[Federal Register Volume 78, Number 184 (Monday, September 23, 2013)]
[Rules and Regulations]
[Pages 58415-58448]
[FR Doc No: 2013-22010]

Vol. 78

Monday,

No. 184

September 23, 2013

Part III

Environmental Protection Agency

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40 CFR Part 60

Oil and Natural Gas Sector: Reconsideration of Certain Provisions of
New Source Performance Standards; Final Rule

Federal Register / Vol. 78 , No. 184 / Monday, September 23, 2013 /
Rules and Regulations

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2010-0505, FRL-9844-4]
RIN 2060-AR75

Oil and Natural Gas Sector: Reconsideration of Certain Provisions
of New Source Performance Standards

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final Amendments.

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SUMMARY: This action finalizes the amendments to new source performance
standards for the oil and natural gas sector. The Administrator
received petitions for reconsideration of certain aspects of the August
12, 2012, final standards. These amendments are a result of
reconsideration of certain issues raised by petitioners related to
implementation of storage vessel provisions. The final amendments
provide clarity of notification and compliance dates, ensure control of
all storage vessel affected facilities and update key definitions. This
action also corrects technical errors that were inadvertently included
in the final standards.

DATES: This final rule is effective on September 23, 2013.

ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2010-0505. All documents in the docket are
listed on the http://www.regulations.gov Web site. Although listed in
the index, some information is not publicly available, e.g.,
confidential business information or other information whose disclosure
is restricted by statute. Certain other material, such as copyrighted
material, is not placed on the Internet and will be publicly available
only in hard copy form. Publicly available docket materials are
available either electronically through http://www.regulations.gov or
in hard copy at the EPA's Docket Center, Public Reading Room, EPA West
Building, Room Number 3334, 1301 Constitution Avenue NW., Washington,
DC 20004. The Public Reading Room is open from 8:30 a.m. to 4:30 p.m.,
Monday through Friday, excluding legal holidays. The telephone number
for the Public Reading Room is<PHONE_NUMBER>, and the telephone number
for the Air Docket is<PHONE_NUMBER>.

FOR FURTHER INFORMATION CONTACT: Mr. Bruce Moore, Sector Policies and
Programs Division (E143-05), Office of Air Quality Planning and
Standards, Environmental Protection Agency, Research Triangle Park,
North Carolina 27711, telephone number:<PHONE_NUMBER>; facsimile
number:<PHONE_NUMBER>; email address<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: Organization of This Document. The
information presented in this preamble is organized as follows:

I. Preamble Acronyms and Abbreviations
II. General Information
    A. Executive Summary
    B. Does this reconsideration notice apply to me?
    C. How do I obtain a copy of this document and other related
information?
    D. Judicial Review
III. Summary of Final Amendments
    A. Initial Notification and Compliance Dates
    B. Group 1 and Group 2 Storage Vessel Emission Standards
Applicability
    C. Group 1 Storage Vessel Affected Facility Control Requirements
    D. Alternative 4-tpy Uncontrolled Actual VOC Emission Rate
    E. Definition of Storage Vessel
    F. Definition of Storage Vessel Affected Facility
    G. Streamlined Compliance Monitoring Provisions
    H. Combustion Control Device Manufacturer Test Protocol
    I. Annual Report and Compliance Certification
IV. Summary of Significant Changes Since Proposal
    A. Group 1 Storage Vessel Affected Facility Control Requirements
and Applicability
    B. Applicability Dates and Compliance Dates
    C. Definition of Storage Vessel Affected Facility
V. Summary of Significant Comments and Responses
    A. Major Comments Concerning Applicability Dates and Compliance
Dates
    B. Major Comments Concerning the Storage Vessel Affected
Facility Definition
    C. Major Comments Concerning Storage Vessel Control Requirements
    D. Major Comments Concerning Ongoing Compliance Requirements
    E. Major Comments Concerning Design Requirements
    F. Major Comments Concerning Impacts
VI. Technical Corrections and Clarifications
VII. Impacts of These Final Amendments
    A. What are the air impacts?
    B. What are the energy impacts?
    C. What are the compliance costs?
    D. What are the economic and employment impacts?
    E. What are the benefits of the proposed standards?
VIII. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act
    D. Unfunded Mandates Reform Act
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From
Environmental Health and Safety Risks
    H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
    K. Congressional Review Act

I. Preamble Acronyms and Abbreviations

    Several acronyms and terms are included in this preamble. While
this may not be an exhaustive list, to ease the reading of this
preamble and for reference purposes, the following terms and acronyms
are defined here:

API American Petroleum Institute
AVO Auditory, Visual and Olfactory
BOE Barrels of Oil Equivalent
bbl Barrel
bpd Barrels Per Day
BID Background Information Document
BSER Best System of Emissions Reduction
CAA Clean Air Act
CFR Code of Federal Regulations
CPMS Continuous Parametric Monitoring Systems
EIA Energy Information Administration
EPA Environmental Protection Agency
GOR Gas to Oil Ratio
HAP Hazardous Air Pollutant
HPDI HPDI, LLC
Mcf Thousand Cubic Feet
NTTAA National Technology Transfer and Advancement Act of 1995
NEI National Emissions Inventory
NEMS National Energy Modeling System
NESHAP National Emissions Standards for Hazardous Air Pollutants
NSPS New Source Performance Standards
OAQPS Office of Air Quality Planning and Standards
OMB Office of Management and Budget
PRA Paperwork Reduction Act
PTE Potential to Emit
RFA Regulatory Flexibility Act
SISNOSE Significant Economic Impact on a Substantial Number of Small
Entities
tpy Tons per Year
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act
VCS Voluntary Consensus Standards
VOC Volatile Organic Compounds
VRU Vapor Recovery Unit

II. General Information

A. Executive Summary

1. Purpose of This Regulatory Action
    The purpose of this action is to finalize amendments to the 40 CFR
part 60, subpart OOOO, Standards of Performance for Crude Oil and
Natural Gas Production, Transmission and

Distribution final rule promulgated under section 111(b) of the Clean
Air Act (CAA), which was published on August 16, 2012 [77 FR 49490].
The amendments being finalized were proposed on April 12, 2012 [78 FR
22126]. Specifically, this final rule action amends aspects of the 2012
new source performance standards (2012 NSPS) to address select issues
raised by different stakeholders through several administrative
petitions for reconsideration of the 2012 NSPS. The select issues being
reconsidered and addressed by this action are related primarily to
implementation of the storage vessel provisions.
2. Summary of Major Amendments to the NSPS
    This rule finalizes a number of aspects of the proposal but, after
consideration of public comments received, it also makes certain
changes, as described in this section.
a. Initial Notification and Compliance Dates
    For Group 1 storage vessels (i.e., those the construction,
reconstruction or modification of which began after August 23, 2011,
and on or before April 12, 2013),\1\ the final amendments require that
owners/operators estimate emissions from the storage vessels to
determine affected facility no later than October 15, 2013, and a
notification be submitted with the facilities' annual report due by
January 15, 2014, to inform regulatory agencies of the existence and
location of the Group 1 storage vessel affected facilities. The final
amendments retain the requirement that all Group 1 storage vessel
affected facilities comply with the emission standards but, in a change
from proposal, extend the compliance deadline to April 15, 2015. Since
all Group 1 affected facilities are required to meet the emission
standards, the final amendments do not require Group 1 storage vessel
affected facilities to track emission increase events, as we had
proposed.
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    \1\ The 2012 NSPS proposal was published on August 23, 2011, and
the proposed rule for this action was published on April 12, 2013.
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    For Group 2 storage vessel affected facilities (i.e., those the
construction, reconstruction or modification of which began after April
12, 2013), the final amendments extend the compliance date to April 15,
2014 (or 60 days after startup, whichever is later), for implementing
the emission standards, as proposed.
    In response to comments regarding the confusion about when the
affected facility status for Group 1 storage vessels should be
determined, we have also made clarifying changes to Sec.  60.5365(e) in
the final amendments that clearly specify October 15, 2013, as the
deadline for calculating potential volatile organic compound (VOC)
emissions from Group 1 storage vessels for determining the affected
facility status.
b. Group 1 and Group 2 Storage Vessel Emission Standards Applicability
    We have amended Sec.  60.5395 to more clearly specify that the
requirements of the NSPS apply to Group 1 and Group 2 storage vessel
affected facilities (i.e., those with potential to emit (PTE) 6 or more
tpy of VOC, as determined by the methods and dates specified in this
final rule). We amended this language in response to several comments
expressing confusion about whether the requirements applied to all
Group 1 storage vessels or just those with VOC emissions of 6 tpy or
greater (i.e., affected facilities).
c. Group 1 Storage Vessel Affected Facility Emission Standards and
Compliance Dates
    A key feature of this action is that the final amendments require
control of all storage vessel affected facilities constructed since the
August 23, 2011, proposal date of the 2012 NSPS. This decision, as
summarized in this section and discussed fully in sections IV.A and V.C
of this preamble, was based on new information we received that
indicates that the projected control device supply appears to be
greater than we originally estimated.
    In the preamble to the proposed amendments, based on the
information then available to the EPA, we developed an estimate of the
supply of the type of combustors likely to be used by owners and
operators to comply with the control requirements and concluded that
control supply would not catch up with its demand under this rule until
2016. To avoid delaying control until such time, we proposed that Group
1 affected facilities notify the EPA of their presence and location by
October 15, 2013, but need not comply with the 95 percent reduction
requirement unless they experience an emission increase event. However,
new information we received since proposal indicates that the combustor
suppliers have the manufacturing capacity to meet the demand posed both
by this regulation and a variety of state and local regulations that
require the installation of control devices. Therefore, in the final
amendments, we are not changing the requirement of the 2012 NSPS that
Group 1 storage vessel affected facilities comply with the emission
standard requirements. However, we have extended the current compliance
deadline. For the reasons discussed in detail in section IV.A, these
final amendments require that Group 2 affected facilities comply with
the emission standards by April 15, 2014, as we proposed, and that
Group 1 affected facilities comply by April 15, 2015.
d. Alternative 4-tpy Uncontrolled Actual VOC Emission Rate
    To help alleviate the control supply shortage believed to exist at
the time, we had proposed that affected facilities meet the 95%
reduction requirement or an uncontrolled actual VOC emission rate of
less than 4 tpy, which would allow control devices to be removed from
storage vessel affected sources below that emission rate and relocated
to those that have just come on line and have PTE of 6 tpy VOC or more.
As mentioned above, new information we received since proposal indicate
that the combustor suppliers have the manufacturing capacity to meet
the demand posed by this regulation, which in turn would suggest that a
supply buffer may no longer be necessary. However, for the reasons
provided in section V.C of this preamble, we are finalizing the
amendment to the storage vessel emission standards as proposed due to
questionable cost effectiveness, the secondary environmental impact and
the energy impacts from the continued operation of the combustion
control device at an inlet stream concentration of less than about 4
tpy. We were aware but had not highlighted these concerns in the
proposed amendment because the perceived supply problem alone
necessitated proposing the amendment. The resolution of the supply
issue, however, shifts our focus back to these concerns. As explained
in more detail in section V.C of this preamble, in light of the
questionable cost effectiveness of additional control, the secondary
environmental impact and the energy impacts we conclude that the best
system of emissions reduction (BSER) for reducing VOC emissions from
storage vessel affected facilities is not represented by continued
control when their sustained uncontrolled emission rates fall below 4
tpy. We are therefore finalizing the amendment as proposed. Under the
final amendments, an owner or operator may comply with the uncontrolled
actual VOC emission rate instead of the 95 percent control requirement
where it can be demonstrated that, based on records of monthly
determinations of actual

emission rate for the 12 consecutive months immediately preceding the
demonstration, that the storage vessel affected facility uncontrolled
actual VOC emissions for each month during that 12-month period have
been below 4 tpy. The final amendments require that the owner or
operator re-evaluate the uncontrolled actual VOC emissions on a monthly
basis. If the results of the monthly determination show that the
uncontrolled actual VOC emission rate is 4 tpy or more, the owner or
operator would have 30 days to meet the 95 percent control requirement.
We discuss this further in section V.C of this preamble.
e. Definition of Storage Vessel Affected Facility
    We have finalized the proposed amendments to the definition of
``storage vessel affected facility'' in the final rule (see Sec.
60.5365(e)) to (1) include the 6 tpy VOC emission threshold and to
clarify that a source can take into account any legally and practically
enforceable emission limit under federal, state, local or tribal
authority when determining the VOC emission rate for purposes of this
threshold; (2) clarify that a storage vessel affected facility whose
VOC PTE decreases to less than 6 tpy would remain an affected facility;
and (3) to clarify that PTE does not include any vapor recovered and
routed to a process.
f. Streamlined Compliance Monitoring Provisions
    We received several comments regarding the streamlined compliance
monitoring provisions; our review of the comments did not result in
significant changes since proposal. These compliance monitoring
provisions include inspections of covers, closed-vent systems and
control devices, performed at least monthly. We believe that these
measures are sufficient to ensure that storage vessel affected
facilities that have installed controls meet the 95 percent VOC
reduction standard. Although the more stringent compliance monitoring
provisions in the 2012 NSPS may provide better assurance of compliance,
there are significant issues regarding their implementation, which have
been raised in several administrative reconsideration petitions. We
continue to evaluate the reconsideration issues related to compliance
monitoring and intend to complete our reconsideration by the end of
2014.
3. Cost and Benefits
    Owners and operators of storage vessel affected facilities are
expected to install and operate the same or similar air pollution
control technologies under these final amendments as would have been
necessary to meet the previously finalized standards for the oil and
natural gas sector under the 2012 NSPS. We project that these
amendments will not result in a significant change in costs and or
benefits compared to the 2012 NSPS. The final amendments continue to
require that all storage vessel affected facilities comply with the
emission standards. Although the final amendments may not achieve the
same level of emission reductions as the 2012 NSPS, it was necessary to
revise the standards due to the limitations of the 2012 rule. The
revisions provided in the final amendments were needed for the reasons
explained in this preamble, and we believe the rule provides
significant benefits. We anticipate that, if there are any changes in
costs for these units, such changes would likely be small relative to
both the overall costs of the individual projects and the overall costs
and benefits of the final rule.

B. Does this reconsideration notice apply to me?

    Categories and entities potentially affected by today's notice
include:

      Table 1--Industrial Source Categories Affected by This Action
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                                                  Examples of regulated
            Category             NAICS code \1\          entities
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Industry.......................          211111  Crude Petroleum and
                                                  Natural Gas
                                                  Extraction.
                                         211112  Natural Gas Liquid
                                                  Extraction.
                                         221210  Natural Gas
                                                  Distribution.
                                         486110  Pipeline Distribution
                                                  of Crude Oil.
                                         486210  Pipeline Transportation
                                                  of Natural Gas.
Federal government.............  ..............  Not affected.
State/local/tribal government..  ..............  Not affected.
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\1\ North American Industry Classification System.

    This table is not intended to be exhaustive, but rather is meant to
provide a guide for readers regarding entities likely to be affected by
this action. If you have any questions regarding the applicability of
this action to a particular entity, consult either the air permitting
authority for the entity or your EPA regional representative as listed
in 40 CFR 60.4 or 40 CFR 63.13 (General Provisions).

C. How do I obtain a copy of this document and other related
information?

    In addition to being available in the docket, electronic copies of
these proposed rules will be available on the Worldwide Web through the
Technology Transfer Network (TTN). Following signature, a copy of each
proposed rule will be posted on the TTN's policy and guidance page for
newly proposed or promulgated rules at the following address: http://www.epa.gov/ttn/oarpg/. The TTN provides information and technology
exchange in various areas of air pollution control.

D. Judicial Review

    Under section 307(b)(1) of the CAA, judicial review of this final
rule is available only by filing a petition for review in the U.S.
Court of Appeals for the District of Columbia Circuit by November 22,
2013. Under section 307(d)(7)(B) of the CAA, only an objection to this
final rule that was raised with reasonable specificity during the
period for public comment can be raised during judicial review.
Moreover, under section 307(b)(2) of the CAA, the requirements
established by this final rule may not be challenged separately in any
civil or criminal proceedings brought by the EPA to enforce these
requirements. Section 307(d)(7)(B) of the CAA further provides that
``[o]nly an objection to a rule or procedure which was raised with
reasonable specificity during the period for public comment (including
any public hearing) may be raised during judicial review.'' This
section also provides a mechanism for us to convene a proceeding for
reconsideration, ``[i]f the person raising an objection can demonstrate
to the EPA that it was

impracticable to raise such objection within [the period for public
comment] or if the grounds for such objection arose after the period
for public comment (but within the time specified for judicial review)
and if such objection is of central relevance to the outcome of the
rule.'' Any person seeking to make such a demonstration to us should
submit a Petition for Reconsideration to the Office of the
Administrator, U.S. EPA, Room 3000, Ariel Rios Building, 1200
Pennsylvania Ave. NW., Washington, DC 20460, with a copy to both the
person(s) listed in the preceding FOR FURTHER INFORMATION CONTACT
section, and the Associate General Counsel for the Air and Radiation
Law Office, Office of General Counsel (Mail Code 2344A), U.S. EPA, 1200
Pennsylvania Ave. NW., Washington, DC 20460.

III. Summary of Final Amendments

    The final amendments include revisions to certain reconsidered
aspects of the existing 2012 NSPS which primarily affect the
implementation of the regulation of VOC emissions from storage vessels.
A summary of the final amendments resulting from our reconsideration
are provided in the following paragraphs.

A. Initial Notification and Compliance Dates

    For Group 1 storage vessel affected facilities, we have amended the
2012 NSPS to require that a notification be submitted with the initial
annual report, to inform regulatory agencies of the existence and
location of the vessels. In addition, we have amended the 2012 NSPS to
require that all Group 1 storage vessel affected facilities comply with
the emission standards no later than April 15, 2015, and that all Group
2 storage vessel affected facilities comply no later than April 15,
2014, (or 60 days after startup, whichever is later).
    The final amendments also make clarifying changes to Sec.  60.5395
that clearly specify October 15, 2013, as the deadline for calculating
potential VOC emissions from Group 1 storage vessels to determine
affected facility status.

B. Group 1 and Group 2 Storage Vessel Emission Standards Applicability

    We have amended Sec.  60.5395 to clearly state that the emission
standards apply to Group 1 and Group 2 storage vessel affected
facilities (as opposed to all storage vessels).

C. Group 1 Storage Vessel Affected Facility Control Requirements

    The final amendments retain the requirement in the 2012 NSPS that
all storage vessel affected facilities meet the emission standards.
However, the final amendments require that owners and operators of
Group 1 storage vessel affected facilities comply with the emission
standards by April 15, 2015, and that Group 2 storage vessel affected
facilities comply by April 15, 2014.

D. Alterative 4-tpy Uncontrolled Actual VOC Emission Rate

    We have amended the storage vessel standards to include a sustained
uncontrolled actual VOC emission rate of less than 4 tpy. Specifically,
an owner or operator may comply with the uncontrolled actual VOC
emission rate instead of the 95 percent control requirement where it
can be demonstrated that, based on records of monthly emission
estimates for the 12 months immediately preceding the demonstration,
that the storage vessel affected facility uncontrolled actual VOC
emissions estimated each of those months were below 4 tpy. The owner or
operator would be required to re-evaluate the uncontrolled actual VOC
emissions on a monthly basis. If the results of the monthly
determination show that the uncontrolled actual VOC emission rate is 4
tpy or more, the owner or operator would have 30 days to meet the 95
percent control requirement, unless the increase was associated with
the fracturing or refracturing of a well feeding the storage vessel
affected facility. In that case, 95 percent control would be required
as soon as liquids are routed from the fractured or refractured well to
the storage vessel. We discuss this further in section V.C of this
preamble.

E. Definition of Storage Vessel

    The final amendments revise the definition of ``storage vessel'' to
clarify that it refers only to vessels containing crude oil,
condensate, intermediate hydrocarbon liquids or produced water.

F. Definition of Storage Vessel Affected Facility

    The final amendments revise the definition of ``storage vessel
affected facility'' (see Sec.  60.5365(e)) to (1) include the 6 tpy VOC
emission limit and to clarify that a source can take into account any
legally and practically enforceable emission limit under federal,
state, local or tribal authority when determining the VOC emission rate
for purposes of this threshold; (2) clarify that a storage vessel
affected facility whose VOC PTE decreases to less than 6 tpy would
remain an affected facility; (3) clarify that ``other mechanisms'' (or
non-federally enforceable mechanisms) must be legally and practically
enforceable under federal, state, local or tribal authority; and (4)
clarify that vapor from a storage vessel that is recovered and routed
to a process is not to be counted in the PTE for purposes of
determining affected facility status.
    We also added language at Sec.  60.5395(f) to address storage
vessel affected facilities that are removed from service. Owners and
operators are required to include a notification in their next annual
report that the storage vessel has been taken out of service. If a
storage vessel's return to service is associated with fracturing or
refracturing of a well feeding the storage vessel, the storage vessel
is subject to control requirements immediately upon returning to
service. If, however, the storage vessel's return to service is not
associated with well fracturing or refracturing, the PTE of the storage
vessel must be determined within 30 days. If the PTE is 4 tpy or
greater, then the storage vessel affected facility must comply with
control requirements within 60 days of returning to service.

G. Streamlined Compliance Monitoring Provisions

    For storage vessels that install controls to meet the 95 percent
VOC reduction standard, we have amended the 2012 NSPS to adopt the
streamlined compliance monitoring provisions as proposed without
significant changes. These compliance monitoring provisions include
inspections performed at least monthly of covers, closed-vent systems
and control devices. As mentioned above, we continue to evaluate the
reconsideration issues raised concerning the compliance monitoring
provisions in the 2012 NSPS and intend to complete our reconsideration
by the end of 2014.

H. Combustion Control Device Manufacturer Test Protocol

    We have finalized amendments to the enclosed combustor manufacturer
test protocol in the NSPS to align it with a similar protocol in the
Oil and Natural Gas National Emission Standards for Hazardous Air
Pollutants (NESHAP) (40 CFR 63, subpart HH).

I. Annual Report and Compliance Certification

    We finalized amendments to allow 90 days after the end of the
compliance period for submittal of the annual report and compliance
certification.

IV. Summary of Significant Changes Since Proposal

    Section III summarized the amendments to the 2012 NSPS that the

EPA is finalizing in this rule. This section will discuss the key
changes the EPA has made since the April 12, 2013, proposal. These
changes are the result of the EPA's consideration of the many
substantive and thoughtful comments submitted on the proposal and other
information received since proposal. We believe that the changes we
have made sufficiently address concerns expressed by commenters and
improve the clarity of the rule while improving or preserving public
health and environmental protection required under the CAA.

A. Group 1 Storage Vessel Affected Facility Control Requirements and
Applicability

    We received comments requesting clarification regarding Group 1
storage vessel affected facility control requirement applicability. We
also received comments on our estimate of the supply of combustors used
to comply with the control requirements and our use of this estimate to
determine the requirements for Group 1 storage vessel affected
facilities.
    To the extent that there was confusion regarding the applicability
of Group 1 storage vessel affected facility control requirements, we
agree that there is a need for more clarity in the final amendments. To
accomplish this, we have included amendments to Sec.  60.5395(b) that
make it clear that these requirements apply only to Group 1 storage
vessel affected facilities (emphasis added) (i.e., those that have the
PTE of 6 tpy VOC or more, as determined by the dates specified in the
rule, as amended), not all Group 1 storage vessels. Refer to section
V.A of this preamble for further discussion of comments and responses
pertaining to these changes.
    In the proposed amendments, based on the information then available
to the EPA, we concluded that control supply would not catch up with
its demand under this rule until 2016. To avoid delaying control until
such time, we proposed that Group 1 affected facilities notify the EPA
of their presence and location by October 15, 2013, but need not comply
with the 95 percent reduction requirement unless they experience an
emission increase event. Information we received since proposal
indicate that the combustor suppliers have the manufacturing capacity
to meet the demand posed both by this regulation and a variety of state
and local regulations that require the installation of control devices
even when accounting for the need to cover Group 1 well in advance of
the projected 2016 date. Therefore, in the final amendments we did not
finalize the proposed requirement for Group 1 storage vessel affected
facilities to be controlled only if there is an emission increase
event. However, as explained in more detail below, we have concerns
regarding the projections of potential combustor supply; the pace at
which the combustor manufacturing industry can ramp up production and
provide the necessary supply in the short-term; and the availability of
trained personnel to install these devices on all affected facilities
that will have already come on line by the current compliance date of
October 15, 2013, as well as the additional approximately 1,100 new
affected facilities per month that may need control. Consideration of
these factors leads us to conclude that an adjustment to the compliance
schedule is warranted.
    First, we note that there is a great variability in the projections
of potential combustor supply, with one supplier's projection greatly
exceeding the other suppliers' projections. Our revised conclusion
regarding supply of control devices is largely based on this one
supplier's manufacturing capacity, which, if changed, could potentially
affect sources' ability to acquire and install control by the current
compliance deadline (i.e., October 15, 2013 or 60 days after startup,
whichever is later). In light of the above, additional time is needed
beyond October 15, 2013, for compliance with the 95 percent reduction
requirement. Secondly, we share the concern raised by several
commenters that, due to the large number of storage vessel affected
facilities, some may not be able to secure the necessary trained
personnel to install control devices by the current compliance
deadline, especially in the near term. Under the 2012 NSPS,
installation of controls would be required by the current compliance
date of October 15, 2013, for over 20,000 affected facilities that we
estimate will have already come on line since the August 23, 2011,
proposal date of the 2012 NSPS, as well as the additional approximately
1,100 new affected facilities per month that will need to install
control 60 days after start-up. Lastly, while the overall supply of
combustors appears to be adequate, we have concerns about how quickly
the combustor manufacturing industry can ramp up production and provide
the necessary supply in the short-term. We are doubtful that, even at
full current capacity, there would be sufficient control devices to
meet the October 15, 2013, compliance date. For the reasons stated
above, we decided to take a phase-in compliance approach that requires
the newer affected facilities (which would have higher emissions) to
comply first. Accordingly, the final amendments require that Group 2
affected facilities comply with the emission standards by April 15,
2014, as we proposed, and that Group 1 affected facilities comply by
April 15, 2015.
    Refer to section V.C of this preamble for further discussion
regarding these changes.
    In addition, we had proposed a list of examples of ``events'' that
would trigger control requirements for Group 1 storage vessel affected
facilities. As noted, all Group 1 storage vessel affected facilities
must meet the control requirements by April 15, 2015. Therefore, we no
longer need to look to events that may be presumed to increase
emissions to determine which Group 1 storage vessel affected facilities
are subject to control requirements. All proposed provisions related to
tracking events have been removed from the final amendments, thereby
simplifying the rule and avoiding additional burden and potential
confusion.
    Refer to section V.A of this preamble for further discussion
regarding these changes.

B. Applicability Dates and Compliance Dates

    As discussed in section IV.A of this preamble, the EPA previously
concluded that there will be an insufficient supply of combustion
control devices for all storage vessel affected facilities until 2016,
based on information available at proposal. To avoid postponing control
for all storage vessels affected facilities until 2016, we proposed
alternative measures for Group 1 and Group 2 storage vessel affected
facilities. For Group 1 storage vessel affected facilities, we proposed
to require initial notification by October 15, 2013, to inform
regulatory agencies of the existence and location of these storage
vessels. We also proposed that Group 1 storage vessel affected
facilities that undergo an event after April 12, 2013, that could
reasonably be expected to lead to an increase in VOC PTE would be
subject to control requirements. For Group 2 storage vessel affected
facilities, we proposed April 15, 2014, as the compliance date for
implementing control requirements.
    In response to comments concerning Group 1 storage vessel control
requirement applicability and compliance being tied to the ``events''
listed in Sec.  60.5395(b)(2) and unclear notification and compliance
dates for both Group 1 and Group 2 storage vessels, we have made
changes to the

final amendments. For Group 1 storage vessels, we are requiring that
the owner or operator determine whether the storage vessel is an
affected facility no later than October 15, 2013. In the proposed
amendments, owners or operators of Group 1 storage vessel affected
facilities had to submit an initial notification of these storage
vessels by October 15, 2013, as well as an initial annual report by
January 15, 2014. In the final amendments, the initial notification may
be combined with the initial annual report to reduce the burden of
submitting two notifications within a 90-day period. As discussed
previously in section IV.A of this preamble, the final amendments
retain the requirement in the 2012 NSPS that all Group 1 storage vessel
affected facilities comply with emission standards, and specify that
compliance must be achieved by April 15, 2015. Therefore, we have
removed all provisions related to tracking emission increase events
from the final amendments.
    For Group 2 storage vessel affected facilities, we are finalizing
April 15, 2014, (or 60 days after startup, whichever is later) as the
compliance date for implementing control requirements.
    Refer to section V.A of this preamble for further discussion of
comments and responses regarding these provisions.

C. Definition of Storage Vessel Affected Facility

    We proposed to amend the definition of ``storage vessel affected
facility'' to specify that the storage vessel must have a VOC PTE equal
to or greater than 6 tpy to be an affected facility and to clarify that
the owner or operator can take into account any legally and practically
enforceable emission limit in an operating permit, or by another
mechanism under state, local or tribal authority, when determining the
VOC PTE. The proposed amendment also clarified that a storage vessel
affected facility whose potential VOC emissions decrease to less than
the threshold of 6 tpy would remain an affected facility. We proposed
this amendment to clarify that a storage vessel complying with the
proposed uncontrolled actual VOC emission rate would remain an affected
facility.
    We received comments opposing the revisions to the definition of
``storage vessel affected facility'' to the extent that it may allow
storage vessel operators to account for non-federally enforceable
emission limitations that may change in the future and are not
enforceable by the EPA in the determination of VOC PTE. Upon
evaluation, we believe that the commenters' concern arises from
language we used in the proposed amendments to Sec.  60.5365(e) to
define the storage vessel affected facility which could have been
confusing due to the phrase ``other mechanisms.'' Therefore, the final
amendments clarify that ``other mechanisms'' must be legally and
practically enforceable under federal, state, local or tribal
authority.
    We received public comments that requested that the 6 tpy threshold
for storage vessel affected facilities be determined after application
of a vapor recovery unit (VRU) (i.e., taking the VRU vapor recovery
into account in the emissions determination) for Group 1 and Group 2
storage vessels.
    In September 2012, in response to issues brought to the EPA's
attention after the publication of the 2012 NSPS, we clarified that we
do not consider VRUs that route recovered gas and vapor back to the
process to be control devices, which is consistent with their treatment
under 40 CFR part 63, subpart HH.\2\
---------------------------------------------------------------------------

    \2\ Letter from Peter Tsirigotis to Matthew Todd, American
Petroleum Institute. September 28, 2012. Docket Item No. EPA-HQ-OAR-
2010-0505-4595.
---------------------------------------------------------------------------

    As long as certain operating requirements are met, we believe it is
appropriate to take into account reductions in VOC emissions that
result from the recovery of vapor and routing of it to a VRU when
determining the VOC PTE from a storage vessel for purposes of
determining affected facility status. Routing of vapor through a VRU to
a process reduces VOC emissions without secondary environmental impacts
(e.g., NOX emissions) and is responsible conservation of our
energy resources. However, it does not totally eliminate VOC emissions,
since the VRU cannot operate 100 percent of the time due to maintenance
and repair down time. Our September 28, 2012, letter clarified that the
cover and closed vent requirements must be met when VRU is used to meet
the 95 percent reduction emission standards. That said, we previously
determined that routing of vapor through a cover and properly operated
closed-vent system would recover all vapor routed to the system as long
as the VRU is operating (i.e., 95 percent of the vapor being routed to
a line when operating for 95 percent of the time). In light of the
above, as long as the VRU is operated consistent with those
requirements, we believe that it is appropriate to exclude 95 percent
of the vapor that would otherwise be emitted if not recovered when
determining PTE for purposes of determining affected facility status.
As a result of this comment, and based on our prior clarification of
this issue, the final amendments to Sec.  60.5365(e) include a
provision that ``any vapor from the storage vessel that is recovered
and routed to a process through a VRU designed and operated as
specified in this section is not required to be included in the
determination of VOC potential to emit for purposes of determining
affected facility status.'' Further, we have added language to Sec.
60.5365(e) that provides for this adjustment of PTE as long as (1) the
storage vessel is operated in compliance with cover requirements in
Sec.  60.5411(b) and the closed-vent system requirements in Sec.
60.5411(c), which has a requirement that the CVS (including the VRU) is
operational at least 95 percent of the time, and that the operator
maintain records demonstrating compliance with these requirements.
    We were concerned that, should a VRU be removed or operated
inconsistent with the conditions that were the basis for the PTE
reduction following the PTE determination for assessing whether the
storage vessel is an affected facility, emissions could increase
without the storage vessel being subject to control. To address that
possibility, we have added language to Sec.  60.5365(e) such that, in
the event of removal of apparatus that recovers and routes vapor to a
process or operation that is inconsistent with the conditions for
qualifying for the PTE reduction, the owner or operator would be
required to determine PTE from the storage vessel within 30 days of
such removal or operation. If the PTE is determined to be 6 tpy VOC or
more, then the storage vessel would be an affected facility and subject
to the control requirements in Sec.  60.5395. We believe this approach
will help avoid circumvention of the NSPS.
    We received comment that storage vessel affected facilities that
are removed from service should cease to be considered affected
facilities. Although, for the reasons presented in section V.C of this
preamble, we disagree with the commenter and have added language at
Sec.  60.5395(f) to address storage vessel affected facilities that are
removed from service. Owners and operators are required to include a
notification in their next annual report following removal from service
that the storage vessel has been taken out of service. If a storage
vessel's return to service is associated with the fracturing or
refracturing of a well feeding the storage vessel, the storage vessel
is subject to control requirements immediately upon returning to
service. If, however, the storage vessel's return to service is not

associated with well fracturing or refracturing, the PTE of the storage
vessel must be determined within 30 days. If the PTE is 4 tpy or
greater, then the storage vessel affected facility must comply with
control requirements within 60 days of returning to service.

V. Summary of Significant Comments and Responses

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

A. Major Comments Concerning Applicability Dates and Compliance Dates

1. When do Group 1 storage vessels have to determine emissions?
a. Applicability Determination
    Comment: One commenter requested that the final rule specify the
date upon which the determination of the potential VOC emission rate
should occur for the purpose of determining whether the storage vessel
is an affected facility. According to the commenter, since the EPA has
stipulated controls to not be cost effective for storage vessels
emitting less than 6 tpy of VOC, and emission rates for storage vessels
in the oil production segment tend to decrease as production declines,
the commenter believes the determination should be made near to the
date upon which controls would be required in order to minimize the
potential to install controls on storage vessels for which production
decline has rendered controls no longer cost effective. The commenter
stated that the proposed revisions would require a determination by
October 15, 2013, of whether individual Group 1 storage vessels are
affected facilities, and thus October 15, 2013, would be an appropriate
date upon which determination of the potential VOC emission rate should
be based. According to the commenter, this would remain consistent with
the requirement for determining the potential VOC emission rate for
Group 2 storage vessels by April 15, 2014 or 30 days after startup,
whichever comes later.
    The commenter appears to suggest that, like Group 2, Group 1
storage vessel affected facilities located in the natural gas
processing and natural gas transmission and storage segments should
also be required to determine potential VOC emissions as the trigger
for installing control instead of tracking events but to do so by April
15, 2015 (instead of April 15, 2014, proposed for Group 2). According
to the commenter, control of the relatively low number of Group 1
storage vessel affected facilities in these segments could likely be
accommodated by this date.
    Another commenter pointed out that the proposed reconsideration
rule does not establish the date for a Group 1 storage vessel to
determine its potential emissions. The commenter also recommended that
notifications are only required for tanks that exceed the 6 tpy
threshold on October 15, 2013. Although the publication date of the
proposed reconsideration rule was April 12, 2013, the commenter
contends that the EPA is not required to, nor should it, establish the
emissions determination date for the source category of Group 1 storage
vessels on that date. First, given the rapidly declining emissions at
storage vessels following initial fracturing, the commenter believes
that the expected emissions reduction to be gained from Group 1 storage
vessels is likely to be limited. The commenter also states that the
proposal date of April 12, 2013, has passed and operators may not be
able to accurately back-calculate emissions from that date. Moreover,
the commenter contends that emissions from many of these storage
vessels will be below the 6 tpy affected source threshold as of October
2013. Given EPA's proposed approach, where storage vessel affected
facilities whose emissions drop below 6 tpy remain subject to the
standard, the commenter believes that many Group 1 storage vessels will
be unnecessarily captured in the source category and required to
indefinitely track ``events'' and perhaps install control devices even
if their emissions never again exceed 6 tpy.
    Response: The final amendments to Sec.  60.5365(e) specify that
Group 1 storage vessel affected facilities must determine potential VOC
emissions by October 15, 2013, for purposes of determining whether it
is an affected facility. For the reasons provided in the Response to
Public Comments on the Proposed Amendments document available in the
docket, the final amended Sec.  60.5365(e) requires that Group 1
affected facilities submit a notification with the first annual report
by January 15, 2014, to inform regulatory agencies of their existence
and locations. Determining potential emissions and affected source
status early on is not only necessary for Group 1 affected facilities
to comply with the notification requirement by January 15, 2014,\3\ it
will also provide Group 1 affected facilities advance notice and time
to secure the necessary control devices and schedule the installation
personnel to perform the installation by April 15, 2015. We reject
suggestions by some commenters that emission determination be conducted
closer to the deadline for installing control because such delay would
frustrate the reason for extending the compliance date for Group 1
affected facilities in the final amendments (i.e., to provide advance
notice and time to secure the necessary control devices and schedule
the installation personnel to perform installation). Further, the
commenters apparently assumed, though incorrectly, that the EPA has
concluded that control is not cost effective when VOC emissions are
below 6 tpy. No such determination has been made by the EPA or
demonstrated by commenters. On the contrary, as discussed in section
V.C of this preamble, we have determined that continuing control at
uncontrolled emission rates of 4 tpy or above is cost-effective. For
the reasons stated above, the final amendments specify October 15,
2013, as the deadline for determining the VOC PTE for Group 1 storage
vessels. If the VOC PTE of the Group 1 storage vessel is 6 tpy or
greater on October 15, 2013 (or an earlier date if the owner or
operator chooses to make the determination prior to October 15, 2013),
then the storage vessel is a Group 1 storage vessel affected facility
and is subject to the NSPS, which for Group 1 includes the notification
requirement by January 15, 2014 (i.e., the date by which the first
annual report is due), and the control requirement by April 15, 2015.
We are not finalizing the proposed requirement that Group 1 storage
vessels track events that may increase the VOC PTE of the storage
vessel (refer to section V.A of this preamble) and install control
should there be such event; this proposed Group 1 storage vessel
requirement is no longer necessary since the final amendments retain
the control requirement for all Group 1 storage vessel affected
facilities.
---------------------------------------------------------------------------

    \3\ We had proposed to require such notification by October 15,
2013, but, in response to comment, we have extended this deadline
slightly to January 15, 2014, to allow Group 1 affected facilities
to submit the notification with their annual report instead of
separately.
---------------------------------------------------------------------------

    One of the commenters expressed concern that Group 1 storage
vessels will have to indefinitely track events for these storage
vessels and install controls even if VOC emissions do not exceed 6 tpy.
The final amendments do not include requirements for owners and
operators to track events for Group 1 storage vessels, so this comment
is now moot.
    The EPA does not believe it is necessary to defer the date at which
Group 1 storage vessels located in the natural gas processing and
natural gas transmission and storage segments are required to determine
emissions. The commenter was suggesting an

alternative to tracking events for storage vessels in these segments,
and the final amendments do not include the proposed event tracking
provisions.
b. Determination After an Event
    Comment: One commenter sought clarification that the requirement to
re-estimate emissions when there is an event that could reasonably be
expected to increase emissions does not apply to non-affected
facilities. Two commenters requested that the EPA specify whether the
VOC emissions increase for Group 1 storage vessels are to be based on
potential or actual emissions. Another commenter suggested that the EPA
clarify that the baseline emissions used to determine whether a Group 1
storage vessel experiences an emission increase is the level of
emissions immediately prior to the event.
    Response: In the final amendments, we have removed the requirement
to track events for Group 1 storage vessels (refer to section IV.A of
this preamble). Therefore, these concerns are now moot.
2. Which Group 1 storage vessels are subject to the initial
notification requirements and when are the notifications due?
    Comment: One commenter states that the definitions for ``Group 1
storage vessel'' and ``storage vessel'' in Sec.  60.5430 do not contain
the 6 tpy threshold required for a ``storage vessel affected facility''
under Sec.  60.5365(e). The commenter believes that the EPA's intent is
to only be notified by October 15, 2013, of Group 1 storage vessels
that exceed 6 tpy and for operators to monitor these vessels for a
subsequent ``event'' because any storage vessel under 6 tpy is not an
affected facility and therefore should not be subject to requirements
under the rule. The commenter further states that in Sec.  60.5395, the
heading which premises paragraph (b)(1) states, ``You must comply with
the standards in this section for each storage vessel affected
facility.'' The commenter asserts that, based on the definition of
Group 1 storage vessel and the order of requirements in the above
provisions, this requirement could be misinterpreted to mean that all
storage vessels between those specified Group 1 dates must be reported,
regardless of their PTE.
    Another commenter agreed, stating that none of the storage vessel
definitions contains the 6 tpy threshold that is included in the Sec.
60.5365(e) definition of ``storage vessel affected facility.'' The
commenter added that, as proposed, Sec.  60.5395(b) seems to include
requirements for ``Group 1 storage vessel affected facilities'' but the
notification and event requirements in proposed Sec.  60.5395(b)(1) and
(2) apply to ``Group 1 storage vessels'' rather than ``Group 1 storage
vessel affected facilities.'' The commenter believes that these
requirements may be misinterpreted to apply to all storage vessels
containing an accumulation of crude oil, condensate, intermediate
hydrocarbon liquids, or produced water, regardless of whether their
potential emissions meet the 6 tpy threshold.
    Response: As proposed, Sec.  60.5395(a)(1) states that owners or
operators of Group 1 storage vessel affected facilities must comply
with paragraph Sec.  60.5395(b). The commenters are correct in their
interpretation that the Sec.  60.5395(b) requirements apply only to
Group 1 storage vessel affected facilities (i.e., those Group 1 storage
vessels with potential VOC emissions of 6 tpy or more), not all Group 1
storage vessels. For clarity, we have moved the affected facility
determination requirements from Sec.  60.5395 to Sec.  60.5365(e) and
have only requirements that apply to affected facilities now in Sec.
60.5395. The final amendments to Sec.  60.5365(e) clarify our intent.
    We also proposed in Sec.  60.5395(b) that owners or operators
submit the initial notification of Group 1 storage vessel affected
facilities by October 15, 2013. As discussed in section V.A of this
preamble, the final amendments require that owners or operators
determine the VOC PTE of Group 1 storage vessels by October 15, 2013,
and submit the initial notification for Group 1 storage vessel affected
facilities, which may be included in the first annual report, by
January 15, 2014. The provisions in the final amendments to allow the
initial notification of Group 1 storage vessel affected facilities to
be submitted with the initial annual report are discussed further in
the Response to Public Comments on the Proposed Amendments, available
in the docket.
3. Group 1 Storage Vessels That Become Affected Facilities on or After
April 12, 2013
    Comment: One commenter requested that Group 1 storage vessels that
experience a triggering event should follow the same schedule for Group
2 storage vessel affected facilities to install controls (by April 15,
2014, or 60 days after startup, whichever is later), except that there
could be a hard deadline for Group 1 storage vessel affected facilities
along a natural gas pipeline. The commenter pointed to the preamble of
the proposed amendments (FR 78 22131) that indicates the EPA's intent
was for Group 1 storage vessel affected facilities, after a triggering
event, to become subject to the same control requirements as those in
Group 2, and that these controls would be required no later than 60
days after the event, or April 15, 2014, whichever is later. According
to the commenter, this intent was overlooked in the proposed rule
amendments.
    Two commenters added that the final rule should specify a
compliance period for Group 1 storage vessels that originally had
potential VOC emissions less than 6 tpy and subsequently experience an
event that causes the potential VOC emission rate to meet or exceed 6
tpy. In such cases, the commenters requested that the storage vessel
should be required to achieve compliance within 60 days after the
event.
    Another commenter contended that almost all events that would
increase emissions at Group 1 storage vessels are planned or are of a
foreseeable nature. The commenter believes that it is feasible for
storage vessel operators to install and operate controls simultaneously
with the occurrence of such planned events. The commenter added that
because emissions from storage vessels are likely to be highest
immediately after the events listed in 60.5395(b)(2), it is also
essential for protection of public health that controls be implemented
as soon as possible.
    Response: As explained in section IV.A of this preamble, the
emission standards remain applicable to all Group 1 affected
facilities, as in the 2012 NSPS. Accordingly, we are not finalizing the
proposed requirement to track emission increase events and meet the
control requirement as a result of such events for Group 1 storage
vessels affected facilities. Thus, comments/issues relative to
compliance schedule for Group 1 storage vessel affected facilities that
experience an event are now moot.

B. Major Comments Concerning the Storage Vessel Affected Facility
Definition

    Comment: In the reconsideration proposal, the EPA proposed to
include a VOC emissions threshold of 6 tpy to determine, in part, which
storage vessels are affected facilities. Additionally, the proposal
allowed operators to take into account requirements under a legally and
practically enforceable limit in an operating permit or by other
mechanism. One commenter opposed this proposal to the extent that it
allows storage vessel operators to account for non-federally
enforceable emission limitations. According to the

commenter, the inclusion of non-federally enforceable limitations leads
to oversight concerns, and some storage vessels would avoid the NSPS
under the proposed threshold.
    Additionally, the commenter maintains that the CAA does not allow
``synthetic minor'' programs to determine applicability of its NSPS
regulations. The commenter states that the term ``potential to emit''
is not found in section 111 of the CAA but is a concept from CAA
programs governing expressly defined major sources. As a result, the
commenter states that the CAA does not specify that a minor source
program run by the states or other entities should be a means to avoid
NSPS regulations. According to the commenter, allowing non-federally
enforceable standards to exempt sources from NSPS is problematic
because states vary widely in the letter, implementation, and
enforcement of their synthetic minor programs.
    Response: In the preamble to the proposed amendments we stated that
our intent was that ``a source can take into account any legal and
practically enforceable emissions limit under federal, state, local or
tribal authority when determining the VOC emission rate for purposes of
[the 6 tpy] threshold'' (78 FR 22132). The language we used in the
proposed amendments to Sec.  60.5365(e) to define the storage vessel
affected facility allows the owner or operator to ``tak[e] into account
requirements under a legally and practically enforceable limit in an
operating permit or by other mechanism.'' We agree with the commenter
in so much as the term ``other mechanism'' may be construed to include
non-federally enforceable mechanisms that may have questionable, if
any, enforceability provisions. Therefore, the final amendments removed
the term ``other mechanisms'' and revised the provision to allow the
owner or operator to ``tak[e] into account requirements under a legally
and practically enforceable limit in an operating permit or requirement
under a Federal, state, local or tribal authority.'' We believe that
the amendment clarifies only legally and practically enforceable limits
can be considered when a source determines its PTE. The EPA's ability
to require Federal enforceability rather than just legal and practical
enforceability has been an issue since the DC Circuit decision in
National Mining Assn. v. EPA, 59 F.3d 1351 (D.C. Cir. 1995). As we have
yet to address this remand/vacatur, the agency does not feel at this
time that it can dictate Federal enforceability in this context.
    Concerning the comments on our use of PTE as an applicability
threshold, that was based on our BSER determination made in the 2012
NSPS taking into account the control's cost effectiveness. Section
111(a)(1) of the CAA specifically identifies cost of achieving
reduction as a factor to consider in setting NSPS standards. Nothing in
section 111 of the CAA prohibits the EPA from using PTE to reflect our
cost consideration in establishing applicability thresholds under
section 111. Petitioner failed to explain how the fact that PTE is
often used in connection with determining major source status in other
provisions of the CAA bars its use for determining applicability status
under section 111.

C. Major Comments Concerning Storage Vessel Control Requirements

1. CAA Section 111 Requirements
    Comments: According to one commenter, section 111 of the CAA is
fundamentally a technology-forcing provision that can and should be
used to spur aggressive deployment of emission control technologies.
The commenter contends that standards are to be set stringently, in
order to force the development of new technology. If the EPA must phase
in controls, and can otherwise justify such an approach under section
111, the commenter believes the EPA must do so in as limited a way
possible, ensuring it does not disrupt incentives which would otherwise
expand pollution control development.
    The commenter added that the courts have clarified that EPA's
selection of BSER is only limited by cost when industry demonstrates an
``inability to adjust itself in a healthy economic fashion to the end
sought by the Act as represented by the standards prescribed.''
Further, the commenter states that creating deferrals meant to track
control equipment supply is not technology-forcing, but market-
following. According to the commenter, this ignores the role of
standard-setting in incentivizing higher production of control
equipment. If EPA cites availability of control devices in deferring or
reducing the stringency of an NSPS, the commenter contends that the EPA
must offer a strong demonstration that supply constraints render the
standard unachievable or prohibitively expensive for the industry as a
whole.
    Response: As explained in section IV.A of this preamble, the EPA
proposed to phase in the control requirement for storage vessel
affected facilities based on its belief at the time that there would
not be enough control devices to meet the demand of all storage vessel
affected facilities by the October 15, 2013, compliance date in the
2012 NSPS or any time in the near future. Although new information
received since our proposal indicates that control supply may not be an
issue, the EPA is phasing in the storage vessel control requirement in
the final amendments for the reasons provided in section IV.A. The
phase-in approach has never been based on cost, as the commenter
suggests; rather, as indicated in section IV.A of this preamble and in
the preamble to the April 12, 2013, reconsideration proposal, the
phase-in approach is intended to avoid setting a control requirement
that cannot be met due to limitations associated with installing
control devices. We do not believe that a standard that ignores such
limitations accurately represents the BSER for these affected
facilities.
2. Group 1 Requirements
a. No Control of Group 1 Storage Vessels
    Comment: According to one commenter the proposal to exempt Group 1
storage vessels that do not experience increases in emissions rests on
questionable projections of estimated current and future supply of
control devices, number of storage vessels and decline of oil and
natural gas well production. The commenter contends that the EPA cited
only unidentified oil and gas industry sources for the asserted level
of control device production and provided no justification for
forecasted rate of production increase or the production rate plateau
of 1,400 units per month. The commenter believes that it is as or more
likely that industry would continue to expand control device production
in response to the proposed standards, but the proposed delays would
slow control manufacture by removing demand. According to the
commenter, the EPA could remove its artificial ceiling for control
manufacture and accelerate the compliance deadline for Group 2 storage
vessels and require most or all Group 1 storage vessels to control
emissions by mid-2015. The commenter contended that the EPA must
disclose the information underlying these forecasts to allow the public
to evaluate their reasonableness and offer comments.
    The commenter added that the assumption of one storage vessel per
well overestimates the number of new storage vessels and is
unjustified. The commenter provided examples of increased use of multi-
well pads.
    According to the commenter, the EPA uses the fact that oil and gas
wells

decline in production over time as justification for exempting Group 1
storage vessels from control requirements. The commenter states that
the EPA's forecast of control equipment availability implies no
reduction in the number of storage vessels requiring control. This is
contrary to the justification given for exempting Group 1 storage
vessels from control requirements. According to estimates of a decline
in production, the commenter believes that some Group 1 storage vessels
could remain a significant source of emissions.
    The commenter also contended that the EPA's projections indicate
that the supply of existing control devices will be adequate to meet
the combined demands of Group 1 and 2 storage vessels by 2016. It is
not clear to the commenter what portion of the estimated 20,000 Group 1
storage vessels would ultimately be subject to control, so it is
unclear whether subpart OOOO would ever apply to those Group 1 storage
vessels with high emissions. Even assuming that emissions from these
Group 1 storage vessels generally continue to decline over their
remaining lives, the commenter believes that allowing this group of
storage vessels to be uncontrolled would result in a large amount of
excess emissions relative to the current rule. Conservative estimates
by the commenter indicate that the proposal to leave Group 1 storage
vessels unregulated would allow over 3 million tpy VOC and 700,000 tpy
of methane to be emitted. Taking into account the production decline,
the commenter contends that an analysis of the Bakken shale formation
indicates that in 2015 storage vessels could still be emitting about 30
percent of their initial emissions. For the reasons given above, the
commenter believes that the Group 1 storage vessel exemption is
arbitrary and falls short of section 111 mandates that standards of
performance reflect BSER.
    The commenter further contended that if EPA's analysis indicates a
sufficient supply of control devices will be available in the future,
then Group 1 storage vessels should be controlled within a reasonable
time. The commenter states that a compliance deadline in mid 2015 would
provide adequate time for all storage vessels currently subject to the
proposed rule to come into compliance. To support this view, the
commenter reasons that, if some fraction of the Group 1 storage vessels
will no longer have emissions exceeding 6 tpy, the demand for control
devices is likely to be lower than the EPA's projections, given the
opportunities to manifold closely-spaced storage vessels, the increased
practice of multi-well pads which would share storage vessels, and the
EPA's statement in the preamble to the proposed rule that control
device manufacturers are likely to be flexible in their ability to meet
equipment demand increases in the future.
    Another commenter agrees that an alternate compliance schedule is
necessary to accommodate the increased demand for control devices but
recommended that Group 1 storage vessels that continue to have
emissions greater than 6 tpy as of the Group 2 compliance date be
required to comply with the control requirements of the rule.
    Several commenters express concern that the increased demand for
control devices will lead to delays in getting the devices installed
and that additional time to comply with the proposed standards is
required. One commenter states that the companies that supply the
services to comply with the proposed amendments will have their time
monopolized by the large oil and gas companies, leading to a shortage
of these services for small oil and gas companies. Another commenter
similarly expresses concern that small independent producers will
experience a shortage of service personnel because the smaller
producers have less leverage and buying power than large producers.
    Response: In the preamble to the proposed amendments, we discussed
our rationale for requiring controls only on those Group 1 storage
vessel affected facilities that have an event that would likely lead to
an increase in the potential to emit VOC (78 FR 22130). Our decision to
require controls only on Group 1 storage vessels that experience such
an event was based, in large part, on our understanding at that time
and the information then available of the supply of combustors that
likely would be used to comply with the control requirements. As we
understood the combustor manufacturing industry at the time of
proposal, the total capacity to produce combustors was approximately
300 units per month, which was based on information from six combustor
manufacturers, and that the industry had the capability of increasing
that capacity by about 100 units per month.
    In response to comments questioning our combustor supply analysis,
we reassessed the production capacity of the combustor manufacturing
industry. We were able to confirm the data for some of the six
manufacturers for which we had data at proposal, which leads us to
believe the data as a whole for these manufacturers are reasonable
(i.e., current capacity on average of about 600 units per year for each
company). In addition, we were able to identify five additional
combustor manufacturers. Of these five, three provided production
capacity estimates that were in line with the data we originally had
for the six companies, one provided production estimates that were
significantly higher than any of the other companies, and one did not
provide any data. We averaged the production capacity of the nine
similar companies to complete the missing data from the one facility
that did not provide data. We then summed the capacity of these 11
companies to determine total current manufacturing capacity of
combustors, which was approximately 2,300 units per month.
    We also estimated future capacity of the combustor manufacturers
based on information provided by the manufacturers for anticipated
future increases in production capacity. Based on this information, we
estimated future capacity to be as high as approximately 3,000 units
per month by April 15, 2015.
    The new information described above (for further details, see the
memorandum entitled Combustor Supply and Demand Analysis, available in
the docket) seems to indicate that the combustor suppliers have the
manufacturing capacity to meet the demand posed by all (i.e., both
Group 1 and Group 2) storage vessel affected facilities required to
comply with emission standards in the 2012 NSPS. Therefore, in the
final amendments, we continue to require that Group 1 storage vessel
affected facilities comply with the emission standard requirements.
However, we have extended the current compliance deadline for the
reasons stated below.
    While the overall projected supply of combustors appears to be
adequate, we do not have information as to whether the combustor
manufacturers are producing at the projected capacity and, if not, how
quickly they can ramp up production to provide the necessary supply for
the 2012 NSPS. More importantly, we note that there is a great
variability in the projections of combustor supply, where one
supplier's projection greatly exceeds the other suppliers' projections
and accounts for a significant portion of the supply. To gauge the
sensitivity of this one company on the combustor supply, we revisited
our supply analysis assuming this company could manufacture combustors
only at the highest manufacturing rate reported by any of the other
combustor manufacturers. We found that under this scenario the supply
of combustors never satisfies the

demand. Thus, this one manufacturer is critical in meeting the overall
demand imposed by the 2012 NSPS.
    Because this company plays such an important role in meeting the
combustor supply, any factor that may delay or slow their production
may significantly affect the ability of Group 1 and Group 2 storage
vessel affected facilities to achieve compliance by the current
compliance deadline in the 2012 NSPS (i.e., October 15, 2013, or 60
days after startup, whichever is later). In light of the above, we
believe it is prudent to allow more time for compliance to lift the
pressure on the demand of control devices, especially in the short
term. Under the 2012 NSPS, compliance is required by October 15, 2013,
for an estimated over 20,000 storage vessel affected facilities that
will have come on line since the August 23, 2011, (the proposal date of
the 2012 NSPS), and an additional 1,100 new affected facilities per
month will need to install control 60 days after start-up. Extending
the current compliance deadline would allow the market to more easily
absorb any events that may cause combustor manufacturing to fall short
of the projected production capacity.
    In addition to the supply issues described above, commenters raise
the concern about not being able to secure the necessary trained
personnel to install control devices by the current compliance
deadline. In light of the large number of storage vessel affected
facilities (estimated over 20,000 by October 15, 2013, with an
additional 1,000 per month after that), and given the wide geographic
distribution of oil and gas wells across the United States, we believe
that the commenters raise a legitimate concern. In particular, we are
concerned about how a potential shortage of trained personnel may
impact small businesses. The comments we received indicate that larger
owners and operators may be able to garner the majority of the
available installation personnel due to their greater resources and
influence. This may result in a situation where small owners and
operators may be placed in a disadvantage to their larger competitors
in obtaining installation personnel. If such a situation should occur,
the smaller owners and operators may be forced to shut down wells or
delay drilling new wells until installation personnel are made
available.
    In light of the issues described above that may hinder storage
vessel affected facilities' ability to comply by the current October
15, 2013, deadline, we do not believe it is reasonable to retain that
compliance date. Instead, in the final amendments, we take a phase-in
compliance approach that first addresses newer affected facilities
(which would have higher emissions) while assuring that all affected
facilities have time to acquire and schedule installation of control.
The final amendments establish Group 1 and Group 2 affected facilities,
as proposed, where Group 1 are those affected facilities that came on
line on or before April 12, 2013, and Group 2 are those that come on
line after that date. The final amendments require that Group 2 comply
by April 15, 2014 (or 60 days after start-up, whichever is later), a 6-
month extension from the current October 15, 2013, deadline for these
newer affected facilities. The final amendments require that Group 1
comply by April 15, 2015. Were we to require that both groups comply by
April 15, 2014, an estimated 30,000 affected facilities would be
competing to acquire and install control by that date; as a result, the
6 month extension would do little to ease the demand for control or
skilled personnel to install control should either become an issue in
the near future. Also, requiring Group 1 to comply by April 15, 2014
would likely affect Group 2's ability to comply, thus undermining our
goal to address the newer storage affected facilities sooner. Lastly,
considering the large number of Group 1 affected facilities (which we
estimate to be around 19,400), we believe that requiring all Group 1
affected facilities to comply by April 15, 2015 is reasonable. In light
of the issues discussed above, we do not expect that these affected
facilities would wait until near that deadline and risk noncompliance;
rather, we believe that the deadline provides Group 1 advance notice
and allows them time to plan for acquiring and scheduling installation
of control device by that date. Therefore, in the final amendments, we
have specified that all Group 1 storage vessel affected facilities must
comply by April 15, 2015, and that Group 2 storage vessel affected
facilities must comply by April 15, 2014, or 60 days after startup,
whichever is later.
b. Clarification of ``Events'' That May Increase Emissions
    Comment: Several commenters request that the EPA more clearly
define the types of events that would trigger emission increases for
Group 1 storage vessels. Seven commenters request that the EPA limit
the examples to a finite list of events to remove ambiguity. One
commenter states that the ``events'' that trigger control requirements
for Group 1 tanks should be more specific for storage vessels at well
sites. According to the commenter, only the events described in Sec.
60.5395(b)(2)(i) through (iii) of the proposed amendments should be
considered triggering events for storage vessels that store reservoir
fluids (i.e., at well sites, tank batteries, centralized production
facilities).
    One commenter requested that the EPA delete the list of examples of
events that would increase emissions from the rule language and provide
that control requirements are triggered by a change that, in the
owner's/operator's judgment, is one that could reasonably be expected
to increase VOC emissions.
    One commenter suggests that the EPA should clarify the illustrative
list of emission-increasing events to include well maintenance
activities, such as liquids unloading, various well workover
procedures, and any other well maintenance activities which increase
production.
    Response: As discussed in section IV.A of this preamble, the final
amendments do not change the requirement in the 2012 NSPS that all
storage vessel affected facilities, including those we define as Group
1 affected facilities, to meet the emission standards, although the
amendments extend the time for compliance. Since all Group 1 storage
vessel affected facilities remain subject to control requirements,
there is no need to track events in order to determine which Group 1
storage vessel affected facilities are subject to control requirements,
we are not finalizing the proposed provisions related to events in the
final amendments.
c. At what emission rate are Group 1 storage vessels that experience an
event required to install controls?
    Comment: Three commenters request that the EPA clarify that Group 1
storage vessels that experience an event that results in an increase in
emissions would not be required to install controls if the VOC
emissions are below the 6-tpy emission threshold. Two commenters
recommend that the 6 tpy threshold be included either in the definition
of ``Group 1 storage vessels'' in Sec.  60.5430 or be explicitly listed
as a condition in the requirement under Sec.  60.5395(b)(1).
    One commenter states that if emissions from a Group 1 storage
vessel affected facility decrease below 6 tpy due to production
decline, and it was determined even after a potentially triggering
event that emissions had not returned to a level above 6 tpy, the
storage vessel should not become subject to Group 2 controls. This view
is generally supported by two additional commenters. The commenter
refers to Sec.  60.5410(i) which specifies that the

requirement for installing Group 2-level controls is further limited to
Group 1 storage vessel affected facilities for which the potential VOC
emission rate is 6 tpy or greater after the triggering event. According
to the commenter, this 6 tpy threshold is reasonable and appropriate
because the EPA concluded in the initial rulemaking that Group 2
controls would not be cost effective for storage vessels emitting less
than 6 tpy of VOC.
    The commenter adds that based on statements in the preamble (78 FR
22132) and regulatory language in Sec.  60.5410(i), this 6 tpy
threshold should be repeated in Sec.  60.5395.
    Response: As discussed in the previous comment response, the final
amendments do not require that Group 1 storage vessels track events.
Therefore, these comments are now moot.
3. Alternative 4-tpy Uncontrolled Actual VOC Emission Rate
    Comment: One commenter states that the proposed 4 tpy emission
rate, below which controls would not be required, is not BSER and would
allow large and unjustifiable emissions increases. According to the
commenter, the 95 percent control limit ensures that actual emissions
do not exceed 0.2 tpy. Under the proposal, a storage vessel could emit
up to 4 tpy indefinitely which is nearly a 3.8 tpy increase above the
emissions that would be allowed under the proposed NSPS.
    According to the commenter, once control devices are removed, it is
more likely that unplanned events will cause significant emissions
spikes, further increasing air pollution. For example, if an operator
diverts a sudden surge of VOC-containing liquids to a storage vessel
for which the operator has removed controls under the proposed mass-
based limit, there will be no way to control the resulting emissions
spike. The commenter contends that the result is that transient but
significant emissions events may become more common at storage vessels
using the proposed mass-based limits.
    The commenter adds that even if it is assumed that the proposed
emission rate would apply for a single year of a given group of storage
vessels' lives, the proposal would allow tens of thousands of tons of
pollution in that year. If storage vessels operate longer, or decline
more slowly after passing the 4 tpy threshold, the amount of additional
air emissions will be even higher.
    The commenter could find no authority in the CAA for abandoning
BSER controls after they have been installed. Having already determined
that 95 percent control is BSER, the commenter states that the EPA
provided no justification of the basic premise or the level of the
proposed emission rate. The emission rate has not been demonstrated to
alleviate any control device shortage, and control devices that would
become available due to the emission rate are unlikely to be available
for more than a decade after the proposal is finalized.
    The commenter contends that the EPA has not shown that the proposed
4 tpy limit corresponds to BSER. To make such a demonstration, the
commenter believes, it would be necessary for the EPA to show that
control technology has not been demonstrated below the 4 tpy emission
rate, meaning that such sources can properly escape control, or that
controls are not cost-effective for the industry as a whole below such
an emission rate. According to the commenter, controls clearly are
available for storage vessels with emissions of 4 tpy and below, so
there is no justification for the 4 tpy emission rate on control
technology availability grounds. Additionally, the commenter contends
that significant VOC emissions can be captured below the proposed
threshold. With respect to cost, the commenter believes recent
information indicates the annualized cost of storage vessel combustors
has declined substantially since subpart OOOO was finalized,
significantly enhancing the cost effectiveness of controlling VOC
emissions from storage vessels with a PTE of 4 tpy or less. The
commenter provides information from a Colorado Department of Public
Health and Environment (DPHE) pending rulemaking showing that the
annualized combustor costs are around $15,900/yr, as compared to the
previous value of $19,600/yr, resulting in a cost effectiveness of
$4200/ton at 4 tpy.
    Further, the commenter believes that the EPA's control costs
overestimate actual costs because the EPA does not take into account
savings that would be experienced when controls are shared among
storage vessels. As a result, controls are more affordable at lower
uncontrolled emissions thresholds. According to the commenter, if the
EPA sets a very low emission threshold at which removal and reuse is
permissible, more vessels would have to buy new control devices,
raising control costs again. Thus, the commenter believes that the
EPA's analysis does not compare this variation, or considered the
appropriate way to design such a system in light of the variation.
    According to the commenter, the EPA states in the proposal that
control device manufacture will lag the growing population of storage
vessels for a few years and used this rationale to separately waive
controls for Group 1 storage vessels and assure adequate supply of
control devices for Group 2 storage vessels. The commenter contends
that the EPA further states that allowing affected storage vessels to
remove controls under the proposed emission rate would help alleviate
the control device shortage. According to the commenter, the EPA's
justification that imposing the emission rate is due to uncertainty in
their control technology projections and that an additional exemption
would ``help build a buffer'' against this uncertainty is not a
cognizable justification for a section 111 standard under the CAA.
Further, the commenter does not believe that the EPA has demonstrated
either the necessity or appropriateness of the proposed emission rate.
    The commenter states that the EPA's concerns about ``buffering''
technology supply could only justify this departure from the existing
standard if the proposed emission rate was also demonstrated to be
BSER. According to the commenter, the EPA determined that requiring
storage vessels with uncontrolled emissions greater than 6 tpy to
achieve 95 percent control of those emissions reflects BSER and is cost
effective. The commenter states that if these controls were maintained
on a storage vessel as its emissions declined over time, total
uncontrolled emissions would continue to fall. But under the proposed
emission rate, the commenter contends that emissions could instead jump
sharply after the threshold has been crossed. The commenter believes
that this reversal in the emissions trend does not reflect BSER because
it does not reflect the best demonstrated system of emissions control.
According to the commenter, it is instead what happens when BSER
controls are removed.
    The commenter adds that for the EPA's ``buffer'' rationale to hold
up, operators must be able to cost-effectively and regularly remove
used control devices, store them as needed, and transfer them to new
storage vessels at a rate which will meaningfully address the control
device shortage which the EPA projects. The commenter asserts that the
EPA provided no evidence showing operators would be able to do this, or
would choose to do so. According to the commenter, storage vessels
installed now would in all likelihood not take advantage of the
proposal until the 15th year of operation (based on decline curve data
provided by the commenter showing that it would take up to 15 years for
well production to decline to a level to produce uncontrolled storage
vessel emissions of

4 tpy). As a result, the commenter believes that the proposed emission
rate would not generate any control devices for transfer for more than
a decade, which is long after the EPA estimates adequate control
devices will be available. Thus, according to the commenter's analysis,
even if control devices could be transferred, such transfers will not
buffer a short-term shortage. That shortage, if it exists, will long
have passed. Instead, the commenter believes that the proposed emission
rate would simply increase air pollution.
    The commenter further states that even if the EPA were to actually
require operators to build the buffer it desires, the EPA offers no
evidence that such a buffer is required indefinitely. Elsewhere in the
proposal, the commenter contends, the EPA expresses its view that
control device manufacturers will respond to the standards by
manufacturing enough control devices to meet the demand imposed by the
standards, perhaps after an initial delay. The commenter points out
that past experience shows that control devices become available if
they are required, and this technology-forcing function is central to
how section 111 is intended to work. By instead allowing operators to
avoid purchasing new controls, and to remove them from other sources
and reuse them, the commenter contends that the EPA permanently limits
the market for new control technology, while also allowing excess
emissions. The result will be fewer controls in the long-term, and more
pollution.
    The commenter believes that the Wyoming guidance the EPA mentions
in the proposal does not comply with section 111 standards, and
contends that the EPA does not offer evidence that it has avoided
excess pollution.
    Another commenter believes the EPA's choice of an uncontrolled
emission rate of 4 tpy as the emission rate is arbitrary and
unsupported. The commenter states that the EPA provided no engineering
basis, credible health benefit estimate, or other justification for why
the 4 tpy emission rate is appropriate.
    The commenter also states that the EPA did not provide any
justification or analysis demonstrating whether control at 4 tpy is
cost effective. The commenter states a cost effectiveness analysis was
performed for the 6 tpy applicability threshold, but no such
information is provided for the proposed 4 tpy emission rate. The
commenter opined that this approach will create situations of great
inequity where neighboring facilities may have identical PTE VOC
emissions from a single storage vessel or battery, but very different
regulatory burdens. The commenter provides an example where a site with
emissions of 5.95 tpy is not subject to any of the notification,
reporting, or control requirements of this NSPS. However, a neighboring
site with initial production emissions of 6.1 tpy must notify, control,
monitor, record, and report to comply with the NSPS. The commenter
provides that, as natural production declines occur, after a year of
uncontrolled emissions of 3.95 tpy (below the 4 tpy threshold) the
additional controls may be removed, but the burden of reporting and
recordkeeping continues indefinitely for this site.
    The commenter also states that this approach may also drive
companies to design their sites in a way that results in increased
emissions overall, defeating the goal of the rule itself. For example,
according to the commenter, to avoid applicability of the rule as a
whole, new sites will likely be designed with more tanks such that no
single tank will exceed the 6 tpy applicability threshold but emissions
from the larger number of small tanks may have higher overall
emissions. The commenter believes that this in turn may exacerbate the
shortage of storage tanks that already exists and may further delay
production due to the lack of tank availability. Further, the commenter
states that the proposed emission rate may lead to hastily constructed
tanks that may not be as soundly designed and constructed creating
potential concerns for public health and safety as well as air quality.
    The commenter contends that the EPA focused on the concept of any
planned event that has the potential to increase emissions to or above
4 tpy. However, according to the commenter, this does not account for
any potential short-term activities that may trigger reinstallation of
controls such as degassing, refilling, inspection or maintenance when
emissions in the long-term would otherwise remain below the 4 tpy
level. The commenter states that this may result in the delay of
appropriate maintenance or other actions that would otherwise be
conducted. Building on the example of neighboring sites described
above, the commenter states that, if the second site wanted to confirm
tank integrity by inspection and cleaning, one-time emissions may raise
the annual uncontrolled PTE to over 4 tpy, thus triggering not only
reinstallation of controls but all associated monitoring, recordkeeping
and reporting requirements.
    Several commenters believe that a more appropriate approach would
be to allow the removal of controls if a storage vessel has had
uncontrolled actual emissions that remain below 6 tpy VOCs for 6
months. The commenters also believe that this initial determination is
sufficient and that no further monitoring should be required unless
otherwise required under Sec.  60.5395(b)(2). According to the
commenters, wells experiencing natural production decline are unlikely
to ever experience an increase in emissions, but instead will continue
to experience an emissions decrease. The commenters state that this
continuing natural decline also supports the contention that 6 months
is a sufficient timeframe to monitor emissions before removing
controls.
    One commenter adds that the proposed approach would require owners/
operators to make a one-time commitment of what a tank will contain to
the extent that potential emissions will ever exceed 6 tpy. The
commenter believes that this inappropriately extends the ``once in,
always in'' policy beyond its previous applications. While it appears
that EPA would allow vessels to come in and out of regulation based on
whether they contain crude oil, condensate, intermediate hydrocarbon
liquids, or produced water at a given time, the commenter contended
that the proposal would create a one-time determination of potential
emissions that forever captures a tank, regardless of whether it
continues to hold the materials that would bring it within regulation.
In proposing low emitting storage vessels remain subject to the rule
indefinitely, the commenter believes that the EPA is imposing
unnecessary and burdensome control, recordkeeping, and reporting
requirements on many storage vessels. Should EPA retain this ``once in,
always in'' requirement, the commenter recommends that it should affirm
that storage vessels no longer holding VOC-containing liquids or that
are taken out of service are no longer an affected source.
    Concerning re-installation of controls, several commenters state
that the threshold should be 6 tpy instead of 4 tpy based on the EPA's
cost effectiveness determination.
    Response: To help alleviate the control supply shortage believed to
exist at the time, we had proposed to amend the storage vessel emission
standards to require compliance with either the 95 percent reduction
requirement or an uncontrolled actual VOC emission rate of less than 4
tpy, which would allow control devices to be removed from storage
vessel affected facilities below

that emission rate and relocated to those that have just come on line
and have the VOC PTE of 6 tpy or more. As previously mentioned, new
information we received since proposal indicates that the combustor
suppliers have the manufacturing capacity to meet the demand posed by
this NSPS, which in turn suggests that a supply buffer may no longer be
necessary. However, for the reasons stated below, we have amended the
storage vessel emission standards as proposed due to the cost
effectiveness of continuing control and the increasing environmental
disbenefits and energy impacts from the continued operation of the
combustion control device at an inlet stream VOC concentration of less
than 4 tpy.
    As shown in the memo entitled Cost and Secondary Environmental
Impacts Associated with Controlling Storage Vessels under the Oil and
Natural Gas Sector New Source Performance Standards, available in the
docket, our analysis indicates that the cost of controls for each
storage vessel affected facility at a VOC emission rate of 4 tpy is
approximately $5,100 per ton. This cost increases to approximately
$6,900 per ton at an emission rate of 3 tpy, and to approximately
$10,000 per ton at 2 tpy. For comparison, we note that, in a previous
NSPS rulemaking [72 FR 64864 (November 16, 2007)], we had concluded
that a VOC control option was not cost effective at a cost of $5,700/
ton, which calls into question the cost effectiveness of continuing
control of storage vessel affected facilities at an emission rate below
4 tpy.
    One commenter recommends that, if we retain the uncontrolled VOC
emission rate, it should be set no higher than 0.3 tpy (representing
the emission rate of a 6 tpy VOC emission stream controlled at 95
percent) rather than 4 tpy. We emphasize that the 4 tpy uncontrolled
VOC emission rate is not based on equivalency to the 95 percent
reduction, nor do we think such conversion to an emission limit is
appropriate considering it would result in a range of emission limits
depending on the baseline uncontrolled emissions. The 0.3 tpy suggested
by the commenter only represents the limit for sources with PTE of 6
tpy while those with higher PTE would have higher limits that equate to
95 percent reduction. Further, at the commenter's suggested emission
rate of 0.3 tpy, the cost would be approximately $70,000 per ton of
emission reduction, which we do not consider to be cost effective.
    One commenter questioned the basis of our control cost estimates
and pointed to a recent update by Colorado DPHE, an earlier version of
which we used as the basis for our cost estimate, which indicated a
lower cost of control. We point out that the lower cost in the revised
Colorado analysis is primarily due to a lower cost (by approximately
half) of the fuel for the pilot flame. Our assumption is that gas
prices will remain relatively stable over time and question whether
this lower fuel cost is applicable to all areas of the U.S. outside
Colorado and whether such costs will be maintained in the long term. We
also point out that the Colorado analysis did not include costs for a
surveillance system or data management system, which were included in
our analysis. Finally, the Colorado analysis showed an increase in
capital cost of about $2,000 over the capital costs in our analysis.
For these reasons, we believe our costs, if anything, may underestimate
costs rather than overestimate as the commenter claims. We made no
changes to our cost analysis based on this comment.
    Another commenter suggested that our cost estimate overestimates
costs because we did not take into account savings that would result
when control devices are shared by storage vessels. The comment is
incorrect. In our analysis, we assumed that there would be one control
device used per well site. We also acknowledged that there are likely
multiple storage vessels per well site, all of which would be routed to
a single control device.
    In addition to cost effectiveness, we evaluated the secondary
impact from continuing control below 4 tpy. As shown in the memo
entitled Cost and Secondary Environmental Impacts Associated with
Controlling Storage Vessels under the Oil and Natural Gas Sector New
Source Performance Standards, available in the docket, on a nationwide
basis, the combustion of the pilot flame fuel and the combustion of the
VOC vapor in the storage vessel vent stream will result in increases in
NOX, CO, CO2, and methane emissions, most notably
CO2 emissions. We estimate that the operation of each
combustion control device on a VOC storage vessel vent stream flow rate
of 3 tpy will result in the following secondary emissions: 54 tpy of
carbon dioxide (CO2), 0.14 tpy of carbon monoxide (CO) and
0.028 tpy of nitrogen oxides (NOX).
    We also evaluated the energy impacts associated with continuing
control below 4 tpy. The discussion here for secondary energy and
environmental impacts is on the basis of one combustion control device.
As of the date of publication of this preamble, we estimate that there
are approximately 20,000 storage vessel affected facilities that
require combustion control devices and that the number is projected to
increase by about 11,000 per year. We also estimate that on average,
from 2014 through 2020, approximately 8,000 storage vessel affected
facilities per year will experience VOC emissions decline to below 4
tpy. Our information indicates that the fuel usage (primarily methane)
for the pilot flame on a single combustion control device may be
approximately 12 tpy (based on a fuel flow rate of 70 scf/hr for the
pilot flame, or about 613 Mcf per year). Thus, at a storage vessel VOC
emission rate of 4 tpy, a combustion device would have to combust an
amount of fuel gas about 3 times the mass of the VOC vapor from the
tank being controlled simply to keep the pilot flame operating. This
ratio increases even further for VOC emission rates less than 4 tpy.
Considering the nationwide energy impact of continuing to operate the
pilot flame of an extremely large number of combustion control devices
for VOC flow rates far lower than the pilot flame fuel flow rates, we
question whether this is a responsible use of our energy resources.
    In light of the cost-effectiveness, the secondary environmental
impacts and the energy impacts, we have concluded that the BSER for
reducing VOC emissions from storage vessel affected facilities is not
represented by continued control when their sustained uncontrolled
emission rates fall below 4 tpy. For the reason stated above, we have
amended the storage vessel emission standards to require that, at all
times, affected facilities comply with either the 95 percent reduction
requirement or an uncontrolled actual VOC emission rate of less than 4,
as proposed. Under the final amendments, an owner or operator may
comply with the uncontrolled VOC emission rate instead of the 95
percent control requirement where it can be demonstrated that, based on
records of monthly determinations of VOC emissions for the 12
consecutive months immediately preceding the demonstration, that the
storage vessel affected facility uncontrolled actual VOC emissions each
month during that 12-month period are below 4 tpy. The final amendments
require that the owner or operator re-evaluate the uncontrolled VOC
emissions on a monthly basis. For the same reasons discussed below in
this section in our response to comments concerning storage vessels
that are taken out of service, the 4 tpy alternative emission standards
in the final amendments at Sec.  60.5395(d)(2) require control to be

applied in either of two cases. First, if a well feeding a storage
vessel affected facility undergoes fracturing or refracturing, the
owner or operator must comply with the 95 percent reduction
requirements in Sec.  60.5395(d)(1) as soon as liquids from the well
following fracturing or refracturing are routed to the storage vessel
affected facility, regardless of the last monthly emissions
determination. On the other hand, if a monthly emissions determination
required in Sec.  60.5395(d)(2) indicates that VOC emissions from a
storage vessel affected facility have increased to 4 tpy or greater,
and the increase is not associated with fracturing or refracturing of a
well feeding the storage vessel, then the owner or operator must apply
95 percent control according to Sec.  60.5395(d)(1) within 30 days of
the monthly calculation.
    One commenter stated that the 4 tpy uncontrolled VOC emission rate
does not represent BSER. As previously explained, due to the cost
effectiveness, the secondary environmental impact and energy impact,
the 4 tpy emission rate likely represents a point below which continued
control ceases to be the BSER for reducing VOC emissions from storage
vessel affected facilities.
    One commenter asserted that some maintenance events at neighboring
sites may cause short-term spikes in VOC emissions of 4 tpy or more,
thereby triggering control for at least another 12 months. As discussed
above, the final amendments provide for two alternative emission
standards, either of which must be met at all times. However, the 2012
NSPS contains affirmative defense provisions that may be considered in
cases where malfunctions occur causing emissions to exceed the
standard. Planned activities are expected to be conducted in compliance
with the emission standards.
    We also made changes to the final amendments to clarify our intent
that the uncontrolled VOC emission rate is available for all storage
vessel affected facilities. In the proposed amendments, Sec.
60.5395(d)(2) conditionally allowed the owner or operator to meet an
uncontrolled actual VOC emission rate so long as the monthly actual
uncontrolled emission rate remained below 4 tpy. However, in the
proposed amendments we included the following qualifier in Sec.
60.5395(d)(2): ``provided that you have been using a control device and
have demonstrated that the VOC emissions have been below 4 tpy without
considering control for at least the 12 consecutive months immediately
preceding the demonstration.''
    We now believe that this qualifier places undue restriction on the
use of the emission rate. Under the qualifier, Group 1 affected
facilities that had uncontrolled emission below 4 tpy by the amended
compliance date would not be able to avail itself of this option. We
see no reason for such limitation and have therefore removed the
qualifier language in the final amendments.
    Concerning a commenter's assertion that one storage vessel with PTE
of just over 6 tpy would be subject to control, recordkeeping and
reporting requirements but that a storage vessel with PTE of just under
6 tpy would not be subject to any requirements, we respond that
applicability thresholds exist for many rules and that subpart OOOO is
not unique in that regard. With regard to the assertion that owners and
operators may try to circumvent the NSPS by installing multiple small
throughput storage vessels to keep individual tank emissions below the
6 tpy threshold, this comment pertains to the 2012 NSPS and not the
proposed reconsideration, since changes to that threshold were not
proposed. In response to the commenter's concern about transient
emissions above 4 tpy that are caused by operator actions, storage
vessels that increase emissions to at least the 4 tpy actual VOC
emissions limit are subject to the control requirements. Owners and
operators must ensure that they are aware of emissions increases that
may occur after an activity and take appropriate action to control
those emissions as required by the NSPS. With regard to uncontrolled
VOC emissions of 6 tpy for 6 consecutive months being a more
appropriate uncontrolled actual VOC emission limit, we have explained
in section IV.B our rationale for the 4 tpy emission limit. In
addition, we have never determined that control below 6 tpy is not
cost-effective; to the contrary, we have determined that control at 4
tpy and above is cost-effective. Furthermore, we are concerned that
setting the emission limit to allow removal of control if uncontrolled
emissions are below 6 tpy for 6 consecutive months does not provide for
reasonable certainty that emissions would not be controlled to the
maximum extent possible that is still cost-effective and that does not
create undue secondary impacts. Moreover, a full 12 months of sustained
monthly uncontrolled actual emissions estimates below the 4 tpy limit
will reasonably ensure that emissions fluctuations will not cause
excursions above the limit, requiring controls to be reapplied. In the
context of once in always in, the EPA has not extended this policy by
providing that storage vessel affected facilities that subsequently
reduce PTE to below 6 tpy remain affected facilities. The EPA
historically has never let facilities in and out of affected facility
status and is consistent in subpart OOOO. Having storage vessels remain
affected facilities when emissions decline allows regulatory agencies
to track emissions of these storage vessels and to monitor compliance
if they increase. Further, operators are not restricted as to what they
store in a tank; if the contents are crude oil, condensate, hydrocarbon
intermediates or produced water, and the storage vessel has PTE of at
least 6 tpy, it is a storage vessel affected facility and subject to
subpart OOOO. In addition, in response to a comment that a tank is
forever an affected facility regardless of its future contents, we
disagree. If a tank ceases to be used for a purpose other than to hold
an accumulation of any of the materials listed above, then it ceases to
fit the definition of storage vessel under subpart OOOO and is
therefore no longer an affected facility subject to the standards.
    One commenter requests that we clarify that a storage vessel
affected facility that is taken out of service ceases to be an affected
facility under the NSPS. On the contrary, the storage vessel remains to
be an affected facility, although we realize that there may be undue
burden associated with control and monitoring, recordkeeping and
reporting requirements for storage vessels that are not in service.
However, if a storage vessel affected facility that is out of service
is returned to service, an emissions determination is necessary to see
whether it can continue compliance with the 4 tpy uncontrolled emission
rate or it must now install control to meet the 95 percent reduction
requirement. In the 2012 NSPS, we concluded that we need to provide
sufficient time for determining emissions and, if necessary, installing
control. See 77 FR 49490, at 49526 (August 16, 2012). Accordingly, the
2012 NSPS provide 30 days for determining emissions and an additional
30 days to make control operational. We believe that a similar time
frame is needed for a dormant storage vessel returned to service to
demonstrate continued compliance with the 4 tpy uncontrolled emission
rate or to install control to meet the 95 percent reduction
requirement. After all, these storage vessels may very well have very
low emissions upon startup and should not be forced to install control
immediately without an opportunity to demonstrate that they can
continue

compliance with the 4 tpy uncontrolled emission rate. However, we are
concerned that a dormant storage vessel that is returned to service
associated with the fracturing or refracturing of a well feeding it is
likely to release substantial amounts of vapor if not controlled right
away due to the initially high liquid flow and flash emissions from
freshly fractured or refractured wells. We also believe that potential
emissions associated with fracturing and refracturing of a well are
unlikely to meet the 4 tpy uncontrolled emission rate. We are therefore
not providing the time period described above for storage vessels
returned to service associated with fracturing or refracturing of a
well. In light of these considerations, we have added language at Sec.
60.5395(f) of the final amendments to address storage vessel affected
facilities that are removed from service. After taking a storage vessel
affected facility out of service, owners or operators are required
provide notification in their next annual report that the storage
vessel has been taken out of service. If a storage vessel's return to
service is associated with fracturing or refracturing of a well feeding
the storage vessel, the storage vessel must comply with control
requirements in Sec.  60.5395(d) immediately upon returning to service.
If, however, the storage vessel's return to service is not associated
with well fracturing or refracturing, the PTE of the storage vessel
must be determined within 30 days. If the PTE is 4 tpy or greater, then
the storage vessel affected facility must comply with control
requirements in Sec.  60.5395(d) within 60 days of being returned to
service.

D. Major Comments Concerning Ongoing Compliance Requirements

1. Burden of Monitoring and Testing Requirements
    Comment: One commenter states that the monitoring and testing
requirements for storage vessels in the 2012 NSPS are overly complex
and stringent given the large number of units affected and the
remoteness of some wells sites. The commenter supports the EPA's intent
to reduce the monitoring and testing burden on affected sources by
means of the streamlined monitoring provisions in the proposed
amendments. However, the commenter contends that many of these
``streamlined'' provisions remain overly burdensome due to the large
number of affected vessels and the remoteness of the well sites at
which they are installed. In particular, the commenter believes that
Sec.  60.5416 should only require an annual auditory, visual and
olfactory (AVO) inspection of the vessel and control device, and that
Method 22 observation should be required only if smoke is observed by
the operator.
    Another commenter states that, as proposed, the monthly inspections
and obligations for prompt repairs can be accomplished with existing
personnel and not add significantly to the cost of compliance while
ensuring that the required emissions controls are operating properly.
    Response: In this action, the EPA is finalizing the streamlined
compliance monitoring requirements, as proposed, with minor clarifying
changes. As we stated in the preamble to the proposed amendments (78 FR
22134), we will continue to fully evaluate the compliance demonstration
and monitoring issues. We intend to complete our reconsideration of
these requirements, along with other issues for which we intend to
grant reconsideration, by the end of 2014.
    In response to the comment stating that the streamlined monitoring
provisions are still too burdensome, the EPA has re-evaluated the
Method 22 requirements in the proposed reconsideration rule and
continues to believe that an observation time of fifteen minutes with a
one minute smoke allowance for all combustion controls is appropriate.
For manufacturer-tested enclosed combustors, the required frequency of
the Method 22 test is quarterly. For all other combustion controls, the
required frequency of the Method 22 test is monthly. A ``smoke/no
smoke'' determination is essentially what Method 22 requires. Method 22
simply requires the observer to note how long emissions were seen over
a period of time (15 minutes for monthly testing, 1 hour for quarterly
testing). If smoke is seen for more than a specified amount of time, it
is a violation. We have information indicating that personnel are on-
site at each well at least monthly. Since the Method 22 observation
does not require highly trained personnel to conduct the test, we
believe the personnel already on-site are capable of performing the
test. Thus, we do not agree with the commenter that the monitoring
provisions in the reconsideration proposal would result in undue
burden, or that they are inappropriate considering the remoteness of
the well sites. We have therefore finalized those provisions.
2. Streamlined Compliance Monitoring
    Comment: Several commenters commented on the proposed streamlined
compliance monitoring requirements for closed vent systems and control
devices installed to reduce VOC emissions from storage vessels. Four
commenters request that the EPA make the streamlined compliance
monitoring requirements permanent. One of these commenters states that
monitoring requirements imposed by the 2012 NSPS would be particularly
onerous for small, independent operators that cannot afford the number
of employees-hours required to travel to distant well sites with such
high frequency. According to the commenters, their suggested changes to
the proposed amendments would meet the goal of proper monitoring of
emissions without requiring such a large amount of human and capital
resources. Two commenters oppose the streamlined monitoring
requirements and request that the EPA reinstate the more rigorous
requirements in the 2012 NSPS. One commenter states that portions of
the streamlined monitoring requirements are unnecessary and burdensome.
    Another commenter expresses concern that the proposed amendments
replace instrument-based monitoring of control devices and closed vent
systems (CVS) with less reliable methods. Effective monitoring of the
integrity and performance of emission control devices is vital to
ensuring compliance with emissions limitations under section 111,
according to the commenter, and is evident in the radically revised
number of storage vessels with emissions exceeding 6 tpy.
    The commenter pointed out that the current subpart OOOO
requirements for continuous parametric monitoring system (CPMS) and
Method 22 testing, as well as Method 21 monitoring, build on other
long-standing EPA regulations, including storage vessel standards under
subpart HH and the NSPS for volatile organic liquid storage vessels,
subpart Kb. The commenter added that they are also consistent with the
proposed Uniform Standards for CVS and storage vessels. According to
the commenter, the EPA went in the wrong direction by proposing to
eliminate the CPMS requirements, shorten the Method 22 visible
emissions testing, and allow operators to inspect CVS using OVA
inspections.
    The commenter states that previous agency studies indicate that
instrument-based monitoring is cost-effective and more sensitive than
sensory inspections, suggesting that if anything subpart OOOO should
extend such monitoring to all roof fittings that could emit VOC. The
commenter contends that the EPA provided no information in the proposed
reconsideration that questions

the findings of the Uniform Standards on relative effectiveness or cost
of instrument monitoring of storage vessel components. The commenter
also points to the Fort Berthold Indian Reservation Federal
Implementation Plan (FBIR FIP) where the EPA required continuous
parametric monitoring of enclosed combustors, utility flares, and other
control devices. Also in the FBIR FIP according to the commenter, the
EPA rejected reducing the Method 22 observation period to 1 hour to
mitigate burdensome compliance costs as an option that was not
suitable. The commenter does not believe the EPA provided specific
information to warrant a different approach.
    The commenter adds that the EPA did not demonstrate that the
proposed changes are necessary to mitigate cost and burdens raised by
industry. The commenter states that the EPA cited general personnel and
infrastructure concerns in the preamble but did not provide an analysis
of the anticipated costs of implementing monitoring. In proposing to
determine that the current monitoring requirements were infeasible, the
commenter contends that the EPA did not indicate whether it took into
account the reduced monitoring costs associated with the Group 1
exemption for storage vessels that do not undergo an emissions-
increasing event and the deferral of the Group 2 storage vessel
compliance date.
    Further, the commenter states that there is no indication as to
whether Method 21 inspections, CPMS and full Method 22 testing would be
infeasible at storage vessels at or near manned facilities. As a
result, the commenter contends that the EPA's streamlined monitoring
requirements appear to be overly broad as well as inadequately
supported.
    Another commenter adds that periodic monitoring of closed-vent
systems and control devices is a very important part of controlling the
air quality in the nation. The commenter asserts that most well sites
are located far away from cities and sometimes it can be bothersome to
drive back and forth in order to accomplish testing and monitoring
processes. The commenter believes that the best way to encourage
operators to use the appropriate models is by not letting them install
equipment without proper documentation, and to fine them, or even stop
onsite operations in case they do not obey the requirement.
    Response: In today's action, the EPA is finalizing the streamlined
compliance monitoring requirements, as proposed, with minor clarifying
changes. In finalizing these provisions, the EPA has made no
determination on the cost or feasibility of the compliance monitoring
provisions in the 2012 NSPS, as some commenters appear to suggest. We
also agree with the commenters about those provisions' reliability and
effectiveness. However, as we explained in the preamble to the proposed
amendments (78 FR 22134), significant issues regarding their
implementation have been raised in the administrative petitions for
reconsideration of the 2012 NSPS, which we are continuing to evaluate.
We intend to complete our reconsideration of these requirements, along
with any other issues for which we intend to grant reconsideration, by
the end of 2014. We do not believe it is appropriate to impose these
monitoring requirements on affected facilities while we are still
evaluating their implementation issues. However, to avoid delaying
compliance, we have proposed and are finalizing in today's action a set
of streamlined compliance monitoring requirements. We believe that they
are adequate to assure compliance. Several commenters urge us to retain
the monitoring provisions in the 2012 NSPS for the reasons summarized
above, but none of them claim that the streamlined provisions laid out
in the proposal are inadequate to assure compliance. In light of the
above, we are finalizing the streamlined compliance monitoring
requirements, as proposed, with minor clarifying changes.

E. Major Comments Concerning Design Requirements

    Comment: Three commenters support the inclusion of design
parameters in the final amendments. One commenter states that design
parameters are important to reduce the possibility for an unintended
loophole in the rule language which might result in potentially
significant emissions. The commenter adds that their agency has
observed the highest emission rates corresponding to flash VOC
emissions while liquids are being added to an existing storage vessel
and believes that this is common at well sites, where the natural
formation results in high pressure liquids which are then routed
through the separator to a storage vessel that is at or around
atmospheric pressure. The commenter contends that if a closed cover is
not maintained during such liquids addition, a large percentage of the
annual emissions could vent out of a pressure relief valve or thief
hatch, rather than being routed to a control device.
    Another commenter supported this view and states that the final
amendments must ensure that vapor collection systems and control
devices will reduce 95 percent of VOCs during all phases of operation,
including when air pressure significantly increases during loading. The
commenter contends that where systems are currently in place to control
condensate tank emissions at natural gas exploration and production
sites, they are sometimes inadequate for controlling the high-pressure
vapor produced when the tanks receive a slug of condensate. The
commenter points out that the EPA has noted in this rulemaking that the
feasibility of meeting the storage-vessel standards with a vapor
recovery unit may be affected by ``fluctuations in vapor loading caused
by surges in throughput and flash emissions from the storage vessel.''
The commenter provides several possible approaches to assure equipment
is properly designed to meet the storage vessel standards.
    One of the commenters adds that the inclusion of design
requirements would provide enforceable provisions that would assist
permitting agencies in regulating sources.
    Eight commenters generally opposed the inclusion of design
requirements in the final amendments. One commenter states that the EPA
has already established BSER for affected storage vessels as the
reduction of VOC emissions by 95 percent or greater and established
work practice standards for the closed vent system to any control
device or vapor recovery system. According to the commenter, these work
practice standards address potential equipment design and maintenance
issues that could affect the proper collection of and destruction or
recovery of VOC emissions from storage vessels. The commenter asserts
that a storage vessel, closed vent system, and control device that are
not properly designed would not be able to meet the work practice