Document ID: EPA-HQ-OAR-2010-0505-4596
Agency: epa
Document Type: Proposed Rule
Title: Oil and Natural Gas Sector: Reconsideration of Certain Provisions of New Source Performance Standards
Posted Date: 2013-04-12T04:00Z

[Federal Register Volume 78, Number 71 (Friday, April 12, 2013)]
[Proposed Rules]
[Pages 22125-22150]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 2013-07873]

[[Page 22125]]

Vol. 78

Friday,

No. 71

April 12, 2013

Part IV

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; Proposed Rule

  Federal Register / Vol. 78 , No. 71 / Friday, April 12, 2013 / 
Proposed Rules  

[[Page 22126]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2010-0505, FRL-9791-9]
RIN 2060-AR75

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

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule; notice of public hearing.

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SUMMARY: On August 16, 2012, the EPA published final new source 
performance standards for the oil and natural gas sector. The 
Administrator received petitions for reconsideration of certain aspects 
of the standards. In this notice, the EPA is announcing proposed 
amendments as a result of reconsideration of certain issues related to 
implementation of storage vessel provisions. The proposed amendments 
also correct technical errors that were inadvertently included in the 
final rule.

DATES: Comments. Comments must be received on or before May 13, 2013, 
unless a public hearing is requested by April 17, 2013. If a hearing is 
requested on this proposed rule, written comments must be received by 
May 28, 2013.
    Public Hearing. If anyone contacts the EPA requesting a public 
hearing by April 17, 2013 we will hold a public hearing on April 29, 
2013.
    Public Hearing. If a public hearing is requested by April 17, 2013, 
it will be held on April 29, 2013 at the EPA's Research Triangle Park 
Campus, 109 T.W. Alexander Drive, Research Triangle Park, NC 27711. The 
hearing will convene at 10:00 a.m. (Eastern Standard Time) and end at 
5:00 p.m. (Eastern Standard Time). A lunch break will be held from 
12:00 p.m. (Eastern Standard Time) until 1:00 p.m. (Eastern Standard 
Time). Please contact Joan C. Rogers at (919) 541-4487, or at 
rogers.joanc@epa.gov to request a hearing, to determine if a hearing 
will be held and to register to speak at the hearing, if one is held. 
If a hearing is requested, the last day to pre-register in advance to 
speak at the hearing will be April 25, 2013. Additionally, requests to 
speak will be taken the day of the hearing at the hearing registration 
desk, although preferences on speaking times may not be able to be 
fulfilled. If you require the service of a translator or special 
accommodations such as audio description, please let us know at the 
time of registration. If no one contacts the EPA requesting a public 
hearing to be held concerning this proposed rule by April 17, 2013, a 
public hearing will not take place.
    If a hearing is held, it will provide interested parties the 
opportunity to present data, views or arguments concerning the proposed 
action. The EPA will make every effort to accommodate all speakers who 
arrive and register. Because this hearing, if held, will be at a U.S. 
governmental facility, individuals planning to attend the hearing 
should be prepared to show valid picture identification to the security 
staff in order to gain access to the meeting room. In addition, you 
will need to obtain a property pass for any personal belongings you 
bring with you. Upon leaving the building, you will be required to 
return this property pass to the security desk. No large signs will be 
allowed in the building, cameras may only be used outside of the 
building and demonstrations will not be allowed on federal property for 
security reasons. The EPA may ask clarifying questions during the oral 
presentations but will not respond to the presentations at that time. 
Written statements and supporting information submitted during the 
comment period will be considered with the same weight as oral comments 
and supporting information presented at the public hearing. If a 
hearing is held on April 29, 2013, written comments on the proposed 
rule must be postmarked by May 28, 2013. Commenters should notify Ms. 
Rogers if they will need specific equipment, or if there are other 
special needs related to providing comments at the hearing. The EPA 
will provide equipment for commenters to show overhead slides or make 
computerized slide presentations if we receive special requests in 
advance. Oral testimony will be limited to 5 minutes for each 
commenter. The EPA encourages commenters to provide the EPA with a copy 
of their oral testimony electronically (via email or CD) or in hard 
copy form. Verbatim transcripts of the hearings and written statements 
will be included in the docket for the rulemaking. The EPA will make 
every effort to follow the schedule as closely as possible on the day 
of the hearing; however, please plan for the hearing to run either 
ahead of schedule or behind schedule. Information regarding the hearing 
(including information as to whether or not one will be held) will be 
available at: http://www.epa.gov/airquality/oilandgas/actions.html. 
Again, all requests for a public hearing to be held must be received by 
April 17, 2013.

ADDRESSES: Submit your comments, identified by Docket ID Number EPA-HQ-
OAR-2010-0505, by one of the following methods:
     http://www.regulations.gov. Follow the online instructions 
for submitting comments.
     Email: Comments may be sent by electronic mail (email) to 
a-and-r-docket@epa.gov, Attention Docket ID Number EPA-HQ-OAR-2010-
0505.
     Fax: Fax your comments to: (202) 566-1741, Attention 
Docket ID Number EPA-HQ-OAR-2010-0505.
     Mail: Send your comments on this action to: EPA Docket 
Center (EPA/DC), Environmental Protection Agency, Mailcode: 2822T, 1200 
Pennsylvania Ave. NW., Washington, DC 20460, Docket ID Number EPA-HQ-
OAR-2010-0505. Please include a total of two copies. The EPA requests a 
separate copy also be sent to the contact person identified below (see 
FOR FURTHER INFORMATION CONTACT).
     Hand Delivery or Courier: Deliver your comments to: EPA 
Docket Center, EPA West, Room 3334, 1301 Constitution Ave. NW., 
Washington, DC 20460. Please include a total of two copies. Such 
deliveries are only accepted during the Docket's normal hours of 
operation (8:30 a.m. to 4:30 p.m., Monday through Friday, excluding 
legal holidays), and special arrangements should be made for deliveries 
of boxed information.
    Instructions: All submissions must include agency name and 
respective docket number or Regulatory Information Number (RIN) for 
this rulemaking. All comments will be posted without change and may be 
made available online at http://www.regulations.gov, including any 
personal information provided, unless the comment includes information 
claimed to be confidential business information (CBI) or other 
information whose disclosure is restricted by statute. Do not submit 
information that you consider to be CBI or otherwise protected through 
http://www.regulations.gov or email. The http://www.regulations.gov Web 
site is an ``anonymous access'' system, which means the EPA will not 
know your identity or contact information unless you provide it in the 
body of your comment. If you send an email comment directly to the EPA 
without going through http://www.regulations.gov, your email address 
will be automatically captured and included as part of the comment that 
is placed in the public docket and made available on the Internet. If 
you submit an electronic comment, the EPA recommends that you include 
your

[[Page 22127]]

name and other contact information in the body of your comment and with 
any disk or CD-ROM you submit. If the EPA cannot read your comment due 
to technical difficulties and cannot contact you for clarification, the 
EPA may not be able to consider your comment. Electronic files should 
avoid the use of special characters, any form of encryption and be free 
of any defects or viruses.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
through http://www.regulations.gov or in hard copy at the EPA's Docket 
Center, Public Reading Room, EPA West Building, Room Number 3334, 1301 
Constitution Avenue NW., Washington, DC 20004. This Docket Facility 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) 541-3470; email address: moore.bruce@epa.gov.

SUPPLEMENTARY INFORMATION: Outline. The information presented in this 
preamble is organized as follows:

I. Preamble Acronyms and Abbreviations
II. General Information
    A. Does this reconsideration notice apply to me?
    B. What should I consider as I prepare my comments to the EPA?
    C. How do I obtain a copy of this document and other related 
information?
III. Background
IV. Today's Action
V. Executive Summary
VI. Discussion of Provisions Subject to Reconsideration
    A. Storage Vessels Implementation
    B. Periodic Monitoring and Testing of Closed-Vent Systems and 
Control Devices
    C. Test Protocol for Combustion Control Devices
    D. Annual Report and Compliance Certification
    E. Properly Designed Storage Vessels, Closed-Vent Systems and 
Control Devices
VII. Technical Corrections and Clarifications
VIII. Impacts of This Proposed Rule
    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?
IX. 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 of 1995
    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

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
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
OVA Olfactory, Visual and Auditory
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. 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
------------------------------------------------------------------------
                                                         Examples of
             Category               NAICS Code \1\   regulated entities
------------------------------------------------------------------------
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.
------------------------------------------------------------------------
\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).

[[Page 22128]]

B. What should I consider as I prepare my comments to the EPA?

    We seek comment only on the aspects of the final new source 
performance standards for the oil and natural gas sector specifically 
identified in this notice. We are not opening for reconsideration any 
other provisions of the new source performance standards at this time.
    Do not submit information containing CBI to the EPA through http://www.regulations.gov or email. Send or deliver information identified as 
CBI only to the following address: Roberto Morales, OAQPS Document 
Control Officer (C404-02), Office of Air Quality Planning and 
Standards, U.S. Environmental Protection Agency, Research Triangle 
Park, North Carolina 27711, Attention: Docket ID Number EPA-HQ-OAR-
2010-0505. Clearly mark the part or all of the information that you 
claim to be CBI. For CBI information in a disk or CD-ROM that you mail 
to the EPA, mark the outside of the disk or CD-ROM as CBI and then 
identify electronically within the disk or CD-ROM the specific 
information that is claimed as CBI. In addition to one complete version 
of the comment that includes information claimed as CBI, a copy of the 
comment that does not contain the information claimed as CBI must be 
submitted for inclusion in the public docket. Information so marked 
will not be disclosed except in accordance with procedures set forth in 
40 CFR part 2.

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 
TTN. Following signature, a copy of each proposed rule will be posted 
on the TTN's policy and guidance page for newly proposed or promulgated 
rules at the following address: http://www.epa.gov/ttn/oarpg/. The TTN 
provides information and technology exchange in various areas of air 
pollution control.

III. Background

    The Administrator signed the Oil and Natural Gas Sector NSPS (40 
CFR part 60 subpart OOOO) on April 17, 2012, and the final rule was 
published in the Federal Register at 77 FR 49490, August 16, 2012. 
Following promulgation of the final rule, the Administrator received 
petitions for reconsideration of several provisions of the NSPS 
pursuant to CAA section 307(d)(7)(B). Copies of the petitions are 
provided in rulemaking docket EPA-HQ-OAR-2010-0505.

IV. Today's Action

    Today, we are granting reconsideration of, proposing and requesting 
comment on the following limited set of issues raised in the petitions 
described above: (1) Implementation date for the storage vessel 
provisions; (2) definition of ``storage vessel''; (3) definition of 
``storage vessel affected facility'' for applicability purposes; (4) 
requirements for storage vessels constructed, modified or reconstructed 
during the period from the NSPS proposal date, August 23, 2011, to 
April 12, 2013; (5) an alternative mass-based standard for storage 
vessels after extended periods of low uncontrolled emissions; (6) 
compliance demonstration and monitoring provisions for closed-vent 
systems and control devices for storage vessels; (7) revised and 
clarified protocol for manufacturer testing of enclosed combustors; (8) 
broadening of the provision for determining VOC emissions and 
installing controls from only those affected storage vessels in certain 
locations to all affected storage vessels regardless of location; and 
(9) time period allowed for submittal of annual reports and compliance 
certifications. Finally, we are proposing to correct technical errors 
that were inadvertently included in the final rule.
    This notice is limited to the specific issues identified in this 
notice. We will not respond to any comments addressing any other 
provisions of the oil and natural gas sector NSPS. We will address 
other issues for which we intend to grant reconsideration at a later 
time.
    The impacts of today's proposed revisions on the costs and the 
benefits of the final rule are minor but cost-saving. We expect that 
affected facility owners and operators will install and operate the 
same or similar control technologies to meet the proposed revised 
standards in this notice as they would have chosen to comply with the 
standards in the August 2012 final rule, and revisions to the rule will 
not significantly increase emissions.

V. Executive Summary

    The purpose of this action is to propose amendments to 40 CFR part 
60, subpart OOOO, Standards of Performance for Crude Oil and Natural 
Gas Production, Transmission and Distribution. This proposal was 
developed to address certain issues primarily related to implementation 
of storage vessel provisions that have been raised by different 
stakeholders through several administrative petitions for 
reconsideration of the 2012 NSPS. The EPA is proposing to amend the 
NSPS to address these issues.
    Information the EPA had during development of the final rule led to 
underestimation of the number of affected storage vessels. In response 
to information presented in some of the petitions for reconsideration, 
we have revised the estimated number of storage vessels subject to, and 
impacted by, the final NSPS. Based on the increased number of storage 
vessels we now estimate will be impacted by the proposed rule, it is 
clear that more time will be needed for a sufficient number of control 
devices to become available for the impacted storage vessels.
    Based on our analysis and the information provided to us, we 
believe that there are on the order of 970 storage vessels per month 
being installed at this time and expected in the future, and over 
20,000 affected storage vessels constructed, modified or reconstructed 
between the August 23, 2011, proposal date of the NSPS and April 12, 
2013. For ease of reference in this notice, we refer to affected 
storage vessels constructed, modified or reconstructed between the 
August 23, 2011, proposal date of the NSPS and April 12, 2013 as 
``Group 1'' and the cohort of storage vessels constructed, modified or 
reconstructed after April 12, 2013 as ``Group 2.'' Further, based on 
information available to us, there will not be a sufficient supply of 
control devices until 2016. To avoid postponing control for all 
affected storage vessels until 2016, we are proposing alternative 
measures for Group 1 affected sources, because many of these sources 
will likely have experienced significant emissions decline during this 
period. For Group 2 affected sources, we are proposing an April 15, 
2014, compliance date for implementing the control requirements. For 
Group 1, instead of installation of a control device by April 15, 2014, 
we are proposing to require initial notification by October 15, 2013, 
to inform regulatory agencies of the existence and location of the 
vessels. We are also proposing that affected storage vessels in Group 1 
that undergo an event after April 12, 2013 that leads to an increase in 
emissions, even without a physical change or change in the method of 
operation, implement the same control requirements as Group 2.
    For storage vessels that have installed controls to meet the 95 
percent VOC reduction standard, we are proposing streamlined compliance 
monitoring provisions that would be in place during our reconsideration 
of certain

[[Page 22129]]

issues raised in the reconsideration petitions relative to the current 
compliance demonstration and monitoring requirements. We are proposing 
these streamlined provisions to provide assurance of compliance during 
the reconsideration period, while allowing the EPA time to consider 
fully the issues raised by petitioners concerning initial and 
continuous compliance provisions of the final NSPS. These compliance 
monitoring provisions include inspections performed at least monthly of 
covers, closed-vent systems and control devices. These procedures were 
selected to provide frequent checks that will lead to prompt repairs, 
to be performed by personnel already at the site and would require 
little or no specialized compliance monitoring training or equipment.
    We are also proposing that the storage vessel standards include a 
sustained uncontrolled VOC emission rate of less than 4 tpy as an 
alternative emission limit to the 95 percent control in the final NSPS 
under specified circumstances. Specifically, the proposed alternative 
emission limit would be available to those who can demonstrate, based 
on records for the 12 months immediately preceding the demonstration 
and while the control is on, that its uncontrolled emissions during 
that 12 month-period would have been below 4 tpy. More detailed 
discussion of the less than 4 tpy emission limit is presented in 
section VI.A.4. We believe this alternate standard reflects the decline 
in production that all wells experience over time and allows control 
devices to be reused at other locations, which would help alleviate 
control device supply shortages. If, however, emissions subsequently 
increase above the 4 tpy limit, the sources would need to comply with 
the 95 percent control requirement as discussed in detail in section 
VI.4.
    We are proposing to amend the definition of ``storage vessel'' to 
clarify that it refers only to vessels containing crude oil, 
condensate, intermediate hydrocarbon liquids or produced water. We 
believe this amendment addresses concerns raised by several petitioners 
that the definition in the final NSPS was overly broad and encompassed 
a number of unintended vessels, such as fuel tanks.
    We are also proposing to amend the definition of ``storage vessel 
affected facility'' to include the 6 tpy VOC emission threshold. 
Without this threshold, the affected facility definition could impose 
unnecessary burden on operators of storage vessels that are not 
required to reduce emissions. In addition, we are proposing to clarify 
that a source can take into account any legal and practically 
enforceable emission limit under federal, state or local authority when 
determining the VOC emission rate for purposes of this threshold (i.e., 
they would not be subject to the storage vessel provisions of the NSPS 
if their potential to emit VOC was required to be less than 6 tpy under 
such limitation and in fact was).
    We are proposing to revise the combustor control device 
manufacturer test protocol in the NSPS to align it with a similar 
protocol in the Oil and Natural Gas NESHAP (40 CFR 63, subpart HH). Our 
intent in the final NSPS was to make the NSPS and NESHAP protocols 
consistent. In addition, we are soliciting comment on a potential 
compliance approach based on the use of these manufacturer-tested 
combustor models. This potential compliance approach takes advantage of 
an opportunity to reduce the compliance burden on the affected 
facility. A discussion of this concept as it relates to this rule is 
presented in section VI.C of this preamble.
    We are proposing to clarify that a storage vessel affected facility 
whose VOC emissions decrease to less than the threshold of 6 tpy would 
remain an affected facility. We believe this amendment is necessary to 
clarify that a storage vessel complying with the proposed alternative 
emission limit of less than 4 tpy would remain an affected facility and 
would be required to meet the 95 percent reduction standard should its 
uncontrolled emissions increase to 4 tpy or above in the future.
    The final NSPS requires the annual report and compliance 
certification to be submitted within 30 days after the end of the 
compliance period. Several petitioners stated that because the annual 
report requires signature by a responsible official to certify the 
truth, accuracy and completeness of the report, 30 days is insufficient 
to compile all the required information and to obtain the signature of 
a senior company official. Therefore, we are proposing to allow 90 days 
after the end of the compliance period for submittal of the annual 
report and compliance certification. We are also proposing to make 
several clarifications and technical edits to the final NSPS.
    In addition to the proposed revisions to the requirements discussed 
above, we present a discussion in section VI.E concerning the 
importance of proper design, sizing and operation of storage vessel 
affected facilities, their closed-vent systems and associated control 
devices. Improper design or operation of a storage vessel and its 
control system can result in occurrences where peak flow overwhelms the 
storage vessel and its capture systems, resulting in emissions that do 
not reach the control device.

VI. Discussion of Provisions Subject to Reconsideration

    As summarized above, the EPA is proposing to address a number of 
issues that have been raised by different stakeholders through several 
administrative petitions for reconsideration of the final NSPS. The 
following sections present the issues raised by the petitioners that 
the EPA is addressing in this action and how the EPA proposes to 
resolve the issues. We also provide below a discussion of the EPA's 
expectations that operators will employ proper design, sizing and 
operation of storage vessel affected facilities, their closed-vent 
systems and their associated control devices.

A. Storage Vessels Implementation

1. Emission Standards for Storage Vessels
    In their petitions for reconsideration, two petitioners stated that 
the EPA had significantly underestimated the number of storage vessels 
subject to and impacted by the NSPS. The petitioners pointed out that 
the EPA had based its analysis to predict the number of storage vessels 
that would be subject to and impacted by the final rules on storage 
vessels that were located at existing low producing wells. They 
reasoned that storage vessels at low producing wells were likely to 
have low throughput with corresponding low rates of flash emissions. 
Petitioners asserted that they estimated the number of affected storage 
vessels to be approximately 28,000 per year. They stated that, because 
their estimate was much higher than the 304 storage vessels per year 
the EPA had estimated, the 1-year phase in for the storage vessel 
requirements provided in the final rule was insufficient time for an 
adequate number of control devices to become available to meet demand. 
The petitioners suggested remedies that could help alleviate the 
shortage of control devices necessary to control the much greater 
number of storage vessels than the EPA had estimated: (1) Provide a 
greater period of time for phase in (i.e., 3 years instead of the 1 
year provided in the final rule); and (2) allow removal of control 
devices after an extended period of low uncontrolled emissions. The 
first suggestion is addressed below in this section; the second is 
addressed in section VI.A.4.
    In light of petitioners' assertions, we revisited our estimate of 
the number of

[[Page 22130]]

storage vessels subject to the final NSPS. Our existing estimate was 
based on information reported in the NEI that had been used to develop 
the storage vessels provisions of NESHAP subpart HH several years ago. 
These data, combined with model plant information and modeled using 
over 100 tank datasets provided as part of API E&P TANKS, were used to 
develop an estimate of storage vessels expected to have VOC emissions 
of at least 6 tpy, the applicability threshold for storage vessels in 
the NSPS final rule.
    In our original estimate, we used the throughput distribution of 
crude oil and condensate storage vessels as reported in the BID for 
NESHAP subpart HH to estimate the number of storage vessels in each of 
several throughput categories. This distribution was important because 
it was directly related to how we estimated VOC emissions from the 
tanks. We now know that the BID data were highly biased towards lower 
throughput tanks, which typically have lower emissions. We realize 
that, because of the high production rates of hydraulically fractured 
wells (the predominant type of wells today and expected to be the 
predominant type of wells in the future), the liquid throughput and 
resulting flash emissions for future storage vessels are much higher 
than for the storage vessels represented by the BID data. Thus, we now 
realize that the vast majority of the tanks, according to the BID 
distribution, were lower throughput tanks with VOC emissions less than 
6 tpy, while a much higher number of future storage vessels are 
expected to have emissions of 6 tpy or more. Further, we now realize 
that historical trends we have used in the past to project industry 
growth are not applicable to the oil and natural gas sector going 
forward. This also contributed to our underestimate of affected storage 
vessels in the final rule analysis. In summary, the much higher 
production wells and correspondingly higher storage vessel emissions, 
combined with the great increase in the number of wells and associated 
storage vessels, resulted in the number of affected storage vessels to 
be greatly underestimated.
    Based on the information from the petitioners, our re-evaluation of 
our dataset, and additional information described below, we revised our 
estimate of the number of storage vessels subject to the final NSPS. We 
estimated the number of new storage vessels predicted to be installed 
by assuming that there would be one storage vessel associated with each 
completed well. We understand that there may be more than one storage 
vessel associated with each well, but because the majority of VOC 
emissions from storage vessels occur due to flashing from the first 
storage vessel after the separator (where the pressure differential 
between devices is the greatest), other storage vessels would have 
comparatively lower emissions. Further, if more than one storage vessel 
does exist at the well site, it is likely that owners and operators 
would manifold these storage vessels together and route them to a 
single control device or VRU.
    We recognize that an additional source of uncertainty in our 
revised analysis is that we are not able to estimate the number of 
wells on multi-well pads. We believe that these multi-well pads would 
be more likely to take advantage of the proximity of available storage 
vessel capacity, resulting in more than one well being associated with 
a storage vessel or group of storage vessels.
    For the reasons stated above, we believe that our assumption of one 
storage vessel per well provides a reasonable basis for estimating the 
number of affected storage vessels since August 23, 2011, (the date the 
NSPS was proposed) and for future years. We drew estimates and 
predictions of the number of completed wells from 2011 to 2015 from the 
EIA NEMS 2012 forecasting model, a modeling platform consistent with 
the 2012 Annual Energy Outlook reference case.
    To estimate the number of storage vessels that would be associated 
with wells of various production ranges, we used well-level production 
information from 2009 contained in the HPDI database to distribute the 
predicted number of well completions across a range of production rate 
categories using the same proportions as the 2009 well completion data.
    We also made an effort to account for the number of storage vessels 
that would already be subject to and controlled under state 
environmental regulations. We analyzed the regulations in the 11 states 
that represented 95 percent of the total production of crude oil and 
condensate in the U.S. (according to production information published 
by the EIA). These states were Alaska, California, Colorado, Kansas, 
Louisiana, Montana, North Dakota, New Mexico, Oklahoma, Texas and 
Wyoming. These storage vessels were then subtracted from the overall 
count of storage vessels that would be subject to the final rule.
    As a result, we estimated that there may be as many as 46,000 new 
condensate and crude oil storage vessels installed that would be 
subject to the NSPS from August 23, 2011 (the date upon which new, 
modified or reconstructed storage vessels become affected facilities 
under the NSPS), until October 15, 2015. This is an average of 
approximately 11,600 storage vessels per year, or about 970 per month. 
By the current compliance date of October 15, 2013, over 20,000 storage 
vessels will have come online since the original proposal date. These 
units will need to be controlled by October 15, 2013, under the current 
final NSPS.
    Based on our reanalysis, we have reason to believe that there was 
already significant demand for storage vessel emissions control devices 
prior to the 2012 NSPS. For example, as discussed above, several states 
require operators to control VOC emissions from storage vessels. The 
EPA received information from the oil and natural gas industry 
indicating that 3,680 control devices could be manufactured per year as 
of 2012, or about 300 per month. We assumed that, since the NSPS 
requirements were not yet finalized when the agency received this 
information, most of this supply of equipment was being purchased by 
operators needing to meet state requirements. The 300 control devices 
per month discussed above will not be sufficient to satisfy NSPS 
requirements.
    We further believe the supply of combustors will lag demand. Due to 
their uncertainty, manufacturers will delay scaling-up production until 
they are confident of the requirements of the manufacturer test 
protocol, for which we are proposing certain revisions and 
clarifications in this action and intend to finalize later this year. 
Manufacturers also need to make sure their models will pass the test 
and will undergo a favorable review by the EPA before investing in 
scale-up of operations. The manufacturer test protocol is discussed in 
section VI.C below.
    The information available to the EPA leads us to conclude that, 
even with the uncertainty described above, the control device industry 
will be able to ramp up production each month by about 100 units over 
the previous month, beginning now, with our proposed revisions to the 
manufacturer test protocol, to a production capacity of about 1,400 per 
month, or about 17,000 per year, by April 15, 2014. With these 
projections in mind, it is clear that there will be an insufficient 
number of control devices on the market to meet the demand for control 
devices by the current compliance date of October 15, 2013, in addition 
to the ongoing demand for control devices from units that become 
affected after October 15, 2013. In fact, given these projections, it

[[Page 22131]]

is unlikely that supply of control devices will meet existing and new 
demand until 2016.
    We are concerned about delaying control of all storage vessels 
affected facilities until 2016. In order to move the compliance date to 
earlier than 2016, and in an attempt to match supply and demand in the 
most efficient and environmentally protective manner, we are 
considering that the BSER constitutes measures other than immediate 
control for those that have come online to date (i.e., Group 1). 
Specifically, we are proposing a two-part requirement: (1) These 
sources provide initial notification to the EPA by October 15, 2013; 
and (2) for any of these storage vessels that experiences an event on 
or after April 12, 2013, that potentially results in emissions 
increasing, the owner or operator would be subject to the same control 
requirements as those in Group 2.
    The proposed approach not only would avoid delaying controlling all 
units until 2016, it would also help to some degree with proper 
allocation of the limited supplies of control devices in the near 
future and would ensure that those devices are used at the vessels 
expected to have the most significant emissions. As discussed in 
section VI.A.4 below, all oil and natural gas wells decline in 
production over time, with corresponding declines in reservoir pressure 
and liquids production. Often these declines are relatively rapid and 
can occur over a year or two. Accordingly, emissions from storage 
vessels in Group 1 may have declined significantly (potentially below 
the 6 tpy threshold for some) by the time controls are available to all 
affected sources. We recognize, however, that the emissions of these 
Group 1 affected facilities could increase again due to an event 
leading to higher emissions (e.g., if an additional well comes online 
feeding the vessel or a well feeding the storage vessel is later 
refractured or otherwise stimulated leading to an increase in 
production). We are therefore proposing that, if such an increase 
occurs, the Group 1 sources comply with control requirements that apply 
to Group 2.
    Based upon the projected buildup of control device manufacturing 
capacity (i.e., an increase in production capacity of about 100 units 
per month, beginning now, to a production capacity of about 1,400 per 
month, or about 17,000 per year, by April 15, 2014) and, if control is 
not required initially for Group 1, the EPA expects that by April 15, 
2014, there will be sufficient supply of equipment for Group 2. 
Accordingly, we are proposing that Group 2 implement the control 
requirements by April 15, 2014, or 60 days after startup, whichever is 
later. Additionally, the EPA believes manufacturers will be flexible in 
their ability to meet equipment demand increase in the future if crude 
oil and natural gas production increases. Because more controls will be 
applied to storage vessels as a result of this rule, the EPA believes 
that manufacturers will take advantage of scale economies and produce 
units at appropriate rates. We believe that the NSPS reconsideration, 
as proposed, will achieve environmental benefits while minimizing the 
risks of producers needing to slow activities to obtain appropriate 
equipment.
    In summary, based on the discussion of control supply and demand 
presented above, we are proposing differing requirements for storage 
vessels in Group 1 and those in Group 2 in order to ensure that 
controls are available for new or modified storage vessel as soon as 
possible after they come online (i.e., when they have higher 
emissions). Specifically, for Group 2 (i.e., those that are 
constructed, modified or reconstructed on or after April 12, 2013), we 
propose to require reduction of emissions by 95 percent no later than 
60 days after startup or April 15, 2014, whichever is later. For Group 
1 (i.e., those that were constructed, modified or reconstructed after 
August 23, 2011, and before April 12, 2013, many of which may have 
experienced decline in emissions, we are proposing a two-part 
requirement as reflecting BSER: (1) These sources provide initial 
notification to the EPA by October 15, 2013; and (2) for any of these 
storage vessels that experience an event on or after April 12, 2013 
that results in emissions increasing, the owner or operator would be 
subject to the same control requirements as those in Group 2 and would 
have to control emissions no later than 60 days after the event or 
April 15, 2014, whichever is later. Until any such emissions increase, 
there would be no further requirements for Group 1 storage vessels. We 
have included above in the preamble and in the proposed regulatory text 
some examples of events that would potentially lead to emission 
increase. We solicit comment on other examples or suggestions on how to 
define these events in the rule.
    Further, we realize that the events discussed above that would 
likely lead to emissions increases are planned events. Operators of 
Group 1 storage vessels who plan for routing of additional wells to a 
storage vessel, fracturing or refracturing of a well feeding a storage 
vessel or other events are fully aware of such an event before it 
occurs. Therefore, we solicit comment on whether Group 1 storage 
vessels with increased emissions following such an event need the full 
60 days provided for operators to apply controls.
    We believe, based on our analysis of control supply and demand 
discussed above, that sufficient supply of controls will be available 
for Group 2 storage vessels by April 15, 2014. As a result, we propose 
that the BSER for these Group 2 storage vessels would require reduction 
of emissions by 95 percent no later than 60 days after date of 
construction, modification or reconstruction or April 15, 2014, 
whichever is later.
    However, we are concerned with leaving affected sources with high 
emissions uncontrolled prior to April 15, 2014, and certain Group 1 
units after that date. One option is to require control for those with 
emissions above a certain level based on the number of available 
control devices during this period. However, we have insufficient 
information regarding the number of high throughput (and likely to have 
higher VOC emissions) storage vessels. Therefore, we are unable to 
identify an appropriate threshold higher than 6 tpy that would allow us 
to require control of higher emission storage vessels earlier. We are 
also concerned that this may impact the ability of other affected 
sources to acquire control devices and comply by April 15, 2014. We 
solicit information on the number of storage vessels at different 
throughput levels (or VOC emission levels) to further inform our 
consideration of controlling higher emitting storage vessels earlier 
than April 15, 2014.
2. Definition of ``Storage Vessel''
    In the final rule (77 FR 49490), the EPA defined ``storage 
vessel,'' in relevant part, as ``a unit that is constructed primarily 
of nonearthen materials (such as wood, concrete, steel, fiberglass, or 
plastic) which provides structural support and is designed to contain 
an accumulation of liquids or other materials.'' Several petitioners 
took issue with this definition and expressed particular concern that 
the storage vessel definition in the final rule inadvertently included 
nearly every container in the oil and gas production, natural gas 
processing, and natural gas transmission and storage segments. For 
example, one petitioner stated that the definition as written could 
potentially encompass a drinking water bottle. The petitioner stated 
further that while the drinking water bottle would not exceed the 6 tpy 
VOC potential emissions threshold, which was provided

[[Page 22132]]

elsewhere in the final rule, each site would have to maintain 
documentation on each and every container on-site to prove that the 
potential VOC emissions were less than 6 tpy.
    We agree that the current definition is unclear and propose to 
amend the definition of ``storage vessel'' in Sec.  60.5430 of the 
final rule to read, in relevant part, ``a tank or other vessel that is 
designed to contain 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.''
    The proposed amended definition now specifically calls out the type 
of materials that must be stored in the vessel to meet the definition, 
thereby clarifying the scope of storage vessels the EPA intended to 
cover under the NSPS. The proposed definition reflects the EPA's 
intent, as discussed in the original rulemaking. For example, in the 
discussion of our storage tank analysis in the preamble to the proposed 
rule, we stated that ``[c]rude oil, condensate and produced water are 
typically stored in fixed-roof storage vessels.'' 76 FR 52763. 
Similarly, in the preamble discussion of the estimated impacts, we 
addressed only vessels storing these types of materials. Thus, we 
indicated at proposal that our intent was to regulate only certain 
storage vessels (i.e., those storage vessels that may likely emit VOC 
emissions), not every container.
    We had previously believed that, by including a VOC emissions 
threshold in the storage vessel control requirements in Sec.  60.5395 
of the final rule, the rule effectively limited the applicability of 
the storage vessels emission standards to only storage vessels 
containing crude oil, condensate, intermediate hydrocarbon liquids, or 
produced water because, in all likelihood, only tanks storing these 
materials would have the potential to emit VOC at or above the 
threshold. However, as the petitioners pointed out, the definition in 
the final rule was stated in broad enough terms that a reasonable 
interpretation of the definition could lead to confusion as to which 
containers were considered to be storage vessels. If left unchanged, 
the storage vessel definition could result in a significant burden on 
the owner or operator because every container on-site may have to be 
identified and potential VOC emissions determined (and requisite 
records maintained). The proposed amendments to the storage vessel 
definition now limit the definition to vessels containing only those 
types of materials for which we originally intended the NSPS to apply. 
To provide further clarification, we are proposing to add definitions 
in Sec.  60.5430 for condensate, hydrocarbon liquid and produced water. 
We are proposing to adopt the definitions of these terms in 40 CFR part 
63, subpart HH, which similarly requires 95-percent emission reduction 
from storage vessels that are major sources of hazardous air 
pollutants.
3. Storage Vessel Affected Facility Definition at Sec.  60.5365(e)
    In Sec.  60.5365(e) of the final rule (77 FR 49490), we described 
the affected facility as ``[e]ach 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.'' In Sec.  60.5395 of the final rule, 
we require affected facilities emitting more than 6 tpy VOC to reduce 
VOC emissions by 95.0 percent.
    Several petitioners stated that by not including the VOC emissions 
threshold in the affected facility definition, the EPA significantly 
increased the population of storage vessels potentially affected by the 
rule. The petitioners asserted that this very broad description of 
affected facility would result in unnecessary notification, 
recordkeeping and reporting burden, even if the storage vessels had no 
VOC emissions or are not subject to the control requirement.
    We had not intended to subject storage vessels emitting below the 6 
tpy VOC to the NSPS. Although the final rule is clear that storage 
vessels that have always had a PTE below the 6 tpy threshold are not 
subject to the control requirement, the rule inadvertently requires 
them to comply with the recordkeeping and reporting requirements in the 
final rule, which are largely associated with demonstrating and 
assuring compliance with the control requirement. Further, having these 
storage vessels be subject to the NSPS could trigger state permitting 
requirements. We believe these associated burdens are not necessary for 
storage vessels with VOC emissions below 6 tpy, which are not subject 
to the control requirement. On the contrary, we believe it is important 
to limit the scope of the NSPS only to those storage vessels the EPA 
intended to control, thereby avoiding unnecessary unintended 
consequences. For the reason stated above, we agree with petitioners' 
suggestion and are proposing to include the 6 tpy PTE threshold in the 
``storage vessel affected facility'' definition in 60.5395(e).
    Petitioners asserted that a storage vessel's emissions for purposes 
of applying the emissions threshold should consider any legal and 
practically enforceable emissions limit below 6 tpy. We are proposing 
to clarify at Sec.  60.5365(e) 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 this threshold (i.e., they would not be subject to the 
storage vessel provisions of the NSPS if their potential to emit VOC 
was required to be less than 6 tpy under such limitation and they in 
fact were below that limit).
    In addition, petitioners had suggested that sources with a legal 
and practically enforceable requirement for at least 95 percent control 
should not be affected facilities under the NSPS. The petitioners' 
proposal seems to suggest that as long as an emission limitation 
equivalent to the NSPS emission standards can be enforced by state or 
another federal requirement, compliance with the NSPS is not necessary. 
The EPA is concerned regarding the absence of EPA oversight, which CAA 
section 111 contemplates. We are also concerned that such a broad 
proposition, if adopted, would not be limited to just this NSPS but may 
inadvertently impact other future EPA regulations as well. Although we 
are not proposing to add such a provision in this action, we solicit 
comment on the petitioners' suggested approach, in particular on how 
the EPA may implement oversight of the enforcement of this NSPS and on 
distinguishing characteristics between this NSPS and other EPA 
regulations to warrant this approach here without inadvertently 
extending its use in other rulemakings. We also solicit comment if such 
an approach is permissible under CAA section 111.
    The final rule allows 30 days to determine emissions, followed by 
another 30 days to install controls, only for storage vessels located 
at well sites with no existing well in production. For storage vessels 
located at well sites with one or more wells in production, the NSPS 
allowed no time for determining emissions but required control on 
startup. This provision was based on the assumption that, for storage 
vessels at ongoing production sites, the owner or operator would be 
able to anticipate the rate and characteristics of the liquids entering 
the vessel, which would obviate the need for time for emissions 
determination and would allow the appropriate controls to be applied on 
startup if needed. Petitioners raised this provision as problematic and 
stated that

[[Page 22133]]

the NSPS should provide time for emissions determination and control 
device installation for all storage vessels, not just ones at locations 
with no existing well in production. According to the petitioners, in 
many cases at well sites and at other locations, emissions cannot be 
estimated until the storage vessel is in operation, given the 
uncertainties in flowrate and other characteristics of the liquid 
flowing to the vessel. When a new well comes online, even at a location 
where wells are already in production, liquids from the new well can 
have significantly different characteristics than liquids from the 
existing wells. Further, petitioners noted that the language in the 
final rule could be incorrectly interpreted that only storage vessels 
located at well sites were potentially subject to the NSPS. In light of 
the new information, we propose that all new, modified or reconstructed 
Group 2 storage vessels have up to 30 days after startup to determine 
the emissions rate and, if emissions are estimated to be 6 tpy or more, 
controls must be in operation no later than 60 days from startup or by 
April 15, 2014, (our proposed new date for implementing control), 
whichever is later. It is our intent that the NSPS address VOC 
emissions from storage vessels located not only at wells but at any 
location from the well to the point of custody transfer to an oil 
pipeline or to the point of custody transfer from the natural gas 
transmission and storage segment to the local distribution company.
    Petitioners also asserted that 60 days was not a sufficient period 
to determine emissions and install controls if required, although they 
did not provide details supporting this assertion. We believe that 60 
days is sufficient and propose to retain this period. We believe, since 
modeling is generally the method by which emissions are estimated, 
based on several parameters of the material entering the storage 
vessel, that 30 days is sufficient for determining whether emissions 
reach the threshold. Further, we believe that an additional 30 days is 
sufficient to install the combustor and the relatively simple 
associated closed vent system.
    We are also proposing to add a provision to clarify that a storage 
vessel affected facility whose VOC emissions decrease to less than the 
threshold of 6 tpy, even for an extended time, will remain an affected 
facility. We believe this additional clarification is necessary, 
especially in light of our proposed alternative emission limit of less 
than 4 tpy uncontrolled VOC emissions, to address the situation where 
emissions from a storage vessel affected facility declines and later 
increases. We believe it is important to clarify for both the regulated 
community and regulatory agencies that such a storage vessel remains an 
affected facility and would be required to meet the emission standards 
of either the 95 percent VOC reduction requirement or the proposed 
alternative emission limit of less than 4 tpy VOC. This issue is 
related to the discussion below in section VI.A.4 pertaining to 
continued control device use after extended periods of low emissions.
    One petitioner asserted that the final rule creates uncertainty 
because sources subject to the NSPS may trigger state minor or major 
source permitting requirements. Subsequently, the petitioner clarified 
that much of the uncertainty focuses on treatment of replacement 
storage vessels that are installed in cases of failure of existing 
storage vessels due to leakage or other issues. The petitioner was 
concerned that some state permitting programs require construction 
permits for sources that are affected facilities under any NSPS. Under 
subpart OOOO, a replacement storage vessel would be considered a new 
source and an affected facility if it has a PTE of 6 tpy or more and is 
put into service after August 23, 2011.
    Although we understand that operators needing to install 
replacement tanks may potentially have difficulty meeting state 
permitting requirements, it is unclear how the NSPS could be revised to 
help address this issue. Accordingly, we solicit comment on how the 
NSPS could address the issue the petitioner raised.
4. Alternative Mass-Based Standard for Storage Vessel Affected 
Facilities
    The petitioners pointed out that Wyoming \1\ allows for control 
devices to be removed after sustained periods of uncontrolled emissions 
below the applicability threshold. The petitioners also contended that 
allowing control devices to be removed from lower emitting storage 
vessels would increase the number of control devices available to 
install on new storage vessels, which they assert would help alleviate 
the shortage of control devices discussed above in section VI.A.1.
---------------------------------------------------------------------------

    \1\ Oil and Gas Production Facilities, Chapter 6, Section 2 
Permitting Guidance. March 2010.
---------------------------------------------------------------------------

    Although this proposed rule includes an amendment to assure 
adequate supply of control devices, the number of future storage vessel 
affected facilities that would require control is uncertain and may 
exceed our estimated 970 per month (which we relied on in our proposed 
amendment to address this issue). We believe that petitioners' 
suggestion is a reasonable approach to help alleviate any potential 
control device shortage issue for the following reason. Storage vessels 
at oil and natural gas production sites are unlike many other sources 
in that emissions can reasonably be expected to decrease over time and, 
potentially, increase again under certain circumstances. After 
production declines, associated emissions would also decline. 
Petitioners' suggestion would help build a buffer against supply 
shortage by allowing control devices on these low emitting storage 
vessels to be relocated to control emissions from storage vessels that 
have just come online and emitting above 6 tpy. For the reason stated 
above, we are proposing that affected sources meet either the 95 
percent VOC reduction standard or an alternative, mass-based numeric 
limit on uncontrolled emissions.
    Petitioners suggested that 6 tpy, the applicability threshold for 
storage vessel affected facilities under the NSPS, also be used as the 
threshold for uncontrolled emissions for allowing removal of storage 
devices. We disagree that 6 tpy is the appropriate alternative limit. 
In the final NSPS rule, we did not establish 6 tpy as an emission 
limit. Rather, 6 tpy is an applicability threshold, at which level we 
have determined that it is cost effective to require installation and 
operation of a control device to achieve 95 percent VOC reduction. At 6 
tpy uncontrolled emissions, 95 percent control would result in an 
emission rate of 0.3 tpy.
    We think the appropriate limit would likely be something less than 
4 tpy; we believe controlling storage vessels above that level could 
still achieve meaningful VOC reduction. We are therefore proposing to 
amend Sec.  60.5395(a) to include both the existing VOC emissions 
reduction component and an alternative mass-based limit of less than 4 
tpy for uncontrolled emissions. The proposed uncontrolled emission 
limit would be available to those who can demonstrate, based on records 
for the 12 months immediately preceding the demonstration and while the 
control is on, that the uncontrolled emissions during that 12 months 
period would have been below 4 tpy. This uncontrolled emission rate can 
be calculated using information available to the facility operator, 
including such parameters as separator pressure, liquid throughput and 
API gravity. We believe this alternate standard reflects the decline in 
production that all wells experience over time and allows control 
devices to be reused at other locations

[[Page 22134]]

which would help alleviate control device supply shortages. If, 
however, uncontrolled emissions increase to 4 tpy or above, the sources 
would need to once again comply with the 95 percent control 
requirement.
    As mentioned above, we are proposing to amend Sec.  60.5395(a) to 
require sources to achieve either: (1) 95-percent VOC reduction; or (2) 
uncontrolled VOC emissions of less than 4 tpy. We are proposing that 
operators electing the alternative emission limit would be required to 
determine and keep records of the storage vessel's emission rate at 
least monthly while operating under the alternative emissions limit. 
Similar to provisions in the final rule for determining annual 
emissions from storage vessels for applicability purposes, we propose 
that operators may use generally accepted models to estimate 
uncontrolled emissions.
    We solicit comment on our proposal to establish an alternative, 
mass-based numeric limit on uncontrolled emissions. We also solicit 
comment on whether a limit of less than 4 tpy is appropriate and, if 
not, what an appropriate limit would be, including any supporting data 
and rationale. In addition, we solicit comment on whether frequencies 
other than monthly would be appropriate for the emissions 
determinations while operating under the alternative emissions limit, 
whether the frequency of such determinations should decrease after some 
number of periodic estimates below 4 tpy, and whether the emissions 
determination should be required only after some event that would 
likely increase emissions.
    Under the final NSPS rule, owners and operators at well sites with 
no wells already in production have 30 days after determining emissions 
to procure and install control. As discussed elsewhere in this notice, 
we are proposing to provide such 30 days to owners and operators at all 
wells sites. We are similarly proposing here that, if a monthly 
emissions determination indicates VOC emissions of 4 tpy or greater, 
the owner or operator would need to comply with the 95 percent control 
standard by no later than 30 days after the determination indicated 4 
tpy or greater VOC emissions. Under our proposed compliance 
demonstration requirement, the alternative emission limit would again 
be available for that storage vessel only after another 12 months of 
uncontrolled VOC emissions less than 4 tpy while operating under the 95 
percent VOC reduction requirement.
    While we think that owners and operators may need time to reinstall 
control, we are concerned with leaving the emissions unaddressed during 
that period. We therefore solicit comment on whether a 30 day period is 
needed for owners and operators to reinstall control and what 
appropriate measures should be taken during the period to control 
emissions.

B. Periodic Monitoring and Testing of Closed-Vent Systems and Control 
Devices

    The final NSPS (77 FR 49490) requires that VOC emissions be reduced 
by 95 percent for storage vessel affected facilities with VOC emissions 
of 6 tpy or more. We had anticipated that most owners and operators 
will use a combustion control device to achieve the required level of 
emission reduction. The final NSPS requires an initial performance 
test, installation and operation of CPMS and calculation of daily 
averages of the continuously monitored parameters, among other 
requirements. As discussed above in section VI.A.1, we have revised our 
estimate of the number of storage vessels affected by the final rule 
from about 300 to approximately 11,600 per year.
    Several of the petitioners assert that the compliance monitoring 
requirements are overly complex and stringent given the large number 
affected storage vessels each year and the remoteness of the well sites 
at which they are installed. The petitioners argue that the well sites 
are unmanned for periods of time up to a month. According to the 
petitioners, proper operation of the CPMS and performance of other 
monitoring requirements would require specialized personnel to be on-
site far more frequently. The petitioners also point out that most well 
sites do not have the communications and power infrastructure in place 
to operate the CPMS.
    The petitioners also argue that insufficient resources are 
available to perform the required Method 21 testing of the closed-vent 
systems and that lengthy (the NSPS requires a 2 hour observation) 
Method 22 testing of combustion control devices is unnecessary and 
overly burdensome.
    Based on our revised estimate of the number of storage vessel 
affected facilities, combined with our knowledge of the remoteness of 
these locations, we believe that petitioners have raised legitimate 
issues regarding the monitoring and testing requirements relative to 
control devices for storage vessels in the final NSPS rule and that 
these issues warrant our reconsideration of these requirements. The EPA 
also recognizes that delaying implementation of the storage vessel NSPS 
pending this reconsideration would further delay the important 
environmental benefits that will result from the NSPS. We are working 
with stakeholders to fully evaluate these issues and intend to complete 
our reconsideration of these monitoring and testing requirements by the 
end of 2014.
    The additional information discussed above has raised significant 
concerns that the compliance monitoring provisions and field testing 
provisions of the final rule may not be appropriate for this large 
number of affected storage vessels, which is much greater than we had 
expected and with many in remote locations. Therefore, we are proposing 
certain streamlined monitoring and continuous compliance demonstration 
requirements to provide assurance during the EPA's reconsideration 
process, that closed-vent systems and control devices are designed and 
operated properly and that the control devices, when in use, are 
achieving the required 95 percent control.
    We believe the proposed requirements do not pose the concerns 
raised by the petitioners regarding burden imposed by the final rule 
due to the vast number of facilities and remote locations involved. The 
requirements we are proposing are intended to be carried out by 
personnel routinely at the well sites without the need for specialized 
training or instrumentation.
    Meanwhile, we will continue to fully evaluate the compliance 
demonstration and monitoring issues raised by the petitioners. We 
intend to complete our reconsideration of these requirements, along 
with other issues for which we intend to grant reconsideration, at a 
later date.
    As mentioned above, we are proposing a suite of streamlined 
compliance and monitoring requirements that would apply instead of the 
requirements in the final rule during the EPA's reconsideration of 
associated issues. First, under Sec.  60.5416, instead of the detailed 
Method 21 monitoring requirements, the proposed requirements would 
include inspection requirements for covers and closed-vent systems. The 
proposed inspection requirements include monthly sensory (i.e., OVA) 
inspections of: (1) Closed-vent system joints, seams and other sealed 
connections (e.g., welded joints); (2) other closed-vent system 
components such as peak pressure and vacuum valves; and (3) the 
physical integrity of tank thief hatches, covers, seals and pressure 
relief valves.

[[Page 22135]]

    Second, under Sec.  60.5417, instead of the CPMS requirements, the 
proposed requirements would include the following inspection 
requirements: (1) Monthly observation for visible smoke emissions 
employing section 11 of EPA Method 22 for a 15 minute period; (2) 
monthly visual inspection of the physical integrity of the control 
device; and (3) monthly check of the pilot flame and signs of improper 
operations. If the pilot flame is absent or if smoking is observed more 
than 1 minute during a 15-minute period, then the operator must take 
further action to ascertain the cause of the malfunction, including 
checking the combustor air vent for obstructions and checking for 
liquid from the knockout drum reaching the combustor (i.e., the 
knockout drum is not draining properly). The owner or operator would be 
required to take corrective action as soon as practicable and as safely 
as possible after visible smoke emissions or other problems are 
observed. Each inspection of the storage vessel and associated control 
device and closed-vent system would be required to be documented in a 
logbook required to be kept securely on-site. Many storage vessels 
already have weatherproof containers mounted nearby where other records 
are kept.
    Third, we are proposing requirements that would apply instead of 
the field performance testing requirements in Sec.  60.5413. We are 
proposing to require that, where controls are used to reduce emissions, 
sources use control devices that by design can achieve 95 percent or 
more emission reduction and operate such devices according to the 
manufacturer's instructions, procedures and maintenance schedule, 
including appropriate sizing of the combustor for the application. 
Documentation that a combustor is designed for at least 95 percent 
control could include such items as manufacturer technical literature 
showing combustor performance, manufacturer's guarantee of control 
efficiency, relevant test reports, etc. We are retaining and strongly 
encourage use of the option for operators to employ combustor models 
that pass manufacturer-conducted performance tests according to the EPA 
combustor test protocol. We believe that operators have an incentive to 
use manufacturer-tested combustors, since those combustors are not 
subject to subsequent performance tests. However, we seek comment on 
other potential approaches to provide incentive for operators to employ 
manufacturer-tested combustor models.
    We solicit input from the public and from states with relevant 
experience on the effectiveness of these types of streamlined 
monitoring techniques in assuring compliance with the emission 
reduction measures of the NSPS. Further, we encourage operators to 
document their experiences with these streamlined measures to better 
inform the EPA in its future evaluation of these measures.

C. Test Protocol for Combustion Control Devices

    The proposed oil and natural gas sector NESHAP (76 FR 52738) 
included an option for manufacturers' performance testing of certain 
combustion control devices as an alternative to on-site testing by the 
owner or operator. We explained the need for this alternative in the 
preamble to the proposed rule (see 76 FR 52785). The proposed NSPS also 
included this option. In order to promote consistency between the oil 
and natural gas sector NSPS and NESHAP, the proposed NSPS rule language 
referenced the relevant sections in the NESHAP (40 CFR 63, subpart HH) 
for the manufacturers' test protocol.
    We received comments to the proposed rule indicating that the 
cross-referencing to the NESHAP was burdensome and posed other 
problems. In response, we eliminated the cross-referencing by 
incorporating the manufacturers' performance test protocol from the 
NESHAP into the final NSPS.
    After publication of the final rule, some of the petitioners 
pointed out that the language we used in the final NSPS appeared to 
indicate that manufacturers' performance testing is mandatory for all 
combustion control devices. The petitioners also noted inconsistencies 
between the regulatory language in the NSPS and NESHAP for the 
manufacturers' performance test protocol.
    In response to the petitioners' comments, we reviewed the 
manufacturers' performance test protocol in the NSPS. We found that not 
all of the revisions made to the NESHAP protocol after proposal were 
carried over to the NSPS. These revisions involved modifications to the 
test procedures and reporting requirements. This inadvertent error led 
to most of the issues raised by the petitioners. It was the EPA's 
intent to have essentially the same manufacturers' performance test 
protocol and reporting requirements in both the NSPS and the NESHAP.
    In response, we are proposing to amend Sec.  60.5413(d) to be 
consistent with the current requirements of 40 CFR 63.772(h) to ensure 
consistency between the rules. This effort will also streamline 
testing, because enclosed combustor models that pass the test protocol 
will meet both the NSPS and NESHAP requirements, eliminating the need 
to test each model for NSPS and NESHAP compliance separately.
    Additionally, we are proposing to modify the reporting requirements 
for owners and operators using a manufacturer tested control device in 
the NSPS to match the same requirements in the NESHAP. We are proposing 
to revise Sec.  60.5412(a)(i) to clarify that the manufacturers' 
performance testing applies to the model of the combustion control 
device, not each individual control device. Finally, we are proposing 
to clarify that manufacturers' performance testing is optional by 
revising Sec.  60.5415(e)(2)(vii).
    As discussed in the 2011 proposed rule preamble (76 FR 52785), 
performance testing of control devices that are not configured with a 
distinct combustion chamber presents several technical issues that are 
more optimally addressed through manufacturer testing, and once these 
units are installed at a facility, through periodic inspection and 
maintenance in accordance with manufacturers' recommendations.
    In the final rule (77 FR 49490), the EPA provided a path for 
compliance that involved operators purchasing certified combustors 
combined with annual compliance demonstrations. We would like to 
explore whether the compliance certification process could be made 
sufficiently robust to reduce or minimize future compliance 
demonstration obligations. We solicit comment on the desirability of 
such an approach and suggestions on how to design a sufficiently 
rigorous certification process to assure compliance while minimizing 
burden on both operators and implementing agencies.
    We are also soliciting comment on one potential framework for 
implementing the certification process for enclosed combustors used to 
meet the emissions standards under NSPS subpart OOOO and NESHAP subpart 
HH. The EPA notes that the following concept is one possible compliance 
tool, and welcomes comment on this or any other compliance tool 
incorporating an enclosed combustor certification program. We plan to 
continue to work with all stakeholders as we further develop this 
concept with the goal of ultimately designing a pathway that assures 
compliance without slowing responsible production of oil and natural 
gas.
    One possible compliance tool includes a requirement for owners or 
operators to use enclosed combustors that have been certified by the 
EPA. The

[[Page 22136]]

manufacturer's role would be to submit a performance test for each 
unique model manufactured. The manufacturer could submit the 
performance test to the EPA where it would be evaluated for 
completeness and compliance with the emissions standard required by the 
rule. In order to ease compliance, the EPA could require that the 
manufacturer's control device be sold as ``compliance ready''; i.e. 
equipped with a thermocouple (or equivalent device) and data recorder. 
Initial discussions with control device manufacturers indicate that 
this may already be common practice. The EPA requests comment as to 
whether enclosed combustors could be sold as ``compliance ready,'' and 
whether such an approach would ease compliance.
    An owner or operator that purchases a certified control device 
could demonstrate initial compliance by providing proof of purchase of 
the EPA-certified device, in the form of a purchase order or receipt. 
The EPA could supplement such a requirement with a manufacturer 
reporting requirement providing the names of entities that had 
purchased certified control devices. Such a model of reporting may 
ensure that the purchase and installation of certified devices has 
occurred, and could also ensure compliance with the rule.
    The owner or operator could demonstrate ongoing compliance, in 
part, through monitoring of the presence of the continuous pilot flame. 
As discussed previously, a certified control device could be sold as 
``compliance ready''; i.e., it would be equipped with a thermocouple 
(or equivalent device) and data recorder thereby simplifying the 
continuous compliance demonstration for the owner or operator.
    We welcome comment on this potential compliance option or on other 
compliance options.

D. Annual Report and Compliance Certification

    Petitioners also asserted that the 30-day period to submit the 
annual report in Sec.  60.5420(b) is too short because of the large 
number of affected facilities to be included in the annual reports of 
many companies and the requirement to have the reports signed by a 
responsible official. We agree that the 30-day period may be too short 
to compile all of the required information and properly inform a 
responsible official such that the official may certify the truth, 
accuracy and completeness of the annual report. Therefore, we are 
proposing to amend Sec.  60.5420(b) to allow 90 days from the end of 
the compliance period for submittal of the annual report and compliance 
certification. This is consistent with Title V reporting and 
certification requirements.
    One petitioner pointed out that the public was not provided an 
opportunity to comment on the requirement in the final rule for 
certification by a responsible official and that such certification, 
modeled on Title V requirements, is not appropriate for the oil and 
natural gas sector due to the number of sources involved and other 
factors. We have reconsidered the certification requirement and, for 
the same reasons provided in the final rule preamble (77 FR 49527), we 
are proposing to retain this requirement. Specifically, we believe that 
self-certification is an important mechanism for assuring the public 
that the information submitted by each facility is accurate. In 
addition, the Title V program has successfully employed self-
certification since its inception and we believe it is a good model for 
the certification provisions in the final rule. For these reasons, we 
are proposing to retain the certification provision in the final rule.
    We believe that the petitioner's main concern may have been the 30-
day period allowed for submittal of the certification, which the 
petitioner claimed insufficient in light of the number of affected 
sources. As discussed above, we are proposing to allow 90 days for 
submitting the compliance certification.

E. Properly Designed Storage Vessels, Closed-Vent Systems and Control 
Devices

    It is the EPA's experience that proper design and sizing of storage 
vessels and their associated closed-vent systems and control devices 
are important considerations in effective control of VOC emissions from 
storage vessels. For example, such factors as type of gasket material, 
weighting of thief hatch covers, release point of pressure relief 
valves, sizing of the storage vessel itself, diameter of lines 
conveying vapor to the control device, sizing of the control device and 
other factors can greatly affect the ability of the system to achieve 
the control efficiency required by the NSPS. Improper design or 
operation of the storage vessel and its control system can result in 
occurrences where peak flow overwhelms the storage vessel and its 
capture systems, resulting in emissions that do not reach the control 
device, effectively reducing the control efficiency. We believe that it 
is essential that operators employ properly designed, sized and 
operated storage vessels to achieve effective emissions control. We 
believe that such efforts on the part of owners and operators can 
result in more effective control of VOC emissions from storage vessels 
subject to the NSPS. Although we are not proposing today to add 
requirements for proper design of storage vessels and associated 
closed-vent systems and control devices, we solicit comment on whether 
such provisions should be included in the final rule.

VII. Technical Corrections and Clarifications

    Following publication of the final NSPS, we subsequently 
determined, following review of the petitions and discussions with 
affected parties, that the final rule warrants correction clarification 
in certain areas. The EPA is proposing corrections to applicability 
dates and monitoring, recordkeeping and reporting requirements for all 
affected facilities. In addition, we are proposing corrections that are 
editorial in nature including typographical and grammatical errors, as 
well as incorrect cross-references. Details of the specific changes we 
are proposing to the regulatory text may be found in the docket for 
this action.\2\
---------------------------------------------------------------------------

    \2\ Memorandum from Moore, Bruce, U.S. EPA, to Docket No. EPA-
HQ-OAR-2010-0505, ``Technical Corrections to the Final Oil and 
Natural Gas Sector New Source Performance Standards.'' January 7, 
2013.
---------------------------------------------------------------------------

VIII. Impacts of This Proposed Rule

    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 controls for this proposed 
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 proposed in this action as they would 
have installed to comply

[[Page 22137]]

with the previously finalized standards. Accordingly, we believe that 
this proposed rule will not result in significant changes in emissions 
of any of the regulated pollutants.

B. What are the energy impacts?

    This proposed 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 proposed 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.

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 proposed in this action as they 
would have chosen to comply with the previously finalized standards, we 
do not anticipate that this proposed 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 proposal 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 proposed 
rule.

IX. 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).
    A RIA was prepared for the April 2012 final rule and can be found 
at: http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf. Because this action does not impose new 
compliance costs on affected sources, we project that this rule will 
result in no significant change in costs, emission reductions or 
benefits in 2015, the year of full implementation of the NSPS.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
Today's notice of reconsideration does not change the information 
collection requirements previously finalized 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 PRA, 
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 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 this proposed rule on 
small entities, I certify that this action will not have a SISNOSE. In 
determining whether a rule has a SISNOSE, the impact of concern is any 
significant adverse economic impact on small entities, since the 
primary purpose of the regulatory flexibility analyses is to identify 
and address regulatory alternatives ``which minimize any significant 
economic impact of the rule on small entities.'' 5 U.S.C. 603 and 604. 
Thus, an agency may certify that a rule will not have a SISNOSE if the 
rule relieves regulatory burden, or otherwise has a positive economic 
effect on all of the small entities subject to the rule.
    The EPA has determined that none of the small entities will 
experience a significant impact because the notice of reconsideration 
imposes no additional compliance costs on owners or operators of 
affected sources. We have therefore concluded that today's notice of 
reconsideration will not result in a SISNOSE. We continue to be 
interested in the potential impacts of the proposed rule on small 
entities and welcome comments on issues related to such impacts.

D. Unfunded Mandates Reform Act of 1995

    This action contains no federal mandates under the provisions of 
Title II of the UMRA of 1995, 2 U.S.C. 1531-1538 for state, local or 
tribal governments or the private sector. The 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 rule is also not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments. This action 
contains no requirements that apply to such governments nor does it 
impose obligations upon them.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the states, on the relationship between 
the national government and the states, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. This proposal 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 EPA 
policy to promote communications between the EPA and state and local 
governments, the EPA specifically solicits comment on this proposed 
action from state and local officials.

[[Page 22138]]

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 Indian tribes or on the distribution 
of power and responsibilities between the federal government and Indian 
tribes, as specified in Executive Order 13175. Thus, Executive Order 
13175 does not apply to this action.
    The EPA specifically solicits additional comment on this proposed 
action from tribal officials.

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

    This action is not subject to Executive Order 13045 (62 FR 19885, 
April 23, 1997) because it is not economically significant as defined 
in Executive Order 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 action has no impacts 
thus health and risk assessments were not conducted.
    The public is 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 NTTAA, Public Law 104-113, 12(d) (15 U.S.C. 
272 note) directs the EPA to use VCS 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 VCS bodies. The 
NTTAA directs the EPA to provide Congress, through OMB, explanations 
when the agency decides not to use available and applicable VCS.
    This proposed rulemaking does not involve technical standards. 
Therefore, the EPA is not considering the use of any VCS.

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

    Executive Order 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 proposed rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment. This proposal is a reconsideration of an existing rule and 
imposes no new impacts or costs.

List of Subjects in 40 CFR Part 60

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

    Dated: March 28, 2013.
Bob Perciasepe,
Acting Administrator.

    For the reasons set out in the preamble, Title 40, chapter I of the 
Code of Federal Regulations is proposed to be 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 paragraph (e) 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 taking into account requirements under a legally and 
practically enforceable limit in an operating permit or by other 
mechanism. 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. A storage vessel that has been 
determined in accordance with Sec.  60.5395(c) to have a potential to 
emit of less than 6 tpy is not a storage vessel affected facility, 
provided that the owner or operator has maintained record of such 
determination.
* * * * *
0
3. Section 60.5380 is amended by:
0
a. Revising paragraph (a)(2); and
0
b. Revising paragraphs (b) and (c).
    The revisions 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 
flow line, as defined in Sec.  60.5430.
    (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 paragraphs (c)(1) and (2).
    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. However, you must comply with 
the requirements in either paragraph (b)(2) or (c)(2), as applicable.
    (a) The requirements of paragraph (b)(1) or (c)(1) of this section 
are not required if you determine that the use

[[Page 22139]]

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.
* * * * *
    (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 as defined in this subpart, 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 as defined in this subpart, you must comply with 
paragraphs (c) through (g) of this section.
    (b) Requirements for Group 1 storage vessel affected facilities. 
(1) You must submit a notification identifying each Group 1 storage 
vessel, including its location, by October 15, 2013.
    (2) On or after April 12, 2013, if you have an event that could 
reasonably be expected to increase VOC emissions from your Group 1 
storage vessel, you must comply with paragraphs (d) through (g) of this 
section. For the purposes of this section, an event includes, but is 
not limited to, the examples specified in paragraphs (b)(2)(i) through 
(iv) of this section.
    (i) Routing a well to the storage vessel that was not previously 
routed to the storage vessel.
    (ii) Conducting hydraulic fracturing on a well routed to the 
storage vessel.
    (iii) Conducting hydraulic refracturing on a well routed to the 
storage vessel.
    (iv) Any other event that could increase the VOC emissions from the 
storage vessel affected facility.
    (c) Emissions determination. You must comply with paragraphs (c)(1) 
or (2) of this section.
    (1) For Group 2 storage vessels constructed, modified or 
reconstructed before April 15, 2014, you must determine the VOC 
emission rate no later than April 15, 2014, or 30 days after startup, 
whichever is later. To make this determination, you must use any 
generally accepted model or calculation methodology. If the VOC 
emission rate is determined to be equal to 6 tpy or greater, you must 
comply with paragraphs (d) through (g) of this section.
    (2) For Group 2 storage vessels constructed on or after April 15, 
2014, you must determine the VOC emission rate using any generally 
accepted model or calculation methodology within 30 days after startup 
and minimize emissions to the extent practicable during the 30-day 
period using good engineering practices through the period prior to 
installation of control. If the VOC emission rate is determined to be 
equal to 6 tpy or greater, you must comply with paragraphs (d) through 
(g) of this section.
    (d) You must comply with the requirements of paragraph (d)(1) or 
(2) of this section.
    (1) Reduce VOC emissions by 95.0 percent or greater by April 15, 
2014 or within 60 days after startup, whichever is later.
    (2) Maintain the VOC emissions from the storage vessel affected 
facility at less than 4 tpy without considering control, 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. You must determine the VOC emission rate each month 
using any generally accepted model or calculation methodology and 
minimize emissions to the extent practicable during this period using 
good engineering practice. Monthly calculations must be separated by at 
least 14 days.
    (e) Control requirements. (1) Except as required in paragraph 
(e)(2) of this section, if you use a control device (such as an 
enclosed combustion device or vapor recovery 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 flow line, as 
defined in Sec.  60.5430. If you route emissions to a flow line, 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).
    (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) Reserved.
    (g) Compliance, notification, recordkeeping, and reporting. If you 
use a control device to reduce emissions or if you route your emissions 
to a flow line, you must comply with paragraphs (g)(1) and (2) of this 
section.
    (1) You must demonstrate initial compliance with standards as 
required by Sec.  60.5410(h).
    (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. Revising paragraph (d) introductory text;
0
f. Revising paragraphs (d)(1) and (2);
0
g. Revising paragraph (d)(4);
0
h. Removing and reserving paragraph (e); and
0
i. Adding paragraphs (h) and (i).
    The revisions and addition 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

[[Page 22140]]

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 
flow line, as defined in Sec.  60.5430.
    (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.
    (8) You must maintain the records as specified in Sec.  
60.5420(c)(2).
* * * * *
    (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.
    (3) * * *
    (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 that is subject to 
Sec.  60.5395(d), you must comply with paragraphs (h)(1) through (5) of 
this section.
    (1) You must determine the VOC emission rate within 30 days after 
startup. You must use good engineering practices to minimize emissions 
during the 30-day period.
    (2) You must reduce VOC emissions by 95.0 percent or greater within 
60 days after startup or by April 15, 2014, whichever is later.
    (3) If you use a control device to reduce emissions, or if you 
route emissions to a flow line, you must demonstrate initial compliance 
by meeting the requirements in paragraphs (h)(3)(i) and (ii) of this 
section. For a Group 1 storage vessel affected facility, you must 
demonstrate initial compliance within 30 days after an event (as 
provided in Sec.  60.5395(b)) or by April 15, 2014, whichever is later. 
For a Group 2 storage vessel affected facility, you must demonstrate 
initial compliance within 60 days after startup or by April 15, 2014, 
whichever is later.
    (i) 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).
    (ii) You must route the closed vent system to a control device that 
meets the conditions specified in Sec.  60.5412(c) and (d) or to a flow 
line, as defined in Sec.  60.5430.
    (4) You must submit the information required for your storage 
vessel affected facility in paragraphs (h)(4)(i) through (iii) of this 
section in the initial annual report required in Sec.  60.5420(b).
    (i) The results of the emissions determination conducted under 
Sec.  60.5395(b) or (c), as applicable, and the methodology used to 
determine emissions.
    (ii) A statement that you have met the requirements of paragraph 
(h)(2) of this section.
    (iii) A statement that you have met the emissions standards in 
Sec.  60.5395(d).
    (5) You must maintain the records required for your storage vessel 
affected facility, as specified in Sec.  60.5420(c)(5) for each storage 
vessel affected facility.
    (i) For each Group 1 storage vessel, you must submit a notification 
identifying each storage vessel, including its location by October 15, 
2013. If you have an event that results in VOC emissions from the Group 
1 storage vessel equal to or greater than 6 tpy after April 12, 2013, 
as specified in Sec.  60.5395(b), you must comply with paragraph (h) of 
this section.
0
7. Section 60.5411 is amended by:
0
a. Revising the section heading;
0
b. Revising paragraph (a) introductory text;
0
c. Revising paragraph (a)(1);
0
d. Revising paragraph (a)(3)(i)(A);
0
e. Revising paragraph (b) introductory text;
0
f. Revising paragraph (b)(1);
0
g. Revising paragraph (b)(2)(iv);
0
h. Adding paragraph (b)(3); and
0
i. 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

[[Page 22141]]

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 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 flow line 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 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 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 to a control device designed and operated in 
accordance with the requirements of paragraph (a) of this section or to 
a flow line, as defined in Sec.  60.5430.
    (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 flow line. 
(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 flow line, as defined in Sec.  60.5430.
    (2) You must design and operate the closed vent system with no 
detectable emissions, as determined using olfactory, visual and 
auditory inspections.
    (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 flow line, as defined in Sec.  60.5430.
    (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 flow line to the atmosphere that 
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 flow line 
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 paragraph (a) introductory text;
0
b. Revising paragraph (a)(1) introductory text;
0
c. Revising paragraph (a)(2);
0
d. Revising paragraph (b);
0
e. Revising paragraph (c) introductory text;
0
f. Revising paragraph (c)(1); and
0
g. 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?

* * * * *
    (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, for a centrifugal 
compressor affected facility, 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 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 analysis 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 (13).
* * * * *
    (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).

[[Page 22142]]

    (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 on-site 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).
0
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 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.

[[Page 22143]]

    (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.
    (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] TP12AP13.000

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

[[Page 22144]]

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 section must submit the information listed in 
paragraphs (d)(12)(i) through (vi) in the test report required by this 
section.
    (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.
    (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 on site 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 paragraph (b) introductory text;
0
b. Revising paragraph (b)(2);
0
c. Revising paragraph (e) introductory text;
0
d. Removing and reserving paragraphs (e)(1) and (2);
0
e. Adding paragraph (e)(3); and
0
f. 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 paragraph (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

[[Page 22145]]

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 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.
    (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 on site 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 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 flow line to meet the requirement of Sec.  60.5395(d)(1).
    (1) [Reserved]
    (2) [Reserved]
    (3) For each storage vessel affected facility subject to Sec.  
60.5395(d)(1), you must comply with paragraphs (e)(3)(i) and (ii) of 
this section.
    (i) You must reduce VOC emissions by 95.0 percent or greater.
    (ii) 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 flow line, 
as defined in Sec.  60.5430, must be operational 95 percent of the year 
or greater.
* * * * *
    (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:
* * * * *

[[Page 22146]]

0
11. Section 60.5416 is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraph (a) introductory text;
0
c. Revising paragraph (a)(1)(ii);
0
d. Revising paragraph (a)(2)(iii);
0
e. Revising paragraph (a)(3)(ii);
0
f. Revising paragraph (b) introductory text,
0
g. Revising paragraph (b)(9) introductory text;
0
h. Revising paragraph (b)(11); and
0
i. 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 or route emissions 
to a flow line, 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 (8) 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, 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 to the atmosphere.
    (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 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

[[Page 22147]]

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.
    (8) Records. Records shall be maintained as specified in this 
section and in Sec.  60.5420(c)(12).
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 
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

[[Page 22148]]

observed, you must clear the obstruction as soon as practicable.
    (B) You must check for liquid reaching 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 maintained 
onsite as specified in Sec.  60.5420(c)(14).
0
13. Section 60.5420 is amended by:
0
a. Revising paragraph (a) introductory text;
0
b. Revising paragraph (a)(1);
0
c. Adding paragraph (a)(3);
0
d. Revising paragraph (b) introductory text;
0
e. Revising paragraph (b)(3)(iii);
0
f. Revising paragraph (b)(5) introductory text;
0
g. Revising paragraph (b)(5)(i);
0
h. Revising paragraphs (b)(6)(i) and (ii);
0
i. Revising paragraphs (b)(7)(i) and (ii);
0
j. Adding paragraph (b)(8);
0
k. Revising paragraph (c) introductory text;
0
l. Revising paragraph (c)(1)(v);
0
m. Revising paragraph (c)(5) introductory text;
0
n. Revising paragraph (c)(5)(ii);
0
o. Adding paragraph (c)(5)(v);
0
p. Revising paragraphs (c)(6) through (11); and
0
q. Adding paragraphs (c)(12) through (14).
    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) through (3) 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).
* * * * *
    (3) You must submit a notification identifying each Group 1 storage 
vessel by October 15, 2013. The notification must contain 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.
    (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 (14) of this section.
* * * * *
    (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 
identification information specified in Sec.  60.5390(b)(2) or Sec.  
60.5390(c)(2).
* * * * *
    (6) * * *
    (i) An identification, including the location, of each storage 
vessel affected facility constructed, modified or reconstructed 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 the requirements in Sec.  60.5395(b) or (c) or as required in Sec.  
60.5395(d)(2).
* * * * *
    (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 http://www.epa.gov/ttn/chief/ert/index.html) 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/OAQPS/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

[[Page 22149]]

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 (14) of this section. All records must be maintained 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).
* * * * *
    (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.
* * * * *
    (ii) Records of each VOC emissions determination for each storage 
vessel affected facility required under Sec.  60.5395(b), (c) and 
(d)(2), as applicable, including identification of the model or 
calculation methodology used to calculate the VOC emission rate.
* * * * *
    (v) You must maintain records of the identification and location of 
each Group 1 storage vessel. If you have an event, as specified in 
Sec.  60.5395(b)(2), that could reasonably be expected to increase VOC 
emissions from your Group 1 storage vessel, you must maintain records 
of the VOC emissions rate determination.
    (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 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) For each closed vent system used to comply with this subpart 
that must operate with no detectable emissions, 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 cover and closed vent system installed on storage 
vessel affected facilities used to comply with Sec.  60.5416(c), a 
record of all inspections.
    (13) 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).
    (14) 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 records must be maintained 
onsite.
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 definition for ``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.
* * * * *
    Group 1 storage vessel means a storage vessel, as defined in this 
section, that is constructed, modified or reconstructed on or after 
August 23, 2011, and before April 12, 2013.
    Group 2 storage vessel means a storage vessel, as defined in this 
section, that is constructed, modified or reconstructed on or 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. 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. Appendix to subpart OOOO of part 60 is amended by revising Tables 1 
and 2 to read as follows:

[[Page 22150]]

       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  88.51X0.0101Y0.0125 or 99.9, whichever is smaller
----------------------------------------------------------------------------------------------------------------
20<=Y<50..............................            79.0  88.51X0.0101Y0.0125 or 97.9, whichever              97.9
                                                         is 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
----------------------------------------------------------------------------------------------------------------

           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              97.5
                                                         is 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. 2013-07873 Filed 4-11-13; 8:45 am]
BILLING CODE 6560-50-P