Oil and Natural Gas Sector: Reconsideration of Certain Provisions of New Source Performance Standards, 58415-58448 [2013-22010]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 78, Number 184 (Monday, September 23, 2013)]
[Rules and Regulations]
[Pages 58415-58448]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-22010]



[[Page 58415]]

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 https://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 https://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 (202) 566-1744, and the telephone number 
for the Air Docket is (202) 566-1742.

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: (919) 541-5460; facsimile 
number: (919) 685-3200; email address: moore.bruce@epa.gov.

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

[[Page 58417]]

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

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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: https://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

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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

[[Page 58420]]

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

[[Page 58421]]

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

[[Page 58422]]

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

[[Page 58423]]

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

[[Page 58424]]

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

[[Page 58425]]

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

[[Page 58426]]

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

[[Page 58427]]

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

[[Page 58428]]

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

[[Page 58429]]

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

[[Page 58430]]

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

[[Page 58431]]

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

[[Page 58432]]

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 
standards and minimum control device destruction efficiency already 
required in the proposed rule; therefore, any process design standards 
would only be duplicative requirements and result in more burden to 
industry and state agencies responsible for compliance.
    The commenter maintains that the EPA should not attempt to expand 
any NSPS regulations by specifically regulating the process or 
mechanical design of storage vessels or the closed vent system to 
control devices or vapor recovery systems. The commenter further states 
that owners and operators are responsible for designing process 
equipment based on individual site process conditions and safety 
considerations. According to the

[[Page 58433]]

commenter, it would be a massive undertaking for the EPA to attempt to 
write regulations regarding the specific ``proper'' design of storage 
vessels and closed vent systems. The commenter expresses doubt that the 
EPA could provide enough flexibility in process and mechanical design 
of equipment regulations to cover all the unique process conditions at 
individual facilities.
    One commenter adds that over-prescriptive regulations on storage 
vessel design could stifle technological innovation, including new tank 
designs that emit less than current storage vessels. Additionally, 
according to the commenter, storage vessels are specifically designed 
in accordance with federal safety standards and these specifications 
should not be potentially compromised under any circumstances. Further, 
the commenter states that it is in the best economic interest of all 
operators to procure properly designed equipment and operate storage 
vessels efficiently. Lastly, the commenter states that, under the CAA, 
operators already have a general duty requirement to ``maintain and 
operate any affected facility including air pollution control equipment 
in a manner consistent with good air pollution control practices for 
minimizing emissions.''
    One commenter does not believe that the EPA has the authority under 
NSPS to require a particular technology or design as a performance 
standard. The commenter contends that the EPA should not mandate a 
particular technology, but rather allow companies to choose the 
technology to best meet the emission standard.
    One state agency commenter believes that specifying design 
requirements in regulations will stifle innovation and create a plateau 
for new products. The commenter believes that such restrictions will 
not allow for economic or technological creation of new methods or 
equipment. The commenter further states that, as the industry grows and 
changes, so too should the facilities and equipment associated with it, 
but prescriptive design requirements would not allow this to happen. 
Also, according to the commenter, due to high variability of materials 
and situations in the field it seems illogical and inappropriate to 
deem only certain designs of facilities and equipment acceptable or 
not. The commenter contends that design requirements specified by rule 
could cause certain facilities or regions to be unable to implement 
engineering solutions necessary to account for site- or region-specific 
conditions.
    Response: The EPA appreciates the information provided by these 
commenters in response to the EPA's solicitation of comment on whether 
the NSPS should include design requirements for storage vessels, closed 
vent system and control devices. In the preamble to the proposed rule, 
we had solicited comment on whether the EPA should require that storage 
vessel installations and associated controls be sized and designed 
properly for specific applications to minimize excess emissions due to 
improperly sized and designed storage vessels or control systems. We 
did not solicit comment on whether the EPA should require specific 
technology or design parameters. Accordingly, because the 
reconsideration proposal did not include any specific design 
requirements for storage vessels and associated closed vent systems and 
control device, no such requirement is included in the final 
amendments.

F. Major Comments Concerning Impacts

    Comment: One commenter contends that the EPA failed to assess the 
air quality impacts of its proposed amendments and the EPA must provide 
further analysis of air quality impacts to support that the proposed 
revised standards is BSER. According to the commenter's analysis, Group 
1 storage vessels that do not experience an event that would increase 
emissions would result in an increase from the final NSPS in VOC 
emissions of over 3 million tpy and methane emissions of over 700,000 
tpy. In addition, the commenter states that the six-month delay of the 
compliance date for Group 2 storage vessels results in an increases of 
450,000 tpy of VOC emissions and 100,000 tpy of methane emissions. The 
commenter added that the removal of a control device from sources whose 
uncontrolled emissions drop below 4 tpy would result in an emission 
increase of 3.8 tpy VOC per vessel. Assuming that the 11,600 new 
vessels the EPA projects would qualify for the uncontrolled actual VOC 
emission rate, emissions would increase by 23,000 tpy VOC and 5,000 tpy 
methane. The commenter also contends that the removal of the control 
device would result in sources left uncontrolled during any unplanned 
events that would generate significant emissions. Additionally, the 
commenter states that using their decline curve analysis, new sources 
would not qualify for uncontrolled actual VOC emission rate for at 
least 14 years, and the increase in pollution is not justified by the 
EPA's control device availability concerns.
    Response: As we discussed in section IV.A of this preamble, we are 
not finalizing our proposal to subject only those Group 1 storage 
vessels that experience an event to the emission standards. Thus, all 
Group 1 storage vessel affected facilities will be subject to the 
emission standards, as required under the 2012 NSPS. We believe this 
addresses the commenters' concerns about any increase in emissions 
based on our proposal to require Group 1 to control only if there is a 
subsequent emission increase event. The commenter is also concerned 
with emission increase from delayed compliance. However, we believe 
that the extended deadlines in the final amendments are justified for 
the reasons stated in section IV.A, and we are phasing the compliance 
deadlines to address facilities with projected higher emissions more 
quickly.
    We have also provided further analysis of air quality impacts, as 
the commenter suggests, as well as the cost effectiveness and energy 
impact associated with the proposed uncontrolled emission rate of less 
than 4 tpy. As discussed in more detail in section V.C of this 
preamble, 4 tpy likely represents a point below which control ceases to 
be the BSER for reducing VOC emissions from storage vessel affected 
facilities due to the cost effectiveness, the secondary environmental 
impact and energy impact.

VI. Technical Corrections and Clarifications

    The EPA is finalizing corrections to recordkeeping and reporting 
requirements for all affected facilities. In addition, the final 
amendments include corrections that are editorial in nature, such as 
typographical and grammatical errors, as well as incorrect cross-
references.

VII. Impacts of These Final Amendments

    Our analysis shows that owners and operators of storage vessel 
affected facilities would choose to install and operate the same or 
similar air pollution control technologies under the proposed standards 
as would have been necessary to meet the previously finalized 
standards. We project that this rule will result in no significant 
change in costs, emission reductions, or benefits. Even if there were 
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. Since we believe that 
owners and operators would put on the same

[[Page 58434]]

controls for this revised final rule that they would have for the 
original final rule, there should not be any incremental costs related 
to this proposed revision.

A. What are the air impacts?

    We believe that owners and operators of storage vessel affected 
facilities will install the same or similar control technologies to 
comply with the revised standards finalized in this action as they 
would have installed to comply with the previously finalized standards. 
Accordingly, we believe that this final rule will not result in 
significant changes in emissions of any of the regulated pollutants.

B. What are the energy impacts?

    This final rule is not anticipated to have an effect on the supply, 
distribution, or use of energy. As previously stated, we believe that 
owners and operators of storage vessel affected facilities would 
install the same or similar control technologies as they would have 
installed to comply with the previously finalized standards.

C. What are the compliance costs?

    We believe there will be no significant change in compliance costs 
as a result of this final rule because owners and operators of storage 
vessel affected facilities would install the same or similar control 
technologies as they would have installed to comply with the previously 
finalized standards. However, we note that there likely will be 
reductions of costs imposed on owners and operators associated with the 
streamlined compliance monitoring procedures provided in the final 
amendments.

D. What are the economic and employment impacts?

    Because we expect that owners and operators of storage vessel 
affected facilities would install the same or similar control 
technologies to meet the standards finalized in this action as they 
would have chosen to comply with the previously finalized standards, we 
do not anticipate that this final rule will result in significant 
changes in emissions, energy impacts, costs, benefits, or economic 
impacts. Likewise, we believe this rule will not have any impacts on 
the price of electricity, employment or labor markets, or the U.S. 
economy.

E. What are the benefits of the proposed standards?

    As previously stated, the EPA anticipates the oil and natural gas 
sector will not incur significant compliance costs or savings as a 
result of this rule and we do not anticipate any significant emission 
changes resulting from this rule. Therefore, there are no direct 
monetized benefits or disbenefits associated with this rule.

VIII. Statutory and Executive Order Reviews

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

    This action is not a ``significant regulatory action'' under the 
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is 
therefore not subject to review under Executive Orders 12866 and 13563 
(76 FR 3821, January 21, 2011).
    An RIA was prepared for the April 2012 NSPS and can be found at: 
https://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf. This final rule will not result in a significant 
change in costs, emission reductions, or benefits in 2015 (the year of 
full implementation of the 2012 NSPS being amended with this action).

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
This action does not change the information collection requirements 
previously finalized under the 2012 NSPS and, as a result, does not 
impose any additional burden on industry. However, OMB has previously 
approved the information collection requirements contained in the 
existing regulations (see 77 FR 49490) under the provisions of the 
Paperwork Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB 
control number 2060-0673). The OMB control numbers for the EPA's 
regulations are listed in 40 CFR part 9 and 48 CFR chapter 15.

C. Regulatory Flexibility Act

    The Regulatory Flexibility Act (RFA) generally requires an agency 
to prepare a regulatory flexibility analysis of any rule subject to 
notice and comment rulemaking requirements under the Administrative 
Procedure Act or any other statute unless the agency certifies that the 
rule will not have a significant economic impact on a substantial 
number of small entities. Small entities include small businesses, 
small organizations, and small governmental jurisdictions.
    For purposes of assessing the impacts of this rule on small 
entities, a small entity is defined as: (1) A small business in the oil 
or natural gas industry whose parent company has no more than 500 
employees (or revenues of less than $7 million for firms that transport 
natural gas via pipeline); (2) a small governmental jurisdiction that 
is a government of a city, county, town, school district, or special 
district with a population of less than 50,000; and (3) a small 
organization that is any not-for-profit enterprise which is 
independently owned and operated and is not dominant in its field.
    After considering the economic impacts of today's final rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. The EPA has 
determined that none of the small entities will experience a 
significant impact because these final amendments will not impose 
additional compliance costs on owners or operators of affected 
facilities.

D. Unfunded Mandates Reform Act

    This action contains no federal mandates under the provisions of 
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 
1531-1538 for State, local, or tribal governments or the private 
sector. This action imposes no enforceable duty on any state, local or 
tribal governments or the private sector. Therefore, this action is not 
subject to the requirements of sections 202 or 205 of the UMRA.
    This action is also not subject to the requirements of section 203 
of UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. This action 
contains no requirements that apply to small governments nor does it 
impose obligations upon them.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. This final rule is a 
reconsideration of an existing rule and imposes no new impacts or 
costs. Thus, Executive Order 13132 does not apply to this action.
    In the spirit of Executive Order 13132, and consistent with the EPA 
policy to promote communications between the EPA and state and local 
governments, the EPA specifically solicited comment on the proposed 
action from state and local officials.

[[Page 58435]]

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

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). It will not have 
substantial direct effect on tribal governments, on the relationship 
between the federal government and tribal governments or on the 
distribution of power and responsibilities between the federal 
government and tribal governments, as specified in Executive Order 
13175. Thus, Executive Order 13175 does not apply to this action.
    In the spirit of Executive Order 13175, and consistent with the EPA 
policy to promote communications between the EPA and tribal 
governments, the EPA specifically solicited comment on the proposed 
action from tribal officials. The EPA notes that significant oil and 
natural gas development is occurring on some tribal lands and has been 
mindful of this in consideration of these final amendments.

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

    This action is not subject to EO 13045 (62 FR 19885, April 23, 
1997) because it is not economically significant as defined in EO 
12866, and because the agency does not believe the environmental health 
risks or safety risks addressed by this action present a 
disproportionate risk to children. This final rule will not result in a 
significant change in emission reductions and benefits in 2015, the 
year of full implementation of the 2012 NSPS being amended with this 
action. Therefore, health and risk assessments were not conducted.
    The public was invited to submit comments or identify peer-reviewed 
studies and data that assess effects of early life exposure to HAP from 
oil and natural gas sector activities.

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

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22, 2001)), because it is not a significant regulatory action 
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (``NTTAA''), Public Law 104-113, 12(d) (15 U.S.C. 272 note) 
directs the EPA to use voluntary consensus standards in its regulatory 
activities unless to do so would be inconsistent with applicable law or 
otherwise impractical. Voluntary consensus standards are technical 
standards (e.g., materials specifications, test methods, sampling 
procedures, and business practices) that are developed or adopted by 
voluntary consensus standards bodies. The NTTAA directs the EPA to 
provide Congress, through OMB, explanations when the agency decides not 
to use available and applicable voluntary consensus standards.
    This final rule does not involve technical standards. Therefore, 
the EPA is not considering the use of any voluntary consensus 
standards.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order (EO) 12898 (59 FR 7629 (Feb. 16, 1994)) establishes 
federal executive policy on environmental justice. Its main provision 
directs federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    The EPA has determined that this final rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority, low-income, or indigenous populations because it 
does not affect the level of human health or environmental protection 
for all affected populations. This final rule is a reconsideration of 
an existing rule and imposes no new impacts or costs. Therefore, this 
final rule would not have any disproportionately high and adverse human 
health or environmental effects on any population, including any 
minority, low income or indigenous populations.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996, generally 
provides that before a rule may take effect, the agency promulgating 
the rule must submit a rule report, which includes a copy of the rule, 
to each House of Congress and to the Comptroller General of the United 
States. The EPA will submit a report containing this rule and other 
required information to the U.S. Senate, the U.S. House of 
Representatives, and the Comptroller General of the United States prior 
to publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective September 23, 2013.

List of Subjects in 40 CFR Part 60

    Administrative practice and procedure, Air pollution control, 
Intergovernmental relations, Reporting and recordkeeping.

    Dated: August 2, 2013.
Gina McCarthy,
Administrator.

    For the reasons set out in the preamble, title 40, chapter I of the 
Code of Federal Regulations is amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

    Authority:  42 U.S.C. 7401, et seq.

Subpart OOOO--[Amended]

0
2. Section 60.5365 is amended by revising paragraphs (e) and (h)(4) to 
read as follows:


Sec.  60.5365  Am I subject to this subpart?

* * * * *
    (e) Each storage vessel affected facility, which is a single 
storage vessel located in the oil and natural gas production segment, 
natural gas processing segment or natural gas transmission and storage 
segment, and has the potential for VOC emissions equal to or greater 
than 6 tpy as determined according to this section by October 15, 2013 
for Group 1 storage vessels and by April 15, 2014, or 30 days after 
startup (whichever is later) for Group 2 storage vessels. A storage 
vessel affected facility that subsequently has its potential for VOC 
emissions decrease to less than 6 tpy shall remain an affected facility 
under this subpart. The potential for VOC emissions must be calculated 
using a generally accepted model or calculation methodology, based on 
the maximum average daily throughput determined for a 30-day period of 
production prior to the applicable emission determination deadline 
specified in this section. The determination may take into account 
requirements under a legally and practically enforceable limit in an 
operating permit or other requirement

[[Page 58436]]

established under a Federal, State, local or tribal authority. 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, provided you 
comply with the requirements in paragraphs (e)(1) through (4) of this 
section.
    (1) You meet the cover requirements specified in Sec.  60.5411(b).
    (2) You meet the closed vent system requirements specified in Sec.  
60.5411(c).
    (3) You maintain records that document compliance with paragraphs 
(e)(1) and (2) of this section.
    (4) In the event of removal of apparatus that recovers and routes 
vapor to a process, or operation that is inconsistent with the 
conditions specified in paragraphs (e)(1) and (2) of this section, you 
must determine the storage vessel's potential for VOC emissions 
according to this section within 30 days of such removal or operation.
* * * * *
    (h) * * *
    (4) A gas well facility initially constructed after August 23, 
2011, is considered an affected facility regardless of this provision.
0
3. Section 60.5380 is amended by revising paragraphs (a)(2), (b), and 
(c) to read as follows:


Sec.  60.5380  What standards apply to centrifugal compressor affected 
facilities?

* * * * *
    (a) * * *
    (2) If you use a control device to reduce emissions, you must equip 
the wet seal fluid degassing system with a cover that meets the 
requirements of Sec.  60.5411(b), that is connected through a closed 
vent system that meets the requirements of Sec.  60.5411(a) and routed 
to a control device that meets the conditions specified in Sec.  
60.5412(a), (b) and (c). As an alternative to routing the closed vent 
system to a control device, you may route the closed vent system to a 
process.
    (b) You must demonstrate initial compliance with the standards that 
apply to centrifugal compressor affected facilities as required by 
Sec.  60.5410(b).
    (c) You must demonstrate continuous compliance with the standards 
that apply to centrifugal compressor affected facilities as required by 
Sec.  60.5415(b).
* * * * *

0
4. Section 60.5390 is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraph (a); and
0
c. Revising paragraph (c).
    The revisions read as follows:


Sec.  60.5390  What standards apply to pneumatic controller affected 
facilities?

    For each pneumatic controller affected facility you must comply 
with the VOC standards, based on natural gas as a surrogate for VOC, in 
either paragraph (b)(1) or (c)(1) of this section, as applicable. 
Pneumatic controllers meeting the conditions in paragraph (a) of this 
section are exempt from this requirement.
    (a) The requirements of paragraph (b)(1) or (c)(1) of this section 
are not required if you determine that the use of a pneumatic 
controller affected facility with a bleed rate greater than the 
applicable standard is required based on functional needs, including 
but not limited to response time, safety and positive actuation. 
However, you must tag such pneumatic controller with the month and year 
of installation, reconstruction or modification, and identification 
information that allows traceability to the records for that pneumatic 
controller, as required in Sec.  60.5420(c)(4)(ii).
* * * * *
    (c)(1) Each pneumatic controller affected facility constructed, 
modified or reconstructed on or after October 15, 2013, at a location 
between the wellhead and a natural gas processing plant or the point of 
custody transfer to an oil pipeline must have a bleed rate less than or 
equal to 6 standard cubic feet per hour.
    (2) Each pneumatic controller affected facility at a location 
between the wellhead and a natural gas processing plant or the point of 
custody transfer to an oil pipeline must be tagged with the month and 
year of installation, reconstruction or modification, and 
identification information that allows traceability to the records for 
that controller as required in Sec.  60.5420(c)(4)(iii).
* * * * *

0
5. Section 60.5395 is revised to read as follows:


Sec.  60.5395  What standards apply to storage vessel affected 
facilities?

    Except as provided in paragraph (h) of this section, you must 
comply with the standards in this section for each storage vessel 
affected facility.
    (a)(1) If you are the owner or operator of a Group 1 storage vessel 
affected facility, you must comply with paragraph (b) of this section.
    (2) If you are the owner or operator of a Group 2 storage vessel 
affected facility, you must comply with paragraph (c) of this section.
    (b) Requirements for Group 1 storage vessel affected facilities. If 
you are the owner or operator of a Group 1 storage vessel affected 
facility, you must comply with paragraphs (b)(1) and (2) of this 
section.
    (1) You must submit a notification identifying each Group 1 storage 
vessel affected facility, including its location, with your initial 
annual report as specified in Sec.  60.5420(b)(6)(iv).
    (2) You must comply with paragraphs (d) through (g) of this 
section.
    (c) Requirements for Group 2 storage vessel affected facilities. If 
you are the owner or operator of a Group 2 storage vessel affected 
facility, you must comply with paragraphs (d) through (g) of this 
section.
    (d) You must comply with the control requirements of paragraph 
(d)(1) of this section unless you meet the conditions specified in 
paragraph (d)(2) of this section.
    (1) Reduce VOC emissions by 95.0 percent according to the schedule 
specified in (d)(1)(i) and (ii) of this section.
    (i) For each Group 2 storage vessel affected facility, you must 
achieve the required emissions reductions by April 15, 2014, or within 
60 days after startup, whichever is later.
    (ii) For each Group 1 storage vessel affected facility, you must 
achieve the required emissions reductions by April 15, 2015.
    (2) Maintain the uncontrolled actual VOC emissions from the storage 
vessel affected facility at less than 4 tpy without considering 
control. Prior to using the uncontrolled actual VOC emission rate for 
compliance purposes, you must demonstrate that the uncontrolled actual 
VOC emissions have remained less than 4 tpy as determined monthly for 
12 consecutive months. After such demonstration, you must determine the 
uncontrolled actual VOC emission rate each month. The uncontrolled 
actual VOC emissions must be calculated using a generally accepted 
model or calculation methodology. Monthly calculations must be based on 
the average throughput for the month. Monthly calculations must be 
separated by at least 14 days. You must comply with paragraph (d)(1) of 
this section if your storage vessel affected facility meets the 
conditions specified in paragraphs (d)(2)(i) or (ii) of this section.
    (i) If a well feeding the storage vessel affected facility 
undergoes fracturing or refracturing, you must comply with paragraph 
(d)(1) of this section as soon as liquids from the well following 
fracturing or refracturing are routed to the storage vessel affected 
facility.

[[Page 58437]]

    (ii) If the monthly emissions determination required in this 
section indicates that VOC emissions from your storage vessel affected 
facility increase to 4 tpy or greater and the increase is not 
associated with fracturing or refracturing of a well feeding the 
storage vessel affected facility, you must comply with paragraph (d)(1) 
of this section within 30 days of the monthly calculation.
    (e) Control requirements. (1) Except as required in paragraph 
(e)(2) of this section, if you use a control device to reduce emissions 
from your storage vessel affected facility, you must equip the storage 
vessel with a cover that meets the requirements of Sec.  60.5411(b) and 
is connected through a closed vent system that meets the requirements 
of Sec.  60.5411(c), and you must route emissions to a control device 
that meets the conditions specified in Sec.  60.5412(c) and (d). As an 
alternative to routing the closed vent system to a control device, you 
may route the closed vent system to a process.
    (2) If you use a floating roof to reduce emissions, you must meet 
the requirements of Sec.  60.112b(a)(1) or (2) and the relevant 
monitoring, inspection, recordkeeping, and reporting requirements in 40 
CFR part 60, subpart Kb.
    (f) Requirements for storage vessel affected facilities that are 
removed from service. If you are the owner or operator of a storage 
vessel affected facility that is removed from service, you must comply 
with paragraphs (f)(1) and (2) of this section.
    (1) You must submit a notification in your next annual report, 
identifying all storage vessel affected facilities removed from service 
during the reporting period.
    (2) If the storage vessel affected facility identified in paragraph 
(f)(1) of this section is returned to service, you must comply with 
paragraphs (f)(2)(i) through (iii) of this section.
    (i) If returning your storage vessel affected facility to service 
is associated with fracturing or refracturing of a well feeding the 
storage vessel affected facility, you must comply with paragraph (d) of 
this section immediately upon returning the storage vessel to service.
    (ii) If returning your storage vessel affected facility to service 
is not associated with a well that was fractured or refractured, you 
must comply with paragraphs (f)(2)(ii)(A) and (B) of this section.
    (A) You must determine emissions as specified in Sec.  60.5365(e) 
within 30 days of returning your storage vessel affected facility to 
service.
    (B) If the uncontrolled VOC emissions without considering control 
from your storage vessel affected facility are 4 tpy or greater, you 
must comply with paragraph (d) of this section within 60 days of 
returning to service.
    (iii) You must submit a notification in your next annual report 
identifying each storage vessel affected facility that has been 
returned to service.
    (g) Compliance, notification, recordkeeping, and reporting. You 
must comply with paragraphs (g)(1) through (3) of this section.
    (1) You must demonstrate initial compliance with standards as 
required by Sec.  60.5410(h) and (i).
    (2) You must demonstrate continuous compliance with standards as 
required by Sec.  60.5415(e)(3).
    (3) You must perform the required notification, recordkeeping and 
reporting as required by Sec.  60.5420.
    (h) Exemptions. This subpart does not apply to storage vessels 
subject to and controlled in accordance with the requirements for 
storage vessels in 40 CFR part 60, subpart Kb, 40 CFR part 63, subparts 
G, CC, HH, or WW.

0
6. Section 60.5410 is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraphs (a)(3) and (4);
0
c. Revising paragraphs (b)(2) through (5);
0
d. Revising paragraphs (b)(7) and (8);
0
e. Removing and reserving paragraph (c)(2);
0
f. Revising paragraphs (d) introductory text, (d)(1), (d)(2), and 
(d)(4);
0
g. Removing and reserving paragraph (e); and
0
h. Adding paragraphs (h) and (i).
    The revisions and additions read as follows:


Sec.  60.5410  How do I demonstrate initial compliance with the 
standards for my gas well affected facility, my centrifugal compressor 
affected facility, my reciprocating compressor affected facility, my 
pneumatic controller affected facility, my storage vessel affected 
facility, and my equipment leaks and sweetening unit affected 
facilities at onshore natural gas processing plants?

    You must determine initial compliance with the standards for each 
affected facility using the requirements in paragraphs (a) through (i) 
of this section. The initial compliance period begins on October 15, 
2012, or upon initial startup, whichever is later, and ends no later 
than one year after the initial startup date for your affected facility 
or no later than one year after October 15, 2012. The initial 
compliance period may be less than one full year.
    (a) * * *
    (3) You must maintain a log of records as specified in Sec.  
60.5420(c)(1)(i) through (iv) for each well completion operation 
conducted during the initial compliance period.
    (4) For each gas well affected facility subject to both Sec.  
60.5375(a)(1) and (3), as an alternative to retaining the records 
specified in Sec.  60.5420(c)(1)(i) through (iv), you may maintain 
records of one or more digital photographs with the date the photograph 
was taken and the latitude and longitude of the well site imbedded 
within or stored with the digital file showing the equipment for 
storing or re-injecting recovered liquid, equipment for routing 
recovered gas to the gas flow line and the completion combustion device 
(if applicable) connected to and operating at each gas well completion 
operation that occurred during the initial compliance period. As an 
alternative to imbedded latitude and longitude within the digital 
photograph, the digital photograph may consist of a photograph of the 
equipment connected and operating at each well completion operation 
with a photograph of a separately operating GIS device within the same 
digital picture, provided the latitude and longitude output of the GIS 
unit can be clearly read in the digital photograph.
    (b) * * *
    (2) If you use a control device to reduce emissions, you must equip 
the wet seal fluid degassing system with a cover that meets the 
requirements of Sec.  60.5411(b) that is connected through a closed 
vent system that meets the requirements of Sec.  60.5411(a) and is 
routed to a control device that meets the conditions specified in Sec.  
60.5412(a), (b) and (c). As an alternative to routing the closed vent 
system to a control device, you may route the closed vent system to a 
process.
    (3) You must conduct an initial performance test as required in 
Sec.  60.5413 within 180 days after initial startup or by October 15, 
2012, whichever is later, and you must comply with the continuous 
compliance requirements in Sec.  60.5415(b)(1) through (3).
    (4) You must conduct the initial inspections required in Sec.  
60.5416(a) and (b).
    (5) You must install and operate the continuous parameter 
monitoring systems in accordance with Sec.  60.5417(a) through (g), as 
applicable.
* * * * *
    (7) You must submit the initial annual report for your centrifugal 
compressor affected facility as required in Sec.  60.5420(b)(3) for 
each centrifugal compressor affected facility.

[[Page 58438]]

    (8) You must maintain the records as specified in Sec.  
60.5420(c)(2).
    (c) * * *
    (2) [Reserved]
* * * * *
    (d) To achieve initial compliance with emission standards for your 
pneumatic controller affected facility you must comply with the 
requirements specified in paragraphs (d)(1) through (6) of this 
section, as applicable.
    (1) You must demonstrate initial compliance by maintaining records 
as specified in Sec.  60.5420(c)(4)(ii) of your determination that the 
use of a pneumatic controller affected facility with a bleed rate 
greater than 6 standard cubic feet of gas per hour is required as 
specified in Sec.  60.5390(a).
    (2) You own or operate a pneumatic controller affected facility 
located at a natural gas processing plant and your pneumatic controller 
is driven by a gas other than natural gas and therefore emits zero 
natural gas.
* * * * *
    (4) You must tag each new pneumatic controller affected facility 
according to the requirements of Sec.  60.5390(b)(2) or (c)(2).
* * * * *
    (e) [Reserved]
* * * * *
    (h) For each storage vessel affected facility, you must comply with 
paragraphs (h)(1) through (5) of this section. For a Group 1 storage 
vessel affected facility, you must demonstrate initial compliance by 
April 15, 2015, except as otherwise provided in paragraph (i) of this 
section. For a Group 2 storage vessel affected facility, you must 
demonstrate initial compliance by April 15, 2014, or within 60 days 
after startup, whichever is later.
    (1) You must determine the potential VOC emission rate as specified 
in Sec.  60.5365(e).
    (2) You must reduce VOC emissions in accordance with Sec.  
60.5395(d).
    (3) If you use a control device to reduce emissions, or if you 
route emissions to a process, you must demonstrate initial compliance 
by meeting the requirements in Sec.  60.5395(e).
    (4) You must submit the information required for your storage 
vessel affected facility as specified in Sec.  60.5420(b).
    (5) You must maintain the records required for your storage vessel 
affected facility, as specified in Sec.  60.5420(c)(5) through (8) and 
Sec.  60.5420(c)(12) and (13) for each storage vessel affected 
facility.
    (i) For each Group 1 storage vessel affected facility, you must 
submit the notification specified in Sec.  60.5395(b)(2) with the 
initial annual report specified in Sec.  60.5420(b)(6).

0
7. Section 60.5411 is amended by:
0
a. Revising the section heading;
0
b. Revising paragraphs (a) introductory text, (a)(1), and (a)(3)(i)(A);
0
c. Revising the heading of paragraph (b), and paragraphs (b)(1) and 
(b)(2)(iv);
0
d. Adding paragraph (b)(3); and
0
e. Adding paragraph (c).
    The revisions and additions read as follows:


Sec.  60.5411  What additional requirements must I meet to determine 
initial compliance for my covers and closed vent systems routing 
materials from storage vessels and centrifugal compressor wet seal 
degassing systems?

* * * * *
    (a) Closed vent system requirements for centrifugal compressor wet 
seal degassing systems. (1) You must design the closed vent system to 
route all gases, vapors, and fumes emitted from the material in the wet 
seal fluid degassing system to a control device or to a process that 
meets the requirements specified in Sec.  60.5412(a) through (c).
* * * * *
    (3) * * *
    (i) * * *
    (A) You must properly install, calibrate, maintain, and operate a 
flow indicator at the inlet to the bypass device that could divert the 
stream away from the control device or process to the atmosphere that 
is capable of taking periodic readings as specified in Sec.  
60.5416(a)(4) and sounds an alarm when the bypass device is open such 
that the stream is being, or could be, diverted away from the control 
device or process to the atmosphere.
* * * * *
    (b) Cover requirements for storage vessels and centrifugal 
compressor wet seal degassing systems. (1) The cover and all openings 
on the cover (e.g., access hatches, sampling ports, pressure relief 
valves and gauge wells) shall form a continuous impermeable barrier 
over the entire surface area of the liquid in the storage vessel or wet 
seal fluid degassing system.
    (2) * * *
    (iv) To vent liquids, gases, or fumes from the unit through a 
closed-vent system designed and operated in accordance with the 
requirements of paragraph (a) or (c) of this section to a control 
device or to a process.
    (3) Each storage vessel thief hatch shall be weighted and properly 
seated. You must select gasket material for the hatch based on 
composition of the fluid in the storage vessel and weather conditions.
    (c) Closed vent system requirements for storage vessel affected 
facilities using a control device or routing emissions to a process. 
(1) You must design the closed vent system to route all gases, vapors, 
and fumes emitted from the material in the storage vessel to a control 
device that meets the requirements specified in Sec.  60.5412(c) and 
(d), or to a process.
    (2) You must design and operate a closed vent system with no 
detectable emissions, as determined using olfactory, visual and 
auditory inspections. Each closed vent system that routes emissions to 
a process must be operational 95 percent of the year or greater.
    (3) You must meet the requirements specified in paragraphs 
(c)(3)(i) and (ii) of this section if the closed vent system contains 
one or more bypass devices that could be used to divert all or a 
portion of the gases, vapors, or fumes from entering the control device 
or to a process.
    (i) Except as provided in paragraph (c)(3)(ii) of this section, you 
must comply with either paragraph (c)(3)(i)(A) or (B) of this section 
for each bypass device.
    (A) You must properly install, calibrate, maintain, and operate a 
flow indicator at the inlet to the bypass device that could divert the 
stream away from the control device or process to the atmosphere that 
sounds an alarm, or, initiates notification via remote alarm to the 
nearest field office, when the bypass device is open such that the 
stream is being, or could be, diverted away from the control device or 
process to the atmosphere.
    (B) You must secure the bypass device valve installed at the inlet 
to the bypass device in the non-diverting position using a car-seal or 
a lock-and-key type configuration.
    (ii) Low leg drains, high point bleeds, analyzer vents, open-ended 
valves or lines, and safety devices are not subject to the requirements 
of paragraph (c)(3)(i) of this section.

0
8. Section 60.5412 is amended by:
0
a. Revising paragraphs (a) introductory text, (a)(1) introductory text, 
and (a)(2);
0
b. Revising paragraph (b);
0
c. Revising paragraphs (c) introductory text and (c)(1); and
0
d. Adding paragraph (d).
    The revisions and addition read as follows:


Sec.  60.5412  What additional requirements must I meet for determining 
initial compliance with control devices used to comply with the 
emission standards for my storage vessel or centrifugal compressor 
affected facility?

* * * * *

[[Page 58439]]

    (a) Each control device used to meet the emission reduction 
standard in Sec.  60.5380(a)(1) for your centrifugal compressor 
affected facility must be installed according to paragraphs (a)(1) 
through (3) of this section. As an alternative, you may install a 
control device model tested under Sec.  60.5413(d), which meets the 
criteria in Sec.  60.5413(d)(11) and Sec.  60.5413(e).
    (1) Each combustion device (e.g., thermal vapor incinerator, 
catalytic vapor incinerator, boiler, or process heater) must be 
designed and operated in accordance with one of the performance 
requirements specified in paragraphs (a)(1)(i) through (iv) of this 
section.
* * * * *
    (2) Each vapor recovery device (e.g., carbon adsorption system or 
condenser) or other non-destructive control device must be designed and 
operated to reduce the mass content of VOC in the gases vented to the 
device by 95.0 percent by weight or greater as determined in accordance 
with the requirements of Sec.  60.5413. As an alternative to the 
performance testing requirements, you may demonstrate initial 
compliance by conducting a design analysis for vapor recovery devices 
according to the requirements of Sec.  60.5413(c).
* * * * *
    (b) You must operate each control device installed on your 
centrifugal compressor affected facility in accordance with the 
requirements specified in paragraphs (b)(1) and (2) of this section.
    (1) You must operate each control device used to comply with this 
subpart at all times when gases, vapors, and fumes are vented from the 
wet seal fluid degassing system affected facility, as required under 
Sec.  60.5380(a), through the closed vent system to the control device. 
You may vent more than one affected facility to a control device used 
to comply with this subpart.
    (2) For each control device monitored in accordance with the 
requirements of Sec.  60.5417(a) through (g), you must demonstrate 
compliance according to the requirements of Sec.  60.5415(b)(2), as 
applicable.
    (c) For each carbon adsorption system used as a control device to 
meet the requirements of paragraph (a)(2) or (d)(2) of this section, 
you must manage the carbon in accordance with the requirements 
specified in paragraphs (c)(1) or (2) of this section.
    (1) Following the initial startup of the control device, you must 
replace all carbon in the control device with fresh carbon on a 
regular, predetermined time interval that is no longer than the carbon 
service life established according to Sec.  60.5413(c)(2) or (3) or 
according to the design required in paragraph (d)(2) of this section, 
for the carbon adsorption system. You must maintain records identifying 
the schedule for replacement and records of each carbon replacement as 
required in Sec.  60.5420(c)(10) and (12).
* * * * *
    (d) Each control device used to meet the emission reduction 
standard in Sec.  60.5395(d) for your storage vessel affected facility 
must be installed according to paragraphs (d)(1) through (3) of this 
section, as applicable. As an alternative, you may install a control 
device model tested under Sec.  60.5413(d), which meets the criteria in 
Sec.  60.5413(d)(11) and Sec.  60.5413(e).
    (1) Each enclosed combustion device (e.g., thermal vapor 
incinerator, catalytic vapor incinerator, boiler, or process heater) 
must be designed to reduce the mass content of VOC emissions by 95.0 
percent or greater. You must follow the requirements in paragraphs 
(d)(1)(i) through (iii) of this section.
    (i) Ensure that each enclosed combustion device is maintained in a 
leak free condition.
    (ii) Install and operate a continuous burning pilot flame.
    (iii) Operate the enclosed combustion device with no visible 
emissions, except for periods not to exceed a total of one minute 
during any 15 minute period. A visible emissions test using section 11 
of EPA Method 22, 40 CFR part 60, appendix A, must be performed at 
least once every calendar month, separated by at least 15 days between 
each test. The observation period shall be 15 minutes. Devices failing 
the visible emissions test must follow manufacturer's repair 
instructions, if available, or best combustion engineering practice as 
outlined in the unit inspection and maintenance plan, to return the 
unit to compliant operation. All inspection, repair and maintenance 
activities for each unit must be recorded in a maintenance and repair 
log and must be available for inspection. Following return to operation 
from maintenance or repair activity, each device must pass a Method 22, 
40 CFR part 60, appendix A, visual observation as described in this 
paragraph.
    (2) Each vapor recovery device (e.g., carbon adsorption system or 
condenser) or other non-destructive control device must be designed and 
operated to reduce the mass content of VOC in the gases vented to the 
device by 95.0 percent by weight or greater. A carbon replacement 
schedule must be included in the design of the carbon adsorption 
system.
    (3) You must operate each control device used to comply with this 
subpart at all times when gases, vapors, and fumes are vented from the 
storage vessel affected facility through the closed vent system to the 
control device. You may vent more than one affected facility to a 
control device used to comply with this subpart.

0
9. Section 60.5413 is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraph (a)(7);
0
c. Revising paragraph (d); and
0
d. Adding paragraph (e).
    The revisions and addition read as follows:


Sec.  60.5413  What are the performance testing procedures for control 
devices used to demonstrate compliance at my storage vessel or 
centrifugal compressor affected facility?

    This section applies to the performance testing of control devices 
used to demonstrate compliance with the emissions standards for your 
centrifugal compressor affected facility. You must demonstrate that a 
control device achieves the performance requirements of Sec.  
60.5412(a) using the performance test methods and procedures specified 
in this section. For condensers, you may use a design analysis as 
specified in paragraph (c) of this section in lieu of complying with 
paragraph (b) of this section. In addition, this section contains the 
requirements for enclosed combustion device performance tests conducted 
by the manufacturer applicable to both storage vessel and centrifugal 
compressor affected facilities.
    (a) * * *
    (7) A control device whose model can be demonstrated to meet the 
performance requirements of Sec.  60.5412(a) through a performance test 
conducted by the manufacturer, as specified in paragraph (d) of this 
section.
* * * * *
    (d) Performance testing for combustion control devices--
manufacturers' performance test. (1) This paragraph applies to the 
performance testing of a combustion control device conducted by the 
device manufacturer. The manufacturer must demonstrate that a specific 
model of control device achieves the performance requirements in 
paragraph (d)(11) of this section by conducting a performance test as 
specified in paragraphs (d)(2) through (10) of this section. You must 
submit a test report for each combustion control device in accordance 
with the

[[Page 58440]]

requirements in paragraph (d)(12) of this section.
    (2) Performance testing must consist of three one-hour (or longer) 
test runs for each of the four firing rate settings specified in 
paragraphs (d)(2)(i) through (iv) of this section, making a total of 12 
test runs per test. Propene (propylene) gas must be used for the 
testing fuel. All fuel analyses must be performed by an independent 
third-party laboratory (not affiliated with the control device 
manufacturer or fuel supplier).
    (i) 90-100 percent of maximum design rate (fixed rate).
    (ii) 70-100-70 percent (ramp up, ramp down). Begin the test at 70 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 100 percent of the maximum design 
rate. Hold at 100 percent for 5 minutes. In the 10-15 minute time 
range, incrementally ramp back down to 70 percent of the maximum design 
rate. Repeat three more times for a total of 60 minutes of sampling.
    (iii) 30-70-30 percent (ramp up, ramp down). Begin the test at 30 
percent of the maximum design rate. During the first 5 minutes, 
incrementally ramp the firing rate to 70 percent of the maximum design 
rate. Hold at 70 percent for 5 minutes. In the 10-15 minute time range, 
incrementally ramp back down to 30 percent of the maximum design rate. 
Repeat three more times for a total of 60 minutes of sampling.
    (iv) 0-30-0 percent (ramp up, ramp down). Begin the test at the 
minimum firing rate. During the first 5 minutes, incrementally ramp the 
firing rate to 30 percent of the maximum design rate. Hold at 30 
percent for 5 minutes. In the 10-15 minute time range, incrementally 
ramp back down to the minimum firing rate. Repeat three more times for 
a total of 60 minutes of sampling.
    (3) All models employing multiple enclosures must be tested 
simultaneously and with all burners operational. Results must be 
reported for each enclosure individually and for the average of the 
emissions from all interconnected combustion enclosures/chambers. 
Control device operating data must be collected continuously throughout 
the performance test using an electronic Data Acquisition System. A 
graphic presentation or strip chart of the control device operating 
data and emissions test data must be included in the test report in 
accordance with paragraph (d)(12) of this section. Inlet fuel meter 
data may be manually recorded provided that all inlet fuel data 
readings are included in the final report.
    (4) Inlet testing must be conducted as specified in paragraphs 
(d)(4)(i) through (ii) of this section.
    (i) The inlet gas flow metering system must be located in 
accordance with Method 2A, 40 CFR part 60, appendix A-1, (or other 
approved procedure) to measure inlet gas flow rate at the control 
device inlet location. You must position the fitting for filling fuel 
sample containers a minimum of eight pipe diameters upstream of any 
inlet gas flow monitoring meter.
    (ii) Inlet flow rate must be determined using Method 2A, 40 CFR 
part 60, appendix A-1. Record the start and stop reading for each 60-
minute THC test. Record the gas pressure and temperature at 5-minute 
intervals throughout each 60-minute test.
    (5) Inlet gas sampling must be conducted as specified in paragraphs 
(d)(5)(i) through (ii) of this section.
    (i) At the inlet gas sampling location, securely connect a 
Silonite-coated stainless steel evacuated canister fitted with a flow 
controller sufficient to fill the canister over a 3-hour period. 
Filling must be conducted as specified in paragraphs (d)(5)(i)(A) 
through (C) of this section.
    (A) Open the canister sampling valve at the beginning of each test 
run, and close the canister at the end of each test run.
    (B) Fill one canister across the three test runs such that one 
composite fuel sample exists for each test condition.
    (C) Label the canisters individually and record sample information 
on a chain of custody form.
    (ii) Analyze each inlet gas sample using the methods in paragraphs 
(d)(5)(ii)(A) through (C) of this section. You must include the results 
in the test report required by paragraph (d)(12) of this section.
    (A) Hydrocarbon compounds containing between one and five atoms of 
carbon plus benzene using ASTM D1945-03.
    (B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 
(CO2), nitrogen (N2), oxygen (O2) 
using ASTM D1945-03.
    (C) Higher heating value using ASTM D3588-98 or ASTM D4891-89.
    (6) Outlet testing must be conducted in accordance with the 
criteria in paragraphs (d)(6)(i) through (v) of this section.
    (i) Sample and flow rate must be measured in accordance with 
paragraphs (d)(6)(i)(A) through (B) of this section.
    (A) The outlet sampling location must be a minimum of four 
equivalent stack diameters downstream from the highest peak flame or 
any other flow disturbance, and a minimum of one equivalent stack 
diameter upstream of the exit or any other flow disturbance. A minimum 
of two sample ports must be used.
    (B) Flow rate must be measured using Method 1, 40 CFR part 60, 
appendix A-1 for determining flow measurement traverse point location, 
and Method 2, 40 CFR part 60, appendix A-1 for measuring duct velocity. 
If low flow conditions are encountered (i.e., velocity pressure 
differentials less than 0.05 inches of water) during the performance 
test, a more sensitive manometer must be used to obtain an accurate 
flow profile.
    (ii) Molecular weight and excess air must be determined as 
specified in paragraph (d)(7) of this section.
    (iii) Carbon monoxide must be determined as specified in paragraph 
(d)(8) of this section.
    (iv) THC must be determined as specified in paragraph (d)(9) of 
this section.
    (v) Visible emissions must be determined as specified in paragraph 
(d)(10) of this section.
    (7) Molecular weight and excess air determination must be performed 
as specified in paragraphs (d)(7)(i) through (iii) of this section.
    (i) An integrated bag sample must be collected during the Method 4, 
40 CFR part 60, appendix A-3, moisture test following the procedure 
specified in (d)(7)(i)(A) through (B) of this section. Analyze the bag 
sample using a gas chromatograph-thermal conductivity detector (GC-TCD) 
analysis meeting the criteria in paragraphs (d)(7)(i)(C) through (D) of 
this section.
    (A) Collect the integrated sample throughout the entire test, and 
collect representative volumes from each traverse location.
    (B) Purge the sampling line with stack gas before opening the valve 
and beginning to fill the bag. Clearly label each bag and record sample 
information on a chain of custody form.
    (C) The bag contents must be vigorously mixed prior to the gas 
chromatograph analysis.
    (D) The GC-TCD calibration procedure in Method 3C, 40 CFR part 60, 
appendix A, must be modified by using EPA Alt-045 as follows: For the 
initial calibration, triplicate injections of any single concentration 
must agree within 5 percent of their mean to be valid. The calibration 
response factor for a single concentration re-check must be within 10 
percent of the original calibration response factor for that 
concentration. If this criterion is not met, repeat the initial 
calibration using at least three concentration levels.

[[Page 58441]]

    (ii) Calculate and report the molecular weight of oxygen, carbon 
dioxide, methane, and nitrogen in the integrated bag sample and include 
in the test report specified in paragraph (d)(12) of this section. 
Moisture must be determined using Method 4, 40 CFR part 60, appendix A-
3. Traverse both ports with the Method 4, 40 CFR part 60, appendix A-3, 
sampling train during each test run. Ambient air must not be introduced 
into the Method 3C, 40 CFR part 60, appendix A-2, integrated bag sample 
during the port change.
    (iii) Excess air must be determined using resultant data from the 
EPA Method 3C tests and EPA Method 3B, 40 CFR part 60, appendix A, 
equation 3B-1.
    (8) Carbon monoxide must be determined using Method 10, 40 CFR part 
60, appendix A. Run the test simultaneously with Method 25A, 40 CFR 
part 60, appendix A-7 using the same sampling points. An instrument 
range of 0-10 parts per million by volume-dry (ppmvd) is recommended.
    (9) Total hydrocarbon determination must be performed as specified 
by in paragraphs (d)(9)(i) through (vii) of this section.
    (i) Conduct THC sampling using Method 25A, 40 CFR part 60, appendix 
A-7, except that the option for locating the probe in the center 10 
percent of the stack is not allowed. The THC probe must be traversed to 
16.7 percent, 50 percent, and 83.3 percent of the stack diameter during 
each test run.
    (ii) A valid test must consist of three Method 25A, 40 CFR part 60, 
appendix A-7, tests, each no less than 60 minutes in duration.
    (iii) A 0-10 parts per million by volume-wet (ppmvw) (as propane) 
measurement range is preferred; as an alternative a 0-30 ppmvw (as 
carbon) measurement range may be used.
    (iv) Calibration gases must be propane in air and be certified 
through EPA Protocol 1--``EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards,'' September 1997, as 
amended August 25, 1999, EPA-600/R-97/121(or more recent if updated 
since 1999).
    (v) THC measurements must be reported in terms of ppmvw as propane.
    (vi) THC results must be corrected to 3 percent CO2, as 
measured by Method 3C, 40 CFR part 60, appendix A-2. You must use the 
following equation for this diluent concentration correction:
[GRAPHIC] [TIFF OMITTED] TR23SE13.000


Where:

Cmeas = The measured concentration of the pollutant.
CO2meas = The measured concentration of the 
CO2 diluent.
3 = The corrected reference concentration of CO2 diluent.
Ccorr = The corrected concentration of the pollutant.

    (vii) Subtraction of methane or ethane from the THC data is not 
allowed in determining results.
    (10) Visible emissions must be determined using Method 22, 40 CFR 
part 60, appendix A. The test must be performed continuously during 
each test run. A digital color photograph of the exhaust point, taken 
from the position of the observer and annotated with date and time, 
must be taken once per test run and the 12 photos included in the test 
report specified in paragraph (d)(12) of this section.
    (11) Performance test criteria. (i) The control device model tested 
must meet the criteria in paragraphs (d)(11)(i)(A) through (D) of this 
section. These criteria must be reported in the test report required by 
paragraph (d)(12) of this section.
    (A) Method 22, 40 CFR part 60, appendix A, results under paragraph 
(d)(10) of this section with no indication of visible emissions.
    (B) Average Method 25A, 40 CFR part 60, appendix A, results under 
paragraph (d)(9) of this section equal to or less than 10.0 ppmvw THC 
as propane corrected to 3.0 percent CO2.
    (C) Average CO emissions determined under paragraph (d)(8) of this 
section equal to or less than 10 parts ppmvd, corrected to 3.0 percent 
CO2.
    (D) Excess combustion air determined under paragraph (d)(7) of this 
section equal to or greater than 150 percent.
    (ii) The manufacturer must determine a maximum inlet gas flow rate 
which must not be exceeded for each control device model to achieve the 
criteria in paragraph (d)(11)(iii) of this section. The maximum inlet 
gas flow rate must be included in the test report required by paragraph 
(d)(12) of this section.
    (iii) A control device meeting the criteria in paragraph 
(d)(11)(i)(A) through (D) of this section must demonstrate a 
destruction efficiency of 95 percent for VOC regulated under this 
subpart.
    (12) The owner or operator of a combustion control device model 
tested under this paragraph must submit the information listed in 
paragraphs (d)(12)(i) through (vi) in the test report required by this 
section in accordance with Sec.  60.5420(b)(8).
    (i) A full schematic of the control device and dimensions of the 
device components.
    (ii) The maximum net heating value of the device.
    (iii) The test fuel gas flow range (in both mass and volume). 
Include the maximum allowable inlet gas flow rate.
    (iv) The air/stream injection/assist ranges, if used.
    (v) The test conditions listed in paragraphs (d)(12)(v)(A) through 
(O) of this section, as applicable for the tested model.
    (A) Fuel gas delivery pressure and temperature.
    (B) Fuel gas moisture range.
    (C) Purge gas usage range.
    (D) Condensate (liquid fuel) separation range.
    (E) Combustion zone temperature range. This is required for all 
devices that measure this parameter.
    (F) Excess combustion air range.
    (G) Flame arrestor(s).
    (H) Burner manifold.
    (I) Pilot flame indicator.
    (J) Pilot flame design fuel and calculated or measured fuel usage.
    (K) Tip velocity range.
    (L) Momentum flux ratio.
    (M) Exit temperature range.
    (N) Exit flow rate.
    (O) Wind velocity and direction.
    (vi) The test report must include all calibration quality 
assurance/quality control data, calibration gas values, gas cylinder 
certification, strip charts, or other graphic presentations of the data 
annotated with test times and calibration values.
    (e) Continuous compliance for combustion control devices tested by 
the manufacturer in accordance with paragraph (d) of this section. This 
paragraph applies to the demonstration of compliance for a combustion 
control device tested under the provisions in paragraph (d) of this 
section. Owners or operators must demonstrate that a control device 
achieves the performance requirements in (d)(11) of this section by 
installing a device tested under paragraph (d) of this section and 
complying with the criteria specified in paragraphs (e)(1) through (6) 
of this section.
    (1) The inlet gas flow rate must be equal to or less than the 
maximum specified by the manufacturer.
    (2) A pilot flame must be present at all times of operation.
    (3) Devices must be operated with no visible emissions, except for 
periods not to exceed a total of 2 minutes during any hour. A visible 
emissions test using Method 22, 40 CFR part 60, appendix A, must be 
performed each calendar quarter. The observation period must be 1 hour 
and must be conducted according to EPA Method 22, 40 CFR part 60, 
appendix A.

[[Page 58442]]

    (4) Devices failing the visible emissions test must follow 
manufacturer's repair instructions, if available, or best combustion 
engineering practice as outlined in the unit inspection and maintenance 
plan, to return the unit to compliant operation. All repairs and 
maintenance activities for each unit must be recorded in a maintenance 
and repair log and must be available for inspection.
    (5) Following return to operation from maintenance or repair 
activity, each device must pass an EPA Method 22, 40 CFR part 60, 
appendix A, visual observation as described in paragraph (e)(3) of this 
section.
    (6) If the owner or operator operates a combustion control device 
model tested under this section, an electronic copy of the performance 
test results required by this section shall be submitted via email to 
Oil_and_Gas_PT@EPA.GOV unless the test results for that model of 
combustion control device are posted at the following Web site: 
epa.gov/airquality/oilandgas/.

0
10. Section 60.5415 is amended by:
0
a. Revising paragraphs (b) introductory text and (b)(2);
0
b. Revising paragraph (e) introductory text;
0
c. Removing and reserving paragraphs (e)(1) and (2);
0
d. Adding paragraph (e)(3); and
0
e. Revising paragraph (h)(1) introductory text.
    The revisions and addition read as follows:


Sec.  60.5415  How do I demonstrate continuous compliance with the 
standards for my gas well affected facility, my centrifugal compressor 
affected facility, my stationary reciprocating compressor affected 
facility, my pneumatic controller affected facility, my storage vessel 
affected facility, and my affected facilities at onshore natural gas 
processing plants?

* * * * *
    (b) For each centrifugal compressor affected facility, you must 
demonstrate continuous compliance according to paragraphs (b)(1) 
through (3) of this section.
* * * * *
    (2) For each control device used to reduce emissions, you must 
demonstrate continuous compliance with the performance requirements of 
Sec.  60.5412(a) using the procedures specified in paragraphs (b)(2)(i) 
through (vii) of this section. If you use a condenser as the control 
device to achieve the requirements specified in Sec.  60.5412(a)(2), 
you must demonstrate compliance according to paragraph (b)(2)(viii) of 
this section. You may switch between compliance with paragraphs 
(b)(2)(i) through (vii) of this section and compliance with paragraph 
(b)(2)(viii) of this section only after at least 1 year of operation in 
compliance with the selected approach. You must provide notification of 
such a change in the compliance method in the next annual report, as 
required in Sec.  60.5420(b), following the change.
    (i) You must operate below (or above) the site specific maximum (or 
minimum) parameter value established according to the requirements of 
Sec.  60.5417(f)(1).
    (ii) You must calculate the daily average of the applicable 
monitored parameter in accordance with Sec.  60.5417(e) except that the 
inlet gas flow rate to the control device must not be averaged.
    (iii) Compliance with the operating parameter limit is achieved 
when the daily average of the monitoring parameter value calculated 
under paragraph (b)(2)(ii) of this section is either equal to or 
greater than the minimum monitoring value or equal to or less than the 
maximum monitoring value established under paragraph (b)(2)(i) of this 
section. When performance testing of a combustion control device is 
conducted by the device manufacturer as specified in Sec.  60.5413(d), 
compliance with the operating parameter limit is achieved when the 
criteria in Sec.  60.5413(e) are met.
    (iv) You must operate the continuous monitoring system required in 
Sec.  60.5417 at all times the affected source is operating, except for 
periods of monitoring system malfunctions, repairs associated with 
monitoring system malfunctions, and required monitoring system quality 
assurance or quality control activities (including, as applicable, 
system accuracy audits and required zero and span adjustments). A 
monitoring system malfunction is any sudden, infrequent, not reasonably 
preventable failure of the monitoring system to provide valid data. 
Monitoring system failures that are caused in part by poor maintenance 
or careless operation are not malfunctions. You are required to 
complete monitoring system repairs in response to monitoring system 
malfunctions and to return the monitoring system to operation as 
expeditiously as practicable.
    (v) You may not use data recorded during monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
or required monitoring system quality assurance or control activities 
in calculations used to report emissions or operating levels. You must 
use all the data collected during all other required data collection 
periods to assess the operation of the control device and associated 
control system.
    (vi) Failure to collect required data is a deviation of the 
monitoring requirements, except for periods of monitoring system 
malfunctions, repairs associated with monitoring system malfunctions, 
and required quality monitoring system quality assurance or quality 
control activities (including, as applicable, system accuracy audits 
and required zero and span adjustments).
    (vii) If you use a combustion control device to meet the 
requirements of Sec.  60.5412(a) and you demonstrate compliance using 
the test procedures specified in Sec.  60.5413(b), you must comply with 
paragraphs (b)(2)(vii)(A) through (D) of this section.
    (A) A pilot flame must be present at all times of operation.
    (B) Devices must be operated with no visible emissions, except for 
periods not to exceed a total of 2 minutes during any hour. A visible 
emissions test using section 11. of Method 22, 40 CFR part 60, appendix 
A, must be performed each calendar quarter. The observation period must 
be 1 hour and must be conducted according to section 11. of EPA Method 
22, 40 CFR part 60, appendix A.
    (C) Devices failing the visible emissions test must follow 
manufacturer's repair instructions, if available, or best combustion 
engineering practice as outlined in the unit inspection and maintenance 
plan, to return the unit to compliant operation. All repairs and 
maintenance activities for each unit must be recorded in a maintenance 
and repair log and must be available for inspection.
    (D) Following return to operation from maintenance or repair 
activity, each device must pass a Method 22, 40 CFR part 60, appendix 
A, visual observation as described in paragraph (b)(2)(vii)(B) of this 
section.
    (viii) If you use a condenser as the control device to achieve the 
percent reduction performance requirements specified in Sec.  
60.5412(a)(2), you must demonstrate compliance using the procedures in 
paragraphs (b)(2)(viii)(A) through (E) of this section.
    (A) You must establish a site-specific condenser performance curve 
according to Sec.  60.5417(f)(2).
    (B) You must calculate the daily average condenser outlet 
temperature in accordance with Sec.  60.5417(e).
    (C) You must determine the condenser efficiency for the current 
operating day using the daily average condenser outlet temperature 
calculated under paragraph (b)(2)(viii)(B) of this

[[Page 58443]]

section and the condenser performance curve established under paragraph 
(b)(2)(viii)(A) of this section.
    (D) Except as provided in paragraphs (b)(2)(viii)(D)(1) and (2) of 
this section, at the end of each operating day, you must calculate the 
365-day rolling average TOC emission reduction, as appropriate, from 
the condenser efficiencies as determined in paragraph (b)(2)(viii)(C) 
of this section.
    (1) After the compliance dates specified in Sec.  60.5370, if you 
have less than 120 days of data for determining average TOC emission 
reduction, you must calculate the average TOC emission reduction for 
the first 120 days of operation after the compliance dates. You have 
demonstrated compliance with the overall 95.0 percent reduction 
requirement if the 120-day average TOC emission reduction is equal to 
or greater than 95.0 percent.
    (2) After 120 days and no more than 364 days of operation after the 
compliance date specified in Sec.  60.5370, you must calculate the 
average TOC emission reduction as the TOC emission reduction averaged 
over the number of days between the current day and the applicable 
compliance date. You have demonstrated compliance with the overall 95.0 
percent reduction requirement, if the average TOC emission reduction is 
equal to or greater than 95.0 percent.
    (E) If you have data for 365 days or more of operation, you have 
demonstrated compliance with the TOC emission reduction if the rolling 
365-day average TOC emission reduction calculated in paragraph 
(b)(2)(viii)(D) of this section is equal to or greater than 95.0 
percent.
* * * * *
    (e) You must demonstrate continuous compliance according to 
paragraph (e)(3) of this section for each storage vessel affected 
facility, for which you are using a control device or routing emissions 
to a process to meet the requirement of Sec.  60.5395(d)(1).
    (1) [Reserved]
    (2) [Reserved]
    (3) For each storage vessel affected facility, you must comply with 
paragraphs (e)(3)(i) and (ii) of this section.
    (i) You must reduce VOC emissions as specified in Sec.  60.5395(d).
    (ii) For each control device installed to meet the requirements of 
Sec.  60.5395(d), you must demonstrate continuous compliance with the 
performance requirements of Sec.  60.5412(d) for each storage vessel 
affected facility using the procedure specified in paragraph 
(e)(3)(ii)(A) and either (e)(3)(ii)(B) or (e)(3)(ii)(C) of this 
section.
    (A) You must comply with Sec.  60.5416(c) for each cover and closed 
vent system.
    (B) You must comply with Sec.  60.5417(h) for each control device.
    (C) Each closed vent system that routes emissions to a process must 
be operated as specified in Sec.  60.5411(c)(2).
* * * * *
    (h) * * *
    (1) To establish the affirmative defense in any action to enforce 
such a standard, you must timely meet the reporting requirements in 
Sec.  60.5415(h)(2), and must prove by a preponderance of evidence 
that:
* * * * *

0
11. Section 60.5416 is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraphs (a) introductory text, (a)(1)(ii), (a)(2)(iii), 
and (a)(3)(ii);
0
c. Revising paragraphs (b) introductory text, (b)(9) introductory text, 
and (b)(11); and
0
d. Adding paragraph (c).
    The revisions and addition read as follows:


Sec.  60.5416  What are the initial and continuous cover and closed 
vent system inspection and monitoring requirements for my storage 
vessel and centrifugal compressor affected facility?

    For each closed vent system or cover at your storage vessel or 
centrifugal compressor affected facility, you must comply with the 
applicable requirements of paragraphs (a) through (c) of this section.
    (a) Inspections for closed vent systems and covers installed on 
each centrifugal compressor affected facility. Except as provided in 
paragraphs (b)(11) and (12) of this section, you must inspect each 
closed vent system according to the procedures and schedule specified 
in paragraphs (a)(1) and (2) of this section, inspect each cover 
according to the procedures and schedule specified in paragraph (a)(3) 
of this section, and inspect each bypass device according to the 
procedures of paragraph (a)(4) of this section.
    (1) * * *
    (ii) Conduct annual visual inspections for defects that could 
result in air emissions. Defects include, but are not limited to, 
visible cracks, holes, or gaps in piping; loose connections; liquid 
leaks; or broken or missing caps or other closure devices. You must 
monitor a component or connection using the test methods and procedures 
in paragraph (b) of this section to demonstrate that it operates with 
no detectable emissions following any time the component is repaired or 
replaced or the connection is unsealed. You must maintain records of 
the inspection results as specified in Sec.  60.5420(c)(6).
    (2) * * *
    (iii) Conduct annual visual inspections for defects that could 
result in air emissions. Defects include, but are not limited to, 
visible cracks, holes, or gaps in ductwork; loose connections; liquid 
leaks; or broken or missing caps or other closure devices. You must 
maintain records of the inspection results as specified in Sec.  
60.5420(c)(6).
    (3) * * *
    (ii) You must initially conduct the inspections specified in 
paragraph (a)(3)(i) of this section following the installation of the 
cover. Thereafter, you must perform the inspection at least once every 
calendar year, except as provided in paragraphs (b)(11) and (12) of 
this section. You must maintain records of the inspection results as 
specified in Sec.  60.5420(c)(7).
* * * * *
    (b) No detectable emissions test methods and procedures. If you are 
required to conduct an inspection of a closed vent system or cover at 
your centrifugal compressor affected facility as specified in 
paragraphs (a)(1), (2), or (3) of this section, you must meet the 
requirements of paragraphs (b)(1) through (13) of this section.
* * * * *
    (9) Repairs. In the event that a leak or defect is detected, you 
must repair the leak or defect as soon as practicable according to the 
requirements of paragraphs (b)(9)(i) and (ii) of this section, except 
as provided in paragraph (b)(10) of this section.
* * * * *
    (11) Unsafe to inspect requirements. You may designate any parts of 
the closed vent system or cover as unsafe to inspect if the 
requirements in paragraphs (b)(11)(i) and (ii) of this section are met. 
Unsafe to inspect parts are exempt from the inspection requirements of 
paragraphs (a)(1) through (3) of this section.
    (i) You determine that the equipment is unsafe to inspect because 
inspecting personnel would be exposed to an imminent or potential 
danger as a consequence of complying with paragraphs (a)(1), (2), or 
(3) of this section.
    (ii) You have a written plan that requires inspection of the 
equipment as frequently as practicable during safe-to-inspect times.
* * * * *
    (c) Cover and closed vent system inspections for storage vessel 
affected facilities. If you install a control device

[[Page 58444]]

or route emissions to a process, you must inspect each closed vent 
system according to the procedures and schedule specified in paragraphs 
(c)(1) of this section, inspect each cover according to the procedures 
and schedule specified in paragraph (c)(2) of this section, and inspect 
each bypass device according to the procedures of paragraph (c)(3) of 
this section. You must also comply with the requirements of (c)(4) 
through (7) of this section.
    (1) For each closed vent system, you must conduct an inspection at 
least once every calendar month as specified in paragraphs (c)(1)(i) 
through (iii) of this section.
    (i) You must maintain records of the inspection results as 
specified in Sec.  60.5420(c)(6).
    (ii) Conduct olfactory, visual and auditory inspections for defects 
that could result in air emissions. Defects include, but are not 
limited to, visible cracks, holes, or gaps in piping; loose 
connections; liquid leaks; or broken or missing caps or other closure 
devices.
    (iii) Monthly inspections must be separated by at least 14 calendar 
days.
    (2) For each cover, you must conduct inspections at least once 
every calendar month as specified in paragraphs (c)(2)(i) through (iii) 
of this section.
    (i) You must maintain records of the inspection results as 
specified in Sec.  60.5420(c)(7).
    (ii) Conduct olfactory, visual and auditory inspections for defects 
that could result in air emissions. Defects include, but are not 
limited to, visible cracks, holes, or gaps in the cover, or between the 
cover and the separator wall; broken, cracked, or otherwise damaged 
seals or gaskets on closure devices; and broken or missing hatches, 
access covers, caps, or other closure devices. In the case where the 
storage vessel is buried partially or entirely underground, you must 
inspect only those portions of the cover that extend to or above the 
ground surface, and those connections that are on such portions of the 
cover (e.g., fill ports, access hatches, gauge wells, etc.) and can be 
opened to the atmosphere.
    (iii) Monthly inspections must be separated by at least 14 calendar 
days.
    (3) For each bypass device, except as provided for in Sec.  
60.5411(c)(3)(ii), you must meet the requirements of paragraphs 
(c)(3)(i) or (ii) of this section.
    (i) Set the flow indicator to sound an alarm at the inlet to the 
bypass device when the stream is being diverted away from the control 
device or process to the atmosphere. You must maintain records of each 
time the alarm is sounded according to Sec.  60.5420(c)(8).
    (ii) If the bypass device valve installed at the inlet to the 
bypass device is secured in the non-diverting position using a car-seal 
or a lock-and-key type configuration, visually inspect the seal or 
closure mechanism at least once every month to verify that the valve is 
maintained in the non-diverting position and the vent stream is not 
diverted through the bypass device. You must maintain records of the 
inspections and records of each time the key is checked out, if 
applicable, according to Sec.  60.5420(c)(8).
    (4) Repairs. In the event that a leak or defect is detected, you 
must repair the leak or defect as soon as practicable according to the 
requirements of paragraphs (c)(4)(i) through (iii) of this section, 
except as provided in paragraph (c)(5) of this section.
    (i) A first attempt at repair must be made no later than 5 calendar 
days after the leak is detected.
    (ii) Repair must be completed no later than 30 calendar days after 
the leak is detected.
    (iii) Grease or another applicable substance must be applied to 
deteriorating or cracked gaskets to improve the seal while awaiting 
repair.
    (5) Delay of repair. Delay of repair of a closed vent system or 
cover for which leaks or defects have been detected is allowed if the 
repair is technically infeasible without a shutdown, or if you 
determine that emissions resulting from immediate repair would be 
greater than the fugitive emissions likely to result from delay of 
repair. You must complete repair of such equipment by the end of the 
next shutdown.
    (6) Unsafe to inspect requirements. You may designate any parts of 
the closed vent system or cover as unsafe to inspect if the 
requirements in paragraphs (c)(6)(i) and (ii) of this section are met. 
Unsafe to inspect parts are exempt from the inspection requirements of 
paragraphs (c)(1) and (2) of this section.
    (i) You determine that the equipment is unsafe to inspect because 
inspecting personnel would be exposed to an imminent or potential 
danger as a consequence of complying with paragraphs (c)(1) or (2) of 
this section.
    (ii) You have a written plan that requires inspection of the 
equipment as frequently as practicable during safe-to-inspect times.
    (7) Difficult to inspect requirements. You may designate any parts 
of the closed vent system or cover as difficult to inspect, if the 
requirements in paragraphs (c)(7)(i) and (ii) of this section are met. 
Difficult to inspect parts are exempt from the inspection requirements 
of paragraphs (c)(1) and (2) of this section.
    (i) You determine that the equipment cannot be inspected without 
elevating the inspecting personnel more than 2 meters above a support 
surface.
    (ii) You have a written plan that requires inspection of the 
equipment at least once every 5 years.

0
12. Section 60.5417 is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraph (b) introductory text;
0
c. Revising paragraph (c) introductory text;
0
d. Revising paragraphs (d)(1)(viii)(A) and (B);
0
e. Revising paragraph (d)(2);
0
f. Revising paragraph (f)(1)(iii);
0
g. Revising paragraph (g)(6)(ii); and
0
h. Adding paragraph (h).
    The revisions and addition read as follows:


Sec.  60.5417  What are the continuous control device monitoring 
requirements for my storage vessel or centrifugal compressor affected 
facility?

* * * * *
    (a) For each control device used to comply with the emission 
reduction standard for centrifugal compressor affected facilities in 
Sec.  60.5380, you must install and operate a continuous parameter 
monitoring system for each control device as specified in paragraphs 
(c) through (g) of this section, except as provided for in paragraph 
(b) of this section. If you install and operate a flare in accordance 
with Sec.  60.5412(a)(3), you are exempt from the requirements of 
paragraphs (e) and (f) of this section.
    (b) You are exempt from the monitoring requirements specified in 
paragraphs (c) through (g) of this section for the control devices 
listed in paragraphs (b)(1) and (2) of this section.
* * * * *
    (c) If you are required to install a continuous parameter 
monitoring system, you must meet the specifications and requirements in 
paragraphs (c)(1) through (4) of this section.
* * * * *
    (d) * * *
    (1) * * *
    (viii) * * *
    (A) The continuous monitoring system must measure gas flow rate at 
the inlet to the control device. The monitoring instrument must have an 
accuracy of 2 percent or better. The flow rate at the inlet 
to the combustion device must not exceed the maximum or minimum flow 
rate determined by the manufacturer.
    (B) A monitoring device that continuously indicates the presence of

[[Page 58445]]

the pilot flame while emissions are routed to the control device.
    (2) An organic monitoring device equipped with a continuous 
recorder that measures the concentration level of organic compounds in 
the exhaust vent stream from the control device. The monitor must meet 
the requirements of Performance Specification 8 or 9 of 40 CFR part 60, 
appendix B. You must install, calibrate, and maintain the monitor 
according to the manufacturer's specifications.
* * * * *
    (f) * * *
    (1) * * *
    (iii) If you operate a control device where the performance test 
requirement was met under Sec.  60.5413(d) to demonstrate that the 
control device achieves the applicable performance requirements 
specified in Sec.  60.5412(a), then your control device inlet gas flow 
rate must not exceed the maximum or minimum inlet gas flow rate 
determined by the manufacturer.
* * * * *
    (g) * * *
    (6) * * *
    (ii) Failure of the quarterly visible emissions test conducted 
under Sec.  60.5413(e)(3) occurs.
    (h) For each control device used to comply with the emission 
reduction standard in Sec.  60.5395(d)(1) for your storage vessel 
affected facility, you must demonstrate continuous compliance according 
to paragraphs (h)(1) through (h)(3) of this section. You are exempt 
from the requirements of this paragraph if you install a control device 
model tested in accordance with Sec.  60.5413(d)(2) through (10), which 
meets the criteria in Sec.  60.5413(d)(11), the reporting requirement 
in Sec.  60.5413(d)(12), and meet the continuous compliance requirement 
in Sec.  60.5413(e).
    (1) For each combustion device you must conduct inspections at 
least once every calendar month according to paragraphs (h)(1)(i) 
through (iv) of this section. Monthly inspections must be separated by 
at least 14 calendar days.
    (i) Conduct visual inspections to confirm that the pilot is lit 
when vapors are being routed to the combustion device and that the 
continuous burning pilot flame is operating properly.
    (ii) Conduct inspections to monitor for visible emissions from the 
combustion device using section 11 of EPA Method 22, 40 CFR part 60, 
appendix A. The observation period shall be 15 minutes. Devices must be 
operated with no visible emissions, except for periods not to exceed a 
total of 1 minute during any 15 minute period.
    (iii) Conduct olfactory, visual and auditory inspections of all 
equipment associated with the combustion device to ensure system 
integrity.
    (iv) For any absence of pilot flame, or other indication of smoking 
or improper equipment operation (e.g., visual, audible, or olfactory), 
you must ensure the equipment is returned to proper operation as soon 
as practicable after the event occurs. At a minimum, you must perform 
the procedures specified in paragraphs (h)(1)(iv)(A) and (B) of this 
section.
    (A) You must check the air vent for obstruction. If an obstruction 
is observed, you must clear the obstruction as soon as practicable.
    (B) You must check for liquid reaching the combustor.
    (2) For each vapor recovery device, you must conduct inspections at 
least once every calendar month to ensure physical integrity of the 
control device according to the manufacturer's instructions. Monthly 
inspections must be separated by at least 14 calendar days.
    (3) Each control device must be operated following the 
manufacturer's written operating instructions, procedures and 
maintenance schedule to ensure good air pollution control practices for 
minimizing emissions. Records of the manufacturer's written operating 
instructions, procedures, and maintenance schedule must be available 
for inspection as specified in Sec.  60.5420(c)(13).

0
13. Section 60.5420 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(1);
0
c. Revising paragraph (b) introductory text;
0
d. Revising paragraph (b)(3)(iii);
0
e. Revising paragraph (b)(4)(i);
0
f. Revising paragraph (b)(5) introductory text;
0
g. Revising paragraph (b)(5)(i);
0
h. Revising paragraph (b)(6) introductory text;
0
i. Revising paragraphs (b)(6)(i) and (ii);
0
j. Adding paragraphs (b)(6)(iv) through (vii);
0
k. Revising paragraph (b)(7);
0
l. Adding paragraph (b)(8);
0
m. Revising paragraph (c) introductory text;
0
n. Revising paragraph (c)(1)(v);
0
o. Revising paragraph (c)(4)(ii);
0
p. Revising paragraph (c)(5);
0
q. Revising paragraphs (c)(6) through (11); and
0
r. Adding paragraphs (c)(12) and (13).
    The revisions and additions read as follows:


Sec.  60.5420  What are my notification, reporting, and recordkeeping 
requirements?

    (a) You must submit the notifications according to paragraphs 
(a)(1) and (2) of this section if you own or operate one or more of the 
affected facilities specified in Sec.  60.5365 that was constructed, 
modified, or reconstructed during the reporting period.
    (1) If you own or operate a gas well, pneumatic controller, 
centrifugal compressor, reciprocating compressor or storage vessel 
affected facility you are not required to submit the notifications 
required in Sec.  60.7(a)(1), (3), and (4).
* * * * *
    (b) Reporting requirements. You must submit annual reports 
containing the information specified in paragraphs (b)(1) through (6) 
of this section to the Administrator and performance test reports as 
specified in paragraph (b)(7) or (8) of this section. The initial 
annual report is due no later than 90 days after the end of the initial 
compliance period as determined according to Sec.  60.5410. Subsequent 
annual reports are due no later than same date each year as the initial 
annual report. If you own or operate more than one affected facility, 
you may submit one report for multiple affected facilities provided the 
report contains all of the information required as specified in 
paragraphs (b)(1) through (6) of this section. Annual reports may 
coincide with title V reports as long as all the required elements of 
the annual report are included. You may arrange with the Administrator 
a common schedule on which reports required by this part may be 
submitted as long as the schedule does not extend the reporting period.
* * * * *
    (3) * * *
    (iii) If required to comply with Sec.  60.5380(a)(1), the records 
specified in paragraphs (c)(6) through (11) of this section.
    (4) * * *
    (i) The cumulative number of hours of operation or the number of 
months since initial startup, since October 15, 2012, or since the 
previous reciprocating compressor rod packing replacement, whichever is 
later.
* * * * *
    (5) For each pneumatic controller affected facility, the 
information specified in paragraphs (b)(5)(i) through (iii) of this 
section.
    (i) An identification of each pneumatic controller constructed, 
modified or reconstructed during the reporting period, including the

[[Page 58446]]

identification information specified in Sec.  60.5390(b)(2) or (c)(2).
* * * * *
    (6) For each storage vessel affected facility, the information in 
paragraphs (b)(6)(i) through (vii) of this section.
    (i) An identification, including the location, of each storage 
vessel affected facility for which construction, modification or 
reconstruction commenced during the reporting period. The location of 
the storage vessel shall be in latitude and longitude coordinates in 
decimal degrees to an accuracy and precision of five (5) decimals of a 
degree using the North American Datum of 1983.
    (ii) Documentation of the VOC emission rate determination according 
to Sec.  60.5365(e).
* * * * *
    (iv) You must submit a notification identifying each Group 1 
storage vessel affected facility in your initial annual report. You 
must include the location of the storage vessel, in latitude and 
longitude coordinates in decimal degrees to an accuracy and precision 
of five (5) decimals of a degree using the North American Datum of 
1983.
    (v) A statement that you have met the requirements specified in 
Sec.  60.5410(h)(2) and (3).
    (vi) You must identify each storage vessel affected facility that 
is removed from service during the reporting period as specified in 
Sec.  60.5395(f)(1).
    (vii) You must identify each storage vessel affected facility for 
which operation resumes during the reporting period as specified in 
Sec.  60.5395(f)(2)(iii).
    (7)(i) Within 60 days after the date of completing each performance 
test (see Sec.  60.8 of this part) as required by this subpart, except 
testing conducted by the manufacturer as specified in Sec.  60.5413(d), 
you must submit the results of the performance tests required by this 
subpart to the EPA as follows. You must use the latest version of the 
EPA's Electronic Reporting Tool (ERT) (see https://www.epa.gov/ttn/chief/ert/) existing at the time of the performance test to 
generate a submission package file, which documents the performance 
test. You must then submit the file generated by the ERT through the 
EPA's Compliance and Emissions Data Reporting Interface (CEDRI), which 
can be accessed by logging in to the EPA's Central Data Exchange (CDX) 
(https://cdx.epa.gov/). Only data collected using test methods 
supported by the ERT as listed on the ERT Web site are subject to this 
requirement for submitting reports electronically. Owners or operators 
who claim that some of the information being submitted for performance 
tests is confidential business information (CBI) must submit a complete 
ERT file including information claimed to be CBI on a compact disk or 
other commonly used electronic storage media (including, but not 
limited to, flash drives) to EPA. The electronic media must be clearly 
marked as CBI and mailed to U.S. EPA/OAPQS/CORE CBI Office, Attention: 
WebFIRE Administrator, MD C404-02, 4930 Old Page Rd., Durham, NC 27703. 
The same ERT file with the CBI omitted must be submitted to EPA via CDX 
as described earlier in this paragraph. At the discretion of the 
delegated authority, you must also submit these reports, including the 
confidential business information, to the delegated authority in the 
format specified by the delegated authority. For any performance test 
conducted using test methods that are not listed on the ERT Web site, 
the owner or operator shall submit the results of the performance test 
to the Administrator at the appropriate address listed in Sec.  60.4.
    (ii) All reports, except as specified in paragraph (b)(8) of this 
section, required by this subpart not subject to the requirements in 
paragraph (a)(2)(i) of this section must be sent to the Administrator 
at the appropriate address listed in Sec.  60.4 of this part. The 
Administrator or the delegated authority may request a report in any 
form suitable for the specific case (e.g., by commonly used electronic 
media such as Excel spreadsheet, on CD or hard copy).
    (8) For enclosed combustors tested by the manufacturer in 
accordance with Sec.  60.5413(d), an electronic copy of the performance 
test results required by Sec.  60.5413(d) shall be submitted via email 
to Oil_and_Gas_PT@EPA.GOV unless the test results for that model of 
combustion control device are posted at the following Web site: 
epa.gov/airquality/oilandgas/.
    (c) Recordkeeping requirements. You must maintain the records 
identified as specified in Sec.  60.7(f) and in paragraphs (c)(1) 
through (13) of this section. All records required by this subpart must 
be maintained either onsite or at the nearest local field office for at 
least 5 years.
    (1) * * *
    (v) For each gas well affected facility required to comply with 
both Sec.  60.5375(a)(1) and (3), if you are using a digital photograph 
in lieu of the records required in paragraphs (c)(1)(i) through (iv) of 
this section, you must retain the records of the digital photograph as 
specified in Sec.  60.5410(a)(4).
* * * * *
    (4) * * *
    (ii) Records of the demonstration that the use of pneumatic 
controller affected facilities with a natural gas bleed rate greater 
than the applicable standard are required and the reasons why.
* * * * *
    (5) Except as specified in paragraph (c)(5)(v) of this section, for 
each storage vessel affected facility, you must maintain the records 
identified in paragraphs (c)(5)(i) through (iv) of this section.
    (i) If required to reduce emissions by complying with Sec.  
60.5395(d)(1), the records specified in Sec. Sec.  60.5420(c)(6) 
through (8), Sec.  60.5416(c)(6)(ii), and Sec.  60.6516(c)(7)(ii) of 
this subpart.
    (ii) Records of each VOC emissions determination for each storage 
vessel affected facility made under Sec.  60.5365(e) including 
identification of the model or calculation methodology used to 
calculate the VOC emission rate.
    (iii) Records of deviations in cases where the storage vessel was 
not operated in compliance with the requirements specified in 
Sec. Sec.  60.5395, 60.5411, 60.5412, and 60.5413, as applicable.
    (iv) For storage vessels that are skid-mounted or permanently 
attached to something that is mobile (such as trucks, railcars, barges 
or ships), records indicating the number of consecutive days that the 
vessel is located at a site in the oil and natural gas production 
segment, natural gas processing segment or natural gas transmission and 
storage segment. If a storage vessel is removed from a site and, within 
30 days, is either returned to or replaced by another storage vessel at 
the site to serve the same or similar function, then the entire period 
since the original storage vessel was first located at the site, 
including the days when the storage vessel was removed, will be added 
to the count towards the number of consecutive days.
    (v) You must maintain records of the identification and location of 
each storage vessel affected facility.
    (6) Records of each closed vent system inspection required under 
Sec.  60.5416(a)(1) for centrifugal compressors or Sec.  60.5416(c)(1) 
for storage vessels.
    (7) A record of each cover inspection required under Sec.  
60.5416(a)(3) for centrifugal compressors or Sec.  60.5416(c)(2) for 
storage vessels.
    (8) If you are subject to the bypass requirements of Sec.  
60.5416(a)(4) for centrifugal compressors or

[[Page 58447]]

Sec.  60.5416(c)(3) for storage vessels, a record of each inspection or 
a record each time the key is checked out or a record of each time the 
alarm is sounded.
    (9) If you are subject to the closed vent system no detectable 
emissions requirements of Sec.  60.5416(b) for centrifugal compressors, 
a record of the monitoring conducted in accordance with Sec.  
60.5416(b).
    (10) For each centrifugal compressor affected facility, records of 
the schedule for carbon replacement (as determined by the design 
analysis requirements of Sec.  60.5413(c)(2) or (3)) and records of 
each carbon replacement as specified in Sec.  60.5412(c)(1).
    (11) For each centrifugal compressor subject to the control device 
requirements of Sec.  60.5412(a), (b), and (c), records of minimum and 
maximum operating parameter values, continuous parameter monitoring 
system data, calculated averages of continuous parameter monitoring 
system data, results of all compliance calculations, and results of all 
inspections.
    (12) For each carbon adsorber installed on storage vessel affected 
facilities, records of the schedule for carbon replacement (as 
determined by the design analysis requirements of Sec.  60.5412(d)(2)) 
and records of each carbon replacement as specified in Sec.  
60.5412(c)(1).
    (13) For each storage vessel affected facility subject to the 
control device requirements of Sec.  60.5412(c) and (d), you must 
maintain records of the inspections, including any corrective actions 
taken, the manufacturers' operating instructions, procedures and 
maintenance schedule as specified in Sec.  60.5417(h). You must 
maintain records of EPA Method 22, 40 CFR part 60, appendix A, section 
11 results, which include: company, location, company representative 
(name of the person performing the observation), sky conditions, 
process unit (type of control device), clock start time, observation 
period duration (in minutes and seconds), accumulated emission time (in 
minutes and seconds), and clock end time. You may create your own form 
including the above information or use Figure 22-1 in EPA Method 22, 40 
CFR part 60, appendix A. Manufacturer's operating instructions, 
procedures and maintenance schedule must be available for inspection.

0
14. Section 60.5430 is amended by:
0
a. Adding, in alphabetical order, definitions for the terms 
``Condensate,'' ``Group 1 storage vessel,'' ``Group 2 storage vessel,'' 
``Intermediate hydrocarbon liquid'' and ``Produced water;'' and
0
b. Revising the definitions for ``Flow line'' and ``Storage vessel'' to 
read as follows:


Sec.  60.5430  What definitions apply to this subpart?

* * * * *
    Condensate means hydrocarbon liquid separated from natural gas that 
condenses due to changes in the temperature, pressure, or both, and 
remains liquid at standard conditions.
* * * * *
    Flow line means a pipeline used to transport oil and/or gas to a 
processing facility, a mainline pipeline, re-injection, or routed to a 
process or other useful purpose.
* * * * *
    Group 1 storage vessel means a storage vessel, as defined in this 
section, for which construction, modification or reconstruction has 
commenced after August 23, 2011, and on or before April 12, 2013.
    Group 2 storage vessel means a storage vessel, as defined in this 
section, for which construction, modification or reconstruction has 
commenced after April 12, 2013.
* * * * *
    Intermediate hydrocarbon liquid means any naturally occurring, 
unrefined petroleum liquid.
* * * * *
    Produced water means water that is extracted from the earth from an 
oil or natural gas production well, or that is separated from crude 
oil, condensate, or natural gas after extraction.
* * * * *
    Storage vessel means a tank or other vessel that contains an 
accumulation of crude oil, condensate, intermediate hydrocarbon 
liquids, or produced water, and that is constructed primarily of 
nonearthen materials (such as wood, concrete, steel, fiberglass, or 
plastic) which provide structural support. For the purposes of this 
subpart, the following are not considered storage vessels:
    (1) Vessels that are skid-mounted or permanently attached to 
something that is mobile (such as trucks, railcars, barges or ships), 
and are intended to be located at a site for less than 180 consecutive 
days. If you do not keep or are not able to produce records, as 
required by Sec.  60.5420(c)(5)(iv), showing that the vessel has been 
located at a site for less than 180 consecutive days, the vessel 
described herein is considered to be a storage vessel since the 
original vessel was first located at the site.
    (2) Process vessels such as surge control vessels, bottoms 
receivers or knockout vessels.
    (3) Pressure vessels designed to operate in excess of 204.9 
kilopascals and without emissions to the atmosphere.
* * * * *

0
15. Tables 1 and 2 to Subpart OOOO of part 60 are revised to read as 
follows:

       Table 1 to Subpart OOOO of Part 60--Required Minimum Initial SO2 Emission Reduction Efficiency (Zi)
----------------------------------------------------------------------------------------------------------------
                                                               Sulfur feed rate (X), LT/D
    H2S content of acid gas (Y), %    --------------------------------------------------------------------------
                                         2.0<=X<=5.0          5.0300.0
----------------------------------------------------------------------------------------------------------------
Y>=50................................            79.0    88.51X\0.0101\Y\0.0125\ or 99.9, whichever is smaller.
                                                      ----------------------------------------------------------
20<=Y<50.............................            79.0  88.51X0.0101Y0.0125 or 97.9, whichever is            97.9
                                                                         smaller
                                                      -------------------------------------------
10<=Y<20.............................            79.0  88.51X0.0101Y0.0125 or               93.5            93.5
                                                        93.5, whichever is
                                                        smaller.
Y<10.................................            79.0  79.0.....................            79.0            79.0
----------------------------------------------------------------------------------------------------------------


[[Page 58448]]


           Table 2 to Subpart OOOO of Part 60--Required Minimum SO2 Emission Reduction Efficiency (Zc)
----------------------------------------------------------------------------------------------------------------
                                                               Sulfur feed rate (X), LT/D
    H2S content of acid gas (Y), %    --------------------------------------------------------------------------
                                         2.0<=X<=5.0          5.0300.0
----------------------------------------------------------------------------------------------------------------
Y>=50................................            74.0      85.35X0.0144Y0.0128 or 99.9, whichever is smaller.
                                                      ----------------------------------------------------------
20<=Y<50.............................            74.0  85.35X0.0144Y0.0128 or 97.5, whichever is            97.5
                                                                         smaller
                                                      -------------------------------------------
10<=Y<20.............................            74.0  85.35X0.0144Y0.0128 or               90.8            90.8
                                                        90.8, whichever is
                                                        smaller.
Y<10.................................            74.0  74.0.....................            74.0            74.0
----------------------------------------------------------------------------------------------------------------
X = The sulfur feed rate from the sweetening unit (i.e., the H2S in the acid gas), expressed as sulfur, Mg/D(LT/
  D), rounded to one decimal place.
Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H2S (dry basis)
  rounded to one decimal place.
Z = The minimum required sulfur dioxide (SO2) emission reduction efficiency, expressed as percent carried to one
  decimal place. Zi refers to the reduction efficiency required at the initial performance test. Zc refers to
  the reduction efficiency required on a continuous basis after compliance with Zi has been demonstrated.

[FR Doc. 2013-22010 Filed 9-20-13; 8:45 am]
BILLING CODE 6560-50-P