[Federal Register Volume 83, Number 69 (Tuesday, April 10, 2018)]
[Proposed Rules]
[Pages 15458-15490]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2018-06223]



[[Page 15457]]

Vol. 83

Tuesday,

No. 69

April 10, 2018

Part II





Environmental Protection Agency





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40 CFR Parts 60 and 63





National Emission Standards for Hazardous Air Pollutants and New Source 
Performance Standards: Petroleum Refinery Sector Amendments; Proposed 
Rule

  Federal Register / Vol. 83 , No. 69 / Tuesday, April 10, 2018 / 
Proposed Rules  

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2010-0682; FRL-9976-00-OAR]
RIN 2060-AT50


National Emission Standards for Hazardous Air Pollutants and New 
Source Performance Standards: Petroleum Refinery Sector Amendments

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: This action proposes amendments to the National Emission 
Standards for Hazardous Air Pollutants (NESHAP) Refinery MACT 1 and 
Refinery MACT 2 regulations to clarify the requirements of these rules 
and to make technical corrections and minor revisions to requirements 
for work practice standards, recordkeeping and reporting. This action 
also proposes technical corrections for the New Source Performance 
Standards (NSPS) for Petroleum Refineries.

DATES: Comments. Comments must be received on or before May 25, 2018.
    Under the Paperwork Reduction Act (PRA), comments on the 
information collection provisions are best assured of consideration if 
the Office of Management and Budget (OMB) receives a copy of your 
comments on or before May 10, 2018.
    Public Hearing. If a public hearing is requested by April 16, 2018, 
then we will hold a public hearing on April 25, 2018 at the location 
described in the ADDRESSES section. The last day to pre-register in 
advance to speak at the public hearing will be April 23, 2018.

ADDRESSES: Comments. Submit your comments, identified by Docket ID No. 
EPA-HQ-OAR-2010-0682, at http://www.regulations.gov. Follow the online 
instructions for submitting comments. Once submitted, comments cannot 
be edited or removed from Regulations.gov. Regulations.gov is our 
preferred method of receiving comments. However, other submission 
formats are accepted. To ship or send mail via the United States Postal 
Service, use the following address: U.S. Environmental Protection 
Agency, EPA Docket Center, Docket ID No. EPA-HQ-OAR-2010-0682, Mail 
Code 28221T, 1200 Pennsylvania Avenue NW, Washington, DC 20460. Use the 
following Docket Center address if you are using express mail, 
commercial delivery, hand delivery, or courier: EPA Docket Center, EPA 
WJC West Building, Room 3334, 1301 Constitution Avenue NW, Washington, 
DC 20004. Delivery verification signatures will be available only 
during regular business hours.
    Do not submit electronically any information you consider to be 
Confidential Business Information (CBI) or other information whose 
disclosure is restricted by statute. See section I.C of this preamble 
for instructions on submitting CBI.
    The EPA may publish any comment received to its public docket. 
Multimedia submissions (audio, video, etc.) must be accompanied by a 
written comment. The written comment is considered the official comment 
and should include discussion of all points you wish to make. The EPA 
will generally not consider comments or comment contents located 
outside of the primary submission (i.e., on the Web, cloud, or other 
file sharing system). For additional submission methods, the full EPA 
public comment policy, information about CBI or multimedia submissions, 
and general guidance on making effective comments, please visit https://www2.epa.gov/dockets/commenting-epa-dockets.
    Public Hearing. If a public hearing is requested, it will be held 
at EPA Headquarters, EPA WJC East Building, 1201 Constitution Avenue 
NW, Washington, DC 20004. If a public hearing is requested, then we 
will provide details about the public hearing on our website at: 
https://www.epa.gov/stationary-sources-air-pollution/petroleum-refinery-sector-risk-and-technology-review-and-new-source. The EPA does 
not intend to publish another document in the Federal Register 
announcing any updates on the request for a public hearing. Please 
contact Virginia Hunt at (919) 541-0832 or by email at 
[email protected] to request a public hearing, to register to speak 
at the public hearing, or to inquire as to whether a public hearing 
will be held.
    The EPA will make every effort to accommodate all speakers who 
arrive and register. If a hearing is held at a U.S. government 
facility, individuals planning to attend should be prepared to show a 
current, valid state- or federal-approved picture identification to the 
security staff in order to gain access to the meeting room. An expired 
form of identification will not be permitted. Please note that the Real 
ID Act, passed by Congress in 2005, established new requirements for 
entering federal facilities. If your driver's license is issued by a 
noncompliant state, you must present an additional form of 
identification to enter a federal facility. Acceptable alternative 
forms of identification include: Federal employee badge, passports, 
enhanced driver's licenses, and military identification cards. 
Additional information on the Real ID Act is available at https://www.dhs.gov/real-id-frequently-asked-questions. 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.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed 
action, contact Ms. Brenda Shine, Sector Policies and Programs Division 
(E143-01), Office of Air Quality Planning and Standards, U.S. 
Environmental Protection Agency, Research Triangle Park, North Carolina 
27711; telephone number: (919) 541-3608; fax number: (919) 541-0516; 
and email address: [email protected]. For information about the 
applicability of the NESHAP to a particular entity, contact Ms. Maria 
Malave, Office of Enforcement and Compliance Assurance, U.S. 
Environmental Protection Agency, EPA WJC South Building (Mail Code 
2227A), 1200 Pennsylvania Avenue NW, Washington, DC 20460; telephone 
number: (202) 564-7027; and email address: [email protected].

SUPPLEMENTARY INFORMATION:
    Docket. The EPA has established a docket for this rulemaking under 
Docket ID No. EPA-HQ-OAR-2010-0682. All documents in the docket are 
listed in the 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, is not placed on the internet and will be 
publicly available only in hard copy. Publicly available docket 
materials are available either electronically in Regulations.gov or in 
hard copy at the EPA Docket Center, Room 3334, EPA WJC West Building, 
1301 Constitution Avenue NW, Washington, DC. The Public Reading Room is 
open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding 
legal holidays. The telephone number for the Public Reading Room is 
(202) 566-1744, and the telephone number for the EPA Docket Center is 
(202) 566-1742.
    Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2010-0682. The EPA's policy is that all

[[Page 15459]]

comments received will be included in the public docket 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 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. This type of information should be 
submitted by mail as discussed in section I.C of this preamble. The 
http://www.regulations.gov website 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 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 not include 
special characters or any form of encryption and be free of any defects 
or viruses. For additional information about the EPA's public docket, 
visit the EPA Docket Center homepage at http://www.epa.gov/dockets.
    Preamble Acronyms and Abbreviations. We use multiple acronyms and 
terms in this preamble. While this list may not be exhaustive, to ease 
the reading of this preamble and for reference purposes, the EPA 
defines the following terms and acronyms here:

AFPM American Fuel and Petrochemical Manufacturers
API American Petroleum Institute
AWP Alternative Work Practice
CAA Clean Air Act
CBI Confidential Business Information
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
COMS continuous opacity monitoring system
CPMS continuous parameter monitoring system
CRU catalytic reforming unit
DCU delayed coking unit
EPA Environmental Protection Agency
ERT Electronic Reporting Tool
FCCU fluid catalytic cracking unit
FR Federal Register
HAP hazardous air pollutant(s)
HCN hydrogen cyanide
HON hazardous organic NESHAP
LEL lower explosive limit
MACT maximum achievable control technology
NESHAP national emission standards for hazardous air pollutants
NOCS Notification of Compliance Status
NSPS new source performance standards
NTTAA National Technology Transfer and Advancement Act
OAQPS Office of Air Quality Planning and Standards
OEL open-ended lines
OMB Office of Management and Budget
PDF portable document format
PM particulate matter
PRA Paperwork Reduction Act
PRD pressure relief device
RFA Regulatory Flexibility Act
TTN Technology Transfer Network
UMRA Unfunded Mandates Reform Act
    Organization of this Document. The information in this preamble is 
organized as follows:

I. General Information
    A. Does this action apply to me?
    B. Where can I get a copy of this document and other related 
information?
    C. What should I consider as I prepare my comments for the EPA?
II. Background
III. What actions are we proposing?
    A. Clarifications and Technical Corrections to Refinery MACT 1
    B. Clarifications and Technical Corrections to Refinery MACT 2
    C. Clarifications and Technical Corrections to NSPS Ja
IV. Summary of Cost, Environmental, and Economic Impacts
V. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review and 
Executive Order 13563: Improving Regulation and Regulatory Review
    B. Executive Order 13771: Reducing Regulations and Controlling 
Regulatory Costs
    C. Paperwork Reduction Act (PRA)
    D. Regulatory Flexibility Act (RFA)
    E. Unfunded Mandates Reform Act (UMRA)
    F. Executive Order 13132: Federalism
    G. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    H. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    I. Executive Order 13211: Actions Concerning Regulations That 
Significantly Affect Energy Supply, Distribution, or Use
    J. National Technology Transfer and Advancement Act (NTTAA) and 
1 CFR part 51
    K. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations.

I. General Information

A. Does this action apply to me?

    Table 1 of this preamble lists the NESHAP, NSPS, and associated 
regulated industrial source categories that are the subject of this 
proposal. Table 1 is not intended to be exhaustive, but rather provides 
a guide for readers regarding the entities that this proposed action is 
likely to affect. The proposed standards, once promulgated, will be 
directly applicable to the affected sources. Federal, state, local, and 
tribal government entities would not be affected by this proposed 
action. As defined in the Initial List of Categories of Sources Under 
Section 112(c)(1) of the Clean Air Act Amendments of 1990 (see 57 FR 
31576, July 16, 1992), the Petroleum Refineries--Catalytic Cracking 
(Fluid and Other) Units, Catalytic Reforming Units, and Sulfur Plant 
Units source category includes any facility engaged in producing 
gasoline, napthas, kerosene, jet fuels, distillate fuel oils, residual 
fuel oils, lubricants, or other products from crude oil or unfinished 
petroleum derivatives. This category includes the following refinery 
process units: Catalytic cracking (fluid and other) units, catalytic 
reforming units, and sulfur plant units. The Petroleum Refineries--
Other Sources Not Distinctly Listed includes any facility engaged in 
producing gasoline, napthas, kerosene, jet fuels, distillate fuel oils, 
residual fuel oils, lubricants, or other products from crude oil or 
unfinished petroleum derivatives. This category includes the following 
refinery process units not listed in the Petroleum Refineries--
Catalytic Cracking (Fluid and Other) Units, Catalytic Reforming Units, 
and Sulfur Plant Units source category. The refinery process units in 
this source category include, but are not limited to, thermal cracking, 
vacuum distillation, crude distillation, hydroheating/hydrorefining, 
isomerization, polymerization, lube oil processing, and hydrogen 
production.

    Table 1--NESHAP and Industrial Source Categories Affected by This
                             Proposed Action
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                                                                  NAICS
           Source category                      NESHAP          code \1\
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Petroleum Refineries.................  40 CFR part 63, subpart   324110
                                        CC.
                                       40 CFR part 63, subpart
                                        UUU.
                                       40 CFR part 60, subpart
                                        Ja.
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\1\ North American Industry Classification System.


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B. Where can I get a copy of this document and other related 
information?

    In addition to being available in the docket, an electronic copy of 
this action is available on the internet. Following signature by the 
EPA Administrator, the EPA will post a copy of this proposed action at 
https://www.epa.gov/stationary-sources-air-pollution/petroleum-refinery-sector-risk-and-technology-review-and-new-source. Following 
publication in the Federal Register, the EPA will post the Federal 
Register version of the proposal and key technical documents at this 
same website.
    A redline version of the regulatory language that incorporates the 
proposed changes in this action is available in the docket for this 
action (Docket ID No. EPA-HQ-OAR-2010-0682).

C. What should I consider as I prepare my comments for the EPA?

    Submitting CBI. Do not submit information containing CBI to the EPA 
through http://www.regulations.gov or email. Clearly mark the part or 
all of the information that you claim to be CBI. For CBI information on 
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 comments that includes information claimed 
as CBI, you must submit a copy of the comments that does not contain 
the information claimed as CBI for inclusion in the public docket. If 
you submit a CD-ROM or disk that does not contain CBI, mark the outside 
of the disk or CD-ROM clearly that it does not contain CBI. Information 
not marked as CBI will be included in the public docket and the EPA's 
electronic public docket without prior notice. Information marked as 
CBI will not be disclosed except in accordance with procedures set 
forth in 40 Code of Federal Regulations (CFR) part 2. Send or deliver 
information identified as CBI only to the following address: OAQPS 
Document Control Officer (C404-02), OAQPS, U.S. Environmental 
Protection Agency, Research Triangle Park, North Carolina 27711, 
Attention Docket ID No. EPA-HQ-OAR-2010-0682.

II. Background

    On December 1, 2015 (80 FR 75178), the EPA finalized amendments to 
the Petroleum Refinery NESHAP in 40 CFR part 63, subparts CC and UUU, 
referred to as Refinery MACT 1 and 2, respectively and the NSPS for 
petroleum refineries in 40 CFR part 60, subparts J and Ja. The final 
amendments to Refinery MACT 1 include a number of new requirements, 
such as those for maintenance vents, pressure relief devices (PRDs), 
delayed coking units (DCUs), fenceline monitoring, and flares. The 
final amendments to Refinery MACT 2 include revisions to the continuous 
compliance alternatives for catalytic cracking units and provisions 
specific to startup and shutdown of catalytic cracking units and sulfur 
recovery plants. The December 2015 action also finalized technical 
corrections and clarifications to Refinery NSPS subparts J and Ja to 
address issues raised by the American Petroleum Institute (API) in 
their 2008 and 2012 petitions for reconsideration of the final NSPS Ja 
rule that had not been previously addressed. These include corrections 
and clarifications to provisions for sulfur recovery plants, 
performance testing, and control device operating parameters.
    In the process of implementing these new requirements, numerous 
questions and issues have been identified and we are proposing 
clarifications or technical amendments to address these questions and 
issues. These issues were raised in petitions for reconsideration and 
in separately issued letters from industry and in meetings with 
industry groups.
    The EPA received three separate petitions for reconsideration. Two 
petitions were jointly filed by the API and American Fuel and 
Petrochemical Manufacturers (AFPM). The first of these petitions was 
filed on January 19, 2016, and requested an administrative 
reconsideration under section 307(d)(7)(B) of the Clean Air Act (CAA) 
of certain provisions of Refinery MACT 1 and 2, as promulgated in the 
December 2015 final rule. Specifically, API and AFPM requested that the 
EPA reconsider the maintenance vent provisions in Refinery MACT 1 for 
sources constructed on or before June 30, 2014; the alternate startup, 
shutdown, or hot standby standards for fluid catalytic cracking units 
(FCCUs) constructed on or before June 30, 2014, in Refinery MACT 2; the 
alternate startup and shutdown for sulfur recovery units constructed on 
or before June 30, 2014, in Refinery MACT 2; and the new catalytic 
reforming units (CRUs) purging limitations in Refinery MACT 2. The 
request pertained to providing and/or clarifying the compliance time 
for these sources. Based on this request and additional information 
received, the EPA issued a proposal on February 9, 2016 (81 FR 6814), 
and a final rule on July 13, 2016 (81 FR 45232), fully responding to 
the January 19, 2016, petition for reconsideration. The second petition 
from API and AFPM was filed on February 1, 2016, and outlined a number 
of specific issues related to the work practice standards for PRDs and 
flares, and the alternative water overflow provisions for DCUs, as well 
as a number of other specific issues on other aspects of the rule. The 
third petition was filed on February 1, 2016, by Earthjustice on behalf 
of Air Alliance Houston, California Communities Against Toxics, the 
Clean Air Council, the Coalition for a Safe Environment, the Community 
In-Power and Development Association, the Del Amo Action Committee, the 
Environmental Integrity Project, the Louisiana Bucket Brigade, the 
Sierra Club, the Texas Environmental Justice Advocacy Services, and 
Utah Physicians for a Healthy Environment. The Earthjustice petition 
claimed that several aspects of the revisions to Refinery MACT 1 were 
not proposed, and, thus, the public was precluded from commenting on 
them during the public comment period, including: (1) Work practice 
standards for PRDs and flares; (2) alternative water overflow 
provisions for DCUs; (3) reduced monitoring provisions for fenceline 
monitoring; and (4) adjustments to the risk assessment to account for 
these new work practice standards. On June 16, 2016, the EPA sent 
letters to petitioners granting reconsideration on issues where 
petitioners claimed they had not been provided an opportunity to 
comment. These petitions and letters granting reconsideration are 
available for review in the rulemaking docket (see Docket Item Nos. 
EPA-HQ-OAR-2010-0682-0860, EPA-HQ-OAR-2010-0682-0891 and EPA-HQ-OAR-
2010-0682-0892).
    On October 18, 2016 (81 FR 71661), the EPA proposed for public 
comment the issues for which reconsideration was granted in the June 
16, 2016, letters. The EPA identified five issues in the proposal: (1) 
The work practice standards for PRDs; (2) the work practice standards 
for emergency flaring events; (3) the assessment of risk as modified 
based on implementation of these PRD and emergency flaring work 
practice standards; (4) the alternative work practice (AWP) standards 
for DCUs employing the water overflow design; and (5) the provision 
allowing refineries to reduce the frequency of fenceline monitoring at 
sampling locations that consistently record benzene concentrations 
below 0.9 micrograms per cubic meter. In that notice, the EPA also 
proposed two minor clarifying amendments to correct

[[Page 15461]]

a cross referencing error and to clarify that facilities complying with 
overlapping equipment leak provisions must still comply with the PRD 
work practice standards in the 2015 final rule.
    The February 1, 2016, API and AFPM petition for reconsideration 
included a number of recommendations for technical amendments and 
clarifications that were not specifically addressed in the October 18, 
2016, proposal.\1\ In addition, API and AFPM asked for clarification on 
various requirements of the final amendments in a July 12, 2016, 
letter.\2\ The EPA addressed many of the clarification requests from 
the July 2016 letter and the petition for reconsideration in a letter 
issued on April 7, 2017.\3\ API and AFPM also raised additional issues 
associated with the implementation of the final rule amendments in a 
March 28, 2017, letter to the EPA \4\ and provided a list of 
typographical errors in the rule in a January 27, 2017, meeting \5\ 
with the EPA. On January 10, 2018, AFPM submitted a letter containing a 
comparison of the electronic CFR, CFR, the Federal Register documents, 
and the redline versions of the December 2015 and October 2016 
amendments to the Refinery Sector Rule noting discrepancies providing 
suggestions as to how these discrepancies should be resolved.\6\ These 
items are located in Docket ID No. EPA-HQ-OAR-2016-0682. This proposal 
addresses many of the issues and clarifications identified by API and 
AFPM in their February 2016 petition for reconsideration and their 
subsequent communications with the EPA.
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    \1\ Supplemental Request for Administrative Reconsideration of 
Targeted Elements of EPA's Final Rule ``Petroleum Refinery Sector 
Risk and Technology Review and New Source Performance Standards; 
Final Rule,'' Howard Feldman, API, and David Friedman, AFPM. 
February 1, 2016. Docket Item No. EPA-HQ-OAR-2010-0682-0892.
    \2\ Letter from Matt Todd, API, and David Friedman, AFPM, to 
Penny Lassiter, EPA. July 12, 2016. Available in Docket ID No. EPA-
HQ-OAR-2010-0682.
    \3\ Letter from Peter Tsirigotis, EPA, to Matt Todd, API, and 
David Friedman, AFPM. April 7, 2017. Available at: https://www.epa.gov/stationary-sources-air-pollution/december-2015-refinery-sector-rule-response-letters-qa.
    \4\ Letter from Matt Todd, API, and David Friedman, AFPM, to 
Penny Lassiter, EPA. March 28, 2017. Available in Docket ID No. EPA-
HQ-OAR-2010-0682.
    \5\ Meeting minutes for January 27, 2017, EPA meeting with API. 
Available in Docket ID No. EPA-HQ-OAR-2010-0682.
    \6\ David Friedman, ``Comparison of Official CFR and e-CFR 
Postings Regarding MACT CC/UUU and NSPS Ja Postings.'' Message to 
Penny Lassiter and Brenda Shine. January 10, 2018. Email.
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III. What actions are we proposing?

A. Clarifications and Technical Corrections to Refinery MACT 1

1. Definitions
    We are proposing to clarify the Refinery MACT 1 rule requirements 
by revising several definitions and adding one definition.
a. Flare Purge Gas
    In their March 28, 2017, letter seeking additional clarifications, 
API and AFPM noted that the definition of ``flare purge gas'' could be 
interpreted to preclude the flaring of purge gas that may be introduced 
for safety reasons other than to prevent oxygen infiltration, such as 
to prevent freezing at the flare tip.\7\ They requested that the EPA 
revise the definition to include gas necessary for other safety 
reasons. In the definition of the term, ``flare purge gas,'' we 
included a reference to a primary reason flare purge gas is added at 
the flare tip, namely to prevent oxygen infiltration, but did not 
intend for refiners to interpret this as not allowing them to add flare 
purge gas for other safety reasons. To reflect our intent, we are 
proposing to revise the definition to clarify that flare purge gas may 
also include gas needed for other safety reasons.
---------------------------------------------------------------------------

    \7\ API and AFPM, March 28, 2017.
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b. Flare Supplemental Gas
    In their February 1, 2016, petition for reconsideration, API and 
AFPM requested a change to the definition of ``flare supplemental gas'' 
on the basis that the definition's reference to ``all gas that improves 
the combustion in the flare combustion zone'' could be interpreted to 
include assist air and assist steam. API and AFPM noted, in contrast, 
that the way the term ``flare supplemental gas'' is used throughout the 
rule appears to only include gases that increase combustion efficiency 
by raising the heat content of the combustion zone. This is evidenced 
by the fact that the definition of flare vent gas specifically includes 
flare supplemental gas and specifically excludes total steam or assist 
air. Further, they claimed that the rule incorrectly assumes that 
supplemental gas is always natural gas, and uses the term ``natural 
gas'' in the equations, and, thus, limiting a refiner's ability to use 
fuel gas as supplemental gas.
    We agree that, as written, the definition could be misinterpreted 
and we are proposing to revise the definition of ``flare supplemental 
gas'' at 40 CFR 63.641. We also agree that we did not intend to limit 
flare supplemental gas to only natural gas, so throughout the rule, we 
are proposing to replace all instances of the term ``supplemental 
natural gas'' with the defined term ``flare supplemental gas.'' The 
specific instances of these replacements are provided in Table 2 of 
this preamble (see section III.A.7).
c. Pressure Relief Device and Relief Valve
    In their February 1, 2016, petition for reconsideration, API and 
AFPM noted that Refinery MACT 1 interchangeably uses the term ``relief 
valve'' and the term ``pressure relief device,'' and instead should be 
using the term ``pressure relief device'' throughout because a relief 
valve is only one type of pressure relief device. They requested that a 
definition of pressure relief device be added to Refinery MACT 1 to 
clarify that it includes different types of relief devices, such as 
relief valves and rupture disks. We agree, and we are proposing a 
definition of pressure relief device, proposing to revise the 
definition of relief valve, and proposing to consistently use the term 
``pressure relief device'' throughout the rule.
d. Reference Control Technology for Storage Vessels
    In their February 1, 2016, petition for reconsideration, API and 
AFPM noted that the Refinery MACT 1 storage vessel provisions at 40 CFR 
63.660 require Group 1 storage vessels with floating roofs to comply 
with all the requirements of 40 CFR part 63, subpart WW, including 
requirements for fitting controls. However, the Refinery MACT 1 
definition of ``reference control technology for storage vessels'' at 
40 CFR 63.641 omits reference to these fitting requirements. They 
requested that the EPA revise the definition in 40 CFR 63.641 of 
Refinery MACT 1 to be consistent with the Refinery MACT 1 requirements 
for storage vessels at 40 CFR 63.660. They also noted that the term, 
``reference control technology for storage vessels,'' is never actually 
used in the Refinery MACT 1 storage vessel provisions at 40 CFR 63.660. 
We agree and are revising the definition of reference control 
technology for storage vessels to be consistent with the storage vessel 
rule requirements at 40 CFR 63.660. As it relates to storage vessels, 
the only use of the term, ``reference control technology,'' is in the 
Refinery MACT 1 provisions pertaining to emissions averaging in 40 CFR 
63.652.
2. Miscellaneous Process Vent Provisions
    Petitioners requested a number of amendments and clarifications to 
the

[[Page 15462]]

requirements identifying and managing the subset of miscellaneous 
process vents that result from maintenance activities.
a. Notice of Compliance Status (NOCS) Report
    In their March 28, 2017, letter, API and AFPM noted that the 
miscellaneous process vent provision at 40 CFR 63.643(c) does not 
require an owner or operator to designate a maintenance vent as a Group 
1 or Group 2 miscellaneous process vent. However, they stated that the 
reporting requirements at 40 CFR 63.655(f)(1)(ii) are unclear as to 
whether a NOCS report is needed for maintenance vents. We did not 
intend for the maintenance vents to be included in the NOCS report 
since we do not require the owner or operator to designate a 
maintenance vent as a Group 1 or Group 2 miscellaneous process vent. 
The rule has separate requirements for characterizing, recording, and 
reporting maintenance vents in 40 CFR 63.655 (g)(13) and (h)(12); 
therefore, it is not necessary to identify each and every place where 
equipment may be opened for maintenance in a NOCS report. To clarify, 
we are proposing to add language to 40 CFR 63.643(c) to explicitly 
state that maintenance vents need not be identified in the NOCS report.
b. Availability of a Pure Hydrogen Supply for Compliance With 
Maintenance Vent Provisions
    Under 40 CFR 63.643(c) an owner or operator may designate a process 
vent as a maintenance vent if the vent is only used as a result of 
startup, shutdown, maintenance, or inspection of equipment where 
equipment is emptied, depressurized, degassed, or placed into service. 
Facilities generally must comply with one of three conditions prior to 
venting maintenance vents to the atmosphere (40 CFR 63.643(c)(1)(i-
iii)). However, 40 CFR 63.643(c)(1)(iv) of the rule currently provides 
some flexibility for maintenance vents associated with equipment 
containing pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers) 
at refineries that do not have a pure hydrogen supply. This is because 
catalytic reformer hydrogen (the other primary hydrogen source) 
contains appreciable concentrations of light hydrocarbons which limits 
the ability to reduce the lower explosive limit (LEL) to 10 percent or 
less. For these vents, the LEL of the vapor in the equipment must be 
less than 20 percent, except for one event per year not to exceed 35 
percent.
    API and AFPM requested that the EPA reconsider the standards in 40 
CFR 63.643(c)(1)(iv) for equipment containing pyrophoric catalyst, 
e.g., hydrotreaters or hydrocrackers; in particular, they requested the 
EPA to re-examine the phrase ``. . . at refineries with a pure hydrogen 
supply.'' Specifically, they pointed out that many facilities have a 
pure hydrogen supply that is not used at hydrotreaters or hydrocrackers 
for a variety of reasons, including the fact that these units may be 
far removed from the on-site pure hydrogen production unit and piping 
the pure hydrogen supply to the unit is expensive. In addition, a 
facility could have a pure hydrogen production unit that is idled or 
shut down because a catalytic reforming unit produces adequate hydrogen 
for the facility. Petitioners suggested that the alternative limit for 
equipment containing pyrophoric catalyst should be provided whenever an 
active supply of pure hydrogen is not available at the unit.
    As pyrophoric units (e.g., hydrocrackers and hydrotreaters) require 
hydrogen to operate, at the time we finalized the amendments, we 
expected that pyrophoric units at a refinery with pure hydrogen supply 
would each have a pure hydrogen supply. That is, we did not 
specifically consider that some pyrophoric units at the refinery would 
have a pure hydrogen supply and others would not. We established this 
requirement under the authority of CAA section 112 (c)(2) and (c)(3) to 
address emissions from maintenance events which had been exempted from 
the process vent standards as episodic and non-routine emission sources 
in order to ensure that the maximum achievable control technology 
(MACT) included standards that apply at all times. We based these work 
practices, including those applicable to units without a pure hydrogen 
supply, on practices generally employed by the best performers.
    We reviewed the recent comments received and the additional 
information provided by API and AFPM.\8\ The information confirmed that 
a single refinery may have many pyrophoric units, some that have a pure 
hydrogen supply and some that do not have a pure hydrogen supply. Thus, 
our assumption at the time we issued the final rule regarding which 
units would use a pure hydrogen supply is incorrect. Thus, we are 
proposing to revise the regulations such that units without a pure 
hydrogen supply, even though there may be a pure hydrogen supply 
somewhere else at the facility, could comply with the standard in 40 
CFR 63.643(c)(1)(iv).
---------------------------------------------------------------------------

    \8\ Letter from Matt Todd, API, and David Friedman, AFPM, to 
Penny Lassiter, EPA. August 1, 2017. Available in Docket ID No. EPA-
HQ-OAR-2010-0682.
---------------------------------------------------------------------------

    Specifically, we are proposing to amend 40 CFR 63.643(c)(1)(iv) to 
read (new text highlighted in bold): ``If the maintenance vent is 
associated with equipment containing pyrophoric catalyst (e.g., 
hydrotreaters and hydrocrackers) and a pure hydrogen supply is not 
available at the equipment at the time of the startup, shutdown, 
maintenance, or inspection activity, the LEL of the vapor in the 
equipment must be less than 20 percent, except for one event per year 
not to exceed 35 percent.''
c. Control Requirements for Maintenance Vents
    Paragraph 63.643(a) specifies that Group 1 miscellaneous process 
vents must be controlled by 98 percent or to 20 parts per million by 
volume or to a flare meeting the requirements in 40 CFR 63.670. This 
paragraph also states in the second sentence that requirements for 
maintenance vents are specified in 40 CFR 63.643(c), ``and the owner or 
operator is only required to comply with the requirements in Sec.  
63.643(c).'' Paragraphs (c)(1) through (3) then specify requirements 
for maintenance vents. Paragraph (c)(1) requires that equipment must be 
depressured to a control device, fuel gas system, or back to the 
process until one of the conditions in paragraph (c)(1)(i) through (iv) 
is met. In reviewing these rule requirements, the EPA noted that we did 
not specify that the control device in (c)(1) must also meet 
requirements in paragraph (a). The second sentence in 40 CFR 63.643(a) 
could be misinterpreted to mean that a facility complying with the 
maintenance vent provisions in 40 CFR 63.643(c) must only comply with 
the requirements in paragraph (c) and not the control requirements in 
paragraph (a) for the control device referenced by paragraph (c)(1). 
The second sentence was meant to clarify that there is no obligation 
for characterizing and reporting miscellaneous process vents as Group 1 
and Group 2 if these are maintenance vents. However, we inadvertently 
did not specify control device requirements for the control referenced 
by paragraph (c)(1) in paragraph (c). In omitting these requirements, 
we did not intend that the control requirement for maintenance vents 
prior to atmospheric release would not be compliant with Group 1 
controls as specified under 40 CFR 63.643(a). These control 
requirements

[[Page 15463]]

are consistent with control requirements for other Group 1 
miscellaneous process vents. In order to clarify our intent, we are 
proposing to amend 40 CFR 63.643(c)(1) to read: ``Prior to venting to 
the atmosphere, process liquids are removed from the equipment as much 
as practical and the equipment is depressured to a control device 
meeting requirements in paragraphs (a)(1) or (2) of this section, a 
fuel gas system, or back to the process until one of the following 
conditions, as applicable, is met.''
d. Additional Maintenance Vent Alternative for Equipment Blinding
    We received several requests to address equipment blinding in the 
maintenance venting provisions of 40 CFR 63.643(c). Equipment blinding 
is conducted to isolate equipment for maintenance activities. During 
the installation of the blind flange, a flanged connection in the 
equipment piping must be opened, allowing vapors in the equipment to be 
released to the atmosphere. Additionally, while the piping is open, a 
small amount of purge gas is typically used to ensure air (oxygen) does 
not enter the process equipment. The introduction of purge gas also 
results in emissions.
    In their February 1, 2016, petition for reconsideration, API and 
AFPM requested clarification that emissions that occur when ``opening a 
flange on a CRU reactor to install a blind'' are considered emissions 
from a maintenance vent rather than a CRU vent. Additionally, API 
provided separate submissions with example scenarios and emissions data 
for CRU vents to the EPA on September 11, 2017,\9\ and January 16, 
2018.\10\ In the response to comment document supporting the December 
2015 final rule (see Section 10.2 of Docket Item No. EPA-HQ-OAR-2010-
0682-0802), we noted that only ``catalytic reformer regeneration 
vents'' are excluded from the definition of miscellaneous process vents 
(MPV) and thereby excluded from using the maintenance vent provisions. 
However, we also indicated that other CRU vents could meet the 
definition of a maintenance vent (i.e., an MPV that is only used as a 
result of startup, shutdown, maintenance, or inspection of equipment), 
and that those vents could comply with the maintenance vent provisions 
in 40 CFR 63.643(c). Specifically, we noted that the entire CRU is shut 
down for semi-regenerative units and that the maintenance vent 
provisions may apply in this case. We are clarifying in this preamble 
that vents (separate from the depressurization and purge cycle vent(s) 
covered under Refinery MACT 2) associated with opening a flange to 
install a blind after complete CRU shutdown may comply with the 
maintenance vent provisions.
---------------------------------------------------------------------------

    \9\ Matt Todd, ``Examples.'' Message to Brenda Shine. September 
11, 2017. Email.
    \10\ Karin C. Ritter, ``API Submitting: Flare Flow Meter 
Accuracy White Paper & CRU Data & Summary.'' Message to Penny 
Lassiter and Brenda Shine. January 16, 2018. Email.
---------------------------------------------------------------------------

    In their March 28, 2017, letter, API and AFPM raised additional 
concerns with the maintenance vent requirements and the need to address 
the installation of blinds to isolate equipment for certain maintenance 
activities. They claimed there may be situations where refiners may not 
be able to meet the requirements in 40 CFR 63.643(c)(1)(i) through (iv) 
for maintenance vents, but they must be able to conduct these 
activities. For example, they may not be able to achieve the 10-percent 
LEL criterion in 40 CFR 63.643(c)(1)(i) prior to atmospheric venting 
because a valve used to isolate the equipment will not seat fully so 
organic material may continually leak into the isolated equipment.
    We agree that installing a blind to prepare equipment for 
maintenance may be necessary and may not currently meet the conditions 
specified in 40 CFR 63.643(c)(1). To limit the emissions during the 
blind installation, we are proposing an additional condition addressed 
by the maintenance vent provisions as 40 CFR 63.643(c)(1)(v). We are 
proposing to require depressuring the equipment to 2 pounds (lb) per 
square inch gauge (psig) or less prior to equipment opening and 
maintaining pressure of the equipment where purge gas enters the 
equipment at or below 2 psig during the blind flange installation. The 
low allowable pressure limit will reduce the amount of process gas that 
will be released during the initial equipment opening and ongoing 2-
psig pressure requirement will limit the rate of purge gas use. 
Together, these requirements will limit the emissions during blind 
flange installation and will result in comparable emissions allowed 
under the existing maintenance vent provisions. While we acknowledge 
that there may be circumstances where equipment blinding prior to 
achieving the 10-percent LEL criterion may be necessary, we expect 
these situations to be rare and that the owner or operator would remedy 
the situation as soon as practical (e.g., replace the isolation valve 
or valve seat during the next turnaround in the example provided 
above). Therefore, at 40 CFR 63.643(c)(1)(v), we are proposing that 
this alternative maintenance vent limit be used under those situations 
where the primary limits are not achievable and blinding of the 
equipment is necessary. We are proposing to require refinery owners or 
operators to document each circumstance under which this provision is 
used, providing an explanation why the other criteria could not be met 
prior to equipment blinding and an estimate of the emissions that 
occurred during the equipment blinding process.
e. Recordkeeping for Maintenance Vents on Equipment Containing Less 
Than 72 Pounds (lbs) of Volatile Organic Compounds (VOC)
    Under 40 CFR 63.643(c) an owner or operator may designate a process 
vent as a maintenance vent if the vent is only used as a result of 
startup, shutdown, maintenance, or inspection of equipment where 
equipment is emptied, depressurized, degassed, or placed into service. 
The rule specifies that prior to venting a maintenance vent to the 
atmosphere, process liquids must be removed from the equipment as much 
as practical and the equipment must be depressured to a control device, 
fuel gas system, or back to the process until one of several 
conditions, as applicable, is met (40 CFR 63.643(c)(1)). One condition 
specifies that equipment containing less than 72 lbs/day of volatile 
organic compounds (VOC) can be depressured directly to the atmosphere 
provided that the mass of VOC in the equipment is determined and 
provided that refiners keep records of the process units or equipment 
associated with the maintenance vent, the date of each maintenance vent 
opening, and records used to estimate the total quantity of VOC in the 
equipment at the time of vent opening. Therefore, each maintenance vent 
opening would be documented on an event-basis.
    Industry petitioners noted that there are numerous routine 
maintenance activities, such as replacing sampling line tubing or 
replacing a pressure gauge, that involve potential release of very 
small amounts of VOC, often less than 1 lb per day, that are well below 
the 72 lbs/day of VOC threshold provided in 40 CFR 63.643(c)(1)(iii). 
They claimed that documenting each individual event is burdensome and 
unnecessary. We agree that documentation of each release from 
maintenance vents which serve equipment containing less than 72 lbs of 
VOC is not necessary, as long as there is a demonstration that the 
event is compliant with the requirement that the equipment contains 
less than 72 lbs of VOC. We are, therefore, proposing to revise these 
provisions to require a record demonstrating that the total

[[Page 15464]]

quantity of VOC in the equipment based on the type, size, and contents 
is less than 72 lbs of VOC at the time of the maintenance vent opening. 
However, event-specific records are still required for each maintenance 
vent opening for which the deinventory procedures were not followed or 
for which the equipment opened exceeds the type and size limits 
established in the records for equipment containing less than 72 pounds 
of VOC.
f. Bypass Monitoring for Open-Ended Lines (OEL)
    API and AFPM \11\ requested clarification of the bypass monitoring 
provisions in 40 CFR 63.644(c) for open-ended lines (OEL). This 
provision exempts from bypass monitoring components subject to the 
Refinery MACT 1 equipment leak provisions in 40 CFR 63.648. Noting that 
the provisions in 40 CFR 63.648 only apply to components in organic 
hazardous air pollutant (HAP) service (i.e., greater than 5-weight 
percent HAP), API and AFPM asked whether the EPA also intended to 
exempt open-ended valves or lines that are in VOC service (less than 5-
weight percent HAP) and are capped and plugged in compliance with the 
standards in NSPS subpart VV or VVa or the Hazardous Organic NESHAP 
(HON; 40 CFR part 63, subpart H) that are substantively equivalent to 
the Refinery MACT 1 equipment leak provisions in 40 CFR 63.648. 
Petitioners noted that OELs in conveyances carrying a Group 1 
miscellaneous process vent could be in less than 5-weight percent HAP 
service, but could still be capped and plugged in accordance with 
another rule, such as NSPS subpart VV or VVa or the HON. The EPA agrees 
that, because the use of a cap, blind flange, plug, or second valve for 
an open-ended valve or line is sufficient to prevent a bypass, the 
bypass monitoring requirements in 40 CFR 63.644(c) are redundant with 
NSPS subpart VV in these cases. We are proposing to amend 40 CFR 
63.644(c) to make clear that open-ended valves or lines that are capped 
and plugged sufficiently to meet the standards in NSPS subpart VV at 40 
CFR 60.482-6(a)(2), (b) and (c), are exempt from the bypass monitoring 
in 40 CFR 63.644(c).
---------------------------------------------------------------------------

    \11\ API and AFPM, February 1, 2016, and March 28, 2017.
---------------------------------------------------------------------------

3. Pressure Relief Device Provisions
    In their February 1, 2016, petition, API and AFPM sought 
reconsideration of certain aspects of the requirements for PRDs in 40 
CFR 63.648(j)(1) through (5). As finalized, 40 CFR 63.648(j)(1) 
provides operating requirements for PRDs in organic HAP gas or vapor 
service. Section 63.648(j)(2) specifies pressure release requirements 
for PRDs in organic HAP gas or vapor service. Section 63.648(j)(3) 
(discussed in greater detail below) specifies requirements for pressure 
release management for all PRDs in organic HAP service. Sections 
63.648(j)(4) and (j)(5) provide exemptions from the requirements in 
(j)(1), (2), and (3) if all releases and potential leaks from a PRD are 
routed through a compliant control device or if the PRDs meet certain 
criteria.
    As noted above, 40 CFR 63.648(j)(3) specifies requirements for 
pressure release management for all PRDs in organic HAP service, 
specifically: (j)(3)(i) provides requirements for monitoring affected 
PRDs; (j)(3)(ii) lists options for three redundant release prevention 
measures that must be applied to affected PRDs; (j)(3)(iii) requires 
root cause analysis and corrective action if an affected PRD releases 
to the atmosphere as a result of a pressure release event; (j)(3)(iv) 
stipulates how the facility must determine the number of release events 
during the calendar year for each affected PRD; and (j)(3)(v) specifies 
what release events are deemed a violation of the pressure release 
management work practice standards. Section 63.648(j)(5) identifies the 
types of PRDs exempted from pressure release management requirements in 
(j)(3).
a. Clarification of Requirements for PRD ``in organic HAP service''
    Regarding the applicability of the PRD requirements in 40 CFR 
63.648(j), API and AFPM requested that we clarify whether releases 
listed in paragraph 40 CFR 63.648(j)(3)(v) are limited to PRDs ``in 
organic HAP service.'' The heading for 40 CFR 63.648(j)(3)(v), i.e., 40 
CFR 63.648(j)(3) unambiguously states that the ``requirements specified 
in paragraphs (j)(3)(i) through (v) of this section'' apply to ``all 
pressure relief devices in organic HAP service'' and reflects the 
Agency's intent when promulgating these provisions. Subparagraphs 
(j)(3)(i) through (iv) use the phrase ``affected pressure relief 
device,'' and for consistency and clarity, we are proposing to add that 
phrase--``affected pressure relief device''-- to paragraph (j)(3)(v) to 
clarify that the requirements in (j)(3)(v) also apply only to releases 
from PRDs that are in organic HAP service.
    We also are proposing to amend the introductory text in paragraph 
(j). Currently, paragraph (j) states ``Except as specified in 
paragraphs (j)(4) and (5) of this section, the owner or operator must 
also comply with the requirements specified in paragraph (j)(3) of this 
section for all pressure relief devices.'' For consistency and clarity, 
we are proposing to add ``in organic HAP service'' to the end of this 
sentence to clearly indicate that the word ``all'' includes organic HAP 
liquid service PRDs.
b. Redundant Release Prevention Measures in 40 CFR 63.648(j)(3)(ii)
    As stated earlier, section (j)(3)(ii) lists options for three 
redundant release prevention measures that must be applied to affected 
PRDs. The prevention measures in (j)(3)(ii) include: (A) Flow, 
temperature, level, and pressure indicators with deadman switches, 
monitors, or automatic actuators; (B) documented routine inspection and 
maintenance programs and/or operator training (maintenance programs and 
operator training may count as only one redundant prevention measure); 
(C) inherently safer designs or safety instrumentation systems; (D) 
deluge systems; and (E) staged relief system where initial pressure 
relief valve (with lower set release pressure) discharges to a flare or 
other closed vent system and control device.
    The API and AFPM February 1, 2016, petition for reconsideration 
requested clarification as to whether two prevention measures can be 
selected from the list in 40 CFR 63.648(j)(3)(ii)(A). The rule does not 
state that the measures in paragraph (j)(3)(ii)(A) are to be considered 
a single prevention measure. These measures were grouped in 
subparagraph A because of similarities they have; however, they are 
separate measures. For example, a liquid level monitor discontinues the 
feed to the unit when the liquid level exceeds a set point and an 
overhead pressure monitor discontinues the feed to the unit if the 
pressure exceeds a certain level. If these measures operate 
independently, the EPA considers them two separate redundant prevention 
measures--that is, if the pressure exceeds a certain set point, then 
the feed to the unit is discontinued regardless of the liquid level and 
vice a versa. If both the pressure limit and the liquid level must be 
exceeded to trigger shutting off the feed to the unit, then that would 
be considered a single prevention measure. We also note that there may 
be occasions where the same type of monitor is used, but the parameter 
monitored is different. For example, a temperature monitor on the feed 
to a unit may be used to trigger feed shut-off to the unit, and a 
separate temperature monitor may be used for the vessel

[[Page 15465]]

overhead that also triggers feed shut-off to the unit. As the 
temperature monitors are not monitoring the same process stream and the 
actions of the monitors are independent, these systems would be 
considered two separate ``redundant prevention measures.'' To clarify 
this, we are proposing to revise 40 CFR 63.648(j)(3)(ii)(A) to make 
clear that independent, non-duplicative systems count as separate 
redundant prevention measures.
c. Pilot-Operated PRD and Balanced Bellows PRD
    In a letter dated March 28, 2017, API and AFPM requested 
clarification on whether pilot-operated PRDs are required to comply 
with the pressure release management provisions of 40 CFR 63.648(j)(1) 
through (3).
    A pilot-operated or balanced bellows PRD is often used to relieve 
back pressure so that the main PRD with which it is associated can be 
routed to a control device, back into the process or to the fuel gas 
system. Pilot-operated and balanced bellows PRDs are primarily used for 
pressure relief when the back pressure of the discharge vent may be 
high or variable. Conventional pressure relief devices act on a 
differential pressure between the process gas and the discharge vent. 
If the discharge vent pressure increases, the vessel pressure at which 
the PRD will open increases, potentially leading to vessel over-
pressurization that could cause vessel failure. For systems that have 
high or variable back pressure, either balanced bellows or pilot-
operated PRDs are used. Balanced bellows PRDs use a bellow to shield 
the pressure relief stem and top portion of the valve seat from the 
discharge vent pressure. A balanced bellows PRD will not discharge gas 
to the atmosphere during a release event, except for leaks through the 
bellows vent due to bellows failure or fatigue. Pilot-operated PRDs use 
a small pilot safety valve that discharges to the atmosphere to effect 
actuation of the main valve or piston, which then discharges to a 
control device. Balanced bellows or pilot operated PRDs are a 
reasonable and necessary means to safely control the primary PRD 
release.
    Pilot-operated and balanced bellows PRDs are subject to the 
requirements at 40 CFR 63.648(j)(1) and (2) to ensure the PRDs do not 
leak and properly reseat following a release. However, based on our 
understanding of pilot-operated PRDs (see memorandum, ``Pilot-operated 
PRD,'' in Docket ID No. EPA-HQ-OAR-2010-0682) and balanced bellows 
PRDs, we are proposing that these PRDs are not subject to the 
requirements of 40 CFR 63.648(j)(3).
    Section 63.648(j)(5) identifies the types of PRDs not subject to 
the pressure release management requirements in (j)(3). These include 
PRDs that do not have the potential to emit 72 lbs/day or more of VOC 
based on the valve diameter, the set release pressure, and the 
equipment contents (40 CFR 63.648(j)(5)(v)). In most cases, we expect 
that pilot-operated PRDs would release less than 72 lbs of VOC/day. 
However, this provision does not apply to all pilot vents because some 
have the potential to emit greater than 72 lbs/day of VOC. Even for 
releases greater than 72 lbs/day of VOC, we agree that the root cause 
analysis and corrective action is not necessary because the main 
release vent is not an atmospheric vent, but is instead routed to the 
flare header. Unless this event contributes to a flaring event 
resulting in visible emissions or velocity exceedance, the flare is 
operating as intended and controlling the PRD release. Although we 
expect pilot vent discharges will release less than 72 lbs/day of VOC, 
to ensure these vent discharges are indeed small, and to encourage low-
emitting (e.g., non-flowing) pilot-operated PRDs, we are proposing to 
amend the reporting requirements at 40 CFR 63.655(g)(10) and the 
recordkeeping requirements at 40 CFR 63.655(i)(11) to retain the 
requirements to report and keep records of each release to the 
atmosphere through the pilot vent that exceeds 72 lbs/day of VOC, 
including the duration of the pressure release through the pilot vent 
and the estimate of the mass quantity of each organic HAP release.
4. Delayed Coking Unit Decoking Operation Provisions
    The provisions in 40 CFR 63.657(a) require owners or operators of 
DCU to depressure each coke drum to a closed blowdown system until the 
coke drum vessel pressure or temperature meets the applicable limits 
specified in the rule (2 psig or 220 degrees Fahrenheit for existing 
sources). Special provisions are provided in 40 CFR 63.657(e) and (f) 
for DCU using ``water overflow'' or ``double-quench'' method of 
cooling, respectively. According to 40 CFR 63.657(e), the owner or 
operator of a DCU using the ``water overflow'' method of coke cooling 
must hardpipe the overflow water (i.e., via an overhead line) or 
otherwise prevent exposure of the overflow water to the atmosphere when 
transferring the overflow water to the overflow water storage tank 
whenever the coke drum vessel temperature exceeds 220 degrees 
Fahrenheit. The provision in 40 CFR 63.657(e) also provides that the 
overflow water storage tank may be an open or fixed-roof tank provided 
that a submerged fill pipe (pipe outlet below existing liquid level in 
the tank) is used to transfer overflow water to the tank.
    In the October 18, 2016, reconsideration proposal, we opened the 
provisions in 40 CFR 63.657(e) for public comment, but we did not 
propose to amend the requirements. In response to the October 18, 2016, 
reconsideration proposal, we received several comments regarding the 
provisions in 40 CFR 63.657(e) for DCU using the water overflow method 
of coke cooling. API and AFPM wanted clarification that the water 
overflow requirements in 40 CFR 63.657(e) are only applicable if the 
primary pressure or temperature limits in 40 CFR 63.657(a) were not met 
prior to overflowing any water. We agree that an owner or operator of a 
DCU with a water overflow design does not need to comply with the 
provisions in 40 CFR 63.657(e) unless they cannot comply with the 
primary pressure or temperature limits in 40 CFR 63.657(a) prior to 
overflowing any water. However, if water overflow is used before the 
primary pressure or temperature limits in 40 CFR 63.657(a) are met, 
then the owner or operator must use ``controlled'' water overflow until 
the applicable temperature limit is achieved. This is required because 
the primary pressure limits are based on the vessel pressure, which is 
the pressure of the gas at the top of the coke drum, and once the water 
starts to overflow, we do not consider the pressure in the liquid 
filled overhead line to be representative of the DCU vessel pressure. 
We are proposing to clarify these points in 40 CFR 63.657(e).
    In addition, environmental petitioners questioned whether the 
submerged fill requirement would effectively reduce emissions if gas is 
entrained into the overflow water leaving the coke drum such that the 
gas could then be emitted to the air out of the overflow water storage 
tank. We reviewed schematics of water overflow design DCU and found 
that a typical water overflow DCU uses a separator to prevent gas 
entrainment with the overflow water.\12\ The overhead gas from the 
separator is routed to the DCU's closed blowdown system. The liquids 
accumulate at the bottom of the separator and are then routed to a 
storage vessel. We do not have information on the design of all

[[Page 15466]]

water overflow DCUs. If there are DCUs that do not use a separator, it 
is possible to entrain gases with the DCU water overflow and the 
submerged fill requirement would not effectively reduce emissions from 
the overflow water storage tank if gas is entrained in the water 
overflow. Therefore, we are also proposing to add provisions to 40 CFR 
63.657(e) requiring the use of a separator or disengaging device 
operated in a manner to prevent entrainment of gases from the coke drum 
vessel to the overflow water storage tank. Gases from the separator 
must be routed to a closed vent blowdown system or otherwise controlled 
following the requirements for a Group 1 miscellaneous process vent. As 
separators appear to be an integral part of the water overflow system 
design, we are not projecting any capital investment or additional 
operating costs associated with this proposed amendment.
---------------------------------------------------------------------------

    \12\ Email correspondence from Dave Pavlich, Phillips 66, to 
Brenda Shine, EPA. March 6, 2017. Available in Docket ID No. EPA-HQ-
OAR-2010-0682.
---------------------------------------------------------------------------

5. Fenceline Monitoring Provisions
    We are proposing several amendments to the fenceline monitoring 
provisions in Refinery MACT 1. Many of the proposed revisions to the 
fenceline monitoring provisions are related to requirements for 
reporting monitoring data.
    The December 1, 2015, final rule established provisions for 
monitoring fugitive emissions at refinery fencelines (40 CFR 63.658). 
Under the fenceline monitoring provisions, an owner/operator must 
monitor benzene concentrations around the perimeter (fenceline) of 
their facility using a network of passive air monitors that contain 
sorbent tubes (40 CFR 63.658(c)). Facilities are required to collect 
the tubes and analyze them for benzene every 2 weeks (40 CFR 
63.658(e)), but may request an alternative test method for collecting 
and/or analyzing samples (40 CFR 63.658(k)). Facilities must then 
calculate the difference in the highest and lowest 2-week benzene 
concentrations reported at the facility fenceline, called the [Delta]c 
(40 CFR 63.658(f)). If the annual rolling average [Delta]c exceeds an 
action level of 9 micrograms per cubic meter ([micro]g/m\3\) benzene 
(40 CFR 63.658(f)(3)), the facility must conduct a root cause analysis 
and implement initial corrective action (40 CFR 63.658(g)). If the 
annual rolling [Delta]c value for the next 2-week sampling period after 
the initial corrective action is greater than 9 [micro]g/m\3\, or if 
all corrective action measures identified require more than 45 days to 
implement, the owner or operator must develop a corrective action plan 
(40 CFR 63.658(h)).
    The December 1, 2015, final rule included new EPA Methods 325A and 
B specifying monitor siting and quantitative sample analysis 
procedures. Method 325A requires an additional monitor be placed near 
known VOC emission sources if the VOC emissions source is located 
within 50 meters of the monitoring perimeter and the source is between 
two monitors. The December 1, 2015, final rule at 40 CFR 63.658(c)(1) 
provides ``known sources of VOCs . . . means a wastewater treatment 
unit, process unit, or any emission source requiring control according 
to the requirements of this subpart, including marine vessel loading 
operations.'' In their February 1, 2016, petition for reconsideration, 
API and AFPM recommended that the EPA exclude sources requiring control 
under the miscellaneous process vent requirements of 40 CFR 63.643 and 
the equipment leak requirements of 40 CFR 63.648 from the known sources 
of VOC specified in 40 CFR 63.658(c)(1) so that these emission sources 
would not trigger the need for additional fenceline monitors. In 
response, we are proposing an alternative to the additional monitor 
siting requirement for pumps, valves, connectors, sampling connections, 
and open-ended lines sources that are actively monitored monthly using 
audio, visual, or olfactory means and quarterly using Method 21 or the 
AWP. We believe this is reasonable because these sources may be 
insignificant and, under these circumstances, the timeframe for 
discovery of a leak (1 month to 3 months) and repair (within 15 days of 
discovery) is consistent with the timeframe needed to analyze a passive 
monitor sample (45 days) and complete the initial root cause analysis 
and corrective action (45 days after discovery). We consider this 
requirement to be an adequate alternative to the additional monitor 
requirement.
    In their February 1, 2016, petition for reconsideration, API and 
AFPM suggested that if the [Delta]c for the 2-week sampling period 
following an exceedance of the annual average [Delta]c action level is 
9 [micro]g/m\3\ or less, then appropriate corrective action measures 
may be assumed to already be implemented and the root cause analysis 
and corrective action analysis does not need to be performed. We are 
clarifying in this preamble that if a root cause analysis was performed 
and corrective action measures were implemented prior to the exceedance 
of the annual average [Delta]c action level, then these documented 
actions can be used to fulfill the root cause analysis and corrective 
action requirements in 40 CFR 63.658(g) and recordkeeping in 40 CFR 
63.655(i)(8)(viii).
    In addition, we are proposing a revision to the reporting 
requirements for the fenceline data in 40 CFR 63.655(h)(8). Consistent 
with requests from API and AFPM in their February 1, 2016, petition for 
reconsideration, we are proposing that the quarterly reports are to 
cover calendar year quarters (i.e., Quarter 1 is from January 1 through 
March 31; Quarter 2 is from April 1 through June 30; Quarter 3 is from 
July 1 through September 30; and Quarter 4 is from October 1 through 
December 31) rather than being directly tied to the date compliance 
monitoring began. This proposed change will simplify reporting by 
putting all refinery reports on the same schedule and reducing 
confusion regarding when refiners are required to report, especially if 
they own more than one facility.
    We are also proposing several measures that would reduce burden and 
clarify reporting associated with collecting and analyzing quality 
assurance/quality control samples (field blanks and duplicates) 
associated with the fenceline monitoring requirements in 40 CFR 
63.658(c)(3). First, we are proposing to require only one field blank 
per sampling period rather than two as currently required. Second, we 
are proposing to decrease the number of duplicate samples that must be 
collected each sample period. Instead of requiring a duplicate sample 
for every 10 monitoring locations, we propose that facilities with 19 
or fewer monitoring locations only be required to collect one duplicate 
sample per sampling period and facilities with 20 or more sampling 
locations only be required to collect two duplicate samples per 
sampling period. These proposed changes reflect current practices and 
the needed quality assurance/quality control of blanks and samples. The 
reduced need for quality assurance/quality control samples is a result 
of enhancement and refinement of sample preparation and sorbent tube 
manufacturing, leading to an increase in precision of blanks and lower 
levels of containments in blanks as compared to the developmental stage 
of the method.
    We received questions during the fenceline reporting webinars on 
how to report duplicate sample results and whether duplicate sample 
results are to be used in the calculation of [Delta]c. Because there 
are two analytical results for each set of duplicate samples and the 
final rule was unclear on how to report these results, facilities were 
uncertain whether they should choose one of the two results for use in 
the calculation of

[[Page 15467]]

[Delta]c or whether the results should be averaged. In order to clarify 
how the results of the duplicate sample analyses are to be used, we are 
proposing to require that duplicate samples be averaged together to 
determine the sampling location's benzene concentration for the 
purposes of calculating [Delta]c.
    Consistent with the requirements in 40 CFR 63.658(k) for requesting 
an alternative test method for collecting and/or analyzing samples, we 
are proposing to revise the Table 6 entry for 40 CFR 63.7(f) to 
indicate that 40 CFR 63.7(f) applies except that alternatives directly 
specified in 40 CFR part 63, subpart CC do not require additional 
notification to the Administrator or the approval of the Administrator. 
We also are proposing editorial revisions to the fenceline monitoring 
section; these proposed revisions are included in Table 2 in section 
III.A.7 of this preamble.
6. Flare Control Device Provisions
    API and AFPM requested clarification in a December 1, 2016, letter 
to EPA \13\ regarding assist steam line designs that entrain air into 
the lower or upper steam at the flare tip. The industry representatives 
noted that many of the steam-assisted flare lines have this type of air 
entrainment and likely were part of the dataset analyzed to develop the 
standards established in the 2015 final rule for steam-assisted flares. 
API and AFPM, therefore, maintain that these flares should not be 
considered to have assist air, and that they are appropriately and 
adequately regulated under the final standards for steam-assisted 
flares. Because flares with assist air are required to comply with both 
a combustion zone net heating value (NHVcz) and a net 
heating value dilution parameter (NHVdil), there is 
increased burden in having to comply with two operating parameters, and 
API and AFPM contend that this burden is unnecessary.
---------------------------------------------------------------------------

    \13\ Letter from Matt Todd, API, and David Friedman, AFPM, to 
Penny Lassiter, EPA. December 1, 2016. Available in Docket ID No. 
EPA-HQ-OAR-2010-0682.
---------------------------------------------------------------------------

    Assist air is defined to mean all air intentionally introduced 
prior to or at a flare tip through nozzles or other hardware conveyance 
for the purposes including, but not limited to, protecting the design 
of the flare tip, promoting turbulence for mixing, or inducing air into 
the flame. Assist air includes premix assist air and perimeter assist 
air. Assist air does not include the surrounding ambient air. Air 
entrainment through steam nozzles is intentionally introduced prior to 
or at the flare tip and, therefore, it is considered assist air. 
However, if this is the only assist air introduced prior to or at the 
flare tip, it is reasonable in most cases for the owner or operator to 
only need to comply with the NHVcz operating limit. This is 
because an exceedance of the NHVcz operating limit would 
also cause an exceedance of the NHVdil operating limit in 
many cases.
    We calculated the amount of air that must be entrained in the steam 
to cause a flare meeting the NHVcz operating limit of 270 
British thermal units per standard cubic foot (Btu/scf) to be below the 
NHVdil operating limit of 22 Btu per square foot (Btu/
ft\2\). The NHVdil parameter is a function of flare tip 
diameter. For flare tips with an effective tip diameter of 9 inches or 
more, there are no flare tip steam induction designs that can entrain 
enough assist air to cause a flare operator to have a deviation of the 
NHVdil operating limit without first deviating from the 
NHVcz operating limit. Therefore, we are proposing to allow 
owners or operators of flares whose only assist air is from perimeter 
assist air entrained in lower and upper steam at the flare tip and with 
a flare tip diameter of 9 inches or greater to comply only with the 
NHVcz operating limit.
    Steam-assisted flares with perimeter assist air and an effective 
tip diameter of less than 9 inches would remain subject to the 
requirement to account for the amount of assist air intentionally 
entrained within the calculation of NHVdil. We recognize 
that this assist air cannot be directly measured, but the quantity of 
air entrained is dependent on the assist steam rate and the design of 
the steam tube's air entrainment system. We are proposing to add 
provisions to specify that owners or operators of these smaller 
diameter steam-assisted flares use the steam flow rate and the maximum 
design air-to-steam ratio of the steam tube's air entrainment system 
for determining the flow rate of this assist air. Using the maximum 
design ratio will tend to over-estimate the assist air flow rate, which 
is conservative with respect to ensuring compliance with the 
NHVdil operating limit.
    In addition to these revisions, for air assisted flares, we also 
are providing clarification on determining air flow rates. While we 
specifically provided for the use of engineering calculations for 
determining the flow rate, we received questions in the February 1, 
2016, petition as to whether or not this allowed the use of fan curves 
for determining air assist flow rates. In the December 2015 final rule 
in the introductory paragraph of 40 CFR 63.670(i), we stated that 
continuously monitoring fan speed or power and using fan curves is an 
acceptable method for continuously monitoring assist air flow rates. To 
further clarify this point, we are proposing to include specific 
provisions for continuously monitoring fan speed or power and using fan 
curves for determining assist air flow rates.
    In response to the February 1, 2016, petition for reconsideration 
from API and AFPM, we are also proposing to clarify the requirements 
for conducting visible emissions monitoring. API and AFPM raised a 
concern that the current language in 40 CFR 63.670(h) is unclear and 
could be interpreted to require facilities to flare regulated materials 
in order to conduct the required visible emissions monitoring. We 
recognize that many flares are used only during startup, shutdown, or 
emergency events and we agree that it is not reasonable to require 
refiners to flare regulated materials intentionally in order to conduct 
a visible emissions compliance demonstration. We are proposing to 
clarify that the initial 2-hour visible emissions demonstration should 
be conducted the first time regulated materials are routed to the 
flare. We are also proposing to clarify 40 CFR 63.670(h)(1) to provide 
that the daily 5-minute observations must only be conducted on days the 
flare receives regulated material and that the additional visible 
emissions monitoring is specific to cases when visible emissions are 
observed while regulated material is routed to the flare.
    API and AFPM requested in their February 1, 2016, petition for 
reconsideration that we specify the averaging period for establishing 
the limit for the smokeless capacity of the flare and that it be a 15-
minute average consistent with other flow parameters and velocity 
requirements. Owners or operators would use the cumulative flow rate 
and/or flare tip velocity determined according to 40 CFR 63.670(k) for 
assessing exceedances of the smokeless capacity, and this flow rate is 
specifically determined on a 15-minute block average. Consistent with 
these requirements, we are proposing to clarify, at 40 CFR 
63.670(o)(1)(iii)(B), that the owner or operator must establish the 
smokeless capacity of the flare in a 15-minute block average and at 40 
CFR 63.670(o)(3)(i) that the exceedance of the smokeless capacity of 
the flare is based on a 15-minute block average. We are also correcting 
an error in the units for the cumulative volumetric flow used in the 
flare tip velocity equation in 40 CFR

[[Page 15468]]

63.670(k)(3). We are revising the units to specify standard cubic feet 
rather than actual cubic feet consistent with the cumulative volumetric 
flow monitoring requirements in 40 CFR 63.670(i)(1) and as stated in 
our response to public comments (Docket Item No. EPA-HQ-OAR-2010-0682-
0802) in the discussion under 3.3.5.-Velocity Limit and Calculation 
Method. These specific edits are included in the summary of editorial 
corrections provided in Table 2 of his preamble (see section III.A.7).
    Industry stakeholders with input from vendors have also made 
submissions 14 15 16 expressing concerns over the ability to 
meet the flare vent gas flow rate minimum accuracy requirements in 40 
CFR 60.107a(f)(1)(ii) and in Table 13 of 40 CFR part 63, subpart CC 
when vent streams have low molecular weight. These requirements specify 
an accuracy of 20 percent of the flow rate at velocities 
ranging from 0.1 to 1 foot per second and an accuracy of 5 
percent of the flow rate for velocities greater than 1 foot per second. 
Stakeholders stated that the accuracy requirements could not be met for 
some historical flow events when molecular weight of the flare vent gas 
was low, including: plant power outages caused by weather, compressor 
surges due to lightning strikes, compressor shutdowns due to high 
vibration events, hydrogen plant startup and shutdown, CRU plant 
startups, flare header maintenance activities and routing of high 
hydrogen process streams to the flare during maintenance events and 
process upsets. The EPA recognizes that flares can receive a wide range 
of process streams over a wide range of flows. We are clarifying in 
this preamble that certification of compliance for these flare vent gas 
flow meter accuracy requirements can be made based on the typical range 
of flare gas compositions expected for a given flare.
---------------------------------------------------------------------------

    \14\ Kris A. Battleson, ``Chevron-vendor information for call at 
12 PDT, 3 EDT.'' Message to Gerri Garwood and Brenda Shine. August 
29, 2017. Email.
    \15\ Kris A. Battleson, ``meter QA/QC.'' Message to Brenda 
Shine. September 19, 2017. Email.
    \16\ Karin C. Ritter, ``API Submitting: Flare Flow Meter 
Accuracy White Paper & CRU Data & Summary.'' Message to Penny 
Lassiter and Brenda Shine. January 16, 2018. Email.
---------------------------------------------------------------------------

7. Other Corrections
    We received comments from API and AFPM in their February 1, 2016, 
petition for reconsideration regarding the incorporation of 40 CFR part 
63, subpart WW storage vessel provisions and 40 CFR part 63, subpart SS 
closed vent systems and control device provisions into Refinery MACT 1 
requirements for Group 1 storage vessels at 40 CFR 63.660. The pre-
amended version of the Refinery MACT 1 rule specified (by cross 
reference at 40 CFR 63.646) that storage vessels containing liquids 
with a vapor pressure of 76.6 kilopascals (11.0 pounds per square inch 
(psi)) or greater must be vented to a closed vent system or to a 
control device consistent with the requirements in the HON. The 
petitioners pointed out that the EPA did not retain this provision at 
40 CFR 63.660 in the December 2015 final rule. In reviewing the 
introductory text at 40 CFR 63.660, we agree that the language was 
inadvertently omitted. We did not intend to deviate from the 
longstanding requirement limiting the vapor pressure of material that 
can be stored in a floating roof tank. We are, therefore, proposing to 
revise the introductory text in 40 CFR 63.660 to clarify that owners or 
operators of affected Group 1 storage vessels storing liquids with a 
maximum true vapor pressure less than 76.6 kilopascals (11.0 psi) can 
comply with either the requirements in 40 CFR part 63, subpart WW or SS 
and that owners or operators storing liquids with a maximum true vapor 
pressure greater than or equal to 76.6 kilopascals (11.0 psi) must 
comply with the requirements in 40 CFR part 63, subpart SS.
    We also received comments from API and AFPM in their February 1, 
2016, petition for reconsideration regarding provisions in 40 CFR 
63.660(b). Section 63.660(b)(1) allows Group 1 storage vessels to 
comply with alternatives to those specified in 40 CFR 63.1063(a)(2) of 
subpart WW. Section 63.660(b)(2) specifies additional controls for 
ladders having at least one slotted leg. The petitioners explained that 
40 CFR 63.1063(a)(2)(ix) provides extended compliance time for these 
controls, but that it is unclear whether this additional compliance 
time extends to the use of the alternatives to comply with 40 CFR 
63.660(b). We are proposing language to make clear that the additional 
compliance time applies to the implementation of controls in 40 CFR 
63.660(b).
    We received several questions from industry pertaining to the 
requirement in paragraphs 40 CFR 63.655(f) and 40 CFR 63.655(f)(6) to 
submit a NOCS report. The final rule allows sources that are newly 
subject to Refinery MACT 1 to submit the NOCS in a periodic report 
rather than in a separate notification submission (40 CFR 
63.655(f)(6)). It is reasonable that any source with a compliance date 
on or after February 1, 2016, should be able to follow the same 
approach. We are proposing to amend paragraphs 40 CFR 63.655(f) and 40 
CFR 63.655(f)(6) to expressly provide that sources having a compliance 
date on or after February 1, 2016, may submit the NOCS in the periodic 
report rather than as a separate submission.
    We are also proposing to clarify at 40 CFR 63.660(e) that the 
initial inspection requirements that applied with initial filling of 
the storage vessels are not required again simply because the source 
transitions from the requirements in 40 CFR 63.646 to 40 CFR 63.660.
    We also received comments from API and AFPM \17\ that the deadlines 
in the December 2015 final rule for reporting results of performance 
tests are inconsistent. The electronic reporting requirements in 40 CFR 
63.655(h)(9) provide that the results of performance tests must be 
reported within 60 days of completing the performance test, while the 
NOCS report in 40 CFR 63.655(f), which is required to contain the 
performance test results, is due 150 days from the compliance date in 
the rule. We note that while some performance tests may be required 
prior to the requirement to submit the NOCS report, others may be 
performed when no NOCS report is due. We are proposing revisions to 40 
CFR 63.655(f)(1)(i)(B)(3) and (C)(2), (f)(1)(iii), (f)(2), and (f)(4) 
to clarify that when the results of performance tests [or performance 
evaluations] are to be reported in the NOCS, the results are due by the 
date the NOCS report is due (report is due 150 days from the compliance 
date) whether the results are reported using the Compliance and 
Emissions Data Reporting Interface (CEDRI) or in hard copy as part of 
the NOCS report. If the source submits the test results using CEDRI, we 
are also proposing to specify that the source need not resubmit those 
results in the NOCS, but may instead submit specified information 
identifying that a performance test [or performance evaluation] was 
conducted and the unit(s) and pollutant(s) that were tested. We are 
also proposing to add the phrase ``Unless otherwise specified by this 
subpart'' to 40 CFR 63.655(h)(9)(i) and (ii) to make clear that test 
results associated with a NOCS report are not due within 60 days of 
completing the performance test or performance evaluation. We are also 
amending several references in Table 6--General Provisions 
Applicability to Subpart CC that discuss reporting requirements for 
performance tests or performance evaluations. As the General Provisions 
sections currently only address submissions of written test reports, we 
are proposing to clarify these entries in Table 6 to recognize that 
performance

[[Page 15469]]

test results may be written or electronic. Specifically, we are 
proposing to make these clarifications in Table 6 entries for 40 CFR 
63.6(f)(3), 63.6(h)(8), 63.7(a)(2), and 63.8(e).
---------------------------------------------------------------------------

    \17\ API and AFPM, March 28, 2017.
---------------------------------------------------------------------------

    We also received questions from API and AFPM \18\ on other aspects 
of the electronic reporting requirements. Industry representatives 
requested that electronic reporting only be required if all the test 
methods used to determine the emissions are supported by the Electronic 
Reporting Tool (ERT) (e.g., methods for velocity as well as pollutant 
concentration). We recognize that the ERT does not support all test 
methods and that there is little value in submitting a stack flow 
electronically and the pollutant concentration in written format or 
PDF. We are revising the ERT website to clarify that electronic 
reporting is not required where the ERT does not support the test 
method for the pollutant of interest.
---------------------------------------------------------------------------

    \18\ API and AFPM, March 28, 2017.
---------------------------------------------------------------------------

    We recognize that there are instances when two primary pollutants 
may be measured during a single performance test, one supported by the 
ERT and one not supported by the ERT. For petroleum refineries, this 
occurs if the owner or operator conducts a particulate matter (PM) 
performance test coincident with the hydrogen cyanide performance test. 
Since the PM test methods (Methods 5, 5B, and 5F) are supported by the 
ERT, we require that this performance test be submitted via the ERT. 
However, testing for hydrogen cyanide is not supported by the ERT. The 
owner or operator may meet the reporting requirement for the hydrogen 
cyanide test by either including the test report as an attachment to 
the ERT submission so that both results are submitted electronically or 
by submitting the test report in hard copy or other agreed upon format.
    Industry representatives also recommended that the requirement to 
report electronically be suspended until a reliable system is in place. 
We note that the submission of ERT-formatted performance test and 
performance evaluation reports using CEDRI is fully operational, and 
there are no known or reported system issues. CEDRI accepts all ERT 
version 5 report submissions that are properly created using the ERT. 
If the ERT zip file being uploaded to CEDRI is not created from the ERT 
or does not meet the file format requirements established by the EPA, 
CEDRI will not accept the file upload and will provide the user 
instructions on how to resolve the error(s). In addition, the Central 
Data Exchange (CDX) Helpdesk staff are available during regular 
business hours to support industry users in completing their 
submissions electronically using CEDRI. Any user concerns that cannot 
be resolved by the CDX Helpdesk are escalated to either EPA staff or 
the application support contractors for resolution. To date, over 3,400 
ERT files have been submitted to the EPA through CEDRI. There have been 
43 calls to the Helpdesk for assistance. The CDX Helpdesk resolved 34 
of these calls, and the EPA and their support contractors resolved the 
remaining nine. We encourage all users to continue to contact the CDX 
Helpdesk with any issues encountered during the submission process.
    We have also identified two broad circumstances in which electronic 
reporting extensions may be provided. In both circumstances, the 
decision to accept a claim of needing additional time to report is 
within the discretion of the Administrator, and reporting should occur 
as soon as possible. In 40 CFR 63.655(h)(10)(i), we address the 
situation where an extension may be warranted due to outages of the 
EPA's CDX or CEDRI which preclude a user from accessing the system and 
submitting required reports. If either the CDX or CEDRI is unavailable 
at any time beginning 5 business days prior to the date that the 
submission is due, and the unavailability prevents a user from 
submitting a report by the required date, users may assert a claim of 
EPA system outage. We consider 5 business days prior to the reporting 
deadline to be an appropriate timeframe because, if the system is down 
prior to this time, users still have 1 week to complete reporting once 
the system is back online. However, if the CDX or CEDRI is down during 
the week a report is due, we realize that this could greatly impact the 
ability to submit a required report on time. We will notify users about 
known outages as far in advance as possible by CHIEF Listserv notice, 
posting on the CEDRI website, and posting on the CDX website so that 
users can plan accordingly and still meet reporting deadlines. However, 
if a planned or unplanned outage occurs and users believe that it will 
affect or it has affected their ability to comply with an electronic 
reporting requirement, we have provided a process to assert such a 
claim.
    Consistent with 40 CFR 63.655(h)(10), a source may seek an 
extension of the time to comply with an electronic reporting 
requirement. We are proposing to revise this provision to address the 
situation where an extension may be warranted due to a force majeure 
event, which is defined as an event that will be or has been caused by 
circumstances beyond the control of the affected facility, its 
contractors, or any entity controlled by the affected facility that 
prevents them from complying with the requirement to submit a report 
electronically as required by this rule. Examples of such events are 
acts of nature, acts of war or terrorism, or equipment failure or 
safety hazards beyond the control of the facility. If such an event 
occurs or is still occurring or if there are still lingering effects of 
the event in the 5 business days prior to a submission deadline, we are 
proposing a process to assert a claim of force majeure as a basis for 
extending the reporting deadline to protect refiners from noncompliance 
in cases where they cannot successfully submit a report by the 
reporting deadline for reasons outside of their control.
    We received questions from API and AFPM \19\ regarding the 
integrity checks required for the temperature and pressure monitor 
inspections in Table 13 (40 CFR part 63, subpart CC) and in Items 2, 4, 
6, 7, 9, and 10 of Table 41 (40 CFR part 63, subpart UUU). Commenters 
noted that 40 CFR 63.657(b)(4), which applies to delayed coker pressure 
monitoring, indicates that the ``. . . pressure monitoring system must 
be visually inspected for integrity . . .'' and suggested that the 
table entries likewise specify that visual inspections are required/
acceptable. The continuous parameter monitoring system (CPMS) pressure 
monitoring addressed in Tables 13 and 41 is broader than the monitoring 
requirement in 40 CFR 657(b)(4) and visual monitoring is not required 
for monitoring other systems as it is for delayed coker pressure 
monitoring. However, we agree that visual inspections are acceptable 
for those other systems, though, for those systems, there may be other 
methods of assessing integrity, such as current meters for wiring, that 
are not visual. In recognition of the fact that not all checks will be 
``visual,'' we did not specify ``visual'' inspections in Tables 13 and 
41.
---------------------------------------------------------------------------

    \19\ API and AFPM, March 28, 2017.
---------------------------------------------------------------------------

    In codifying the amendments to 40 CFR 63.655(i)(5), the specific 
recordkeeping requirements in the subparagraphs for regulation as it 
existed prior to the revisions were not retained in the regulations as 
published by the CFR. As reflected in the instructions to the 
amendments, we intended to move the heat exchanger recordkeeping 
requirements from paragraph (i)(4) to (i)(5) and to revise the 
introductory text to new paragraph (i)(5)

[[Page 15470]]

(see instructions 27.j. and 27.l. in 80 FR 75247). These revisions were 
incorporated into the CFR; however, the subparagraphs, which were not 
being revised, were not included in the CFR. We are proposing to revise 
40 CFR 63.655(i)(5) to include the subparagraphs (as previously 
codified in subparagraph (i)(4)) that were inadvertently not included 
in the published CFR.
    Similarly, the amendments to 40 CFR 63.655(h)(5)(iii) included in 
the December 2015 final rule Federal Register document (80 FR 75247) 
were not included in the regulations as published by the CFR. As 
reflected in the instructions to the amendments, we intended for the 
option to use an automated data compression recording system to be an 
approved monitoring alternative. In reviewing this amendment, the EPA 
noted that 40 CFR 63.655(h)(5) specifically addresses mechanisms for 
owners or operators to request approval for alternatives to the 
continuous operating parameter monitoring and recordkeeping provisions, 
while the provisions in 40 CFR 63.655(i)(3) specifically include 
options already approved for CPMS. Consistent with our intent for the 
use of an automated data compression recording system to be an approved 
monitoring alternative, we are proposing to move the paragraphs at 40 
CFR 63.655(h)(5)(iii) to 40 CFR 63.655(i)(3)(ii)(C).
    There are several additional revisions that we are proposing to 
Refinery MACT 1 to correct typographical errors, grammatical errors, 
and cross-reference errors. Table 2 of this preamble summarizes these 
editorial changes as well as other changes as discussed in this 
preamble.

Table 2--Summary of Proposed Editorial and Other Corrections to Refinery
                                 MACT 1
------------------------------------------------------------------------
             Provision                        Proposed revision
------------------------------------------------------------------------
MPV:
    Last sentence in Sec.           Replace ``owner of operator'' with
     63.643(c).                      ``owner or operator.''
    Sec.   63.643(c)(1)(ii).......  Define the term ``psig'' as pounds
                                     per square inch gauge and remove
                                     the last occurrence of
                                     ``equipment.''
    Sec.   63.643(c)(1)(iii)......  Define the term ``VOC'' as total
                                     volatile organic compounds.
PRD:
    Sec.   63.648(a)..............  Correct reference to ``paragraphs
                                     (a)(1) through (2)'' to
                                     ``paragraphs (a)(1) through (3).''
                                     Also, correct reference to
                                     ``paragraphs (c) through (i)'' to
                                     ``paragraphs (c) through (j).''
    Sec.   63.648(c)..............  Correct reference to ``paragraphs .
                                     . . (e) through (i) . . . '' to
                                     ``paragraphs . . . (e) through (j)
                                     . . .''
    Last sentence in Sec.           Add space between majeure and
     63.648(j)(3)(iv).               events.
DCU:
    Sec.   63.655(i)(7)(iii)(B)...  Adjust recordkeeping requirement to
                                     the 5-minute period prior to pre-
                                     vent draining, rather than 15-
                                     minute period.
    Sec.   63.657(a)(1)(i) and      Correct the temperature and pressure
     (ii); Sec.   63.657(a)(2)(i)    limits to be expressed as maximums
     and (ii).                       by adding ``or less'' to each
                                     numerical limit.
    Sec.   63.657(b)(5)...........  Clarify that the output of the
                                     pressure monitoring system must be
                                     reviewed only when the drum is in
                                     service, so the provision reads,
                                     ``The output of the pressure
                                     monitoring system must be reviewed
                                     each day the unit is operated to
                                     ensure . . .''
Fenceline:
    Second sentence in Sec.         Replace ``owner of operator'' with
     63.658(c)(2) and Sec.           ``owner or operator.''
     63.658(e).
    Sec.   63.658(d)(1)...........  Correct the reference to ``paragraph
                                     (i)(1)'' to ``paragraph (i)(2).''
    Sec.   63.658(d)(2)...........  Update the reference to Section 8.3
                                     of Method 325A to more specifically
                                     reference Sections 8.3.1 through
                                     8.3.3 of Method 325A.
    Sec.   63.658(e)(3)(iv).......  Delete the word ``an'' in the first
                                     sentence.
Flares:
    Sec.   63.670(o)..............  Correct the reference to
                                     ``paragraphs (o)(1) through (8)''
                                     to ``paragraphs (o)(1) through
                                     (7).''
    Sec.   63.670(j)(6)...........  Correct the reference to
                                     subparagraphs ``(j)(6)(i) through
                                     (v)'' to ``(j)(6)(i) through
                                     (iii).''
    Sec.   63.670(k)(3) equation    Correct units for Qcum to be
     term for Qcum.                  ``standard cubic feet.''
    Sec.  Sec.  Sec.   63.670(i),   Update the reference to
     (m)(2) including equation       ``supplemental natural gas'' to the
     terms, and (n)(2) including     defined term ``flare supplemental
     equation terms.                 gas.''
    Sec.   63.670(o)(1)(ii)(B)....  Correct the reference to paragraph
                                     ``Sec.   63.648(j)(5)'' to ``Sec.
                                     63.648(j)(3)(ii)(A) through (E).''
                                     \20\
    Sec.  Sec.                      Edit the paragraphs to refer to a 15-
     63.670(o)(1)(iii)(B) and        minute block averaging time
     (o)(3)(i).                      relative to the smokeless design
                                     capacity of the flare.
    Table 13, Hydrogen Analyzer     Add ``Where feasible'' to the
     Requirements for Sampling       description of sampling location
     Location.                       for the hydrogen analyzer.
Storage Vessels:
    Sec.   63.655(f)(1)(i)(A)(1)    Add a reference to the option to
     through (3).                    comply with Sec.   63.660 in
                                     addition to compliance with Sec.
                                     63.646.
    Sec.   63.655(g)(2)(B)(1).....  Add the word ``area'' to the end of
                                     the sentence consistent with the
                                     same requirement in the HON.
    Sec.   63.655(h)(2)(ii).......  Correct the reference to ``Sec.
                                     63.1063(d)(3)'' to ``Sec.
                                     63.1062(d)(3).''
    Sec.   63.660(b)(1)...........  Correct the reference to ``Sec.
                                     63.1063(a)(2)(vii)'' to ``Sec.
                                     63.1063(a)(2)(viii).''
    Sec.   63.660(i)(2)...........  Delete the second use of the word
                                     ``to.''
Other:
    Table 6, Comment for Reference  Correct the reference ``Sec.
     Sec.   63.7(h)(3).              63.7(g)(3)'' to ``Sec.
                                     63.7(h)(3)(i).''
------------------------------------------------------------------------


[[Page 15471]]

B. Clarifications and Technical Corrections to Refinery MACT 2
---------------------------------------------------------------------------

    \20\ A similar revision was included in the October 18, 2016, 
reconsideration notice and proposed rule (81 FR 71661). In the 
reconsideration notice and proposed rule, we proposed to correct the 
reference to paragraph ``Sec.  63.648(j)(5)'' to ``Sec.  
63.648(j)(3)(ii).'' In this proposal, we are including a more 
specific reference to the subparagraphs in 40 CFR 63.648(j)(3) to 
clarify that the rule requires owners and operators to evaluate the 
list of prevention measures in these subparagraphs.
---------------------------------------------------------------------------

1. FCCU Provisions
    In order to demonstrate compliance with the alternative PM standard 
for FCCU at 40 CFR 63.1564(a)(5)(ii), the outlet (exhaust) gas flow 
rate of the catalyst regenerator must be determined. Refinery MACT 2 
provides that owners or operators may determine this flow rate using a 
flow CPMS or the alternative provided in 40 CFR 63.1573(a). Currently, 
the language in 40 CFR 63.1573(a) restricts the use of the alternative 
to occasions when ``the unit does not introduce any other gas streams 
into the catalyst regenerator vent.'' API and AFPM \21\ claim that 
while this restriction is appropriate for determining the flow rate for 
applying emissions limitations downstream of the regenerator because 
additional gases introduced to the vent would not be measured using 
this method, it is not a necessary constraint for determining 
compliance with the alternative PM limit. This is because the 
alternative PM standard applies at the outlet of the regenerator prior 
to the primary cyclone inlet and this is the flow measured by the 
alternative in 40 CFR 63.1573(a). We agree that there should be no such 
restriction when determining the outlet flow rate to the regenerator 
for the purposes of demonstrating compliance with the alternate PM 
standard at 40 CFR 63.1564(a)(5)(ii), and are proposing to amend 40 CFR 
63.1573(a) to remove that restriction.
---------------------------------------------------------------------------

    \21\ API and AFPM, March 28, 2017.
---------------------------------------------------------------------------

    Additionally, API and AFPM noted in their February 1, 2016, 
petition for reconsideration that the FCCU alternative organic HAP 
standard for startup, shutdown, and hot standby in 40 CFR 
63.1565(a)(5)(ii) requires maintaining the oxygen concentration in the 
regenerator exhaust gas at or above 1 vol. percent (dry) (i.e., greater 
than or equal to 1-percent oxygen (O2) measured on a dry 
basis); however, they claim process O2 analyzers measure 
O2 on a wet basis. Therefore, the commenters explained that 
they would need to take a moisture measurement and use the measurement 
to correct the measured O2 in order to demonstrate 
compliance with the standard. Industry commenters explained that this 
is unnecessary as an FCCU meeting the 1-percent O2 
alternative standard measured on a wet basis will be compliant with the 
1-percent limit on a dry basis. We agree that meeting the 1-percent 
O2 standard on a wet basis measurement will always mean that 
there is more O2 than if the concentration value is 
corrected to a dry basis. As such, a wet basis measurement of 1-percent 
O2 is adequate to demonstrate compliance with the minimum 
O2 alternative limit in 40 CFR 63.1565(a)(5)(ii). Therefore, 
we are proposing to amend 40 CFR 63.1565(a)(5)(ii) and Table 10 to 
allow for the use of a wet O2 measurement for demonstrating 
compliance with the standard so long as it is used directly with no 
correction for moisture content.
2. Other Corrections
    API and AFPM commented in their February 1, 2016, petition for 
reconsideration that the amendments to the provision for CPMS 
monitoring and data collection in Refinery MACT 2 at 40 CFR 
63.1572(d)(1) which do not exclude periods of monitoring system 
malfunction, associated repairs, and quality assurance or control 
activities is inconsistent with paragraph (d)(2) which specifies that 
data recorded during required quality assurance or control activities 
may not be used. Additionally, API and AFPM stated that an analogous 
provision in 40 CFR 63.1572(d) for CPMS monitoring and data collection 
was maintained in the final Refinery MACT 1 at 40 CFR 63.671(a)(4). We 
agree that we should maintain consistency between Refinery MACT 1 and 
Refinery MACT 2 whenever possible and, in this case, there is no good 
reason for the two subparts to differ. CPMS readings taken during 
periods of monitoring system malfunctions and repairs do not provide 
accurate or valid data. In order to repair a monitoring system, the 
CPMS must generally be taken offline or completely out of service, and, 
therefore, there would be no data to record. During a monitoring system 
malfunction, while there may or may not be data to record, the 
malfunction will affect the accuracy of the data. This is the reason 
why these data are generally excluded from data averages (as noted in 
40 CFR 63.8(g)(5)). Therefore, we are proposing to amend the language 
in Refinery MACT 2 at 40 CFR 63.1572(d)(1) so that the language is the 
same as that in Refinery MACT 1 at 40 CFR 63.671(a)(4).
    The final amendments provide alternative emission limits during 
periods of startup and shutdown for some units, such as the FCCU 
alternative organic HAP standard for startup, shutdown, and hot standby 
in 40 CFR 63.1565(a)(5)(ii). API and AFPM questioned in their February 
1, 2016, petition for reconsideration whether the recordkeeping 
requirements in 40 CFR 63.1576(a)(2)(i) apply when the owners or 
operators elect to comply with the otherwise applicable emissions 
limitations during periods of startup and shutdown. Separate 
recordkeeping requirements apply when a source is subject to the 
otherwise applicable emissions limits; thus, it is not necessary for 
the recordkeeping requirements in 40 CFR 63.1576(a)(2)(i) to also 
apply. Therefore, we are proposing to amend the recordkeeping 
requirement in 40 CFR 63.1576(a)(2)(i) to apply only when facilities 
elect to comply with the alternative startup and shutdown standards 
provided in 40 CFR 63.1564(a)(5)(ii) or 40 CFR 63.1565(a)(5)(ii) or 40 
CFR 63.1568(a)(4)(ii) or (iii).
    We are proposing to revise Refinery MACT 2 to address the same 
issue raised for Refinery MACT 1 regarding the reporting of initial 
performance tests. We are proposing to amend 40 CFR 63.1574(a)(3) to 
clarify that the results of performance tests conducted to demonstrate 
initial compliance are to be reported by the date the NOCS report is 
due (150 days from the compliance date) whether the results are 
reported using CEDRI or in hard copy as part of the NOCS report and to 
clarify the information to be included in the NOCS if the test results 
are submitted through CEDRI. Unlike Refinery MACT 1, Refinery MACT 2 
has on-going performance test requirements. We are proposing that the 
results of periodic performance tests and the one-time hydrogen cyanide 
(HCN) test required by 40 CFR 63.1571(a)(5) and (6) must be reported 
with the semi-annual compliance reports as specified in 40 CFR 
63.1575(f) instead of within 60 days of completing the performance 
evaluation. Similarly, we are also proposing to streamline reporting of 
the results of performance evaluations for continuous monitoring 
systems (as provided in entry 2 to Table 43) to align with the semi-
annual compliance reports as specified in 40 CFR 63.1575(f), rather 
than requiring a separate report submittal. We are proposing to add the 
phrase ``Unless otherwise specified by this subpart'' to 40 CFR 
63.1575(k)(1) and (2) to indicate that any performance tests or 
performance evaluations required to be reported in a NOCS report or a 
semi-annual compliance report are not subject to the 60-day deadline 
specified in these paragraphs. We are also proposing to add 40 CFR 
63.1575(l) to

[[Page 15472]]

address extensions to electronic reporting deadlines.
    Similar to the revisions in Table 6 to 40 CFR part 63, subpart CC 
(see section III. A.7), we are proposing to revise selected entries in 
Table 44 to Subpart UUU of Part 63--Applicability of NESHAP General 
Provisions to Subpart UUU, to clarify several sections of the General 
Provisions (40 CFR part 63, subpart A) that the reporting can be 
written or electronic, the timing of these reports is specified in 40 
CFR part 63, subpart UUU, and the subpart UUU provisions supersede the 
General Provisions. Specifically, we are proposing to revise Table 44 
entries for 40 CFR 63.6(f)(3), 63.7(h)(7)(i), 63.6(h)(8), 63.7(a)(2), 
63.7(g), 63.8(e), 63.10(d)(2), 63.10(e)(1), 63.10(e)(2), and 
63.10(e)(4) to explain that 40 CFR part 63, subpart UUU specifies how 
and when to report the results of performance tests or performance 
evaluations.
    There are several additional revisions that we are proposing to 
Refinery MACT 2 to correct typographical errors, grammatical errors, 
and cross-reference errors. These editorial corrections are summarized 
in Table 3 of this preamble.

Table 3--Summary of Proposed Editorial and Minor Corrections to Refinery
                                 MACT 2
------------------------------------------------------------------------
             Provision                        Proposed revision
------------------------------------------------------------------------
Sec.   63.1564(b)(4)(iii).........  Correct the reference to ``paragraph
                                     (a)(1)(iii)'' to ``paragraph
                                     (a)(1)(v).''
Sec.   63.1564(c)(3)..............  Correct the reference to ``paragraph
                                     (a)(1)(iii)'' to ``paragraph
                                     (a)(1)(v).''
Sec.   63.1564(c)(4)..............  Correct the reference to ``paragraph
                                     (a)(1)(iv)'' to ``paragraph
                                     (a)(1)(vi).''
Sec.   63.1564(c)(5)(iii).........  Correct the units of measure for
                                     velocity to ft/sec.
Sec.   63.1569(c)(2)..............  Correct the reference to ``paragraph
                                     (a)(2)'' to ``paragraph (a)(3).''
Sec.   63.1571(a)(5) and (6); and   Add ``or within 60 days of startup
 Table 6, Item 1.ii.                 of a new unit'' to the compliance
                                     time for the periodic performance
                                     testing requirement for PM or Ni
                                     and to the one-time performance
                                     testing requirement for HCN.
Sec.   63.1571(d)(1)..............  Correct the reference to ``paragraph
                                     (a)(1)(iii)'' to ``paragraph
                                     (a)(1)(v).''
Sec.   63.1571(d)(2)..............  Correct the reference to ``paragraph
                                     (a)(1)(iv)'' to ``paragraph
                                     (a)(1)(vi).''
Sec.   63.1572(c)(1)..............  Delete duplicative sentence, ``You
                                     must install, operate, and maintain
                                     each continuous parameter
                                     monitoring system according to the
                                     requirements in Table 41 of this
                                     subpart.''
Table 3...........................  Correct the spelling of the word
                                     ``continuous'' in the table's
                                     title.
Table 3, Item 2.c.................  Delete the words, ``the coke burn-
                                     off rate or.'' Correct the footnote
                                     reference from ``3'' to ``1.''
Table 3, Items 6 through 9........  Correct the reference to ``Sec.
                                     60.120a(b)(1)'' to ``Sec.
                                     60.102a(b)(1).''
Table 4, Item 9.c.................  Correct the reference to ``Equation
                                     2 of Sec.   63.571'' to ``Equation
                                     1 of Sec.   63.571, if
                                     applicable.''
Table 4, Item 10.c................  Correct the reference to ``item
                                     6.c.'' to ``item 9.c.'' and add
                                     ``if applicable'' after reference
                                     to Equation 2 of Sec.   63.571.
Table 5, Item 3...................  Correct the reference to
                                     ``60.102a(b)(1)(i)'' to
                                     ``60.102a(b)(1)(ii),'' and correct
                                     the reference to ``1.0 g/kg (1.0 lb/
                                     1,000 lb)'' to ``0.5 g/kg (0.5 lb
                                     PM/1,000 lb).''
Table 6, Item 7...................  Delete '' and 30% opacity'' as this
                                     is not part of Option 1b.
Table 43, Item 2..................  Correct the compliance date to the
                                     effective date of the rule
                                     (February 1, 2016).
------------------------------------------------------------------------

C. Clarifications and Technical Corrections to NSPS Ja

    During recent implementation efforts, it was brought to our 
attention that the testing requirement in 40 CFR 60.105a(b)(2)(ii) 
differs from similar requirements in 40 CFR 60.105a(d)(4), (f)(4), and 
(g)(4) where we allow use of Method 3, 3A, or 3B, both for the 
performance tests and the relative accuracy tests. The language in 40 
CFR 60.105a(b)(2)(ii) does not currently include Methods 3A and 3B (and 
the alternative ANSI/ASME method for EPA Method 3B) and mistakenly 
cites Appendix A-3 rather than Appendix A-2. We are proposing to revise 
40 CFR 60.105a(b)(2)(ii), consistent with the other similar 
requirements in NSPS subpart Ja listed above, to read as follows, ``The 
owner or operator shall conduct performance evaluations of each 
CO2 and O2 monitor according to the requirements 
in Sec.  60.13(c) and Performance Specification 3 of appendix B to this 
part. The owner or operator shall use Method 3, 3A or 3B of appendix A-
2 to this part for conducting the relative accuracy evaluations. The 
method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 3B of appendix A-2 to part 60.'' The EPA is 
proposing a corresponding change to 40 CFR 60.17(g)(14) to add 40 CFR 
60.105a(b) to the list of regulations in which this method has been 
incorporated by reference. It should be noted that through this 
revision, the EPA is proposing to include in a final EPA rule 
regulatory text that includes incorporation by reference. In accordance 
with requirements of 1 CFR 51.5(a), the EPA is proposing to incorporate 
by reference the ANSI/ASME PTC 19.10-1981 test method. The EPA has 
made, and will continue to make, this document generally available 
electronically through www.regulations.gov and/or in hard copy at the 
appropriate EPA office (see the ADDRESSES section of this preamble for 
more information).
    We also identified that the second sentence of 40 CFR 
60.106a(a)(1)(iii) includes the following clause, ``. . . and Method 3 
or 3A of appendix A-2 of part 60 for conducting the relative accuracy 
evaluations'' which is redundant to 40 CFR 60.106a(a)(1)(vi) (and 
again, does not include all three Methods). We are proposing to delete 
this clause. We are also proposing to change the word ``Methods'' to 
``Method'' in the second sentence of 40 CFR 60.106a(a)(1)(iii) to 
better reflect our intent for facilities to select a single performance 
evaluation method.

IV. Summary of Cost, Environmental, and Economic Impacts

    This proposed rule is expected to result in overall cost and burden 
reductions. Specifically, the proposed amendments expected to reduce 
burden are: Revisions of the maintenance vent provisions related to the 
availability of a pure hydrogen supply for equipment containing 
pyrophoric catalyst, revisions of recordkeeping requirements for 
maintenance vents associated with equipment containing less than 72 lbs 
VOC, inclusion of specific provisions for pilot-operated and balanced 
bellows PRDs, and inclusion of specific provisions related to steam 
tube air entrainment for flares. These proposed amendments are 
described in detail in sections III.A.2.b, III.A.2.d, III.A.3.c, and 
III.A.5 of this preamble, respectively. The other proposed amendments 
will have an insignificant effect on the

[[Page 15473]]

compliance costs associated with these standards. Additionally, none of 
the proposed amendments are projected to appreciably impact the 
emissions reductions associated with these standards.
    Some of the cost reductions associated with this proposed rule were 
not fully captured in the impacts estimated for the December 2015 final 
rule. The total capital investment cost of the December 2015 final rule 
was estimated at $283 million, $112 million from the final amendments 
for storage vessels, DCUs, and fenceline monitoring, and $171 million 
from standards for flares and PRDs. The annualized costs of the final 
amendments for storage vessels, DCUs, and fenceline monitoring were 
estimated to be approximately $13.0 million and the annualized costs of 
the final standards for flares and PRDs were estimated to be 
approximately $50.2 million. There were no capital costs estimated for 
the maintenance vent provisions in the December 2015 final rule and 
only limited recordkeeping and reporting costs. Furthermore, while 
significant capital and operating costs were projected for flares, we 
may have underestimated the number of steam-assisted flares that would 
also have to demonstrate compliance with the NHVdil 
operating limit.
    As described previously in section III.A.2.b of this preamble, we 
did not specifically consider that some units with pyrophoric catalyst 
at the refinery would have a pure hydrogen supply and others would not. 
Therefore, we did not include costs in the December 2015 final rule 
impacts for refineries that have a pure hydrogen supply to add new 
piping (and possibly increase their hydrogen production capacity) to 
bring pure hydrogen to units with pyrophoric catalyst that were not 
currently piped to receive pure hydrogen. Based on information provided 
by industry petitioners, the capital investment cost to supply pure 
hydrogen to pyrophoric units that currently do not have a pure hydrogen 
supply (but that are located at refineries with a pure hydrogen supply) 
is estimated to be approximately $76 million. Using a capital recovery 
of 0.0944 based on 20-year equipment life and 7-percent interest, 
hydrogen supply upgrades would have increased the previously estimated 
annualized cost by $7,174,400 per year. Table 4 provides the cost 
reduction expected for the proposed amendments concerning hydrogen 
supply for pyrophoric units, as well as other proposed amendments.

                    Table 4--Projected Impacts of the Proposed Amendments to Refinery MACT 1
----------------------------------------------------------------------------------------------------------------
                                                                     Estimated
                                      Current         Current         capital        Estimated     Reduction in
                                    estimate of     estimate of     investment      annualized      annualized
                                   Dec 2015 rule   Dec 2015 rule      cost if         cost if         cost of
                                      capital       annualized     proposed rule   proposed rule     refinery
                                    investment    costs, million        is              is          standards,
                                  costs, million       $/yr        implemented,    implemented,    million $/yr
                                         $                           million $     million $/yr
----------------------------------------------------------------------------------------------------------------
Maintenance vents provisions for              76            7.17               0               0            7.17
 equipment with pyrophoric
 catalyst.......................
MPV recordkeeping requirements..               0           0.678               0           0.001           0.677
PRD requirements................            11.1            3.33            10.0            3.00            0.33
Flare monitoring for steam-                  130            26.9             130            23.6            3.31
 assisted flares with air
 entrainment....................
----------------------------------------------------------------------------------------------------------------

    For the proposed amendments to the recordkeeping requirements for 
equipment containing less than 72 lbs of VOC, the impacts in the 
December 2015 final rule only included one-time planning costs for how 
to comply with the maintenance vent requirements; it was assumed that 
facilities would have maintenance records for each activity, so no 
additional recordkeeping burden was estimated. According to industry 
petitioners, there are numerous activities, such as replacing pressure 
transducers or tubing that would qualify under the less than 72 lbs of 
VOC provisions, but for which event-specific records are not 
traditionally maintained. Based on the per event recordkeeping 
requirement for maintenance vents using the 72 lbs VOC provision in the 
December 2015 rule, we now estimate that there would be 500 of these 
small maintenance vent openings per year per refinery and that 0.1 hour 
would be required to record each individual event, resulting in a 
nationwide burden of $678,625 per year. The revisions in the proposed 
rule, would only require records that should be part of the annual 
planning assessment and records for events not following the 
deinventory procedures included in these plans. We estimate that each 
facility would spend 0.1 hour for each non-conforming event and would 
only have one such event each year with an estimated nationwide burden 
of $1,357 per year. Thus, the proposed amendments are estimated to 
yield savings of approximately $677,268 per year considering the actual 
estimated annualized burden of the December 2015 final rule.
    We estimated the PRD requirements in the December 2015 rule would 
result in a capital investment of $11.1 million to implement prevention 
measures and flow monitoring systems on PRDs. Combined with the 
recordkeeping and reporting requirements, the annualized cost of the 
PRD provisions in the December 2015 final rule was estimated to be $3.3 
million per year. We estimate that approximately 10 percent of PRDs at 
refineries are either pilot-operated or balanced bellows. Thus, if 
there is a commensurate 10-percent decrease in these costs based on the 
proposed provisions for pilot-operated or balanced bellows PRD, we 
estimate the proposed amendments would yield a reduction in capital 
investment of $1.1 million and a reduction in annualized costs of 
$330,000 per year.
    We estimated that the provisions for steam-assisted flares in the 
December 2015 rule would result in a capital investment of $130 million 
and annualized costs of $23.6 million. However, these costs did not 
include costs to also assess compliance with the NHVdil 
operating limit for those steam-assisted flares that used intentional 
air entrainment within the steam tubes. There is no way to measure this 
air entrainment rate, but engineering calculations were allowed to be 
used. We estimated that there were 190 steam-assisted flares that 
received routine flow. We estimate that 0.5 additional hour would be 
required each day to assess compliance with the NHVdil 
operating limits for these flares. If all 190 steam-assisted flares 
were designed for air entrainment in the steam tubes,

[[Page 15474]]

this would suggest that the annualized cost of the December 2015 final 
rule for steam-assisted flares is closer to $26.9 million per year and 
that the proposed amendments allowing owners or operators of certain 
steam-assisted flares with air entrainment at the flare tip to comply 
only with the NHVcz operating limits would reduce annualized 
costs by approximately $3.3 million.
    A detailed memorandum documenting the estimated burden reduction 
has been included in the docket for this rulemaking (see memorandum 
titled, ``Impact Estimates for the 2017 Proposed Revisions to Refinery 
MACT 1,'' in Docket ID No. EPA-HQ-OAR-2010-0682).

V. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive Orders 
can be found at http://www2.epa.gov/laws-regulations/laws-and-executive-orders.

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 and was, 
therefore, not submitted to OMB for review.

B. Executive Order 13771: Reducing Regulations and Controlling 
Regulatory Costs

    This action is expected to be an Executive Order 13771 deregulatory 
action. Details on the estimated cost savings of this proposed rule can 
be found in EPA's analysis of the potential costs and benefits 
associated with this action.

C. Paperwork Reduction Act (PRA)

    The information collection activities in this proposed rule have 
been submitted for approval to OMB under the PRA. The Information 
Collection Request (ICR) document that the EPA prepared has been 
assigned EPA ICR number 1692.11. You can find a copy of the ICR in the 
docket for this rule, and it is briefly summarized here.
    One of the proposed technical amendments included in this notice 
impacts the recordkeeping requirements in 40 CFR part 63, subpart CC 
for certain maintenance vents associated with equipment containing less 
than 72 lbs VOC as found at 40 CFR 63.655(i)(12)(iv). The new 
recordkeeping requirement specifies records used to estimate the total 
quantity of VOC in the equipment and the type and size limits of 
equipment that contain less than 72 lb of VOC at the time of the 
maintenance vent opening be maintained. As specified in 40 CFR 
63.655(i)(12)(iv), additional records are required if the deinventory 
procedures were not followed for each maintenance vent opening or if 
the equipment opened exceeded the type and size limits (i.e., 72 lbs 
VOC). These additional records include identification of the 
maintenance vent, the process units or equipment associated with the 
maintenance vent, the date of maintenance vent opening, and records 
used to estimate the total quantity of VOC in the equipment at the time 
the maintenance vent was opened to the atmosphere. These records will 
assist the EPA with determining compliance with the standards set forth 
in 40 CFR 63.643(c)(iv).
    Respondents/affected entities: Owners or operators of existing or 
new major source petroleum refineries that are major sources of HAP 
emissions. The NAICS code is 324110 for petroleum refineries.
    Respondent's obligation to respond: All data in the ICR that are 
recorded are required by the proposed amendments to 40 CFR part 63, 
subpart CC--National Emission Standards for Hazardous Air Pollutants 
for Petroleum Refineries.
    Estimated number of respondents: 142.
    Frequency of response: Once per year per respondent.
    Total estimated burden: 16 hours (per year). Burden is defined at 5 
CFR 1320.3(b).
    Total estimated cost: $1,640 (per year), includes $0 annualized 
capital or operation and maintenance costs.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information, the 
accuracy of the provided burden estimates and any suggested methods for 
minimizing respondent burden to the EPA using the docket identified at 
the beginning of this rule. You may also send your ICR-related comments 
to OMB's Office of Information and Regulatory Affairs via email to 
[email protected], Attention: Desk Officer for the EPA. Since 
OMB is required to make a decision concerning the ICR between 30 and 60 
days after receipt, OMB must receive comments no later than May 10, 
2018.
     The EPA will respond to any ICR-related comments in the final 
rule.

D. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic 
impact on a substantial number of small entities under the RFA. In 
making this determination, the impact of concern is any significant 
adverse economic impact on small entities. An agency may certify that a 
rule will not have a significant economic impact on a substantial 
number of small entities if the rule relieves regulatory burden, has no 
net burden, or otherwise has a positive economic effect on the small 
entities subject to the rule. The action consists of amendments, 
clarifications, and technical corrections which are expected to reduce 
regulatory burden. As described in section IV of this preamble, we 
expect burden reduction for: Revisions of the maintenance vent 
provisions related to the availability of a pure hydrogen supply for 
equipment containing pyrophoric catalyst, revisions of recordkeeping 
requirements for maintenance vents associated with equipment containing 
less than 72 lbs VOC, inclusion of specific provisions for pilot-
operated and balanced bellows PRDs, and inclusion of specific 
provisions related to steam tube air entrainment for flares. 
Furthermore, as noted in section IV of this preamble, we do not expect 
the proposed amendments to change the expected economic impact analysis 
performed for the existing rule. We have, therefore, concluded that 
this action will relieve regulatory burden for all directly regulated 
small entities.

E. Unfunded Mandates Reform Act (UMRA)

    This action does not contain any unfunded mandate as described in 
UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect 
small governments. The action imposes no enforceable duty on any state, 
local, or tribal governments or the private sector.

F. 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.

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

    This action does not have tribal implications as specified in 
Executive Order 13175. It will not have substantial direct effect on 
tribal governments, on the relationship between the federal government 
and Indian tribes, or on the

[[Page 15475]]

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.

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

    This action is not subject to Executive Order 13045 because it is 
not economically significant as defined in Executive Order 12866, and 
because the EPA does not believe the environmental health or safety 
risks addressed by this action present a disproportionate risk to 
children. The proposed amendments serve to make technical 
clarifications and corrections. We expect the proposed revisions will 
have an insignificant effect on emission reductions. Therefore, the 
proposed amendments should not appreciably increase risk for any 
populations.

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

    This action is not subject to Executive Order 13211 because it is 
not a significant regulatory action under Executive Order 12866.

J. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR 
Part 51

    This rulemaking involves technical standards. As described in 
section III.C of this preamble, the EPA proposes to use the voluntary 
consensus standard ANSI/ASME PTC 19-10-1981--Part 10 ``Flue and Exhaust 
Gas Analyses'' as an acceptable alternative to EPA Methods 3A and 3B 
for the manual procedures only and not the instrumental procedures. 
This method is available at the American National Standards Institute 
(ANSI), 1899 L Street NW, 11th floor, Washington, DC 20036 and the 
American Society of Mechanical Engineers (ASME), Three Park Avenue, New 
York, NY 10016-5990. See https://wwww.ansi.org and https://www.asme.org.

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

    The EPA believes that this action does not have disproportionately 
high and adverse human health or environmental effects on minority 
populations, low-income populations, and/or indigenous peoples, as 
specified in Executive Order 12898 (59 FR 7629, February 16, 1994). The 
proposed amendments serve to make technical clarifications and 
corrections. We expect the proposed revisions will have an 
insignificant effect on emission reductions. Therefore, the proposed 
amendments should not appreciably increase risk for any populations.

List of Subjects in 40 CFR Parts 60 and 63

    Environmental protection, Administrative practice and procedures, 
Air pollution control, Hazardous substances, Incorporation by 
reference, Intergovernmental relations, Reporting and recordkeeping 
requirements.

    Dated: March 20, 2018.
E. Scott Pruitt,
Administrator.

    For the reasons stated 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 A--General Provisions

0
2. Section 60.17 is amended by revising paragraph (g)(14) to read as 
follows:


Sec.  60.17  Incorporations by reference.

* * * * *
    (g) * * *
    (14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 
10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved 
for Sec. Sec.  60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i), 
and (j), 60.105a(b), (d), (f), and (g), Sec.  60.106a(a), Sec.  
60.107a(a), (c), and (d), tables 1 and 3 to subpart EEEE, tables 2 and 
4 to subpart FFFF, table 2 to subpart JJJJ, Sec.  60.285a(f), 
Sec. Sec.  60.4415(a), 60.2145(s) and (t), 60.2710(s), (t), and (w), 
60.2730(q), 60.4900(b), 60.5220(b), tables 1 and 2 to subpart LLLL, 
tables 2 and 3 to subpart MMMM, 60.5406(c), 60.5406a(c), 60.5407a(g), 
60.5413(b), 60.5413a(b) and 60.5413a(d).
* * * * *

Subpart Ja--Standards of Performance for Petroleum Refineries for 
Which Construction, Reconstruction, or Modification Commenced After 
May 14, 2007

0
3. Section 60.105a is amended by revising paragraph (b)(2)(ii) to read 
as follows:


Sec.  60.105a  Monitoring of emissions and operations for fluid 
catalytic cracking units (FCCU) and fluid coking units (FCU).

* * * * *
    (b) * * *
    (2) * * *
    (ii) The owner or operator shall conduct performance evaluations of 
each CO2 and O2 monitor according to the 
requirements in Sec.  60.13(c) and Performance Specification 3 of 
appendix B to this part. The owner or operator shall use Method 3, 3A 
or 3B of appendix A-2 to this part for conducting the relative accuracy 
evaluations. The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust 
Gas Analyses,'' (incorporated by reference--see Sec.  60.17) is an 
acceptable alternative to EPA Method 3B of appendix A-2 to part 60.
* * * * *
0
4. Section 60.106a is amended by revising paragraph (a)(1)(iii) to read 
as follows:


Sec.  60.106a  Monitoring of emissions and operations for sulfur 
recovery plants.

    (a) * * *
    (1) * * *
    (iii) The owner or operator shall conduct performance evaluations 
of each SO2 monitor according to the requirements in Sec.  
60.13(c) and Performance Specification 2 of appendix B to part 60. The 
owner or operator shall use Method 6 or 6C of appendix A-4 to part 60. 
The method ANSI/ASME PTC 19.10-1981, ``Flue and Exhaust Gas Analyses,'' 
(incorporated by reference--see Sec.  60.17) is an acceptable 
alternative to EPA Method 6.
* * * * *

PART 63--NATIONAL EMISSION STANDARDS FOR HAZARDOUS AIR POLLUTANTS 
FOR SOURCE CATEGORIES

0
5. The authority citation for part 63 continues to read as follows:

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

Subpart CC--National Emission Standards for Hazardous Air 
Pollutants From Petroleum Refineries

0
6. Section 63.641 is amended by:
0
a. Revising the definitions of ``Flare purge gas'', ``Flare 
supplemental gas'' and ``Relief valve'';
0
b. Adding a new definition of ``Pressure relief device''; and
0
c. Revising paragraphs (1)(i) and (ii) of the definition of ``Reference 
control technology for storage vessels.''
    The revisions and addition read as follows:

[[Page 15476]]

Sec.  63.641  Definitions.

* * * * *
    Flare purge gas means gas introduced between a flare header's water 
seal and the flare tip to prevent oxygen infiltration (backflow) into 
the flare tip or for other safety reasons. For a flare with no water 
seal, the function of flare purge gas is performed by flare sweep gas 
and, therefore, by definition, such a flare has no flare purge gas.
    Flare supplemental gas means all gas introduced to the flare to 
improve the heat content of combustion zone gas. Flare supplemental gas 
does not include assist air or assist steam.
* * * * *
    Pressure relief device means a valve, rupture disk, or similar 
device used only to release an unplanned, nonroutine discharge of gas 
from process equipment in order to avoid safety hazards or equipment 
damage. A pressure relief device discharge can result from an operator 
error, a malfunction such as a power failure or equipment failure, or 
other unexpected cause. Such devices include conventional, spring-
actuated relief valves, balanced bellows relief valves, pilot-operated 
relief valves, rupture disks, and breaking, buckling, or shearing pin 
devices.
* * * * *
    Reference control technology for storage vessels means either:
    (1) * * *
    (i) An internal floating roof, including an external floating roof 
converted to an internal floating roof, meeting the specifications of 
Sec.  63.1063(a)(1)(i), (a)(2), and (b) and Sec.  63.660(b)(2);
    (ii) An external floating roof meeting the specifications of Sec.  
63.1063(a)(1)(ii), (a)(2), and (b) and Sec.  63.660(b)(2); or
* * * * *
    Relief valve means a type of pressure relief device that is 
designed to re-close after the pressure relief.
* * * * *
0
7. Section 63.643 is amended by:
0
a. Revising paragraphs (c) introductory text, (c)(1), and (c)(1)(ii) 
through (iv); and
0
b. Adding a new paragraph (c)(1)(v).
    The revisions and addition read as follows:


Sec.  63.643  Miscellaneous process vent provisions.

* * * * *
    (c) An owner or operator may designate a process vent as a 
maintenance vent if the vent is only used as a result of startup, 
shutdown, maintenance, or inspection of equipment where equipment is 
emptied, depressurized, degassed or placed into service. The owner or 
operator does not need to designate a maintenance vent as a Group 1 or 
Group 2 miscellaneous process vent nor identify maintenance vents in a 
Notification of Compliance Status report. The owner or operator must 
comply with the applicable requirements in paragraphs (c)(1) through 
(3) of this section for each maintenance vent according to the 
compliance dates specified in table 11 of this subpart, unless an 
extension is requested in accordance with the provisions in Sec.  
63.6(i).
    (1) Prior to venting to the atmosphere, process liquids are removed 
from the equipment as much as practical and the equipment is 
depressured to a control device meeting requirements in paragraphs 
(a)(1) or (2) of this section, a fuel gas system, or back to the 
process until one of the following conditions, as applicable, is met.
    (i) * * *
    (ii) If there is no ability to measure the LEL of the vapor in the 
equipment based on the design of the equipment, the pressure in the 
equipment served by the maintenance vent is reduced to 5 pounds per 
square inch gauge (psig) or less. Upon opening the maintenance vent, 
active purging of the equipment cannot be used until the LEL of the 
vapors in the maintenance vent (or inside the equipment if the 
maintenance is a hatch or similar type of opening) is less than 10 
percent.
    (iii) The equipment served by the maintenance vent contains less 
than 72 pounds of total volatile organic compounds (VOC).
    (iv) If the maintenance vent is associated with equipment 
containing pyrophoric catalyst (e.g., hydrotreaters and hydrocrackers) 
and a pure hydrogen supply is not available at the equipment at the 
time of the startup, shutdown, maintenance, or inspection activity, the 
LEL of the vapor in the equipment must be less than 20 percent, except 
for one event per year not to exceed 35 percent considering all such 
maintenance vents at the refinery.
    (v) If, after applying best practices to isolate and purge 
equipment served by a maintenance vent, none of the applicable 
criterion in paragraphs (c)(1)(i) through (iv) can be met prior to 
installing or removing a blind flange or similar equipment blind, the 
pressure in the equipment served by the maintenance vent is reduced to 
2 psig or less, Active purging of the equipment may be used provided 
the equipment pressure at the location where purge gas is introduced 
remains at 2 psig or less.
* * * * *
0
8. Section 63.644 is amended by revising paragraph (c) introductory 
text and adding paragraph (c)(3) to read as follows:


Sec.  63.644  Monitoring provisions for miscellaneous process vents.

* * * * *
    (c) The owner or operator of a Group 1 miscellaneous process vent 
using a vent system that contains bypass lines that could divert a vent 
stream away from the control device used to comply with paragraph (a) 
of this section either directly to the atmosphere or to a control 
device that does not comply with the requirements in Sec.  63.643(a) 
shall comply with either paragraph (c)(1), (2), or (3) of this section. 
Use of the bypass at any time to divert a Group 1 miscellaneous process 
vent stream to the atmosphere or to a control device that does not 
comply with the requirements in Sec.  63.643(a) is an emissions 
standards violation. Equipment such as low leg drains and equipment 
subject to Sec.  63.648 are not subject to this paragraph (c).
* * * * *
    (3) Use a cap, blind flange, plug, or a second valve for an open-
ended valve or line following the requirements specified in Sec.  
60.482-6(a)(2), (b) and (c).
* * * * *
0
9. Section 63.648 is amended by:
0
a. Revising the introductory text of paragraphs (a), (c), and (j);
0
b. Revising paragraphs (j)(3)(ii)(A) and (E), (j)(3)(iv), (j)(3)(v) 
introductory text, and (j)(4).
    The revisions and additions read as follows:


Sec.  63.648  Equipment leak standards.

    (a) Each owner or operator of an existing source subject to the 
provisions of this subpart shall comply with the provisions of 40 CFR 
part 60, subpart VV, and paragraph (b) of this section except as 
provided in paragraphs (a)(1) through (3), and (c) through (j) of this 
section. Each owner or operator of a new source subject to the 
provisions of this subpart shall comply with subpart H of this part 
except as provided in paragraphs (c) through (j) of this section.
* * * * *
    (c) In lieu of complying with the existing source provisions of 
paragraph (a) in this section, an owner or operator may elect to comply 
with the requirements of Sec. Sec.  63.161 through 63.169, 63.171, 
63.172, 63.175, 63.176, 63.177, 63.179, and 63.180 of subpart H except 
as provided in paragraphs (c)(1) through (12) and (e) through (j) of 
this section.
* * * * *
    (j) Except as specified in paragraph (j)(4) of this section, the 
owner or

[[Page 15477]]

operator must comply with the requirements specified in paragraphs 
(j)(1) and (2) of this section for pressure relief devices, such as 
relief valves or rupture disks, in organic HAP gas or vapor service 
instead of the pressure relief device requirements of Sec.  60.482-4 or 
Sec.  63.165, as applicable. Except as specified in paragraphs (j)(4) 
and (5) of this section, the owner or operator must also comply with 
the requirements specified in paragraph (j)(3) of this section for all 
pressure relief devices in organic HAP service.
* * * * *
    (3) * * *
    (ii) * * *
    (A) Flow, temperature, liquid level and pressure indicators with 
deadman switches, monitors, or automatic actuators. Independent, non-
duplicative systems within this category count as separate redundant 
prevention measures.
    (B) * * *
    (C) * * *
    (D) * * *
    (E) Staged relief system where initial pressure relief device (with 
lower set release pressure) discharges to a flare or other closed vent 
system and control device.
* * * * *
    (iv) The owner or operator shall determine the total number of 
release events occurred during the calendar year for each affected 
pressure relief device separately. The owner or operator shall also 
determine the total number of release events for each pressure relief 
device for which the root cause analysis concluded that the root cause 
was a force majeure event, as defined in this subpart.
    (v) Except for pressure relief devices described in paragraphs 
(j)(4) and (5) of this section, the following release events from an 
affected pressure relief device are a violation of the pressure release 
management work practice standards.
* * * * *
    (4) Pressure relief devices routed to a control device. (i) If all 
releases and potential leaks from a pressure relief device are routed 
through a closed vent system to a control device, back into the process 
or to the fuel gas system, the owner or operator is not required to 
comply with paragraph (j)(1), (2), or (3) (if applicable) of this 
section.
    (ii) If a pilot-operated pressure relief device is used and the 
primary release valve is routed through a closed vent system to a 
control device, back into the process or to the fuel gas system, the 
owner or operator is required to comply only with paragraphs (j)(1) and 
(2) of this section for the pilot discharge vent and is not required to 
comply with paragraph (j)(3) of this section for the pilot-operated 
pressure relief device.
    (iii) If a balanced bellows pressure relief device is used and the 
primary release valve is routed through a closed vent system to a 
control device, back into the process or to the fuel gas system, the 
owner or operator is required to comply only with paragraphs (j)(1) and 
(2) of this section for the bonnet vent and is not required to comply 
with paragraph (j)(3) of this section for the balanced bellows pressure 
relief device.
    (iv) Both the closed vent system and control device (if applicable) 
referenced in paragraphs (j)(4)(i) through (iii) of this section must 
meet the requirements of Sec.  63.644. When complying with this 
paragraph (j)(4), all references to ``Group 1 miscellaneous process 
vent'' in Sec.  63.644 mean ``pressure relief device.''
    (v) If a pressure relief device complying with this paragraph 
(j)(4) is routed to the fuel gas system, then on and after January 30, 
2019, any flares receiving gas from that fuel gas system must be in 
compliance with Sec.  63.670.
* * * * *
0
10. Section 63.655 is amended by:
0
a. Revising the introductory text of paragraph (f);
0
b. Revising paragraphs (f)(1)(i)(A)(1) through (3), (f)(1)(i)(B)(3), 
(f)(1)(i)(C)(2), (f)(1)(iii), (f)(2), (f)(4), (f)(6), (g)(2)(B)(1) and 
(g)(10) introductory text;
0
c. Redesignating paragraph (g)(10)(iii) as (g)(10)(iv);
0
d. Adding new paragraph (g)(10)(iii);
0
e. Revising paragraph (g)(13) introductory text and paragraphs 
(h)(2)(ii);
0
f. Removing and reserving paragraph (h)(5)(iii)(B);
0
g. Revising paragraph (h)(8);
0
h. Revising paragraphs (h)(9)(i) introductory text and (ii) 
introductory text;
0
i. Adding new paragraph (h)(10);
0
j. Revising paragraph (i)(3)(ii)(B);
0
k. Adding new paragraphs (i)(3)(ii)(C), (i)(5)(i) through (v);
0
l. Revising paragraphs (i)(7)(iii)(B) and (i)(11) introductory text;
0
m. Adding new paragraph (i)(11)(iv);
0
n. Revising paragraph (i)(12) introductory text and paragraph 
(i)(12)(iv); and adding new paragraph (i)(12)(vi).
    The revisions and additions read as follows:


Sec.  63.655  Reporting and recordkeeping requirements.

* * * * *
    (f) Each owner or operator of a source subject to this subpart 
shall submit a Notification of Compliance Status report within 150 days 
after the compliance dates specified in Sec.  63.640(h) with the 
exception of Notification of Compliance Status reports submitted to 
comply with Sec.  63.640(l)(3), for storage vessels subject to the 
compliance schedule specified in Sec.  63.640(h)(2), and for sources 
listed in Table 11 of this subpart that have a compliance date on or 
after February 1, 2016. Notification of Compliance Status reports 
required by Sec.  63.640(l)(3), for storage vessels subject to the 
compliance dates specified in Sec.  63.640(h)(2), and for sources 
listed in Table 11 of this subpart that have a compliance date on or 
after February 1, 2016 shall be submitted according to paragraph (f)(6) 
of this section. This information may be submitted in an operating 
permit application, in an amendment to an operating permit application, 
in a separate submittal, or in any combination of the three. If the 
required information has been submitted before the date 150 days after 
the compliance date specified in Sec.  63.640(h), a separate 
Notification of Compliance Status report is not required within 150 
days after the compliance dates specified in Sec.  63.640(h). If an 
owner or operator submits the information specified in paragraphs 
(f)(1) through (5) of this section at different times, and/or in 
different submittals, later submittals may refer to earlier submittals 
instead of duplicating and resubmitting the previously submitted 
information. Each owner or operator of a gasoline loading rack 
classified under Standard Industrial Classification Code 2911 located 
within a contiguous area and under common control with a petroleum 
refinery subject to the standards of this subpart shall submit the 
Notification of Compliance Status report required by subpart R of this 
part within 150 days after the compliance dates specified in Sec.  
63.640(h).
    (1) * * *
    (i) * * *
    (A) * * *
    (1) For each Group 1 storage vessel complying with either Sec.  
63.646 or Sec.  63.660 that is not included in an emissions average, 
the method of compliance (i.e., internal floating roof, external 
floating roof, or closed vent system and control device).
    (2) For storage vessels subject to the compliance schedule 
specified in Sec.  63.640(h)(2) that are not complying with Sec.  
63.646 or Sec.  63.660 as applicable, the anticipated compliance date.
    (3) For storage vessels subject to the compliance schedule 
specified in Sec.  63.640(h)(2) that are complying with Sec.  63.646 or 
Sec.  63.660, as applicable, and

[[Page 15478]]

the Group 1 storage vessels described in Sec.  63.640(l), the actual 
compliance date.
    (B) * * *
    (3) If the owner or operator elects to submit the results of a 
performance test, identification of the storage vessel and control 
device for which the performance test will be submitted, and 
identification of the emission point(s) that share the control device 
with the storage vessel and for which the performance test will be 
conducted. If the performance test is submitted electronically through 
the EPA's Compliance and Emissions Data Reporting Interface (CEDRI) in 
accordance with Sec.  63.655(h)(9), the process unit(s) tested, the 
pollutant(s) tested, and the date that such performance test was 
conducted may be submitted in the Notification of Compliance Status in 
lieu of the performance test results. The performance test results must 
be submitted to CEDRI by the date the Notification of Compliance Status 
is submitted.
    (C) * * *
    (2) If a performance test is conducted instead of a design 
evaluation, results of the performance test demonstrating that the 
control device achieves greater than or equal to the required control 
efficiency. A performance test conducted prior to the compliance date 
of this subpart can be used to comply with this requirement, provided 
that the test was conducted using EPA methods and that the test 
conditions are representative of current operating practices. If the 
performance test is submitted electronically through the EPA's 
Compliance and Emissions Data Reporting Interface in accordance with 
Sec.  63.655(h)(9), the process unit(s) tested, the pollutant(s) 
tested, and the date that such performance test was conducted may be 
submitted in the Notification of Compliance Status in lieu of the 
performance test results. The performance test results must be 
submitted to CEDRI by the date the Notification of Compliance Status is 
submitted.
* * * * *
    (iii) For miscellaneous process vents controlled by control devices 
required to be tested under Sec.  63.645 of this subpart and Sec.  
63.116(c) of subpart G of this part, performance test results including 
the information in paragraphs (f)(1)(iii)(A) and (B) of this section. 
Results of a performance test conducted prior to the compliance date of 
this subpart can be used provided that the test was conducted using the 
methods specified in Sec.  63.645 and that the test conditions are 
representative of current operating conditions. If the performance test 
is submitted electronically through the EPA's Compliance and Emissions 
Data Reporting Interface in accordance with Sec.  63.655(h)(9), the 
process unit(s) tested, the pollutant(s) tested, and the date that such 
performance test was conducted may be submitted in the Notification of 
Compliance Status in lieu of the performance test results. The 
performance test results must be submitted to CEDRI by the date the 
Notification of Compliance Status is submitted.
* * * * *
    (2) If initial performance tests are required by Sec. Sec.  63.643 
through 63.653, the Notification of Compliance Status report shall 
include one complete test report for each test method used for a 
particular source. On and after February 1, 2016, for data collected 
using test methods supported by the EPA's Electronic Reporting Tool 
(ERT) as listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at 
the time of the test, you must submit the results in accordance with 
Sec.  63.655(h)(9) by the date that you submit the Notification of 
Compliance Status, and you must include the process unit(s) tested, the 
pollutant(s) tested, and the date that such performance test was 
conducted in the Notification of Compliance Status. All other 
performance test results must be reported in the Notification of 
Compliance Status.
* * * * *
    (4) Results of any continuous monitoring system performance 
evaluations shall be included in the Notification of Compliance Status 
report, unless the results are required to be submitted electronically 
by Sec.  63.655(h)(9). For performance evaluation results required to 
be submitted through CEDRI, submit the results in accordance with Sec.  
63.655(h)(9) by the date that you submit the Notification of Compliance 
Status and include the process unit where the CMS is installed, the 
parameter measured by the CMS, and the date that the performance 
evaluation was conducted in the Notification of Compliance Status.
* * * * *
    (6) Notification of Compliance Status reports required by Sec.  
63.640(l)(3), for storage vessels subject to the compliance dates 
specified in Sec.  63.640(h)(2), and for sources listed in Table 11 of 
this subpart that have a compliance date on or after February 1, 2016 
shall be submitted no later than 60 days after the end of the 6-month 
period during which the change or addition was made that resulted in 
the Group 1 emission point or the existing Group 1 storage vessel was 
brought into compliance or the requirements with compliance dates on or 
after February 1, 2016, became effective, and may be combined with the 
periodic report. Six-month periods shall be the same 6-month periods 
specified in paragraph (g) of this section. The Notification of 
Compliance Status report shall include the information specified in 
paragraphs (f)(1) through (f)(5) of this section. This information may 
be submitted in an operating permit application, in an amendment to an 
operating permit application, in a separate submittal, as part of the 
periodic report, or in any combination of these four. If the required 
information has been submitted before the date 60 days after the end of 
the 6-month period in which the addition of the Group 1 emission point 
took place, a separate Notification of Compliance Status report is not 
required within 60 days after the end of the 6-month period. If an 
owner or operator submits the information specified in paragraphs 
(f)(1) through (f)(5) of this section at different times, and/or in 
different submittals, later submittals may refer to earlier submittals 
instead of duplicating and resubmitting the previously submitted 
information.
* * * * *
    (g) * * *
    (2) * * *
    (B) * * *
    (1) A failure is defined as any time in which the internal floating 
roof has defects; or the primary seal has holes, tears, or other 
openings in the seal or the seal fabric; or the secondary seal (if one 
has been installed) has holes, tears, or other openings in the seal or 
the seal fabric; or, for a storage vessel that is part of a new source, 
the gaskets no longer close off the liquid surface from the atmosphere; 
or, for a storage vessel that is part of a new source, the slotted 
membrane has more than a 10 percent open area.
* * * * *
    (10) For pressure relief devices subject to the requirements Sec.  
63.648(j), Periodic Reports must include the information specified in 
paragraphs (g)(10)(i) through (iv) of this section.
* * * * *
    (iii) For pilot-operated pressure relief devices in organic HAP 
service, report each pressure release to the atmosphere through the 
pilot vent that equals or exceeds 72 pounds of VOC per day, including 
duration of the pressure release through the pilot vent and

[[Page 15479]]

estimate of the mass quantity of each organic HAP released.
* * * * *
    (13) For maintenance vents subject to the requirements in Sec.  
63.643(c), Periodic Reports must include the information specified in 
paragraphs (g)(13)(i) through (iv) of this section for any release 
exceeding the applicable limits in Sec.  63.643(c)(1). For the purposes 
of this reporting requirement, owners or operators complying with Sec.  
63.643(c)(1)(iv) must report each venting event for which the lower 
explosive limit is 20 percent or greater; owners or operators complying 
with Sec.  63.643(c)(1)(v) must report each venting event conducted 
under those provisions and include an explanation for each event as to 
why utilization of this alternative was required.
* * * * *
    (h) * * *
    (2) * * *
    (ii) In order to afford the Administrator the opportunity to have 
an observer present, the owner or operator of a storage vessel equipped 
with an external floating roof shall notify the Administrator of any 
seal gap measurements. The notification shall be made in writing at 
least 30 calendar days in advance of any gap measurements required by 
Sec.  63.120(b)(1) or (2) of subpart G or Sec.  63.1063(d)(3) of 
subpart WW. The State or local permitting authority can waive this 
notification requirement for all or some storage vessels subject to the 
rule or can allow less than 30 calendar days' notice.
* * * * *
    (8) For fenceline monitoring systems subject to Sec.  63.658, each 
owner or operator shall submit the following information to the EPA's 
Compliance and Emissions Data Reporting Interface (CEDRI) on a 
quarterly basis. (CEDRI can be accessed through the EPA's Central Data 
Exchange (CDX) (https://cdx.epa.gov/). The first quarterly report must 
be submitted once the owner or operator has obtained 12 months of data. 
The first quarterly report must cover the period beginning on the 
compliance date that is specified in Table 11 of this subpart and 
ending on March 31, June 30, September 30 or December 31, whichever 
date is the first date that occurs after the owner or operator has 
obtained 12 months of data (i.e., the first quarterly report will 
contain between 12 and 15 months of data). Each subsequent quarterly 
report must cover one of the following reporting periods: Quarter 1 
from January 1 through March 31; Quarter 2 from April 1 through June 
30; Quarter 3 from July 1 through September 30; and Quarter 4 from 
October 1 through December 31. Each quarterly report must be 
electronically submitted no later than 45 calendar days following the 
end of the reporting period.
    (i) Facility name and address.
    (ii) Year and reporting quarter (i.e., Quarter 1, Quarter 2, 
Quarter 3, or Quarter 4).
    (iii) For the first reporting period and for any reporting period 
in which a passive monitor is added or moved, for each passive monitor: 
the latitude and longitude location coordinates; the sampler name; and 
identification of the type of sampler (i.e., regular monitor, extra 
monitor, duplicate, field blank, inactive). The owner or operator shall 
determine the coordinates using an instrument with an accuracy of at 
least 3 meters. Coordinates shall be in decimal degrees with at least 
five decimal places.
    (iv) The beginning and ending dates for each sampling period.
    (v) Individual sample results for benzene reported in units of 
[micro]g/m\3\ for each monitor for each sampling period that ends 
during the reporting period. Results below the method detection limit 
shall be flagged as below the detection limit and reported at the 
method detection limit.
    (vi) Data flags that indicate each monitor that was skipped for the 
sampling period, if the owner or operator uses an alternative sampling 
frequency under Sec.  63.658(e)(3).
    (vii) Data flags for each outlier determined in accordance with 
Section 9.2 of Method 325A of appendix A of this part. For each 
outlier, the owner or operator must submit the individual sample result 
of the outlier, as well as the evidence used to conclude that the 
result is an outlier.
    (viii) Based on the information provided for the individual sample 
results, CEDRI will calculate the biweekly concentration difference 
([Delta]c) for benzene for each sampling period and the annual average 
[Delta]c for benzene for each sampling period. The owner or operator 
may change these calculated values, but an explanation must be provided 
whenever a calculated value is changed.
    (9) * * *
    (i) Unless otherwise specified by this subpart, within 60 days 
after the date of completing each performance test as required by this 
subpart, the owner or operator shall submit the results of the 
performance tests following the procedure specified in either paragraph 
(h)(9)(i)(A) or (B) of this section.
* * * * *
    (ii) Unless otherwise specified by this subpart, within 60 days 
after the date of completing each CEMS performance evaluation as 
required by this subpart, the owner or operator must submit the results 
of the performance evaluation following the procedure specified in 
either paragraph (h)(9)(ii)(A) or (B) of this section.
* * * * *
    (10) Extensions to electronic reporting deadlines.
    (i) If you are required to electronically submit a report through 
the Compliance and Emissions Data Reporting Interface (CEDRI) in the 
EPA's Central Data Exchange (CDX), and due to a planned or actual 
outage of either the EPA's CEDRI or CDX systems within the period of 
time beginning 5 business days prior to the date that the submission is 
due, you will be or are precluded from accessing CEDRI or CDX and 
submitting a required report within the time prescribed, you may assert 
a claim of EPA system outage for failure to timely comply with the 
reporting requirement. You must submit notification to the 
Administrator in writing as soon as possible following the date you 
first knew, or through due diligence should have known, that the event 
may cause or caused a delay in reporting. You must provide to the 
Administrator a written description identifying the date, time and 
length of the outage; a rationale for attributing the delay in 
reporting beyond the regulatory deadline to the EPA system outage; 
describe the measures taken or to be taken to minimize the delay in 
reporting; and identify a date by which you propose to report, or if 
you have already met the reporting requirement at the time of the 
notification, the date you reported. In any circumstance, the report 
must be submitted electronically as soon as possible after the outage 
is resolved. The decision to accept the claim of EPA system outage and 
allow an extension to the reporting deadline is solely within the 
discretion of the Administrator.
    (ii) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX and a force majeure event is about to occur, 
occurs, or has occurred or there are lingering effects from such an 
event within the period of time beginning 5 business days prior to the 
date the submission is due, the owner or operator may assert a claim of 
force majeure for failure to timely comply with the reporting 
requirement. For the purposes of this paragraph, a force majeure event 
is defined as an event that will be or has been caused by circumstances 
beyond the control of the affected facility, its contractors, or any 
entity controlled by

[[Page 15480]]

the affected facility that prevents you from complying with the 
requirement to submit a report electronically within the time period 
prescribed. Examples of such events are acts of nature (e.g., 
hurricanes, earthquakes, or floods), acts of war or terrorism, or 
equipment failure or safety hazard beyond the control of the affected 
facility (e.g., large scale power outage). If you intend to assert a 
claim of force majeure, you must submit notification to the 
Administrator in writing as soon as possible following the date you 
first knew, or through due diligence should have known, that the event 
may cause or caused a delay in reporting. You must provide to the 
Administrator a written description of the force majeure event and a 
rationale for attributing the delay in reporting beyond the regulatory 
deadline to the force majeure event; describe the measures taken or to 
be taken to minimize the delay in reporting; and identify a date by 
which you propose to report, or if you have already met the reporting 
requirement at the time of the notification, the date you reported. In 
any circumstance, the reporting must occur as soon as possible after 
the force majeure event occurs. The decision to accept the claim of 
force majeure and allow an extension to the reporting deadline is 
solely within the discretion of the Administrator.
* * * * *
    (i) * * *
    (3) * * *
    (ii) * * *
    (B) Block average values for 1 hour or shorter periods calculated 
from all measured data values during each period. If values are 
measured more frequently than once per minute, a single value for each 
minute may be used to calculate the hourly (or shorter period) block 
average instead of all measured values; or
    (C) All values that meet the set criteria for variation from 
previously recorded values using an automated data compression 
recording system.
    (1) The automated data compression recording system shall be 
designed to:
    (i) Measure the operating parameter value at least once every hour.
    (ii) Record at least 24 values each day during periods of 
operation.
    (iii) Record the date and time when monitors are turned off or on.
    (iv) Recognize unchanging data that may indicate the monitor is not 
functioning properly, alert the operator, and record the incident.
    (v) Compute daily average values of the monitored operating 
parameter based on recorded data.
    (2) You must maintain a record of the description of the monitoring 
system and data compression recording system including the criteria 
used to determine which monitored values are recorded and retained, the 
method for calculating daily averages, and a demonstration that the 
system meets all criteria of paragraph (i)(3)(ii)(C)(1) of this 
section.
* * * * *
    (5) * * *
    (i) Identification of all petroleum refinery process unit heat 
exchangers at the facility and the average annual HAP concentration of 
process fluid or intervening cooling fluid estimated when developing 
the Notification of Compliance Status report.
    (ii) Identification of all heat exchange systems subject to the 
monitoring requirements in Sec.  63.654 and identification of all heat 
exchange systems that are exempt from the monitoring requirements 
according to the provisions in Sec.  63.654(b). For each heat exchange 
system that is subject to the monitoring requirements in Sec.  63.654, 
this must include identification of all heat exchangers within each 
heat exchange system, and, for closed-loop recirculation systems, the 
cooling tower included in each heat exchange system.
    (iii) Results of the following monitoring data for each required 
monitoring event:
    (A) Date/time of event.
    (B) Barometric pressure.
    (C) El Paso air stripping apparatus water flow milliliter/minute 
(ml/min) and air flow, ml/min, and air temperature, [deg]Celsius.
    (D) FID reading (ppmv).
    (E) Length of sampling period.
    (F) Sample volume.
    (G) Calibration information identified in Section 5.4.2 of the 
``Air Stripping Method (Modified El Paso Method) for Determination of 
Volatile Organic Compound Emissions from Water Sources'' Revision 
Number One, dated January 2003, Sampling Procedures Manual, Appendix P: 
Cooling Tower Monitoring, prepared by Texas Commission on Environmental 
Quality, January 31, 2003 (incorporated by reference--see Sec.  63.14).
    (iv) The date when a leak was identified, the date the source of 
the leak was identified, and the date when the heat exchanger was 
repaired or taken out of service.
    (v) If a repair is delayed, the reason for the delay, the schedule 
for completing the repair, the heat exchange exit line flow or cooling 
tower return line average flow rate at the monitoring location (in 
gallons/minute), and the estimate of potential strippable hydrocarbon 
emissions for each required monitoring interval during the delay of 
repair.
* * * * *
    (7) * * *
    (iii) * * *
    (B) The pressure or temperature of the coke drum vessel, as 
applicable, for the 5-minute period prior to the pre-vent draining.
* * * * *
    (11) For each pressure relief device subject to the pressure 
release management work practice standards in Sec.  63.648(j)(3), the 
owner or operator shall keep the records specified in paragraphs 
(i)(11)(i) through (iii) of this section. For each pilot-operated 
pressure relief device subject to the requirements at Sec.  
63.648(j)(4)(ii) or (iii), the owner or operator shall keep the records 
specified in paragraph (i)(11)(iv) of this section.
* * * * *
    (iv) For pilot-operated pressure relief devices, general or 
release-specific records for estimating the quantity of VOC released 
from the pilot vent during a release event, and records of calculations 
used to determine the quantity of specific HAP released for any event 
or series of events in which 72 or more pounds of VOC are released in a 
day.
    (12) For each maintenance vent opening subject to the requirements 
in Sec.  63.643(c), the owner or operator shall keep the applicable 
records specified in (i)(12)(i) through (vi) of this section.
* * * * *
    (iv) If complying with the requirements of Sec.  63.643(c)(1)(iii), 
records used to estimate the total quantity of VOC in the equipment and 
the type and size limits of equipment that contain less than 72 pounds 
of VOC at the time of maintenance vent opening. For each maintenance 
vent opening for which the deinventory procedures specified in 
paragraph (i)(12)(i) of this section are not followed or for which the 
equipment opened exceeds the type and size limits established in the 
records specified in this paragraph, identification of the maintenance 
vent, the process units or equipment associated with the maintenance 
vent, the date of maintenance vent opening, and records used to 
estimate the total quantity of VOC in the equipment at the time the 
maintenance vent was opened to the atmosphere.
* * * * *
    (vi) If complying with the requirements of Sec.  63.643(c)(1)(v), 
identification of the maintenance vent, the process units or equipment 
associated with the maintenance vent,

[[Page 15481]]

records documenting actions taken to comply with other applicable 
alternatives and why utilization of this alternative was required, the 
date of maintenance vent opening, the equipment pressure and lower 
explosive limit of the vapors in the equipment at the time of 
discharge, an indication of whether active purging was performed and 
the pressure of the equipment during the installation or removal of the 
blind if active purging was used, the duration the maintenance vent was 
open during the blind installation or removal process, and records used 
to estimate the total quantity of VOC in the equipment at the time the 
maintenance vent was opened to the atmosphere for each applicable 
maintenance vent opening.
* * * * *
0
11. Section 63.657 is amended by revising paragraphs (a)(1)(i) and 
(ii), (a)(2)(i) and (ii), (b)(5), and (e) to read as follows:


Sec.  63.657  Delayed coking unit decoking operation standards.

    (a) * * *
    (1) * * *
    (i) An average vessel pressure of 2 psig or less determined on a 
rolling 60-event average; or
    (ii) An average vessel temperature of 220 degrees Fahrenheit or 
less determined on a rolling 60-event average.
    (2) * * *
    (i) A vessel pressure of 2.0 psig or less for each decoking event; 
or
    (ii) A vessel temperature of 218 degrees Fahrenheit or less for 
each decoking event.
* * * * *
    (b) * * *
    (5) The output of the pressure monitoring system must be reviewed 
each day the unit is operated to ensure that the pressure readings 
fluctuate as expected between operating and cooling/decoking cycles to 
verify the pressure taps are not plugged. Plugged pressure taps must be 
unplugged or otherwise repaired prior to the next operating cycle.
* * * * *
    (e) The owner or operator of a delayed coking unit using the 
``water overflow'' method of coke cooling prior to complying with the 
applicable requirements in paragraph (a) of this section must overflow 
the water to a separator or similar disengaging device that is operated 
in a manner to prevent entrainment of gases from the coke drum vessel 
to the overflow water storage tank. Gases from the separator or 
disengaging device must be routed to a closed blowdown system or 
otherwise controlled following the requirements for a Group 1 
miscellaneous process vent. The liquid from the separator or 
disengaging device must be hardpiped to the overflow water storage tank 
or similarly transported to prevent exposure of the overflow water to 
the atmosphere. The overflow water storage tank may be an open or 
uncontrolled fixed-roof tank provided that a submerged fill pipe (pipe 
outlet below existing liquid level in the tank) is used to transfer 
overflow water to the tank. The owner or operator of a delayed coking 
unit using the ``water overflow'' method of coke cooling subject to 
this paragraph shall determine the coke drum vessel temperature as 
specified in paragraphs (c) and (d) of this section and shall not 
otherwise drain or vent the coke drum until the coke drum vessel 
temperature is at or below the applicable limits in paragraph 
(a)(1)(ii) or (a)(2)(ii) of this section.
* * * * *
0
12. Section 63.658 is amended by revising paragraphs (c)(1), (c)(2), 
(c)(3), (d)(1), (d)(2), (e) introductory text, (e)(3)(iv), (f)(1)(i), 
and (f)(1)(i)(B) to read as follows:


Sec.  63.658  Fenceline monitoring provisions.

* * * * *
    (c) * * *
    (1) As it pertains to this subpart, known sources of VOCs, as used 
in Section 8.2.1.3 in Method 325A of appendix A of this part for siting 
passive monitors, means a wastewater treatment unit, process unit, or 
any emission source requiring control according to the requirements of 
this subpart, including marine vessel loading operations. For marine 
vessel loading operations, one passive monitor should be sited on the 
shoreline adjacent to the dock. For this subpart, an additional monitor 
is not required if the only emission sources within 50 meters of the 
monitoring boundary are equipment leak sources satisfying all of the 
conditions in paragraphs (c)(1)(i) through (iv) of this section.
    (i) The equipment leak sources in organic HAP service within 50 
meters of the monitoring boundary are limited to valves, pumps, 
connectors, sampling connections, and open-ended lines. If compressors, 
pressure relief devices, or agitators in organic HAP service are 
present within 50 meters of the monitoring boundary, the additional 
passive monitoring location specified in Section 8.2.1.3 in Method 325A 
of appendix A of this part must be used.
    (ii) All equipment leak sources in gas or light liquid service (and 
in organic HAP service), including valves, pumps, connectors, sampling 
connections and open-ended lines, must be monitored using EPA Method 21 
of 40 CFR part 60, appendix A-7 no less frequently than quarterly with 
no provisions for skip period monitoring, or according to the 
provisions of 63.11(c) Alternative Work practice for monitoring 
equipment for leaks. For the purpose of this provision, a leak is 
detected if the instrument reading equals or exceeds the applicable 
limits in paragraphs (c)(1)(ii)(A) through (E) of this section:
    (A) For valves, pumps or connectors at an existing source, an 
instrument reading of 10,000 ppmv.
    (B) For valves or connectors at a new source, an instrument reading 
of 500 ppmv.
    (C) For pumps at a new source, an instrument reading of 2,000 ppmv.
    (D) For sampling connections or open-ended lines, an instrument 
reading of 500 ppmv above background.
    (E) For equipment monitored according to the Alternative Work 
practice for monitoring equipment for leaks, the leak definitions 
contained in 63.11 (c) (6)(i) through (iii).
    (iii) All equipment leak sources in organic HAP service, including 
sources in gas, light liquid and heavy liquid service, must be 
inspected using visual, audible, olfactory, or any other detection 
method at least monthly. A leak is detected if the inspection 
identifies a potential leak to the atmosphere or if there are 
indications of liquids dripping.
    (iv) All leaks identified by the monitoring or inspections 
specified in paragraphs (c)(1)(ii) or (iii) of this section must be 
repaired no later than 15 calendar days after it is detected with no 
provisions for delay of repair. If a repair is not completed within 15 
calendar days, the additional passive monitor specified in Section 
8.2.1.3 in Method 325A of appendix A of this part must be used.
    (2) The owner or operator may collect one or more background 
samples if the owner or operator believes that an offsite upwind source 
or an onsite source excluded under Sec.  63.640(g) may influence the 
sampler measurements. If the owner or operator elects to collect one or 
more background samples, the owner or operator must develop and submit 
a site-specific monitoring plan for approval according to the 
requirements in paragraph (i) of this section. Upon approval of the 
site-specific monitoring plan, the background sampler(s) should be 
operated co-currently with the routine samplers.
    (3) If there are 19 or fewer monitoring locations, the owner or 
operator shall

[[Page 15482]]

collect at least one co-located duplicate sample per sampling period 
and at least one field blank per sampling period. If there are 20 or 
more monitoring locations, the owner or operator shall collect at least 
two co-located duplicate samples per sampling period and at least one 
field blank per sampling period. The co-located duplicates may be 
collected at any of the perimeter sampling locations.
* * * * *
    (d) * * *
    (1) If a near-field source correction is used as provided in 
paragraph (i)(2) of this section or if an alternative test method is 
used that provides time-resolved measurements, the owner or operator 
shall:
* * * * *
    (2) For cases other than those specified in paragraph (d)(1) of 
this section, the owner or operator shall collect and record sampling 
period average temperature and barometric pressure using either an on-
site meteorological station in accordance with Section 8.3.1 through 
8.3.3 of Method 325A of appendix A of this part or, alternatively, 
using data from a United States Weather Service (USWS) meteorological 
station provided the USWS meteorological station is within 40 
kilometers (25 miles) of the refinery.
* * * * *
    (e) The owner or operator shall use a sampling period and sampling 
frequency as specified in paragraphs (e)(1) through (3) of this 
section.
* * * * *
    (3) * * *
    (iv) If every sample at a monitoring site that is monitored at the 
frequency specified in paragraph (e)(3)(iii) of this section is at or 
below 0.9 [micro]g/m\3\ for 2 years (i.e., 4 consecutive semi-annual 
samples), only one sample per year is required for that monitoring 
site. For yearly sampling, samples shall occur at least 10 months but 
no more than 14 months apart.
* * * * *
    (f) * * *
    (1) * * *
    (i) Except when near-field source correction is used as provided in 
paragraph (i) of this section, the owner or operator shall determine 
the highest and lowest sample results for benzene concentrations from 
the sample pool and calculate [Delta]c as the difference in these 
concentrations. Co-located samples must be averaged together for the 
purposes of determining the benzene concentration for that sampling 
location, and, if applicable, for determining [Delta]c. The owner or 
operator shall adhere to the following procedures when one or more 
samples for the sampling period are below the method detection limit 
for benzene:
* * * * *
    (B) If all sample results are below the method detection limit, the 
owner or operator shall use the method detection limit as the highest 
sample result and zero as the lowest sample result when calculating 
[Delta]c.
* * * * *
0
13. Section 63.660 is amended by revising the undesignated introductory 
text, paragraph (b) introductory text, paragraphs (b)(1), (e) and 
(i)(2) to read as follows:


Sec.  63.660  Storage vessel provisions.

    On and after the applicable compliance date for a Group 1 storage 
vessel located at a new or existing source as specified in Sec.  
63.640(h), the owner or operator of a Group 1 storage vessel storing 
liquid with a maximum true vapor pressure less than 76.6 kilopascals 
(11.0 pounds per square inch) that is part of a new or existing source 
shall comply with either the requirements in subpart WW or SS of this 
part according to the requirements in paragraphs (a) through (i) of 
this section and the owner or operator of a Group 1 storage vessel 
storing liquid with a maximum true vapor pressure greater than or equal 
to 76.6 kilopascals (11.0 pounds per square inch) that is part of a new 
or existing source shall comply with the requirements in subpart SS of 
this part according to the requirements in paragraphs (a) through (i) 
of this section.
* * * * *
    (b) A floating roof storage vessel complying with the requirements 
of subpart WW of this part may comply with the control option specified 
in paragraph (b)(1) of this section and, if equipped with a ladder 
having at least one slotted leg, shall comply with one of the control 
options as described in paragraph (b)(2) of this section. If the 
floating roof storage vessel does not meet the requirements of Sec.  
63.1063(a)(2)(i) through (a)(2)(viii) as of June 30, 2014, these 
requirements do not apply until the next time the vessel is completely 
emptied and degassed, or January 30, 2026, whichever occurs first.
    (1) In addition to the options presented in Sec. Sec.  
63.1063(a)(2)(viii)(A) and (B) and 63.1064, a floating roof storage 
vessel may comply with Sec.  63.1063(a)(2)(viii) using a flexible 
enclosure device and either a gasketed or welded cap on the top of the 
guidepole.
* * * * *
    (e) For storage vessels previously subject to requirements in Sec.  
63.646, initial inspection requirements in Sec.  63.1063(c)(1) and 
(2)(i) (i.e., those related to the initial filling of the storage 
vessel) or in Sec.  63.983(b)(1)(A), as applicable, are not required. 
Failure to perform other inspections and monitoring required by this 
section shall constitute a violation of the applicable standard of this 
subpart.
* * * * *
    (i) * * *
    (2) If a closed vent system contains a bypass line, the owner or 
operator shall comply with the provisions of either Sec.  
63.983(a)(3)(i) or (ii) for each closed vent system that contains 
bypass lines that could divert a vent stream either directly to the 
atmosphere or to a control device that does not comply with the 
requirements in subpart SS of this part. Except as provided in 
paragraphs (i)(2)(i) and (ii) of this section, use of the bypass at any 
time to divert a Group 1 storage vessel either directly to the 
atmosphere or to a control device that does not comply with the 
requirements in subpart SS of this part is an emissions standards 
violation. Equipment such as low leg drains and equipment subject to 
Sec.  63.648 are not subject to this paragraph (i)(2).
* * * * *
0
14. Section 63.670 is amended by:
0
a. Revising paragraph (f);
0
b. Revising paragraphs (h) introductory text, (h)(1), and (i) 
introductory text;
0
c. Adding new paragraphs (i)(5) and (6);
0
d. Revising paragraphs (j)(6);
0
h. Revising the definition of the Qcum term in the equation 
in paragraph (k)(3);
0
i. Revising paragraph (m)(2) introductory text;
0
j. Revising the definitions of the QNG2, QNG1, 
and NHVNG terms in the equation in paragraph (m)(2);
0
j. Revising paragraph (n)(2) introductory text and the definitions of 
the QNG2, QNG1, and NHVNG terms in the 
equation in paragraph (n)(2); and
0
l. Revising paragraphs (o) introductory text, (o)(1)(ii)(B), 
(o)(1)(iii)(B), and (o)(3)(i). The revisions and additions read as 
follows:


Sec.  63.670  Requirements for flare control devices.

* * * * *
    (f) Dilution operating limits for flares with perimeter assist air. 
Except as provided in paragraph (f)(1) of this section, for each flare 
actively receiving perimeter assist air, the owner or operator shall 
operate the flare to maintain the net heating value dilution

[[Page 15483]]

parameter (NHVdil) at or above 22 British thermal units per square foot 
(Btu/ft\2\) determined on a 15-minute block period basis when regulated 
material is being routed to the flare for at least 15-minutes. The 
owner or operator shall monitor and calculate NHVdil as 
specified in paragraph (n) of this section.
    (1) If the only assist air provided to a specific flare is 
perimeter assist air intentionally entrained in lower and upper steam 
at the flare tip and the flare tip diameter is 9 inches or greater, the 
owner or operator shall comply only with the NHVcz operating 
limit in paragraph (e) of this section for that flare.
    (2) Reserved.
* * * * *
    (h) Visible emissions monitoring. The owner or operator shall 
conduct an initial visible emissions demonstration using an observation 
period of 2 hours using Method 22 at 40 CFR part 60, appendix A-7. The 
initial visible emissions demonstration should be conducted the first 
time regulated materials are routed to the flare. Subsequent visible 
emissions observations must be conducted using either the methods in 
paragraph (h)(1) of this section or, alternatively, the methods in 
paragraph (h)(2) of this section. The owner or operator must record and 
report any instances where visible emissions are observed for more than 
5 minutes during any 2 consecutive hours as specified in Sec.  
63.655(g)(11)(ii).
    (1) At least once per day for each day regulated material is routed 
to the flare, conduct visible emissions observations using an 
observation period of 5 minutes using Method 22 at 40 CFR part 60, 
appendix A-7. If at any time the owner or operator sees visible 
emissions while regulated material is routed to the flare, even if the 
minimum required daily visible emission monitoring has already been 
performed, the owner or operator shall immediately begin an observation 
period of 5 minutes using Method 22 at 40 CFR part 60, appendix A-7. If 
visible emissions are observed for more than one continuous minute 
during any 5-minute observation period, the observation period using 
Method 22 at 40 CFR part 60, appendix A-7 must be extended to 2 hours 
or until 5-minutes of visible emissions are observed. Daily 5-minute 
Method 22 observations are not required to be conducted for days the 
flare does not receive any regulated material.
* * * * *
    (i) Flare vent gas, steam assist and air assist flow rate 
monitoring. The owner or operator shall install, operate, calibrate, 
and maintain a monitoring system capable of continuously measuring, 
calculating, and recording the volumetric flow rate in the flare header 
or headers that feed the flare as well as any flare supplemental gas 
used. Different flow monitoring methods may be used to measure 
different gaseous streams that make up the flare vent gas provided that 
the flow rates of all gas streams that contribute to the flare vent gas 
are determined. If assist air or assist steam is used, the owner or 
operator shall install, operate, calibrate, and maintain a monitoring 
system capable of continuously measuring, calculating, and recording 
the volumetric flow rate of assist air and/or assist steam used with 
the flare. If pre-mix assist air and perimeter assist are both used, 
the owner or operator shall install, operate, calibrate, and maintain a 
monitoring system capable of separately measuring, calculating, and 
recording the volumetric flow rate of premix assist air and perimeter 
assist air used with the flare. Flow monitoring system requirements and 
acceptable alternatives are provided in paragraphs (i)(1) through (6) 
of this section.
* * * * *
    (5) Continuously monitoring fan speed or power and using fan curves 
is an acceptable method for continuously monitoring assist air flow 
rates.
    (6) For perimeter assist air intentionally entrained in lower and 
upper steam, the monitored steam flow rate and the maximum design air-
to-steam volumetric flow ratio of the entrainment system may be used to 
determine the assist air flow rate.
    (j) * * *
    (6) Direct compositional or net heating value monitoring is not 
required for gas streams that have been demonstrated to have consistent 
composition (or a fixed minimum net heating value) according to the 
methods in paragraphs (j)(6)(i) through (iii) of this section.
* * * * *
    (k) * * *
    (3) * * *
* * * * *
    Qcum = Cumulative volumetric flow over 15-minute 
block average period, standard cubic feet.
* * * * *
    (m) * * *
    (2) Owners or operators of flares that use the feed-forward 
calculation methodology in paragraph (l)(5)(i) of this section and that 
monitor gas composition or net heating value in a location 
representative of the cumulative vent gas stream and that directly 
monitor flare supplemental gas flow additions to the flare must 
determine the 15-minute block average NHVcz using the 
following equation.
* * * * *
    QNG2 = Cumulative volumetric flow of flare 
supplemental gas during the 15-minute block period, scf.
    QNG1 = Cumulative volumetric flow of flare 
supplemental gas during the previous 15-minute block period, scf. 
For the first 15-minute block period of an event, use the volumetric 
flow value for the current 15-minute block period, i.e., 
QNG1=QNG2.
    NHVNG = Net heating value of flare supplemental gas 
for the 15-minute block period determined according to the 
requirements in paragraph (j)(5) of this section, Btu/scf.
* * * * *
    (n) * * *
    (2) Owners or operators of flares that use the feed-forward 
calculation methodology in paragraph (l)(5)(i) of this section and that 
monitor gas composition or net heating value in a location 
representative of the cumulative vent gas stream and that directly 
monitor flare supplemental gas flow additions to the flare must 
determine the 15-minute block average NHVdil using the 
following equation only during periods when perimeter assist air is 
used. For 15-minute block periods when there is no cumulative 
volumetric flow of perimeter assist air, the 15-minute block average 
NHVdil parameter does not need to be calculated.
* * * * *
    QNG2 = Cumulative volumetric flow of flare 
supplemental gas during the 15-minute block period, scf.
    QNG1 = Cumulative volumetric flow of flare 
supplemental gas during the previous 15-minute block period, scf. 
For the first 15-minute block period of an event, use the volumetric 
flow value for the current 15-minute block period, i.e., 
QNG1 =QNG2.
    NHVNG = Net heating value of flare supplemental gas 
for the 15-minute block period determined according to the 
requirements in paragraph (j)(5) of this section, Btu/scf.
* * * * *
    (o) Emergency flaring provisions. The owner or operator of a flare 
that has the potential to operate above its smokeless capacity under 
any circumstance shall comply with the provisions in paragraphs (o)(1) 
through (7) of this section.
    (1) * * *
    (ii) * * *
    (B) Implementation of prevention measures listed for pressure 
relief devices in Sec.  63.648(j)(3)(ii)(A) through (E) for each 
pressure relief device that can discharge to the flare.
* * * * *

[[Page 15484]]

    (iii) * * *
    (B) The smokeless capacity of the flare based on a 15-minute block 
average and design conditions. Note: A single value must be provided 
for the smokeless capacity of the flare.
* * * * *
    (3) * * *
    (i) The vent gas flow rate exceeds the smokeless capacity of the 
flare based on a 15-minute block average and visible emissions are 
present from the flare for more than 5 minutes during any 2 consecutive 
hours during the release event.
* * * * *
0
15. Table 6 to Subpart CC is amended by revising the entries 
``63.6(f)(3)'', ``63.6(h)(8)'', 63.7(a)(2)'', ``63.7(f)'', 
``63.7(h)(3)'', and ``63.8(e)'' to read as follows:

                            Table 6--General Provisions Applicability to Subpart CC a
----------------------------------------------------------------------------------------------------------------
                Reference                    Applies to subpart CC                      Comment
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
63.6(f)(3)..............................  Yes........................  Except the cross-references to Sec.
                                                                        63.6(f)(1) and (e)(1)(i) are changed to
                                                                        Sec.   63.642(n) and performance test
                                                                        results may be written or electronic.
 
                                                  * * * * * * *
63.6(h)(8)..............................  Yes........................  Except performance test results may be
                                                                        written or electronic.
 
                                                  * * * * * * *
63.7(a)(2)..............................  Yes........................  Except test results must be submitted in
                                                                        the Notification of Compliance Status
                                                                        report due 150 days after compliance
                                                                        date, as specified in Sec.   63.655(f)
                                                                        of subpart CC, unless they are required
                                                                        to be submitted electronically in
                                                                        accordance with Sec.   63.655(h)(9).
                                                                        Test results required to be submitted
                                                                        electronically must be submitted by the
                                                                        date the Notification of Compliance
                                                                        Status report is submitted.
 
                                                  * * * * * * *
63.7(f).................................  Yes........................  Except that additional notification or
                                                                        approval is not required for
                                                                        alternatives directly specified in
                                                                        Subpart CC.
 
                                                  * * * * * * *
63.7(h)(3)..............................  Yes........................  Yes, except site-specific test plans
                                                                        shall not be required, and where Sec.
                                                                        63.7(h)(3)(i) specifies waiver submittal
                                                                        date, the date shall be 90 days prior to
                                                                        the Notification of Compliance Status
                                                                        report in Sec.   63.655(f).
 
                                                  * * * * * * *
63.8(e).................................  Yes........................  Except that results are to be submitted
                                                                        electronically if required by Sec.
                                                                        63.655(h)(9).
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------

* * * * *
0
16. Table 13 to Subpart CC is amended by revising the entry ``Hydrogen 
analyzer'' to read as follows:

                         Table 13--Calibration and Quality Control Requirements for CPMS
----------------------------------------------------------------------------------------------------------------
                                                Minimum accuracy
                Parameter                         requirements                  Calibration requirements
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Hydrogen analyzer.......................  2 percent over   Specify calibration requirements in your
                                           the concentration measured   site specific CPMS monitoring plan.
                                           or 0.1 volume percent,       Calibration requirements should follow
                                           whichever is greater.        manufacturer's recommendations at a
                                                                        minimum.
                                                                       Where feasible, select the sampling
                                                                        location at least two equivalent duct
                                                                        diameters from the nearest control
                                                                        device, point of pollutant generation,
                                                                        air in-leakages, or other point at which
                                                                        a change in the pollutant concentration
                                                                        occurs.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------


[[Page 15485]]

Subpart UUU--National Emission Standards for Hazardous Air 
Pollutants for Petroleum Refineries: Catalytic Cracking Units, 
Catalytic Reforming Units, and Sulfur Recovery Units

0
17. Section 63.1564 is amended by revising the first sentence in 
paragraphs (b)(4)(iii), (c)(3), and (c)(4) and revising paragraph 
(c)(5)(iii) to read as follows:


Sec.  63.1564   What are my requirements for metal HAP emissions from 
catalytic cracking units?

* * * * *
    (b) * * *
    (4) * * *
    (iii) If you elect Option 3 in paragraph (a)(1)(v) of this section, 
the Ni lb/hr emission limit, compute your Ni emission rate using 
Equation 5 of this section and your site-specific Ni operating limit 
(if you use a continuous opacity monitoring system) using Equations 6 
and 7 of this section as follows: * * *
* * * * *
    (c) * * *
    (3) If you use a continuous opacity monitoring system and elect to 
comply with Option 3 in paragraph (a)(1)(v) of this section, determine 
continuous compliance with your site-specific Ni operating limit by 
using Equation 11 of this section as follows: * * *
    (4) If you use a continuous opacity monitoring system and elect to 
comply with Option 4 in paragraph (a)(1)(vi) of this section, determine 
continuous compliance with your site-specific Ni operating limit by 
using Equation 12 of this section as follows: * * *
    (5) * * *
    (iii) Calculating the inlet velocity to the primary internal 
cyclones in feet per second (ft/sec) by dividing the average volumetric 
flow rate (acfm) by the cumulative cross-sectional area of the primary 
internal cyclone inlets (ft\2\) and by 60 seconds/minute (for unit 
conversion).
* * * * *
0
18. Section 63.1565 is amended by revising paragraph (a)(5)(ii) to read 
as follows:


Sec.  63.1565   What are my requirements for organic HAP emissions from 
catalytic cracking units?

    (a) * * *
    (5) * * *
    (ii) You can elect to maintain the oxygen (O2) 
concentration in the exhaust gas from your catalyst regenerator at or 
above 1 volume percent (dry basis) or 1 volume percent (wet basis with 
no moisture correction).
* * * * *
0
19. Section 63.1569 is amended by revising paragraph (c)(2) to read as 
follows:


Sec.  63.1569   What are my requirements for HAP emissions from bypass 
lines?

* * * * *
    (c) * * *
    (2) Demonstrate continuous compliance with the work practice 
standard in paragraph (a)(3) of this section by complying with the 
procedures in your operation, maintenance, and monitoring plan.
0
20. Section 63.1571 is amended by revising the paragraphs (a) 
introductory text, (a)(5) introductory text and (a)(6) introductory 
text, and by revising paragraphs (d)(1) and (d)(2) to read as follows:


Sec.  63.1571   How and when do I conduct a performance test or other 
initial compliance demonstration?

    (a) When must I conduct a performance test? You must conduct 
initial performance tests and report the results by no later than 150 
days after the compliance date specified for your source in Sec.  
63.1563 and according to the provisions in Sec.  63.7(a)(2) and Sec.  
63.1574(a)(3). If you are required to do a performance evaluation or 
test for a semi-regenerative catalytic reforming unit catalyst 
regenerator vent, you may do them at the first regeneration cycle after 
your compliance date and report the results in a followup Notification 
of Compliance Status report due no later than 150 days after the test. 
You must conduct additional performance tests as specified in 
paragraphs (a)(5) and (6) of this section and report the results of 
these performance tests according to the provisions in Sec.  
63.1575(f).
* * * * *
    (5) Periodic performance testing for PM or Ni. Except as provided 
in paragraphs (a)(5)(i) and (ii) of this section, conduct a periodic 
performance test for PM or Ni for each catalytic cracking unit at least 
once every 5 years according to the requirements in Table 4 of this 
subpart. You must conduct the first periodic performance test no later 
than August 1, 2017 or within 60 days of startup of a new unit.
* * * * *
    (6) One-time performance testing for Hydrogen Cyanide (HCN). 
Conduct a performance test for HCN from each catalytic cracking unit no 
later than August 1, 2017 or within 60 days of startup of a new unit 
according to the applicable requirements in paragraphs (a)(6)(i) and 
(ii) of this section.
* * * * *
    (d) * * *
    (1) If you must meet the HAP metal emission limitations in Sec.  
63.1564, you elect the option in paragraph (a)(1)(v) in Sec.  63.1564 
(Ni lb/hr), and you use continuous parameter monitoring systems, you 
must establish an operating limit for the equilibrium catalyst Ni 
concentration based on the laboratory analysis of the equilibrium 
catalyst Ni concentration from the initial performance test. Section 
63.1564(b)(2) allows you to adjust the laboratory measurements of the 
equilibrium catalyst Ni concentration to the maximum level. You must 
make this adjustment using Equation 1 of this section as follows: * * *
    (2) If you must meet the HAP metal emission limitations in Sec.  
63.1564, you elect the option in paragraph (a)(1)(vi) in Sec.  63.1564 
(Ni per coke burn-off), and you use continuous parameter monitoring 
systems, you must establish an operating limit for the equilibrium 
catalyst Ni concentration based on the laboratory analysis of the 
equilibrium catalyst Ni concentration from the initial performance 
test. Section 63.1564(b)(2) allows you to adjust the laboratory 
measurements of the equilibrium catalyst Ni concentration to the 
maximum level. You must make this adjustment using Equation 2 of this 
section as follows: * * *
* * * * *
0
21. Section 63.1572 is amended by revising paragraphs (c)(1) and (d)(1) 
to read as follows:


Sec.  63.1572   What are my monitoring installation, operation, and 
maintenance requirements?

* * * * *
    (c) * * *
    (1) You must install, operate, and maintain each continuous 
parameter monitoring system according to the requirements in Table 41 
of this subpart. You must also meet the equipment specifications in 
Table 41 of this subpart if pH strips or colormetric tube sampling 
systems are used. You must meet the requirements in Table 41 of this 
subpart for BLD systems. Alternatively, before August 1, 2017, you may 
install, operate, and maintain each continuous parameter monitoring 
system in a manner consistent with the manufacturer's specifications or 
other written procedures that provide adequate assurance that the 
equipment will monitor accurately.
* * * * *
    (d) * * *
    (1) Except for monitoring malfunctions, associated repairs, and 
required quality assurance or control activities (including as 
applicable, calibration checks and required zero

[[Page 15486]]

and span adjustments), you must conduct all monitoring in continuous 
operation (or collect data at all required intervals) at all times the 
affected source is operating.
* * * * *
0
22. Section 63.1573 is amended by revising paragraph (a)(1) 
introductory text to read as follows:


Sec.  63.1573   What are my monitoring alternatives?

    (a) What are the approved alternatives for measuring gas flow rate? 
(1) You may use this alternative to a continuous parameter monitoring 
system for the catalytic regenerator exhaust gas flow rate for your 
catalytic cracking unit if the unit does not introduce any other gas 
streams into the catalyst regeneration vent (i.e., complete combustion 
units with no additional combustion devices). You may also use this 
alternative to a continuous parameter monitoring system for the 
catalytic regenerator atmospheric exhaust gas flow rate for your 
catalytic reforming unit during the coke burn and rejuvenation cycles 
if the unit operates as a constant pressure system during these cycles. 
You may also use this alternative to a continuous parameter monitoring 
system for the gas flow rate exiting the catalyst regenerator to 
determine inlet velocity to the primary internal cyclones as required 
in Sec.  63.1564(c)(5) regardless of the configuration of the catalytic 
regenerator exhaust vent downstream of the regenerator (i.e., 
regardless of whether or not any other gas streams are introduced into 
the catalyst regeneration vent). If you use this alternative, you shall 
use the same procedure for the performance test and for monitoring 
after the performance test. You shall:
* * * * *
0
23. Section 63.1574 is amended by revising paragraph (a)(3)(ii) to read 
as follows:


Sec.  63.1574   What notifications must I submit and when?

    (a) * * *
    (3) * * *
    (ii) For each initial compliance demonstration that includes a 
performance test, you must submit the notification of compliance status 
no later than 150 calendar days after the compliance date specified for 
your affected source in Sec.  63.1563. For data collected using test 
methods supported by the EPA's Electronic Reporting Tool (ERT) as 
listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of 
the test, you must submit the results in accordance with Sec.  
63.1575(k)(1)(i) by the date that you submit the Notification of 
Compliance Status, and you must include the process unit(s) tested, the 
pollutant(s) tested, and the date that such performance test was 
conducted in the Notification of Compliance Status. For performance 
evaluations of continuous monitoring systems (CMS) measuring relative 
accuracy test audit (RATA) pollutants that are supported by the EPA's 
ERT as listed on the EPA's ERT website at the time of the evaluation, 
you must submit the results in accordance with Sec.  63.1575(k)(2)(i) 
by the date that you submit the Notification of Compliance Status, and 
you must include the process unit where the CMS is installed, the 
parameter measured by the CMS, and the date that the performance 
evaluation was conducted in the Notification of Compliance Status. All 
other performance test and performance evaluation results (i.e., those 
not supported by EPA's ERT) must be reported in the Notification of 
Compliance Status.
* * * * *
0
24. Section 63.1575 is amended by revising paragraphs (f)(1), (k)(1) 
introductory text and (k)(2) introductory text, and adding paragraph 
(l) to read as follows.


Sec.  63.1575   What reports must I submit and when?

* * * * *
    (f) * * *
    (1) A copy of any performance test or performance evaluation of a 
CMS done during the reporting period on any affected unit, if 
applicable. The report must be included in the next semiannual 
compliance report. The copy must include a complete report for each 
test method used for a particular kind of emission point tested. For 
additional tests performed for a similar emission point using the same 
method, you must submit the results and any other information required, 
but a complete test report is not required. A complete test report 
contains a brief process description; a simplified flow diagram showing 
affected processes, control equipment, and sampling point locations; 
sampling site data; description of sampling and analysis procedures and 
any modifications to standard procedures; quality assurance procedures; 
record of operating conditions during the test; record of preparation 
of standards; record of calibrations; raw data sheets for field 
sampling; raw data sheets for field and laboratory analyses; 
documentation of calculations; and any other information required by 
the test method. For data collected using test methods supported by the 
EPA's Electronic Reporting Tool (ERT) as listed on the EPA's ERT 
website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of the test, you must submit 
the results in accordance with Sec.  63.1575(k)(1)(i) by the date that 
you submit the compliance report, and instead of including a copy of 
the test report in the compliance report, you must include the process 
unit(s) tested, the pollutant(s) tested, and the date that such 
performance test was conducted in the compliance report. For 
performance evaluations of CMS measuring relative accuracy test audit 
(RATA) pollutants that are supported by the EPA's ERT as listed on the 
EPA's ERT website at the time of the evaluation, you must submit the 
results in accordance with Sec.  63.1575(k)(2)(i) by the date that you 
submit the compliance report, and you must include the process unit 
where the CMS is installed, the parameter measured by the CMS, and the 
date that the performance evaluation was conducted in the compliance 
report. All other performance test and performance evaluation results 
(i.e., those not supported by EPA's ERT) must be reported in the 
compliance report.
* * * * *
    (k) * * *
    (1) Unless otherwise specified by this subpart, within 60 days 
after the date of completing each performance test as required by this 
subpart, you must submit the results of the performance tests following 
the procedure specified in either paragraph (k)(1)(i) or (ii) of this 
section.
* * * * *
    (2) Unless otherwise specified by this subpart, within 60 days 
after the date of completing each CEMS performance evaluation required 
by Sec.  63.1571(a) and (b), you must submit the results of the 
performance evaluation following the procedure specified in either 
paragraph (k)(2)(i) or (ii) of this section.
* * * * *
    (l) Extensions to electronic reporting deadlines. (1) If you are 
required to electronically submit a report through the Compliance and 
Emissions Data Reporting Interface (CEDRI) in the EPA's Central Data 
Exchange (CDX), and due to a planned or actual outage of either the 
EPA's CEDRI or CDX systems within the period of time beginning 5 
business days prior to the date that the submission is due, you will be 
or are precluded from accessing CEDRI or CDX and submitting a required 
report within the time prescribed, you may assert a claim of EPA system 
outage for failure to timely comply with the reporting

[[Page 15487]]

requirement. You must submit notification to the Administrator in 
writing as soon as possible following the date you first knew, or 
through due diligence should have known, that the event may cause or 
caused a delay in reporting. You must provide to the Administrator a 
written description identifying the date, time and length of the 
outage; a rationale for attributing the delay in reporting beyond the 
regulatory deadline to the EPA system outage; describe the measures 
taken or to be taken to minimize the delay in reporting; and identify a 
date by which you propose to report, or if you have already met the 
reporting requirement at the time of the notification, the date you 
reported. In any circumstance, the report must be submitted 
electronically as soon as possible after the outage is resolved. The 
decision to accept the claim of EPA system outage and allow an 
extension to the reporting deadline is solely within the discretion of 
the Administrator.
    (2) If you are required to electronically submit a report through 
CEDRI in the EPA's CDX and a force majeure event is about to occur, 
occurs, or has occurred or there are lingering effects from such an 
event within the period of time beginning 5 business days prior to the 
date the submission is due, the owner or operator may assert a claim of 
force majeure for failure to timely comply with the reporting 
requirement. For the purposes of this section, a force majeure event is 
defined as an event that will be or has been caused by circumstances 
beyond the control of the affected facility, its contractors, or any 
entity controlled by the affected facility that prevents you from 
complying with the requirement to submit a report electronically within 
the time period prescribed. Examples of such events are acts of nature 
(e.g., hurricanes, earthquakes, or floods), acts of war or terrorism, 
or equipment failure or safety hazard beyond the control of the 
affected facility (e.g., large scale power outage). If you intend to 
assert a claim of force majeure, you must submit notification to the 
Administrator in writing as soon as possible following the date you 
first knew, or through due diligence should have known, that the event 
may cause or caused a delay in reporting. You must provide to the 
Administrator a written description of the force majeure event and a 
rationale for attributing the delay in reporting beyond the regulatory 
deadline to the force majeure event; describe the measures taken or to 
be taken to minimize the delay in reporting; and identify a date by 
which you propose to report, or if you have already met the reporting 
requirement at the time of the notification, the date you reported. In 
any circumstance, the reporting must occur as soon as possible after 
the force majeure event occurs. The decision to accept the claim of 
force majeure and allow an extension to the reporting deadline is 
solely within the discretion of the Administrator.
0
25. Section 63.1576 is amended by revising paragraph (a)(2)(i) to read 
as follows:


Sec.  63.1576   What records must I keep, in what form, and for how 
long?

    (a) * * *
    (2) * * *
    (i) Record the date, time, and duration of each startup and/or 
shutdown period for which the facility elected to comply with the 
alternative standards in Sec.  63.1564(a)(5)(ii) or Sec.  
63.1565(a)(5)(ii) or Sec.  63.1568(a)(4)(ii) or (iii).
* * * * *
0
26. Table 3 to Subpart UUU is amended by revising the table title and 
entries for items 2.c, 6, 7, 8 and 9 to read as follows:
* * * * *

  Table 3 to Subpart UUU of Part 63--Continuous Monitoring Systems for
            Metal HAP Emissions From Catalytic Cracking Units
------------------------------------------------------------------------
                                 If you use this
   For each new or existing      type of control     You shall install,
 catalytic cracking unit . . .   device for your   operate, and maintain
                                    vent . . .            a . . .
------------------------------------------------------------------------
 
                              * * * * * * *
2. * * *
                                c. Wet scrubber..  Continuous parameter
                                                    monitoring system to
                                                    measure and record
                                                    the pressure drop
                                                    across the
                                                    scrubber,\2\ the gas
                                                    flow rate entering
                                                    or exiting the
                                                    control device,\1\
                                                    and total liquid (or
                                                    scrubbing liquor)
                                                    flow rate to the
                                                    control device.
 
                              * * * * * * *
6. Option 1a: Elect NSPS        Any..............  See item 1 of this
 subpart J, PM per coke burn-                       table.
 off limit, not subject to the
 NSPS for PM in 40 CFR 60.102
 or 60.102a(b)(1).
7. Option 1b: Elect NSPS        Any..............  The applicable
 subpart Ja, PM per coke burn-                      continuous
 off limit, not subject to the                      monitoring systems
 NSPS for PM in 40 CFR 60.102                       in item 2 of this
 or 60.102a(b)(1).                                  table.
8. Option 1c: Elect NSPS        Any..............  See item 3 of this
 subpart Ja, PM concentration                       table.
 limit not subject to the NSPS
 for PM in 40 CFR 60.102 or
 60.102a(b)(1).
9. Option 2: PM per coke burn-  Any..............  The applicable
 off limit, not subject to the                      continuous
 NSPS for PM in 40 CFR 60.102                       monitoring systems
 or 60.102a(b)(1).                                  in item 2 of this
                                                    table.
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *
0
27. Table 4 to Subpart UUU of Part 63 is amended by revising the 
entries for items 9.c and 10.c to read as follows:
* * * * *

[[Page 15488]]



  Table 4 to Subpart UUU of Part 63--Requirements for Performance Tests
          for Metal HAP Emissions From Catalytic Cracking Units
------------------------------------------------------------------------
 For each new or
    existing
    catalytic
  cracking unit    You must . . .    Using . . .     According to these
    catalyst                                         requirements . . .
regenerator vent
      . . .
------------------------------------------------------------------------
 
                              * * * * * * *
9. * * *
                  c. Determine     XRF procedure    You must obtain 1
                   the              in appendix A    sample for each of
                   equilibrium      to this          the 3 test runs;
                   catalyst Ni      subpart1; or     determine and
                   concentration.   EPA Method       record the
                                    6010B or 6020    equilibrium
                                    or EPA Method    catalyst Ni
                                    7520 or 7521     concentration for
                                    in SW-8462; or   each of the 3
                                    an alternative   samples; and you
                                    to the SW-846    may adjust the
                                    method           laboratory results
                                    satisfactory     to the maximum
                                    to the           value using
                                    Administrator.   Equation 1 of Sec.
                                                      63.1571, if
                                                     applicable.
 
                              * * * * * * *
10. * * *
                  c. Determine     See item 9.c.    You must obtain 1
                   the              of this table.   sample for each of
                   equilibrium                       the 3 test runs;
                   catalyst Ni                       determine and
                   concentration.                    record the
                                                     equilibrium
                                                     catalyst Ni
                                                     concentration for
                                                     each of the 3
                                                     samples; and you
                                                     may adjust the
                                                     laboratory results
                                                     to the maximum
                                                     value using
                                                     Equation 2 of Sec.
                                                      63.1571, if
                                                     applicable.
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *
0
28. Table 5 to Subpart UUU is amended by revising the entry for item 3 
to read as follows:
* * * * *

  Table 5 to Subpart UUU of Part 63--Initial Compliance With Metal HAP
              Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
                                For the following
   For each new and existing     emission limit .  You have demonstrated
 catalytic cracking unit . . .         . .          compliance if . . .
 
------------------------------------------------------------------------
 
                              * * * * * * *
3. Subject to NSPS for PM in    PM emissions must  You have already
 40 CFR 60.102a(b)(1)(ii),       not exceed 0.5 g/  conducted a
 electing to meet the PM per     kg (0.5 lb PM/     performance test to
 coke burn-off limit.            1,000 lb) of       demonstrate initial
                                 coke burn-off).    compliance with the
                                                    NSPS and the
                                                    measured PM emission
                                                    rate is less than or
                                                    equal to 0.5 g/kg
                                                    (0.5 lb/1,000 lb) of
                                                    coke burn-off in the
                                                    catalyst
                                                    regenerator. As part
                                                    of the Notification
                                                    of Compliance
                                                    Status, you must
                                                    certify that your
                                                    vent meets the PM
                                                    limit. You are not
                                                    required to do
                                                    another performance
                                                    test to demonstrate
                                                    initial compliance.
                                                    As part of your
                                                    Notification of
                                                    Compliance Status,
                                                    you certify that
                                                    your BLD; CO2, O2,
                                                    or CO monitor; or
                                                    continuous opacity
                                                    monitoring system
                                                    meets the
                                                    requirements in Sec.
                                                      63.1572.
 
                              * * * * * * *
------------------------------------------------------------------------

0
29. Table 6 to Subpart UUU is amended by revising the entries for items 
1.a.ii and 7 to read as follows:
* * * * *

 Table 6 to Subpart UUU of Part 63--Continuous Compliance With Metal HAP
              Emission Limits for Catalytic Cracking Units
------------------------------------------------------------------------
                                 Subject to this
                                  emission limit   You shall demonstrate
   For each new and existing    for your catalyst  continuous compliance
 catalytic cracking unit . . .   regenerator vent         by . . .
                                      . . .
------------------------------------------------------------------------
1. * * *......................  a. * * *.........  .....................

[[Page 15489]]

 
                                                   ii. Conducting a
                                                    performance test
                                                    before August 1,
                                                    2017 or within 60
                                                    days of startup of a
                                                    new unit and
                                                    thereafter following
                                                    the testing
                                                    frequency in Sec.
                                                    63.1571(a)(5) as
                                                    applicable to your
                                                    unit.
 
                              * * * * * * *
7. Option 1b: Elect NSPS        PM emissions must  See item 2 of this
 subpart Ja requirements for     not exceed 1.0 g/  table.
 PM per coke burn-off limit,     kg (1.0 lb PM/
 not subject to the NSPS for     1,000 lb) of
 PM in 40 CFR 60.102 or          coke burn-off.
 60.102a(b)(1).
 
                              * * * * * * *
------------------------------------------------------------------------

0
30. Table 10 to Subpart UUU is amended by revising the entry for item 3 
to read as follows:
* * * * *

  Table 10 to Subpart UUU of Part 63--Continuous Monitoring Systems for
           Organic HAP Emissions From Catalytic Cracking Units
------------------------------------------------------------------------
                                                     You shall install,
                                 And you use this  operate, and maintain
   For each new or existing      type of control        this type of
 catalytic cracking unit . . .   device for your   continuous monitoring
                                    vent . . .          system . . .
------------------------------------------------------------------------
 
                              * * * * * * *
3. During periods of startup,   Any..............  Continuous parameter
 shutdown or hot standby                            monitoring system to
 electing to comply with the                        measure and record
 operating limit in Sec.                            the concentration by
 63.1565(a)(5)(ii).                                 volume (wet or dry
                                                    basis) of oxygen
                                                    from each catalyst
                                                    regenerator vent. If
                                                    measurement is made
                                                    on a wet basis, you
                                                    must comply with the
                                                    limit as measured
                                                    (no moisture
                                                    correction).
------------------------------------------------------------------------

0
31. Table 43 to Subpart UUU is amended by revising the entry for item 2 
to read as follows:
* * * * *

      Table 43 to Subpart UUU of Part 63--Requirements for Reports
------------------------------------------------------------------------
                                    The report must    You shall submit
      You must submit . . .          contain . . .     the report . . .
------------------------------------------------------------------------
 
                              * * * * * * *
2. Performance test and CEMS      On and after        Semiannually
 performance evaluation data.      February 1, 2016,   according to the
                                   the information     requirements in
                                   specified in Sec.   Sec.   63.1575(b)
                                     63.1575(k)(1).    and (f).
------------------------------------------------------------------------

0
32. Table 44 to Subpart UUU is amended by revising the entries 
``63.6(f)(3)'', ``63.67(h)(7)(i)'', ``63.6(h)(8)'', ``63.7(a)(2)'', 
``63.7(g)'', ``63.8(e)'', ``63.10(d)(2)'', ``63.10(e)(1)-(2)'', and 
``63.10(e)(4)'' to read as follows:
* * * * *

          Table 44 to Subpart UUU of Part 63--Applicability of NESHAP General Provisions to Subpart UUU
----------------------------------------------------------------------------------------------------------------
                                                             Applies to subpart UUU
              Citation                       Subject                                         Explanation
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Sec.   63.6(f)(3)..................  ......................  Yes...................  Except the cross-references
                                                                                      to Sec.   63.6(f)(1) and
                                                                                      (e)(1)(i) are changed to
                                                                                      Sec.   63.1570(c) and this
                                                                                      subpart specifies how and
                                                                                      when the performance test
                                                                                      results are reported.
 

[[Page 15490]]

 
                                                  * * * * * * *
Sec.   63.6(h)(7)(i)...............  Report COM Monitoring   Yes...................  Except this subpart
                                      Data from Performance                           specifies how and when the
                                      Test.                                           performance test results
                                                                                      are reported.
 
                                                  * * * * * * *
Sec.   63.6(h)(8)..................  Determining Compliance  Yes...................  Except this subpart
                                      with Opacity/VE                                 specifies how and when the
                                      Standards.                                      performance test results
                                                                                      are reported.
 
                                                  * * * * * * *
Sec.   63.7(a)(2)..................  Performance Test Dates  Yes...................  Except this subpart
                                                                                      specifies that the results
                                                                                      of initial performance
                                                                                      tests must be submitted
                                                                                      within 150 days after the
                                                                                      compliance date.
 
                                                  * * * * * * *
Sec.   63.7(g).....................  Data Analysis,          Yes...................  Except this subpart
                                      Recordkeeping,                                  specifies how and when the
                                      Reporting.                                      performance test or
                                                                                      performance evaluation
                                                                                      results are reported and
                                                                                      Sec.   63.7(g)(2) is
                                                                                      reserved and does not
                                                                                      apply.
 
                                                  * * * * * * *
Sec.   63.8(e).....................  CMS Performance         Yes...................  Except this subpart
                                      Evaluation.                                     specifies how and when the
                                                                                      performance evaluation
                                                                                      results are reported.
 
                                                  * * * * * * *
Sec.   63.10(d)(2).................  Performance Test        No....................  This subpart specifies how
                                      Results.                                        and when the performance
                                                                                      test results are reported.
 
                                                  * * * * * * *
Sec.   63.10(e)(1)-(2).............  Additional CMS Reports  Yes...................  Except this subpart
                                                                                      specifies how and when the
                                                                                      performance evaluation
                                                                                      results are reported.
 
                                                  * * * * * * *
Sec.   63.10(e)(4).................  COMS Data Reports.....  Yes...................  Except this subpart
                                                                                      specifies how and when the
                                                                                      performance test results
                                                                                      are reported.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------


[FR Doc. 2018-06223 Filed 4-9-18; 8:45 am]
 BILLING CODE 6560-50-P


