[Federal Register Volume 83, Number 69 (Tuesday, April 10, 2018)]
[Proposed Rules]
[Pages 15458-15490]
[FR Doc No: 2018-06223]

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<PHONE_NUMBER> 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:<PHONE_NUMBER>; fax number:<PHONE_NUMBER>;
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:<PHONE_NUMBER>; 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

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.

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

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.
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    \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

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).
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    \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

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.
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    \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

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

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

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.
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    \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

[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

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

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)

(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).''
------------------------------------------------------------------------

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

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

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,

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