (U.S.
Environmental Protection Agency, letter from George T. Czerniak to Ken
Comey, Flint Hills Resources L.P., September 2, 2004). According to the
commenter, this renders most so-called frac tanks, Baker tanks,
International Organization for Standardization tanks, etc., exempt from
the storage vessel provisions when this form of definition is used.
However, the commenter recognizes that such storage vessels sometimes
become effectively ``stationary'' in oil and gas production operations
and suggests that storage vessels should be deemed stationary if they
remain at a given site for more than 180 consecutive days, consistent
with the period of time allowed under 40 CFR 60.14(g) to achieve
compliance after a modification. The commenter notes that this 180-day
period is reasonable given that the definition of non-road engines in
40 CFR 89.2 allows a period of 12 consecutive months.
    The commenter also points out that cost effectiveness of the
proposed control measures has been evaluated under the assumption that
storage vessels remain in place for the useful life of the control
equipment, and, thus, the control costs are amortized over a period of
years. Since the cost per ton of emission reductions would be much
higher if the controls were applied to a storage vessel that is only on
site temporarily, the commenter believes that a cost-effectiveness
analysis for permanent storage vessels would not be valid for temporary
storage vessels, and, thus, the control requirements for permanent
storage vessels are not justified for temporary storage vessels. The
commenter provides recommended language for the definition of ``storage
vessel'' that addresses this and other

concerns. Another commenter similarly states that costly control
requirements are not appropriate for temporary storage vessels (on site
less than 180 days).
    Response: Based on the commenter's suggestion, the EPA has revised
the definition of storage vessel to clarify that a storage vessel is
subject to 40 CFR part 60, subpart OOOO if it remains on a given site
for more than 180 consecutive days.
    In general, we agree with the commenter's discussion about the
EPA's past practices related to storage vessels. In particular, we
agree that the inherent differences between ``mobile'' or temporary
storage vessels in this source category and other categories indicate
that they should be regulated differently. As mentioned in the previous
response, there are many storage vessels in this source category that
travel from site to site, so we did not feel it was appropriate to
exclude all of these mobile storage vessels from control requirements.
Many temporary storage vessels in this source category are typically
bringing in material such as fracking fluid to well sites and can stay
at a well site for up to several months in order to receive flowback.
These storage vessels are considered to be an essential part of the
drilling and production operation, more akin to how permanent storage
vessels are utilized in the refining and organic chemical manufacturing
sectors, rather than to conventional tank trucks that are typically
excluded in other EPA rules. Therefore, we believe that 180 days is an
appropriate period of time to establish a temporary tank as being
subject to 40 CFR part 60, subpart OOOO, and, therefore, potentially
required to install controls.
3. References to MACT Standards
    Comment: The EPA received comment asserting that the outcome of its
best demonstrated technology (BDT) analysis for proposed 40 CFR part
60, subpart OOOO was calculated to achieve the same level of control as
40 CFR part 63, subpart HH--undermining the BDT determination and
effectively (and unlawfully) extending subpart HH major source MACT
requirements to area source storage vessels.
    As a result, the commenter asserts that the EPA's analysis
precludes other potentially relevant regulatory alternatives--such as
marginally less effective controls that might be applied to a broader
range of storage vessels. The commenter states that the EPA's failure
to consider other control techniques and other levels of control
efficiency that might be achieved by its preferred techniques is
arbitrary and capricious.
    Response: The commenter incorrectly asserts that the EPA's NSPS for
storage vessels was designed to achieve the same level of control as
MACT in 40 CFR part 63, subpart HH. In Portland Cement Assoc. v. EPA,
665 F.3d 177 (D.C. Cir. 2011), the United States Court of Appeals for
the District of Columbia Circuit rejected an argument that the EPA
adopted NESHAP PM standards for NSPS, noting that the EPA arrived at
the same limit for both NESHAP and NSPS using two different mechanisms.
Similarly, in this case, although both the NESHAP and the NSPS require
95-percent control, the EPA established the two standards based on
separate mechanisms. The EPA established the MACT standard in 1998
pursuant to section 112(d)(2) and (3) of the CAA. In contrast, the EPA
established the NSPS based on BSER analysis under CAA section 111. The
BSER analysis for storage vessels consists of the same steps as those
for other affected sources evaluated in the proposed NSPS.
Specifically, the EPA evaluated available information to identify VOC
control options. The EPA then assessed various aspects of the control
options, including their VOC reduction potentials, their cost
effectiveness and secondary air impacts. The commenter did not claim
that any part of the EPA's BSER analysis above was inaccurate or
inappropriate. For the reasons stated above, the commenter's assertion
is without support.
    The commenter also claims that the EPA only analyzed two controls
and, therefore, failed to consider other ``potentially relevant
regulatory alternatives.'' However, the commenter did not identify any
other control option for the EPA's consideration. The commenter simply
suggests that the EPA should consider some less effective controls,
which the commenter claims would have led to greater coverage. Without
more information, it is unclear whether a less effective control than
that we have identified would, in fact, qualify as BSER for controlling
VOC emissions from storage vessels or would have resulted in coverage
of additional storage vessels.
    Comment: Two commenters state that the cost of the performance
tests, monitoring, recordkeeping, etc., that are required through
cross-references to 40 CFR part 63, subpart HH were not adequately
considered by the EPA in the cost-effectiveness determination for 40
CFR part 60, subpart OOOO, which applies to dispersed locations that do
not have electricity or automation, and have limited remote
transmitting unit space.
    Response: The EPA does not take into account monitoring,
recordkeeping and reporting costs in determining cost effectiveness of
controls and in evaluating BSER. Based on this and other comments
detailed in the response to comments for this final rulemaking, the EPA
removed from 40 CFR part 60, subpart OOOO the citations to the
requirements for performance tests, monitoring, recordkeeping, etc., in
40 CFR part 63, subpart HH and incorporated these subpart HH
requirements into subpart OOOO. During the incorporation process, we
made minor revisions to the subpart HH requirements, as appropriate for
subpart OOOO. For example, we removed references to glycol dehydrators
and paragraphs listed as ``reserved.''
4. Availability of Control Equipment
    Comment: Some commenters believe that there will be a shortage of
control equipment available to meet the proposed storage vessel
requirements, and recommend revisions to the compliance deadline for
storage vessels based on a variety of considerations, including the
availability of control devices, lead time needed for manufacturer
testing of their combustors to be compliant with the NSPS and time
needed to install the compliant devices.
    Response: We agree that it will likely take some time beyond the
promulgation date of the NSPS for combustor manufacturers to have
control devices constructed, tested, documented and available for
operators to install in efforts to comply with the storage vessel
requirements of the NSPS. Under the final rule, operators are not
required to conduct individual performance tests on combustors
installed in the field if the combustor manufacturer tests and
documents for the owner or operator that the model achieves a control
efficiency of 95.0 percent. The time required for testing and
documentation is often longer than for a single model when
manufacturers provide multiple models for varying applications based on
capacity. We believe this testing and documentation program would
require an ``adjustment period'' for manufacturers to be ready to
supply the operators with the correct equipment they need.
    We considered whether it would be feasible for on-site testing to
mitigate the shortage of manufacturer tested combustors. Although
owners and operators can test their individual combustors in the field
to determine combustor efficiency, such emissions testing is expensive
and can only be

performed if testing consultants are available to conduct the testing.
We believe that immediately after the effective date of the NSPS there
will be a shortage of available testing consultants concurrent with the
shortage of pre-tested combustor models. As a result, we conclude that
on-site testing would not sufficiently mitigate the difficulty of
owners and operators complying with the NSPS.
    We evaluated whether controls other than combustors would be
available during this adjustment period. Although vapor recovery units
(VRU) can provide 95.0-percent control for storage vessels and are one
means of meeting the storage vessel standards in the NSPS, VRU cannot
be used in every situation. For example, storage vessels located
remotely where there is no available electrical service may not be able
to be controlled using VRU. In addition, storage vessels with low
concentration emission streams or fluctuating emissions may not be
amenable to control by VRU. Further, VRU installations would also
require on-site testing, and owners and operators would be hampered by
the same consultant shortage situation described above for combustors.
    In light of the above, we conclude that there is no BSER for
storage vessel affected sources during the first year after
promulgation, which we believe is appropriate for the adjustment period
mentioned above. At the end of this adjustment period, we believe
owners and operators should have no problem securing control devices
that are manufacturer-tested and have appropriate documentation for
determining control efficiency. Accordingly, the final rule provides
for a 1-year phase-in beginning October 15, 2012 before the 95.0-
percent control requirement is effective.
    With regard to providing time for operators to establish the need
for controls and install them where called for, the EPA agrees that
some lag time may be needed after initial start-up for the owner or
operator to determine the long-term production level of a well and to
procure the appropriate control equipment. The EPA evaluated the
approach taken in the Wyoming rules for new sources, which allows from
30 to 90 days for a source to achieve compliance, depending on the area
of the state. Wyoming allows only 30 days in ozone nonattainment areas,
60 days for concentrated development areas or 90 days elsewhere in the
state. The EPA believes that 60 days is a reasonable period for
controlling new storage vessels at wells sites with no wells already in
production.
    However, for replacement storage vessels or additional storage
vessels at well sites with one or more wells already in production, we
believe the operator already should have information on liquid
composition and throughput. This information would allow estimation of
VOC emissions to determine applicability of control requirements and
for acquisition and installation of a control device concurrent with
the replacement or additional storage vessel being installed. In the
final rule, for storage vessels constructed, modified or reconstructed
at well sites with no well already in production, we have provided for
a 30-day period for throughput to stabilize and for the operator to
estimate VOC emissions to determine whether a control device will be
required. If VOC emissions are estimated to be at least 6 tpy, the
operator is provided an additional 30 days for the control device to
become operational. We believe that the Wyoming experience illustrates
that this will be sufficient time to size and obtain suitable controls.

F. Major Comments Concerning Notification, Recordkeeping and Reporting
Requirements

1. 30-Day Notification and Annual Reports
    Comment: Multiple commenters state that the 30-day advance
notification of well completions under 40 CFR 60.5420(a) should be
removed from the final rule. Commenters assert that this and
notification requirements in 40 CFR 60.7(a) are unduly burdensome and
costly, not adequately explained, not related to verifying compliance
with the proposed rule and could conflict with the need to protect
proprietary business information.
    Multiple commenters also note that industry's estimate of annual
completions is several times higher than the EPA's estimate of 20,000
completions following fracturing and completions following refracturing
annually. The commenters believe that these requirements will likely
overwhelm both regulated entities and state regulators alike.
Commenters offer suggestions, including requiring annual certifications
or maintaining records available for inspection, reducing the proposed
advance notification requirement to 5-10 days and considering
notification programs such as those in Texas and Wyoming. Different
commenters support or oppose requiring a 30-day advance notice with
follow-up notification of 1-2 days before an impending completion.
    Several commenters suggest that the EPA should coordinate with
state and local agencies to eliminate duplicative recordkeeping and
reporting requirements, and that records of interest other than those
submitted to the respective Oil and Gas Commissions should only be
required to be retained and available upon inspection, similar to other
permit requirements.
    Several commenters do not agree that an annual report under 40 CFR
60.7(a)(1), 40 CFR 60.7(a)(3) and 40 CFR 60.7(a)(4) adds any value for
verifying compliance and the EPA should remove this requirement from
the final rule. The commenters add that the best method for compliance
is for an owner or operator to maintain necessary records and to have
the records available for review during an on-site inspection. One
commenter suggests the annual report should include for each type of
affected facility (1) the total number of affected facilities at the
site; (2) the number of facilities that became affected facilities
during the reporting period; (3) the number of exempted facilities; and
(4) the number of affected facilities with a non-compliance situation
during the reporting period. One commenter suggests that it would be
easier for facilities to submit an annual report on a set date each
year, and multiple affected facilities could be included in a single
report. Two commenters propose that all notifications for each year be
delivered in a single annual report corresponding to the reporting
period in which the affected facilities become subject to the rule. One
commenter suggests that operators should be required to keep records at
the nearest manned office, but reports should only be required if they
are requested by the EPA.
    The commenters recommend, where feasible, streamlining the final
notification and reporting requirements to eliminate unduly burdensome
notification and reporting requirements.
    Response: The EPA agrees that certain notification, recordkeeping
and reporting requirements in the General Provisions are unduly
burdensome for the new affected facilities in this NSPS. For that
reason, well completions, pneumatic controllers and storage vessels
will be exempt from the notifications required by 40 CFR 60.7(a)(1),
(3) and (4). We agree that notifications of well completions should be
as streamlined as possible to remove excess burden from both the owners
and operators and regulatory agencies, as well. As a result, we have
removed the 30-day advance notification requirement and instead are
requiring an advance notice via email to the EPA or delegated

authority no later than 2 days prior to completion.
    To avoid duplicative and potentially conflicting notification
requirements and to relieve notification burden from owners and
operators, we have added a provision in the final rule that, if an
owner or operator has met the state requirements for advance
notification of well completions, then the owner and operator are
considered to have met the advance notification requirement for gas
well completions under the NSPS.
    We also believe that the operator should be provided flexibility to
use new technology to document compliance that would result in less
paperwork burden on the part of the operators themselves and on
regulators. To lessen the reporting burden, the final recordkeeping and
reporting requirements for well completions also provide for a
streamlining option that owners and operators may choose in lieu of the
standard annual reporting requirements. The standard annual report must
include copies of all well completion records for each gas well
affected facility for which a completion operation was performed during
the reporting period. The alternative, streamlined annual report for
gas well affected facilities requires submission of a list, with
identifying information of all affected gas wells completed, electronic
or hard copy photographs documenting REC in progress for each well for
which REC was required and the self-certification required in the
standard annual report. The operator retains a digital image of each
REC in progress. The image must include a digital date stamp and
geographic coordinates stamp to help link the photograph with the
specific well completion operation. Operators are not required to take
advantage of the optional recordkeeping and reporting approach, as some
may choose to follow the standard reporting requirements. Under either
approach, the report must include a record of all deviations during the
reporting period in cases where well completion operations with
hydraulic fracturing were not performed in compliance with the
requirements for each gas well affected facility.
    Comment: One commenter requested that the EPA add a self-
certification requirement to the annual report similar to that used in
the title V program. The commenter recommended that the final rule
require the annual report to include a statement signed by a senior
official of the facility attesting to the truth, accuracy and
completeness of the report.
    The commenter also requested that the EPA require that the annual
reports be submitted electronically to facilitate making the reports
publicly available. The commenter suggested using social media outlets,
smart phone applications and other electronic means to make the annual
reports readily available.
    Response: The EPA agrees that self-certification is an important
mechanism for assuring the public that the information submitted by
each facility is accurate. In addition, the title V program has
successfully employed self-certification since its inception.
Therefore, we are requiring self-certification, based on requirements
in the title V program, in the final rule.
    While we agree that having annual reports readily available to the
public is a desirable goal, we did not identify any reporting programs
or electronic databases that may be used for this purpose without
significant modification. Therefore, we are not requiring annual
reports to be submitted electronically, but we will continue to
evaluate this option in the future.
2. Duplicative Recordkeeping and Reporting Requirements
    Comment: Multiple commenters state that the notification,
recordkeeping, monitoring and annual reporting requirements in the
proposed NSPS are duplicative and extremely burdensome for operators
and for state regulators with limited resources. The commenters make
both general and specific recommendations to revise the reporting
requirements in the final rule to eliminate duplication and reduce
burden or better inform the public and regulatory agencies about
deviations. Some commenters would eliminate all or some reports, while
others argue that reporting is an essential compliance and enforcement
mechanism and that additional information should be provided. Some
commenters feel that an owner or operator should maintain necessary
records and have them available for review.
    Commenters want the compliance assurance requirements to be
appropriate for the oil and gas industry and commensurate to the
environmental benefit that will be generated. For example, some
commenters feel that the EPA should exempt small sources regulated
under this rule from the notification and reporting requirements.
    Response: We have considered these and other related comments
presented in the response to comments regarding the proposed reporting
requirements. The EPA agrees that certain notification, recordkeeping
and reporting requirements are unduly burdensome and believes it is
important to minimize the burden of reporting requirements. However, as
noted in several comments, states and other enforcement entities are
confronting limited resources and visiting sites is not always
practical and is particularly challenging in this industry. For that
reason, the EPA believes notifications and reporting requirements are
vital to ensure compliance with our regulations. Therefore, the EPA has
evaluated the proposed notification, recordkeeping and reporting
requirements in an effort to streamline the requirements to reduce
burden on both industry and enforcement at the same time, assuring
compliance with the NSPS. In the final rule, the EPA has removed or
otherwise revised proposed reporting requirements that the EPA believes
to be duplicative or unnecessary, including, but not limited to, those
raised in the comments. These changes will streamline the reporting
process and reduce the reporting burden on sources, including small
sources. For example, as previously discussed, well completions and
continuous bleed natural gas controllers are exempt from the
notifications required by 40 CFR 60.7(a)(1), 40 CFR 60.7(a)(3) and 40
CFR 60.7(a)(4). In addition, the EPA has revised the rule language such
that only continuous bleed natural gas controllers installed, modified
or replaced during the reporting period are reported in the annual
report. In addition, the EPA has revised the 30-day individual
notification requirement for well completions, as discussed above.
3. Electronic Reporting of Emissions Data
    Comment: Commenters suggest a variety of ways in which electronic
reporting could be structured and implemented, with attention to
coordination with various CAA requirements and programs to avoid
duplicative and potentially burdensome requirements. Several commenters
support electronic reporting of emissions data from all sources to be
stored on existing EPA databases, such as the Electronic Greenhouse Gas
Reporting Tool (e-GGRT) or added to the Toxics Release Inventory, and
available to the public. These commenters believe that communities must
have access to air quality information in order to protect public
health. One commenter objects to the use of e-GGRT as a reporting
mechanism in place of a state's own tracking system, where the state
has enforcement responsibility for the emissions date and tracking of
sources subject to the proposed rule. The commenters also suggested a
variety of ways in which electronic

reporting could be structured and implemented.
    Several commenters oppose the implementation of electronic
reporting at this time and are concerned that an ERT will result in
numerous complications and undue additional burden. The commenters
point out that the EPA's experience with e-GGRT indicates that
considerable time and resources are needed to develop and implement
efficient systems and to ensure that electronic reporting enhances
efficiency rather than incurring additional burden on affected sources.
The commenters state that a potential disadvantage associated with an
ERT is that new and/or alternative test methods would not be in the
system. In addition, the commenters believe that an ERT could be
complicated and burdensome for smaller companies that lack
environmental personnel or experience with electronic reporting under
other rules. The commenters suggest that if the EPA delegates authority
to states to implement and enforce the standards, some states may be
unable or unwilling to accept electronic reports. The commenters urge
the EPA to consider other more simplified options to report only the
needed information.
    Response: While the EPA supports and encourages electronic
reporting, after further consideration of all the comments, we do not
believe the e-GGRT is the appropriate mechanism for electronic
reporting under this rule, as recommended by some commenters. The e-
GGRT is not designed to accept all of the types of information required
to be reported under the final rule, and significant modification of
the system would be required to make it operational for this rule.
    However, the final rule does include reporting of performance test
data via the ERT. The EPA must have performance test data to conduct
effective reviews of CAA sections 112 and 129 standards, as well as for
many other purposes, including compliance determinations, emission
factor development and annual emission rate determinations. In
conducting these required reviews, the EPA has found it ineffective and
time consuming, not only for us, but also for regulatory agencies and
source owners and operators, to locate, collect and submit performance
test data because of varied locations for data storage and varied data
storage methods. In recent years, though, stack testing firms have
typically collected performance test data in electronic format, making
it possible to move to an electronic data submittal system that would
increase the ease and efficiency of data submittal and improve data
accessibility.
    In the final rule, as a step to increase the ease and efficiency of
data submittal and improve data accessibility, the EPA is requiring the
electronic submittal of select performance test data. Data entry will
be through an electronic emissions test report structure called the
ERT. The ERT will generate an electronic report which will be submitted
using the CEDRI. The submitted report is submitted through the EPA's
CDX network for storage in the WebFIRE database making submittal of
data very straightforward and easy. Webfire is the EPA's online
emissions factor repository, retrieval and development tool. The
WebFIRE database is open to the public and contains the EPA's
recommended emissions factors for criteria and HAP for industrial and
non-industrial processes. Emissions data collected from the oil and
natural gas sector, as well as many other sectors, will be used to
update our emissions factors. The data will also be used by the EPA's
rule writers to make better informed decisions and learn more detailed
information about emissions from sources. The electronic reporting
requirement in this rule (and other NSPS/NESHAP rules) is only for test
methods that are supported by the ERT.
    One major advantage of submitting performance test data through the
ERT is a standardized method to compile and store much of the
documentation required to be reported by this rule. Another advantage
is that the ERT clearly states what testing information would be
required. Another important benefit of submitting these data to the EPA
at the time the source test is conducted is that it should
substantially reduce the effort involved in data collection activities
in the future.
    State, local and tribal agencies can also benefit from a more
streamlined and accurate review of electronic data submitted to them.
The ERT allows for an electronic review process rather than a manual
data assessment making review and evaluation of the data and
calculations easier and more efficient. Finally, another benefit of
submitting data to WebFIRE electronically is that these data will
greatly improve the overall quality of the existing and new emission
factors by supplementing the pool of emissions test data for
establishing emissions factors and by ensuring that the factors are
more representative of current industry operational procedures. A
common complaint heard from industry and regulators is that emission
factors are outdated or not representative of a particular source
category. With timely receipt and incorporation of data from most
performance tests, the EPA will be able to ensure that emission
factors, when updated, represent the most current range of operational
practices.

X. Summary of Significant NESHAP Comments and Responses

    For purposes of this document, the text within the comment
summaries was provided by the commenter(s) and represents their
opinion(s), regardless of whether the summary specifically indicates
that the statement is from a commenter(s) (e.g., ``The commenter
states'' or ``The commenters assert''). The comment summaries do not
represent the EPA's opinion unless the response to the comment
specifically agrees with all or a portion of the comment.

A. Major Comments Concerning Previously Unregulated Sources

    Comment: One commenter asserts that, although the EPA's original
MACT analysis covered all storage vessels, it issued a MACT standard at
that time that applied to storage vessels with the PFE only. The
commenter states that, while they support the EPA's effort to correct
this omission, the initial analysis for the tanks that the agency did
regulate in 1999 was seriously flawed, and the proposed rule provides
no justification for continuing to rely on a 13-year old analysis to
propose a MACT standard for an entirely new universe of storage vessel
sources. Thus, according to the commenter, the EPA's failure to
properly calculate the MACT floor in setting the MACT standard for
storage vessels violates CAA section 112(d)(2) and (3).
    The commenter states that, because this method has been found to be
unlawful and substantially more data are available at this time, the
EPA must now recalculate the MACT floor and MACT limits for tanks with
the PFE. Cement Kiln Recycling Coalition, et. al. v. U.S. EPA, 255 F.3d
855, 863-64 (D.C. Cir. 2001). The commenter asserts that, in addition
and partly as a consequence of its unlawful reliance on the prior
standards, the EPA also has failed to fulfill the beyond-the-floor
requirement of CAA section 112(d)(2). The commenter opines that, absent
an up-to-date analysis based on current emission controls, an
appropriate beyond-the-floor determination cannot be made.
    Two commenters do not believe that the dataset used is
representative of currently operating small glycol dehydrators. One
commenter believes that the EPA has not satisfied section 112(d)(2) and
(3) of the CAA and that the EPA needs to calculate the MACT

limit based on the best-performing sources that currently exist.
    One commenter recommends that the EPA base its MACT floor analyses
on emissions data from a representative population of small dehydrators
that characterize the population of affected sources within the
category or subcategory. The commenter reports that more current data
sources may be available, such as dehydrator emissions data reported to
state agencies in annual emission reports or in permit applications.
    One commenter opines that the EPA's proposal misses the opportunity
and fails to fulfill the agency's responsibility to properly calculate
the MACT for all sources in this sector based on current, reliable and
representative emission test data. The commenter believes that, by
relying on an incomplete and outdated dataset to set MACT floors and
limits, the EPA has ignored data demonstrating trends in practices,
processes and technologies and the resulting improved performance that
CAA section 112(d) mandates. The commenter asserts that the EPA ignores
the potential HAP emissions that the control devices themselves emit by
failing to collect such emissions data from facilities that have
installed control devices. The commenter argues that the EPA must
collect the appropriate emission test data needed in order to
recalculate and set a proper MACT for glycol dehydrators, storage
vessels and equipment leaks.
    One commenter states that section 112 of the CAA requires the EPA
to set a NESHAP for each category or subcategory of ``major sources''
of HAP emissions. 42 U.S.C. 7412(d)(1). The commenter asserts that the
EPA must set CAA section 112(d) emission standards based on ``maximum
achievable control technology'' or ``MACT.'' The commenter states that
the EPA largely bases its MACT proposal for small glycol dehydrators on
emissions data collected from the industry during the development of
the original MACT standards. 76 FR 52768. The commenter contends that
the data were collected prior to 1997 and did not adequately represent
the emissions profile at that time, and do not reflect the significant
changes in the industry and other technological developments that have
occurred during the past 13 years. According to the commenter, the EPA
has not provided a reasoned explanation of how those data could be
representative of currently operating glycol dehydrators and associated
emission reductions, and how proposals based on those data can
currently meet the MACT requirements for new and existing sources. The
commenter states that the dehydrator technology performance in 1997 was
not accurately reflected in the legacy EPA dataset and has advanced
significantly in the past 13 years. Consequently, according to the
commenter, the EPA has not provided a reasoned explanation of how those
data could be representative of currently operating glycol dehydrators
and associated emission reductions, and how proposals based on those
data can currently meet the MACT requirements for new and existing
sources. The commenter believes this is critical because the 2005 NEI
data reveal that improvements in the environmental performance of the
category have progressed such that there are far more units in service
with lower emissions than reflected in the 1997 data.
    One commenter states that the EPA did not collect recent data
regarding emissions of HAP, including BTEX, from small glycol
dehydrators in either source sector in support of this rulemaking.
Instead, according to the commenter, the EPA appears to have relied on
data collected in the prior MACT rulemaking, going back to 1998 or
prior. The commenter believes that the EPA's analysis is flawed and
questionable because it simply relies on the best-performing sources
that existed a decade ago and fails to identify the best controlled
sources today. The commenter contends that it is unlikely that these
MACT standards reflect either the current best controlled similar
source emissions or the average of the top 12 percent of the currently
best controlled sources. The commenter states that, while the EPA
appropriately proposes to set a MACT limit for these sources for the
first time, the EPA's use of out-dated data fails to demonstrate that
its proposed limit is stringent enough in light of significant
developments in emission control technologies and practices that have
occurred since 1998.
    Response: One commenter argues that EPA has not satisfied sections
112(d)(2) and (3) of the CAA, because the MACT standards set in the
1999 rule have not been re-calculated using current data. To the extent
the commenter is arguing that CAA section 112(d)(6) requires that the
EPA recalculate the MACT standards set in 1999, based on current
emissions test data, the commenter is incorrect. In NRDC v. EPA, 529
F.3d 1077, 1084 (D.C. Cir. 2008), the District of Columbia Circuit held
that it ``[did] not think the words `review, and revise as necessary'
can be construed reasonably as imposing any such obligation'' to re-
calculate the MACT floors. NRDC v. EPA, 529 F.3d 1077, 1084 (D.C. Cir.
2008).
    Moreover, in this action, we did not re-open the MACT standards in
40 CFR part 63, subpart HH for large glycol dehydrators, storage
vessels with the PFE and equipment leaks for or in 40 CFR part 63,
subpart HHH for large glycol dehydrators. As such, the commenter's
request that we re-calculate those standards based on current emissions
data is outside the scope of this rulemaking. We did, however, conduct
a CAA section 112(d)(6) technology review for subpart HH and determined
that there have been no developments in practices, processes or control
technologies for large glycol dehydrators, storage vessels with the PFE
and equipment leaks and that there have been developments for equipment
leaks. See Technology Review for the Final Amendments to Standards for
the Oil and Natural Gas Production and Natural Gas Transmission and
Storage Source Categories and responses on section 112(d)(6) comments
below. We also conducted a CAA section 112(d)(6) technology review for
subpart HHH and determined that there have been no developments in
practices, processes or control technologies for large glycol
dehydrators. Id.
    The remaining comments focus on the data the agency used to set the
proposed MACT standards for small glycol dehydrators, which were left
unregulated in the 1999 rule. The commenters claim that the data the
EPA used to set the BTEX MACT standards for the small glycol
dehydrators subcategory are outdated and that the EPA must collect new
data. However, CAA section 112(d)(3) specifically provides that the
Agency is to determine the average emission limit achieved by the best
performing 12 percent of existing sources ``(for which the
Administrator has emissions information).'' Thus, the EPA is not
required to collect information if it determines that the information
it has is sufficient for it to calculate the MACT standards consistent
with the requirements of CAA section 112. Although the available
emissions information is over a decade old, the available controls for
reducing BTEX emissions from small glycol dehydrators and their control
efficiencies have remained the same during this period, and the
commenters have not provided any data to the contrary.\27\ We,

therefore, believe the data we have are still representative of the
performance of the small dehydrators.
---------------------------------------------------------------------------

    \27\ Memorandum from Brown, Heather, EC/R Inc., to Moore, Bruce,
U.S. EPA, titled Technology Review for the Final Amendments to
Standards for the Oil and Natural Gas Production and Natural Gas
Transmission and Storage Source Categories. Dated April 17, 2012.
---------------------------------------------------------------------------

    Moreover, we believe that the collection and analysis of additional
data would take time and further delay control of these sources, which
we do not think is warranted where, as here, we believe the data on
BTEX emissions for the subcategory of small glycol dehydrators are
still representative of these sources' performance today and the
commenter did not provide any data that indicates otherwise.
    Finally, for small glycol dehydrators, we considered using more
current available data, like the 2005 NEI, however, the NEI dataset
lacks specific information that we believe is relevant to identifying
the best performing units. Specifically, the NEI data lacks information
on inlet HAP content and gas throughput, both of which affect a glycol
dehydrator's HAP emissions. Inlet HAP content varies from well site to
well site. A well-controlled glycol dehydrator at a well site with high
inlet HAP content may have higher HAP emissions than a totally
uncontrolled glycol dehydrator at a well site with a low inlet HAP
content. Natural gas throughput also affects a glycol dehydrator's
overall emissions (i.e., low throughput units will tend to have lower
overall emissions, and vice versa). For the reasons stated above, in
addition to emissions, we need to consider the inlet HAP content and
gas throughput of the small glycol dehydrators in order to properly
identify the best performing sources and establish the MACT standard
for this subcategory. However, information on natural gas throughput
and inlet HAP content is not included in the NEI or any other readily
available data source. Therefore, we used the 1997 data which included
such information for the small dehydrators.
    Comment: One commenter supports the EPA's regulation of previously
unregulated sources in the oil and natural gas sector and the commenter
asserts that CAA sections 112(c) and 112(k) (Urban Air Toxics Strategy)
support their position regarding the regulation of previously
unregulated sources. The commenter asserts that historical regulation
of emission sources within the sector leaves a large number of
dehydrators, storage vessels and equipment at gas processing plants
unregulated. Additionally, the commenter states that historical
regulation has also not limited emissions from a number of other
emission sources (i.e., wells, pneumatic devices, compressor seals,
valves, or flanges or other production equipment located at oil and gas
production facilities or natural gas storage transmission facilities).
    One commenter supports the EPA's recognition of the need to control
emissions from previously uncontrolled emission points and commends the
EPA on addressing small glycol dehydration units and storage vessels
without the PFE. The commenters request that the EPA address all of the
uncontrolled HAP emission points of which it is aware.
    Response: This rule establishes MACT standards for major sources of
small glycol dehydrators that were left unregulated in the 1999 MACT
rule. As explained further below, in several recent rulemakings, we
have chosen to fix certain underlying defects in existing MACT
standards under CAA sections 112(d)(2) and (3), which are the
provisions that directly govern the initial promulgation of MACT
standards (see National Emission Standards for Hazardous Air Pollutants
From Petroleum Refineries, October 28, 2009, 74 FR 55670; and National
Emission Standards for Hazardous Air Pollutants: Group I Polymers and
Resins; Marine Tank Vessel Loading Operations; Pharmaceuticals
Production; and the Printing and Publishing Industry, April 21, 2011,
76 FR 22566). We believe that this approach is reasonable because using
those provisions ensures that the process and considerations are those
associated with initially establishing a MACT standard, and it is
reasonable to make corrections following the process that would have
been followed if we had not made an error at the time of the original
promulgation. We appreciate the commenter's support for regulating
small glycol dehydrators.
    Although the agency had proposed MACT standards under CAA sections
112(d)(2) and (3) for the subcategory of storage vessels without the
PFE, we are not finalizing those standards here. Based on our review of
the comments, we believe that we need additional data in order to set
an emission standard for these vessels. We intend to collect the
appropriate data and propose a MACT emission standard under CAA
sections 112(d)(2) and (3) of the CAA.
    The commenter identifies certain emission sources, other than small
glycol dehydrators and storage vessels without the PFE (e.g., wells),
that it alleges are uncontrolled. CAA section 112(n)(4)(A) prohibits
aggregation of emissions from any oil and gas exploration or production
wells (with their associated equipment) in determining major source
status or for any purpose under CAA section 112. In light of this
prohibition on aggregation, and the fact that the sources identified by
the commenter likely would not, if viewed alone, qualify as a major
source, it is not clear whether emissions from the sources identified
by the commenter can be addressed by a major source NESHAP.\28\
---------------------------------------------------------------------------

    \28\ Even if the commenter were to identify an unregulated
emission point under the NESHAP, it can always petition the agency
to revise the 1999 MACT standards.
---------------------------------------------------------------------------

    The commenter also references CAA section 112(k) (and the Urban Air
Toxic Strategy). CAA section 112(k) is designed to address area source
emissions in urban areas. This rule involves a review of 40 CFR part
63, subparts HH and HHH, both of which address major sources, not area
sources. Further, oil and gas production facilities are typically not
sited in urban areas.
    To the extent that the commenter is requesting EPA to list area
source oil and gas production wells, such a request is outside the
scope of this action. See CAA section 112(n)(4)(B) (specifying certain
requirements for listing ``oil and gas production wells (with its
associated equipment)'' as an area source category).

B. Major Comments Concerning the Risk Review

    Comment: One commenter states that the EPA's analysis for 40 CFR
part 63, subpart HH revealed two facilities (Hawkins Gas Plant,
Hawkins, Texas, and Kathleen Tharp 2, Huffman, Texas) with a cancer MIR
greater than 100-in-1 million based on MACT allowable emissions. The
commenter notes that since the EPA determined that these facilities had
a cancer MIR greater than 100-in-1 million based on MACT allowable
emissions, the EPA determined that the risks are unacceptable for the
Oil and Natural Gas Production MACT source category and additional
regulation was needed. However, the commenter believes these results
are entirely incorrect due to fundamental errors in the EPA's
calculations of MACT allowable risk for these two facilities. In
addition, even if the analysis had been correct, the commenter states
there are significant issues associated with the data for both of these
facilities, which the commenter discusses in detail, that the commenter
believes are sufficient to invalidate the results and the EPA's
conclusion that risks from the Oil and Natural Gas Production source
category are unacceptable.
    Response: We have reviewed our risk results for the Oil and Natural
Gas Production source category and agree

with the commenter that a number of errors were made in our analysis,
including those noted by the commenter. As explained in VII.A.2 of this
preamble, we have revised the risk assessment for this major source
category to correct certain mistakes made in the analysis supporting
the proposed rule.
    Based on our revised risk assessment, in which we evaluated the
risks that remain after promulgation of the original MACT standards, as
well as the MACT standards for small glycol dehydrators established in
this final rule, we have determined the risks for the Oil and Natural
Gas Production major source category are acceptable and that the MACT
standards (including those promulgated here for small glycol
dehydrators) provide an ample margin of safety. Further, we are
retaining the 0.9 Mg/yr benzene compliance alternative, which we had
proposed to remove based on our incorrect conclusion that this
alternative was driving the risk for this major source category.
    Comment: One commenter states that the EPA bases the decision to
eliminate the 0.9 Mg/yr benzene emission limitation for 40 CFR part 63,
subpart HHH on two basic factors: (1) It would reduce the cancer MIR
from 90-in-1 million to 20-in-1 million, and (2) the cost effectiveness
to comply with this option is reasonable. The commenter states that
both of these conclusions are erroneous.
    First, the commenter states that removal of 0.9 Mg/yr benzene
alternative does not reduce risk. The commenter states that the EPA's
own technical analysis indicates that removal of the 0.9 Mg/yr benzene
alternative would have no effect on the MIR.
    Secondly, the commenter states that the EPA's cost analysis is
severely flawed. The commenter also states that the EPA noted at
proposal, that the cost-effectiveness associated with removing the 0.9
Mg/yr benzene compliance alternative for natural gas transmission and
storage facilities was reasonable. However, the commenter explained
that the cost estimates used by the EPA in the ample margin of safety
determination are inadequate. According to the commenter, the EPA did
not conduct any analysis using actual data. Rather, the commenter notes
that the EPA used costs estimated for small dehydrators and made
general assumptions to estimate an upper-end cost effectiveness for
removing the 0.9 Mg/yr benzene alternative limit for large dehydrators
at natural gas transmission and storage facilities. The commenter
believes that, in general, the emission reductions for dehydrators
forced to switch from the 0.9 Mg/yr benzene alternative to 95-percent
control would be considerably less than those achieved by small
dehydrators. The commenter further notes that the cost-effectiveness
calculated for small dehydrators is based on a 95-percent reduction
from an uncontrolled baseline level. According to the commenter, if a
large dehydrator has installed controls to meet the 0.9 Mg/yr
alternative benzene limitation, the cost effectiveness must be based on
the incremental reduction between the existing controls and 95 percent.
The commenter states that the EPA has provided no evidence that these
incremental reductions would be greater than or equal to the 95-percent
reductions that would be achieved for smaller dehydrators. In
conclusion, the commenter states that the rationale used by the EPA in
the preamble to support the removal of the 0.9 Mg/yr compliance
alternative for dehydrators at natural gas transmission and storage
facilities under section 112(f)(2) of the CAA is not supported by any
of the background technical documentation and analyses. The commenter
believes that the EPA has no basis under any other CAA authority for
this action.
    Response: In response to comments, we re-examined our risk
assessment for the Natural Gas Transmission and Storage source category
and discovered a number of errors, which we have discussed in more
detail in section VII.B.2 of this preamble. As explained in that
section, we have revised the risk assessment for this major source
category to correct the mistakes. Based on our revised risk assessment,
in which we evaluated the risks that remain after promulgation of the
original MACT standards, as well as the MACT standards for small glycol
dehydrators in this final rule, we have determined that the risks for
the Oil and Gas Transmission and Storage major source category are
acceptable and that the MACT standards (including those promulgated
here) provide an ample margin of safety. Further, we are retaining the
0.9 Mg/yr benzene compliance alternative, which we had proposed to
remove based on our incorrect conclusion that it was driving the risk
for this major source category. We agree with the commenter that
removal of the 0.9 Mg/yr benzene compliance alternative does not reduce
risks for this major source category. Because we are retaining this
compliance alternative, we need not address the comment on the cost
effectiveness of removing this alternative.

C. Major Comments Concerning the Technology Review

    Comment: One commenter states that, in conducting an 8-year review,
the EPA must ``look back'' at the earlier standard and ascertain
whether: (1) The standard was adopted using procedures that comply with
the law as it has come to be interpreted by the courts; (2) the EPA had
sufficiently accurate and comprehensive data at the time of the initial
standard setting respecting the emissions profile of the category and
properly identified the best performing unit(s); and (3) the EPA had
properly used the available data.
    The commenter states the EPA then must ``look around'' using
currently available data and determine whether: (1) The emissions
profile of the industry has changed in a way that would substantially
affect the MACT floor calculations (the commenter adds that this
includes consideration of any increase in the number of good performing
units available for use in the existing source MACT floor calculation
and in the performance of the best performing unit); (2) data gaps or
uncertainties that affected the earlier decision have been resolved in
the interim or can be resolved using new information available to the
agency; (3) costs or other factors have changed in a way that would
substantially affect the ``beyond-the-floor'' determination; (4) the
use of improved practices, processes or technologies (including
improvements in the performance of existing technologies) has become
more prevalent than at the time of the initial standard setting; or (5)
whether newer regulatory requirements, work practices or emission
limitations (including state and local jurisdiction air pollution
standards and federal enforcement actions), which are more stringent
than the existing CAA section 112(d) standard, have shown the
achievement or achievability of greater emission reductions than the
existing standard requires.
    Response: As explained in the preamble to the proposed rule, our
technology review focused on the identification and evaluation of
``developments in practices, processes, and control technologies''
since the promulgation of the MACT standards for the two oil and gas
source categories at issue here. We first reviewed the available
information. In this regard, we reviewed a variety of sources of data,
including data obtained in subsequent air toxics rules to see if any
practices, processes and control technologies

considered in these actions could be applied to emission sources in the
source categories at issue here. We also consulted the EPA's Reasonably
Available Control Technology (RACT)/Best Available Control Technology
(BACT)/Lowest Achievable Emission Rate (LAER) Clearinghouse (RBLC) and
the Natural Gas STAR program. At proposal, we explained that we
consider any of the following to be a ``development'':

--Any add-on control technology or other equipment that was not
identified and considered during MACT development;
--Any improvements in add-on control technology or other equipment
(that was identified and considered during MACT development) that could
result in significant additional emission reduction;
--Any work practice or operational procedure that was not identified
and considered during MACT development; and
--Any process change or pollution prevention alternative that could be
broadly applied that was not identified and considered during MACT
development.

    The commenter views CAA section 112(d)(6) differently. It appears
to argue that CAA section 112(d)(6) requires that the EPA recalculate
the MACT based on current data and technology. The same argument was
posed to the District of Columbia Circuit, and the Court ``[did] not
think that the words `review, and revise as necessary' can be construed
reasonably as imposing any such obligation.'' NRDC v. EPA, 529 F.3d
1077, 1084 (D.C. Cir. 2008). Thus, contrary to the commenter's
assertion, the EPA is not required pursuant to CAA section 112(d)(6) to
re-calculate the floors it set in 1999.
    To the extent the commenter is arguing that CAA section 112(d)(6)
mandates that the EPA correct any deficiency in an underlying MACT
standard when it conducts the ``technology review'' under that section,
we disagree. We believe that CAA section 112 does not expressly address
this issue, and the EPA has discretion in determining how to address a
purported flaw in a promulgated standard. CAA section 112(d)(6)
provides that the agency must review and revise ``as necessary.'' The
``as necessary'' language must be read in the context of the provision,
which focuses on the review of developments that have occurred since
the time of the original promulgation of the MACT standard and thus
should not be read as a mandate to correct flaws that existed at the
time of the original promulgation.
    In several recent rulemakings, we have chosen to fix underlying
defects in existing MACT standards under CAA sections 112(d)(2) and
(3), the provisions that directly govern the initial promulgation of
MACT standards (see National Emission Standards for Hazardous Air
Pollutants From Petroleum Refineries, October 28, 2009, 74 FR 55670;
and National Emission Standards for Hazardous Air Pollutants: Group I
Polymers and Resins; Marine Tank Vessel Loading Operations;
Pharmaceuticals Production; and the Printing and Publishing Industry,
April 21, 2011, 76 FR 22566). We believe that our approach is
reasonable because using those provisions ensures that the process and
considerations are those associated with initially establishing a MACT
standard, and it is reasonable to make corrections following the
process that would have been followed if we had not made an error at
the time of the original promulgation. As explained elsewhere, we are
not finalizing MACT standards for the subcategory of storage vessels
without the PFE, which were unregulated in the 1999 rule, because after
evaluating the available data and comments received, we believe that we
need additional data in order to set an emission standard for these
vessels. We are, however, finalizing MACT standards under CAA sections
112(d)(2) and (3) for the subcategory of small glycol dehydration
units.
    With regard to our CAA section 112(d)(6) review, we found no
significant developments in practices, processes and control
technologies for reducing emissions from large glycol dehydrators and
storage vessels with PFE.\29\ Accordingly, we are not revising these
standards under CAA section 112(d)(6).
---------------------------------------------------------------------------

    \29\ See footnote 25.
---------------------------------------------------------------------------

    The EPA also conducted a technology review evaluating various
options for controlling HAP emissions from equipment leaks. As
described in the proposed rule (76 FR 52784), we evaluated advancements
in controlling this emissions source since the original standards were
promulgated, including the emission reduction potential and associated
cost-effectiveness of these advancements. As a result of our review, we
revised the leak definition for valves at natural gas processing plants
to 500 ppm, thus, requiring the application of the LDAR requirement at
this lower detection level. As discussed above, the commenter appears
to be arguing that the EPA must redo the MACT floor and beyond-the-
floor analysis under CAA sections 112(d)(2) and (3) within its CAA
section 112(d)(6) technology review, which we disagree.
    Comment: One commenter states that the EPA's technology review for
storage vessel control technologies is limited and makes incorrect
assumptions. The commenter contends that without further support, the
public cannot understand and the EPA cannot justify its proposed
decision; therefore, the EPA's proposal is arbitrary and capricious.
The commenter adds that the EPA must conduct an updated beyond-the-
floor analysis for storage vessels, by determining the ``maximum degree
of reduction in emissions'' that is achievable, as required under CAA
section 112(d)(2). The commenter states that the proposed rule fails to
provide any discussion of a beyond-the-floor determination for storage
vessels.
    One commenter states that the EPA must examine advances in vapor
recovery unit technology and reconsider floating roof technology for
tanks containing liquids that do not have the PFE. The commenter
contends that the EPA improperly rejected technology advances and
developments in pollution prevention systems found in its own RBLC
database and employed by its own Natural Gas STAR partners.
Specifically, according to the commenter, the EPA failed to evaluate
the performance achieved by systems that use thermal or catalytic
oxidizers, either alone or in combination with condensers. According to
the commenter, the EPA's RBLC review identified a BACT determination
for dehydrator efficiency of 98 percent. The commenter also urges the
EPA to evaluate the use of combustion devices and vapor recovery units
that capture vent steam from the tank and turn it into a saleable
product by recompressing the hydrocarbon vapors. The commenter contends
that the EPA rejects technology advances by asserting that those
technologies were considered in the 1999 rulemaking, but fails to
provide support for its decision in either the record of the 1999
rulemaking or the current record. The commenter contends that the EPA
must provide a basis for its decisions and conclusions.
    Response: For the reasons discussed in the prior response, the EPA
disagrees with the commenter's assertion that it must re-do the MACT
floor calculations, including the beyond-the-floor determination, for
the standards that the agency set in 1999. As to the technologies
identified by the commenter, they were in existence and considered by
the EPA at the time the EPA promulgated the original MACT

standards for storage vessels.30 31 In addition, we are not
finalizing control requirements for storage vessels without the PFE, as
described in section VII.A of this preamble. The record does not
support the assertion that the technologies identified by the commenter
have advanced in terms of HAP emission reduction or have become
significantly more cost effective. As explained in the preamble to the
proposed rule (76 FR 52785), we examined technologies that were similar
to the cover and route emissions to a control device that the MACT
floor requires and, thus, would not result in reductions beyond the
existing MACT requirements. Further, evaluation of technologies in the
RBLC did not produce any applicable practices, processes or control
technologies that were not considered during the original MACT for
storage vessels with flash emissions.\32\
---------------------------------------------------------------------------

    \30\ See footnote 25.
    \31\ See EPA Legacy Docket A-94-04 MACT floor memos II-A-006 and
-007.
    \32\ See footnote 25.
---------------------------------------------------------------------------

D. Major Comments Concerning Notification, Recordkeeping and Reporting
Requirements

1. Annual Reports
    Comment: One commenter requested that the EPA add a self-
certification requirement to the annual report similar to that used in
the title V program. The commenter recommended that the final rule
require the annual report to include a statement signed by a senior
official of the facility attesting to the truth, accuracy and
completeness of the report.
    The commenter also requested that the EPA require that the annual
reports be submitted electronically to facilitate making the reports
publicly available. The commenter suggested using social media outlets,
smart phone applications and other electronic means to make the annual
reports readily available.
    Response: The EPA agrees that self-certification is an important
mechanism for assuring the public that the information submitted by
each facility is accurate. In addition, the title V program has
successfully employed self-certification for since its inception.
Therefore, we are requiring self-certification, based on requirements
in the title V program, in the final rule.
    While we agree that having annual reports readily available to the
public is a desirable goal, we did not identify any reporting programs
or electronic databases that may be used for this purpose without
significant modification. Therefore, we are not requiring annual
reports to be submitted electronically, but we will continue to
evaluate this option in the future.
2. Electronic Reporting of Emissions Data
    Several commenters raised similar issues regarding reporting of
emissions data under the NESHAP as under the NSPS, described supra, and
our responses there apply equally here. Please see comments and
responses in section IX.F.3 of this preamble.

XI. What are the cost, environmental and economic impacts of the final
NESHAP and NSPS amendments?

A. What are the air impacts?

    For the oil and natural gas sector NESHAP and NSPS, we 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 selected by the engineering analysis. These
emission reductions associated with the final amendments to 40 CFR part
63, subpart HH and 40 CFR part 63, subpart HHH are based on the
estimated population in 2008. Under the finalized limits for glycol
dehydration units, we have estimated that the HAP emissions reductions
will be 670 tons for existing units subject to the final emissions
limits.
    For the NSPS, we 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
selected by the engineering analysis. These emission reductions are
based on the estimated population in 2015.
    The primary baseline used for the impacts analysis of our NSPS for
completions of hydraulically fractured natural gas wells takes into
account REC conducted pursuant to state regulations covering these
operations and estimates of REC performed voluntarily. To account for
REC performed in regulated states, the EPA subsumed emissions
reductions and compliance costs in states where these completion-
related emissions are already controlled into the baseline.
Additionally, based on public comments and reports to the EPA's Natural
Gas STAR program, the EPA recognizes that some producers conduct well
completions using REC techniques voluntarily for economic and/or
environmental objectives as a normal part of business. To account for
emissions reductions and costs arising from voluntary implementation of
pollution controls, the EPA used information on total emission
reductions reported to the EPA by partners of the EPA Natural Gas STAR.
This estimate of this voluntary REC activity in the absence of
regulation is also included in the baseline.\33\ More detailed
discussion on the derivation of the baseline is presented in a
technical memorandum in the docket, as well as in the Regulatory Impact
Analysis (RIA).
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    \33\ Voluntary short-term actions (such as REC) are challenging
to capture accurately in a prospective analysis, as such, reductions
are not guaranteed to continue. However, Natural Gas STAR represents
a nearly 20-year voluntary initiative with participation from 124
natural gas companies operating in the United States, including 28
producers, over a wide historical range of natural gas prices. This
unique program and dataset, the significant impact of voluntary REC
on the projected cost and emissions reductions (due to significant
REC activity), and the fact that REC can actually increase natural
gas recovered from natural gas wells (offering a clear incentive to
continue the practice), led the agency to conclude that it was
appropriate to estimate these particular voluntary actions in the
baseline for this rule.
---------------------------------------------------------------------------

    Additionally, in the RIA, we provide summary-level estimates of
emissions reductions and engineering compliance costs for a case where
no voluntary REC are assumed to occur. This alternative case is
presented in order to show impacts if conditions were such that REC
were no longer performed on a voluntary basis, but, rather, were
compelled by the regulation, and serves, in part, to capture the
inherent uncertainty in projecting voluntary activity into the future.
As such, this alternative case establishes the full universe of
emissions reductions that are guaranteed by this NSPS (those that are
required to occur under the rule, including those that would likely
occur voluntarily). While the primary baseline may better represent
actual costs (and emissions reductions) beyond those already expected
under business as usual, the alternative case better captures the full
amount of emissions reductions where the NSPS acts as a backstop to
ensure that emission reduction practices occur (practices covered by
this rule).
    Under the final NSPS, we have estimated that the emissions
reductions to be about 190,000 tons VOC affected facilities subject to
the NSPS. The NSPS is also expected to concurrently reduce 1.0 million
tons methane and 11,000 tons HAP. We estimate that direct reductions in
HAP, methane and VOC for the final rules combined total about 12,000
tons, 1.0 million tons and 190,000 tons, respectively. If voluntary
action is not deducted from the NSPS baseline, the emissions reductions
achieved by the final NSPS in HAP, methane and VOC are estimated at

about 19,000 tons, 1.7 million tons and 290,000 tons, respectively.
    The EPA received several comments regarding the emission factor
selected to calculate whole gas emissions (and the associated VOC
emissions) from hydraulically fractured well completions. Comments
focused on the data behind the emission factor, what the emission
factor is intended to represent and the procedures used to develop the
emission factor from the selected data sets. We reviewed all
information received and have decided to retain the data set and the
analysis conducted to develop the emission factor of 9,000 thousand
cubic feet (Mcf) per completion. More detailed discussion is presented
in a technical memorandum on this subject in the docket.

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
analyzed under the final NESHAP amendments and final NSPS.
    The final NESHAP amendments and final NSPS encourage the use of
emission controls that recover hydrocarbon products, such as methane
and condensate that can be used on-site as fuel or reprocessed within
the production process for sale. We estimated that the final standards
will result in net annual costs savings of about $11 million (in 2008
dollars) due to the recovery of salable natural gas and condensate.
Thus, the final standards have a positive impact associated with the
recovery of non-renewable energy resources.

C. What are the cost impacts?

    The estimated total capital cost to comply with the final
amendments to 40 CFR part 63, subpart HH for major sources in the Oil
and Natural Gas Production source category is approximately $2.6
million. The total capital cost for the final amendments to 40 CFR part
63, subpart HHH for major sources in the Natural Gas Transmission and
Storage source category is estimated to be approximately $140,000. All
costs are in 2008 dollars.
    The total estimated net annual cost to industry to comply with the
final amendments to 40 CFR part 63, subpart HH for major sources in the
Oil and Natural Gas Production source category is approximately $3.3
million. The total net annual cost for final amendments to 40 CFR part
63, subpart HHH for major sources in the Natural Gas Transmission and
Storage source category is estimated to be approximately $180,000.
These estimated annual costs include: (1) The cost of capital, (2)
operating and maintenance costs, (3) the cost of monitoring,
inspection, recordkeeping and reporting (MIRR) and (4) any associated
product recovery credits. All costs are in 2008 dollars.
    The estimated total capital cost to comply with the final NSPS is
approximately $25 million in 2008 dollars. The total estimated net
annual cost to industry to comply with the final NSPS is estimated to
be approximately $170 million in 2008 dollars. This annual cost
estimate includes: (1) The cost of capital, (2) operating and
maintenance costs and (3) the cost of MIRR. This estimated annual cost
does not take into account any producer revenues associated with the
recovery of salable natural gas and hydrocarbon condensates.
    When revenues from additional product recovery are considered, the
final NSPS is estimated to result in a net annual engineering cost
savings overall. When including the additional natural gas recovery in
the engineering cost analysis, we assume that producers are paid $4/Mcf
for the recovered gas at the wellhead. The engineering analysis cost
analysis assumes the value of recovered condensate is $70 per barrel.
Based on the engineering analysis, about 43 million Mcf (43 billion
cubic feet) of natural gas and 160,000 barrels of condensate are
estimated to be recovered by control requirements in 2015. Using the
price assumptions, the estimated revenues from natural gas and
condensate recovery are approximately $180 million in 2008 dollars.
    Using the engineering cost estimates, estimated natural gas product
recovery and natural gas product price assumptions, the net annual
engineering cost savings is estimated for the final NSPS to be about
$15 million. Totals may not sum due to independent rounding.
    If voluntary action is not deducted from the baseline, capital
costs for the NSPS are estimated at $25 million and annualized costs
without revenues from product recovery for the NSPS are estimated at
$330 million. In this scenario, given the assumptions about product
prices, estimated revenues from product recovery are $350 million,
yielding an estimated cost of savings of about $22 million.
    As the price assumption is very influential on estimated annualized
engineering costs, we performed a simple sensitivity analysis of the
influence of the assumed wellhead price paid to natural gas producers
on the overall engineering annualized costs estimate of the final NSPS.
At $4.22/Mcf, the price forecast reported in the 2011 Annual Energy
Outlook in 2008 dollars, the annualized cost savings for the final NSPS
are estimated at about $24 million. As indicated by this difference,
the EPA has chosen a relatively conservative assumption (leading to an
estimate of few savings and higher net costs) for the engineering costs
analysis. The natural gas price at which the final NSPS breaks-even
from an estimated engineering costs perspective is around $3.66/Mcf. A
$1/Mcf change in the wellhead natural gas price leads to a $43 million
change in the annualized engineering costs of the final NSPS.
Consequently, annualized engineering costs estimates would increase to
about $29 million under a $3/Mcf price or decrease to about -$58
million under a $5/Mcf price. For further details on this sensitivity
analysis, please refer the RIA for this rulemaking located in the
docket.

D. What are the economic impacts?

    The analysis of energy system impacts EPA performed using the
United States Department of Energy's (DOE) National Energy Modeling
System (NEMS) shows that domestic natural gas production is not likely
to change in 2015 as a result of the final rules, the year used in the
RIA to analyze impacts. Average natural gas prices are also not
estimated to change in response to the final rules. Domestic crude oil
production is not expected to change, while average crude oil prices
are estimated to decrease slightly (about $0.01/barrel or about 0.01
percent at the wellhead for onshore production in the lower 48 states).
All prices are in 2008 dollars. The NEMS-based analysis estimates in
the year of analysis, 2015, that net imports of natural gas and crude
oil will not change.

E. What are the benefits of this final rule?

    The final Oil and Natural Gas NSPS and NESHAP amendments are
expected to result in significant reductions in existing emissions and
prevent new emissions from expansions of the industry. These final
rules combined are anticipated to reduce 12,000 tons of HAP, 190,000
tons of VOC (a precursor to both PM (2.5 microns and less)
(PM2.5) and ozone formation) and 1.0 million tons of methane
(a GHG and a precursor to global ozone formation). These pollutants are
associated with

substantial health effects, welfare effects and climate effects.
    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.\34\ In addition to health improvements, there will
be improvements in visibility effects, ecosystem effects and climate
effects, as well as additional product recovery.
---------------------------------------------------------------------------

    \34\ 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
provide useful context for the break-even analysis, 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 \35\ and U.S. EPA, 2010 \36\),
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 and chronic bronchitis,
hospital admissions and emergency room visits, work loss days,
restricted activity days and respiratory symptoms, as well as
visibility impairment.\37\ 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.\38\
---------------------------------------------------------------------------

    \35\ 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.
    \36\ 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.
    \37\ 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.
    \38\ 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.
---------------------------------------------------------------------------

    In addition to the improvements in air quality and resulting
benefits to human health and non-climate welfare effects previously
discussed, this rule is expected to result in significant climate co-
benefits due to anticipated methane reductions. Methane is a potent GHG
that, once emitted into the atmosphere, absorbs terrestrial infrared
radiation, which contributes to increased global warming and continuing
climate change. Methane reacts in the atmosphere to form ozone and
ozone also impacts global temperatures. According to the
Intergovernmental Panel on Climate Change (IPCC) 4th Assessment Report
(2007), methane is the second leading long-lived climate forcer after
CO2 globally. Total methane emissions from the oil and gas
industry represent about 40 percent of the total methane emissions from
all sources and account for about 5 percent of all CO2e
emissions in the United States, with natural gas systems being the
single largest contributor to United States anthropogenic methane
emissions.\39\ Methane, in addition to other GHG emissions, contributes
to warming of the atmosphere, which, over time, leads to increased air
and ocean temperatures, changes in precipitation patterns, melting and
thawing of global glaciers and ice, increasingly severe weather events,
such as hurricanes of greater intensity and sea level rise, among other
impacts.
---------------------------------------------------------------------------

    \39\ U.S. EPA (2011), 2011 U.S. Greenhouse Gas Inventory Report
Executive Summary available on the internet at http://epa.gov/climatechange/emissions/downloads11/US-GHG-Inventory-2011-Executive-Summary.pdf, accessed 02/13/12.
---------------------------------------------------------------------------

    This rulemaking requires emission control technologies and
regulatory alternatives that will significantly decrease HAP and VOC
emissions from the oil and natural gas sector in the United States. As
a co-benefit, the emission control measures the industry will use to
reduce HAP and VOC emissions will also decrease methane emissions. The
NESHAP Amendments and the NSPS combined are expected to reduce methane
emissions annually by about 1.0 million short tons or about 19 million
metric tons CO2e. After considering the secondary impacts of
this rule as previously discussed, such as increased CO2
emissions from well completion combustion and decreased CO2e
emissions because of fuel-switching by consumers, the methane
reductions become about 18 million metric tons CO2e. The
methane reductions represent about 7 percent of the baseline methane
emissions for this sector reported in the EPA's U.S. Greenhouse Gas
Inventory Report for 2009 (251.55 million metric tons CO2e
when petroleum refineries and petroleum transportation are excluded
because these sources are not examined in this proposal). However, it
is important to note that the emission reductions are based upon
predicted activities in 2015; the EPA did not forecast sector-level
emissions in 2015 for this rulemaking. These emission reductions equate
to the climate benefits of taking approximately 4 million typical
passenger cars off the road or eliminating electricity use from about 2
million typical homes each year.\40\
---------------------------------------------------------------------------

    \40\ U.S. EPA. Greenhouse Gas Equivalency Calculator available
at: http://www.epa.gov/cleanenergy/energy-resources/calculator.html,
accessed 04/09/12.
---------------------------------------------------------------------------

    The EPA recognizes that the methane reductions from this rule will
provide for significant economic climate benefits to society just
described. However, the 2009-2010 Interagency Social Cost of Carbon
Work Group did not produce directly modeled estimates of the social
cost of methane. In the absence of direct model estimates from the
interagency analysis, the EPA has used a ``global warming potential
(GWP) approach'' to estimate the dollar value of this rule's methane
co-benefits. Specifically, the EPA converted methane to CO2
equivalents using the GWP of methane, then multiplied these
CO2 equivalent emission reductions by the social cost of
carbon developed by the Interagency Social Cost of Carbon Work Group.
    The social cost of carbon is an estimate of the net present value
of the flow of monetized damages from a 1-metric ton increase in
CO2 emissions in

a given year (or from the alternative perspective, the benefit to
society of reducing CO2 emissions by 1 ton). For more
information about the social cost of carbon, see the Support Document:
Social Cost of Carbon for Regulatory Impact Analysis Under Executive
Order 12866.\41\ Applying this approach to the methane reductions
estimated for the NESHAP Amendments and NSPS, the 2015 climate co-
benefits vary by discount rate and range from about $100 million to
approximately $1.3 billion; the mean social cost of carbon at the 3-
percent discount rate results in an estimate of about $440 million in
2015.\42\
---------------------------------------------------------------------------

    \41\ Interagency Working Group on Social Cost of Carbon (IWGSC).
2010. Technical Support Document: Social Cost of Carbon for
Regulatory Impact Analysis Under Executive Order 12866. Docket ID
EPA-HQ-OAR-2009-0472-114577. http://www.epa.gov/otaq/climate/regulations/scc-tsd.pdf, accessed 02/12/12.
    \42\ The ratio of domestic to global benefits of emission
reductions varies with key parameter assumptions. See Interagency
Working Group on Social Cost of Carbon. 2010. Technical Support
Document: Social Cost of Carbon for Regulatory Impact Analysis Under
Executive Order 12866.
---------------------------------------------------------------------------

    These co-benefits equate to a range of approximately $110 to $1,400
per short ton of methane reduced, depending upon the discount rate
assumed with a per ton estimate of $480 at the 3-percent discount rate.
These social cost of methane benefit estimates are not the same as
would be derived from direct computations (using the integrated
assessment models employed to develop the Interagency Social Cost of
Carbon estimates) for a variety of reasons, including the shorter
atmospheric lifetime of methane relative to CO2 (about 12
years compared to CO2 whose concentrations in the atmosphere
decay on timescales of decades to millennia). The climate impacts also
differ between the pollutants for reasons other than the radiative
forcing profiles and atmospheric lifetimes of these gases.
    Methane is a precursor to ozone and ozone is a short-lived climate
forcer that contributes to global warming. The use of the IPCC Second
Assessment Report GWP to approximate co-benefits may underestimate the
direct radiative forcing benefits of reduced ozone levels and does not
capture any secondary climate co-benefits involved with ozone-ecosystem
interactions. In addition, a recent the EPA National Center of
Environmental Economics working paper suggests that this quick ``GWP
approach'' to benefits estimation will likely understate the climate
benefits of methane reductions in most cases.\43\ This conclusion is
reached using the 100-year GWP for methane of 25 as put forth in the
IPCC Fourth Assessment Report (AR 4), as opposed to the lower value of
21 used in this analysis. Using the higher GWP estimate of 25 would
increase these reported methane climate co-benefit estimates by about
19 percent. Although the IPCC Assessment Report (AR4) suggested a GWP
of 25 for methane, the EPA has used the GWP of 21 from the IPCC Second
Assessment Report to estimate the methane climate co-benefits for this
oil and gas rule. The EPA uses the 21 GWP in order to provide estimates
more consistent with global GHG inventories, which currently use GWP
from the IPCC Second Assessment Report, and with the US GHG Reporting
program. See the Regulatory Impact Analysis for further details.
---------------------------------------------------------------------------

    \43\ Marten and Newbold (2011), Estimating the Social Cost of
Non-CO2 GHG Emissions: Methane and Nitrous Oxide, NCEE
Working Paper Series 11-01. http://yosemite.epa.gov/EE/epa/eed.nsf/WPNumber/2011-01?OpenDocument.
---------------------------------------------------------------------------

    Due to the uncertainties involved with the ``GWP approach''
estimates presented and methane climate co-benefits estimates available
in the literature, the EPA chooses not to compare these co-benefit
estimates to the costs of the rule for this proposal. Rather, the EPA
presents the ``GWP approach'' climate co-benefit estimates as an
interim method to produce these estimates until the Interagency Social
Cost of Carbon Work Group develops values for non-CO2 GHG.
    For the final NESHAP amendments, a break-even analysis suggests
that HAP emissions would need to be valued at $5,200 per ton for the
benefits to exceed the costs if the health, ecosystem and climate
benefits from the reductions in VOC and methane emissions are assumed
to be zero. Even though emission reductions of VOC and methane are co-
benefits for the final NESHAP amendments, they are legitimate
components of the total benefit-cost comparison. If we assume the
health benefits from HAP emission reductions are zero, the VOC
emissions would need to be valued at $2,900 per ton or the methane
emissions would need to be valued at $8,300 per ton for the co-benefits
to exceed the costs. All estimates are in 2008 dollars. For the final
NSPS, the revenue from additional product recovery exceeds the costs,
which renders a break-even analysis unnecessary when these revenues are
included in the analysis. Based on the methodology from Fann, Fulcher,
and Hubbell (2009),\44\ ranges of benefit-per-ton estimates for
emissions of VOC indicate that on average in the United States, VOC
emissions are valued from $1,200 to $3,000 per ton as a
PM2.5 precursor, but emission reductions in specific areas
are valued from $280 to $7,000 per ton in 2008 dollars. As a result,
even if VOC emissions from oil and natural gas operations result in
monetized benefits that are substantially below the national average,
there is a reasonable chance that the benefits of the rule would exceed
the costs, especially if we were able to monetize all of the additional
benefits associated with ozone formation, visibility, HAP and methane.
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    \44\ Fann, N., C.M. Fulcher, B.J. Hubbell. The influence of
location, source, and emission type in estimates of the human health
benefits of reducing a ton of air pollution. Air Qual Atmos Health
(2009) 2:169-176.
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XII. Statutory and Executive Order Reviews

A. Executive Order 12866, Regulatory Planning and Review and Executive
Order 13563, Improving Regulation and Regulatory Review

    Under section 3(f)(1) of Executive Order 12866 (58 FR 51735,
October 4, 1993), this action is an ``economically significant
regulatory action'' because it is likely to have an annual effect on
the economy of $100 million or more. Accordingly, the EPA submitted
this action to the Office of Management and Budget (OMB) for review
under Executive Order 12866 and Executive Order 13563 (76 FR 3821,
January 21, 2011), and any changes made in response to OMB
recommendations have been documented in the docket for this action.
    In addition, the EPA prepared a Regulatory Impact Analysis (RIA) of
the potential costs and benefits associated with this action. The RIA
available in the docket describes in detail the empirical basis for the
EPA's assumptions and characterizes the various sources of
uncertainties affecting the estimates below. Table 7 shows the results
of the cost and benefits analysis for these final rules.

Table 7--Summary of the Monetized Benefits, Social Costs and Net Benefits for the Final Oil and Natural Gas NSPS
                                          and NESHAP Amendments in 2015
                                             [Millions of 2008$] \1\
----------------------------------------------------------------------------------------------------------------
                                                                                Final NSPS and NESHAP
                                              Final NSPS        Final NESHAP amendments    amendments combined
----------------------------------------------------------------------------------------------------------------
Total Monetized Benefits \2\.........  N/A....................  N/A....................  N/A.
Total Costs \3\......................  -$15 million...........  $3.5 million...........  -$11 million.
Net Benefits.........................  N/A....................  N/A....................  N/A.
Non-monetized Benefits \4\...........  11,000 tons of HAP.....  670 tons of HAP........  12,000 tons of HAP.
                                       190,000 tons of VOC....  1,200 tons of VOC......  190,000 tons of VOC.
                                       1.0 million tons of      420 tons of methane....  1.0 million tons of
                                        methane.                                          methane.
                                      --------------------------------------------------------------------------
                                       Health effects of HAP exposure.
                                       Health effects of PM2.5 and ozone exposure.
                                       Visibility impairment.
                                       Vegetation effects.
                                       Climate effects.
----------------------------------------------------------------------------------------------------------------
\1\ All estimates are for the implementation year (2015).
\2\ While we expect that these avoided emissions will result in improvements in air quality and reductions in
  health effects associated with HAP, ozone, and particulate matter (PM) as well as climate effects associated
  with methane, we have determined that quantification of those benefits and co-benefits cannot be accomplished
  for this rule in a defensible way. This is not to imply that there are no benefits or co-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.
\3\ The engineering compliance costs are annualized using a 7-percent discount rate. The negative cost for the
  final NSPS reflects the inclusion of revenues from additional natural gas and hydrocarbon condensate recovery
  that are estimated as a result of the NSPS. Possible explanations for why there appear to be negative cost
  control technologies are discussed in the engineering costs analysis section in the RIA.
\4\ For the NSPS, reduced exposure to HAP and climate effects are co-benefits. For the NESHAP, reduced VOC
  emissions, PM2.5 and ozone exposure, visibility and vegetation effects and climate effects are co-benefits.
  The specific control technologies for the final NSPS are anticipated to have minor secondary disbenefits,
  including an increase of 1.1 million tons of carbon dioxide (CO2), 550 tons of nitrogen oxides (NOX), 19 tons
  of PM, 3,000 tons of CO and 1,100 tons of total hydrocarbons (THC), as well as emission reductions associated
  with the energy system impacts. The specific control technologies for the NESHAP are anticipated to have minor
  secondary disbenefits, but the EPA was unable to estimate these secondary disbenefits. The net CO2-equivalent
  emission reductions are 18 million metric tons.

B. Paperwork Reduction Act

    The information collection requirements in this rule have been
submitted for approval to the Office of Management and Budget (OMB)
under the Paperwork Reduction Act, 44 U.S.C. 3501, et seq. The
information collection requirements are not enforceable until OMB
approves them.
    The ICR documents prepared by the EPA have been assigned EPA ICR
numbers 2437.01, 2438.01, 2439.01 and 2440.01. The information
requirements are based on notification, recordkeeping and reporting
requirements in the NESHAP General Provisions (40 CFR part 63, subpart
A), which are mandatory for all operators subject to national emission
standards. These recordkeeping and reporting requirements are
specifically authorized by CAA section 114 (42 U.S.C. 7414). All
information submitted to the EPA pursuant to the recordkeeping and
reporting requirements for which a claim of confidentiality is made is
safeguarded according to Agency policies set forth in 40 CFR part 2,
subpart B. This final rule requires maintenance inspections of the
control devices but would not require any notifications or reports
beyond those required by the General Provisions. The recordkeeping
requirements require only the specific information needed to determine
compliance.
    When a malfunction occurs, sources must report them according to
the applicable reporting requirements of 40 CFR part 63, subpart HH or
40 CFR part 63, subpart HHH. An affirmative defense to civil penalties
for exceedances of emission limits that are caused by malfunctions is
available to a source if it can demonstrate that certain criteria and
requirements are satisfied. The criteria ensure that the affirmative
defense is available only where the event that causes an exceedance of
the emission limit meets the narrow definition of malfunction in 40 CFR
63.2 (sudden, infrequent, not reasonable preventable, and not caused by
poor maintenance and/or careless operation) and where the source took
necessary actions to minimize emissions. In addition, the source must
meet certain notification and reporting requirements. For example, the
source must prepare a written root cause analysis and submit a written
report to the Administrator documenting that it has met the conditions
and requirements for assertion of the affirmative defense.
    For this rule, the EPA is adding affirmative defense to the
estimate of burden in the ICR. To provide the public with an estimate
of the relative magnitude of the burden associated with an assertion of
the affirmative defense position adopted by a source, the EPA has
provided administrative adjustments to this ICR that shows what the
notification, recordkeeping and reporting requirements associated with
the assertion of the affirmative defense might entail. The EPA's
estimate for the required notification, reports, and records, including
the root cause analysis, associated with a single incident totals
approximately totals $3,141 and is based on the time and effort
required of a source to review relevant data, interview plant
employees, and document the events surrounding a malfunction that has
caused an exceedance of an emission limit. The estimate also includes
time to produce and retain the record and reports for submission to the
EPA. The EPA provides this illustrative estimate of this burden,
because these costs are only incurred if there has been a violation,
and a source chooses to take advantage of the affirmative defense.
    The EPA provides this illustrative estimate of this burden because
these costs are only incurred if there has been a violation and a
source chooses to take advantage of the affirmative defense. Given the
variety of circumstances under which malfunctions could occur, as well
as differences among sources' operation and maintenance practices, we
cannot reliably predict the severity and frequency of malfunction-
related excess emissions events for a particular source. It is
important to note that the

EPA has no basis currently for estimating the number of malfunctions
that would qualify for an affirmative defense. Current historical
records would be an inappropriate basis, as source owners or operators
previously operated their facilities in recognition that they were
exempt from the requirement to comply with emissions standards during
malfunctions. Of the number of excess emissions events reported by
source operators, only a small number would be expected to result from
a malfunction (based on the definition above), and only a subset of
excess emissions caused by malfunctions would result in the source
choosing to assert the affirmative defense. Thus, we believe the number
of instances in which source operators might be expected to avail
themselves of the affirmative defense will be extremely small.
    For this reason, we estimate a total of 39 such occurrences for all
sources subject to 40 CFR part 63, subpart HH, a total of three such
occurrences for all sources subject to 40 CFR part 63, subpart HHH, and
a total of 6 such occurrences for all sources subject to 40 CFR part
60, subparts KKK and LLL over the 3-year period covered by this ICR. We
expect to gather information on such events in the future, and will
revise this estimate as better information becomes available.
    The annual monitoring, reporting, and recordkeeping burden for this
collection (averaged over the first 3 years after the effective date of
the standards) is estimated to be $20.1 million. This includes 384,866
labor hours per year at a total labor cost of $19.5 million per year,
and annualized capital costs of $0.36 million, and annual operating and
maintenance costs of $0.20 million. This estimate includes initial and
annual performance tests, semiannual excess emission reports,
developing a monitoring plan, notifications and recordkeeping. All
burden estimates are in 2008 dollars and represent the most cost-
effective monitoring approach for affected facilities. Burden is
defined at 5 CFR 1320.3(b).
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When these ICR
are approved by OMB, the agency will publish a technical amendment to
40 CFR part 9 in the Federal Register to display the OMB control
numbers for the approved information collection requirements contained
in the final rule.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act generally requires an agency to
prepare a regulatory flexibility analysis of any rule subject to notice
and comment rulemaking requirements under the Administrative Procedure
Act or any other statute, unless the agency certifies that the rule
will not have a significant economic impact on a substantial number of
small entities (SISNOSE). Small entities include small businesses,
small organizations, and small governmental jurisdictions. For purposes
of assessing the impact of this rule on small entities, a small entity
is defined as: (1) A small business as defined by NAICS codes 211111,
211112, 221210, 486110 and 486210; whose parent company has no more
than 500 employees (or revenues of less than $7 million for firms that
transport natural gas via pipeline); (2) a small governmental
jurisdiction that is a government of a city, county, town, school
district, or special district with a population of less than 50,000;
and (3) a small organization that is any not-for-profit enterprise
which is independently owned and operated and is not dominant in its
field.
    For the final NSPS, the EPA performed an analysis for impacts on a
sample of expected affected small entities by comparing compliance
costs to entity revenues. The baseline used in this analysis takes into
account REC conducted pursuant to state regulations covering these
operations and estimates of REC performed voluntarily. To account for
REC performed in regulated states, the EPA subsumed emissions
reductions and compliance costs in states where these completion-
related emissions are already controlled into the baseline.
Additionally, based on public comments and reports to the EPA's Natural
Gas STAR program, the EPA recognizes that some producers conduct well
completions using REC techniques voluntarily for economic and/or
environmental objectives as a normal part of business. To account for
emissions reductions and costs arising from voluntary implementation of
pollution controls, the EPA used information on total emission
reductions reported to the EPA by partners of the EPA Natural Gas STAR.
This estimate of this voluntary REC activity in the absence of
regulation is also included in the baseline. More detailed discussion
on the derivation of the baseline is presented in a technical
memorandum in the docket, as well as in the RIA.
    Based upon the analysis in the RIA, which is in the Docket, when
revenue from additional natural gas product recovered is not included,
we estimate that 123 of the 127 small firms analyzed (97 percent) are
likely to have impacts less than 1 percent in terms of the ratio of
annualized compliance costs to revenues. Meanwhile, four firms (3
percent) are likely to have impacts greater than 1 percent. Three of
these four firms are likely to have impacts greater than 3 percent.
However, when revenue from additional natural gas product recovery is
included, we estimate that none of the analyzed firms will have an
impact greater than 1 percent.
    For the final NESHAP amendments, we estimate that 11 of the 35
firms (31 percent) that own potentially affected facilities are small
entities. The EPA performed an analysis for impacts on all expected
affected small entities by comparing compliance costs to entity
revenues. Among the small firms, none are likely to have impacts
greater than 1 percent in terms of the ratio of annualized compliance
costs to revenues.
    After considering the economic impact of the combined NSPS and
NESHAP amendments on small entities, I certify this action will not
have a significant impact on a substantial number of small entities
(SISNOSE). While both the NSPS and NESHAP amendment would individually
result in a no SISNOSE finding, the EPA performed an additional
analysis in order to certify the rule in its entirety. This analysis
compared compliance costs to entity revenues for the total of all the
entities affected by the NESHAP amendments and the sample of entities
analyzed for the NSPS. When revenues from additional natural gas
product sales are not included, 132 of the 136 small firms (97 percent)
in the sample are likely to have impacts of less than 1 percent in
terms of the ratio of annualized compliance costs to revenues.
Meanwhile, four firms (3 percent) are likely to have impacts greater
than 1 percent. Three of these four firms are likely to have impacts
greater than 3 percent. When revenues from additional natural gas
product sales are included, none of the 136 small firms (100 percent)
are likely to have impacts greater than 1 percent.
    Our determination is informed by the fact that many affected firms
are expected to receive revenues from the additional natural gas and
condensate recovery engendered by the implementation of the controls
evaluated in this RIA. As much of the additional natural gas recovery
is estimated to arise from completion-related activities, we expect the
impact

on well-related compliance costs to be significantly mitigated. This
conclusion is enhanced because the returns to REC activities occur
without a significant time lag between implementing the control and
obtaining the recovered product, unlike many control options where the
emissions reductions accumulate over long periods of time; the reduced
emission completions occur over a short span of time, during which the
additional product recovery is also accomplished and payments for
recovered products are settled.
    Although this final rule will not impact a substantial number of
small entities, the EPA, nonetheless, has tried to reduce the impact of
this rule on small entities by setting the final emissions limits at
the MACT floor, the least stringent level allowed by law.

D. Unfunded Mandates Reform Act

    This final action does not contain a federal mandate under the
provisions of Title II of the Unfunded Mandates Reform Act of 1995
(UMRA), 2 U.S.C. 1531-1538 for state, local, and tribal governments, in
the aggregate, or to the private sector. The action would not result in
expenditures of $100 million or more for state, local, and tribal
governments, in the aggregate, or to the private sector in any 1 year.
Thus, this final rule is not subject to the requirements of sections
202 or 205 of UMRA.
    This final rule is also not subject to the requirements of section
203 of UMRA because it contains no regulatory requirements that might
significantly or uniquely affect small governments because it contains
no requirements that apply to such governments nor does it impose
obligations upon them.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government, as
specified in Executive Order 13132. These final rules primarily affect
private industry, and do not impose significant economic costs on state
or local governments. On the contrary, we believe the modification
provisions discussed in section IX.A for well completions conducted at
gas wells constructed on or before August 23, 2011, will reduce
permitting burden borne by the States. These provisions will result in
fewer sources becoming affected facilities under the NSPS while
achieving emission reductions beginning October 15, 2012 equal to those
achieved by new sources beginning January 1, 2015. Thus, Executive
Order 13132 does not apply to this action.

F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    Subject to the Executive Order 13175 (65 FR 67249, November 9,
2000) the EPA may not issue a regulation that has tribal implications,
that imposes substantial direct compliance costs, and that is not
required by statute, unless the Federal government provides the funds
necessary to pay the direct compliance costs incurred by tribal
governments, or the EPA consults with tribal officials early in the
process of developing the proposed regulation and develops a tribal
summary impact statement.
    The EPA has concluded that this action will not have tribal
implications because it doesn't impose a significant cost to the tribal
government. However, there are significant tribal interests because of
the growth of the oil and gas production industry in Indian country.
    The EPA initiated a consultation process with tribal officials
early in the process of developing this regulation to permit them to
have meaningful and timely input into its development. During the
consultation process, the EPA conducted outreach and information
meetings prior to the proposal in 2010. The EPA met with the Inter
Tribal Environmental Council, which include many of the Region VI
tribes, The Tribal leadership summit in Region X, and Tribal Energy
Conference hosted by Ft. Belknap, and the National Tribal Forum.
    After the proposal was published, letters were sent to all tribal
leaders offering to consult on a government-to-government basis on the
rule. As part of the consultation process and in response to these
letters, an outreach call was held on October 12, 2011. Tribes that
participated on this call were: Fond du Lac Band of Lake Superior
Chippewa, Fort Belknap Indian Community, Forest County Potawatomi
Community, Southern Ute Indian Tribe, and Pueblo of Santa Clara.
    In this meeting the tribes were presented the information in the
proposal. The tribes asked general clarifying questions but did not
provide specific comments. Comments on the proposal were received from
an affiliate of the Southern Ute Indian Tribe. The commenter expressed
concern about the impacts of the rule on natural gas and oil production
operations on the Southern Ute Indian reservation and requested
additional time to evaluate the impacts. In response to this and other
requests, the comment period was extended. More specific comments can
be found in the docket.

G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 (62 FR 19885,
April 23, 1997) because the Agency does not believe the environmental
health risks or safety risks addressed by this action present a
disproportionate risk to children. This action would not relax the
control measures on existing regulated sources. The EPA's risk
assessments (included in the docket for this final rule) demonstrate
that the existing regulations are associated with an acceptable level
of risk and provide an ample margin of safety to protect public health.

H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    This action is not a ``significant energy action'' as defined in
Executive Order 13211 (66 FR 28355, May 22, 2001), because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. These final rules will result in the
addition of control equipment and monitoring systems for existing and
new sources within the oil and natural gas industry. The final NESHAP
amendments are unlikely to have a significant adverse effect on the
supply, distribution, or use of energy. As such, the final NESHAP
amendments are not ``significant energy actions'' as defined in
Executive Order 13211, (66 FR 28355, May 22, 2001). The final NSPS is
also unlikely to have a significant adverse effect on the supply,
distribution, or use of energy. As such, the final NSPS is not a
``significant energy action'' as defined in Executive Order 13211 (66
FR 28355, May 22, 2001).
    The basis for these determinations is as follows. Emission controls
for the NSPS capture VOC emissions that otherwise would be vented to
the atmosphere. Since methane is co-emitted with VOC, a large
proportion of the averted methane emissions can be directed into
natural gas production streams and sold. One pollution control
requirement of the final NSPS also captures saleable condensates. The
revenues from additional natural gas and condensate recovery are
expected to offset the costs of implementing the final rules.
    We use the NEMS to estimate the impacts of the combined final rules
on

the United States energy system. The NEMS is a publically available
model of the United States energy economy developed and maintained by
the Energy Information Administration of the DOE and is used to produce
the Annual Energy Outlook, a reference publication that provides
detailed forecasts of the United States energy economy.
    Based on public comments and reports to EPA's Natural Gas STAR
program, the EPA recognizes that some producers conduct well
completions using REC techniques, which are required by the final NSPS
for certain completions of hydraulically fractured and refractured
natural gas wells, voluntarily based upon economic and environmental
objectives. The baseline used for the energy system impacts analysis
takes into account REC conducted pursuant to state regulations covering
these operations and estimates of REC performed voluntarily. To account
for REC performed in regulated states, the EPA subsumed emissions
reductions and compliance costs in states where these completion-
related emissions are already controlled into the baseline.
Additionally, based on public comments and reports to the EPA's Natural
Gas STAR program, the EPA recognizes that some producers conduct well
completions using REC techniques voluntarily for economic and/or
environmental objectives as a normal part of business. To account for
emissions reductions and costs arising from voluntary implementation of
pollution controls, the EPA used information on total emission
reductions reported to the EPA by partners of the EPA Natural Gas STAR.
This estimate of this voluntary REC activity in the absence of
regulation is also included in the baseline. More detailed discussion