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Proposed Rule2022-12223

National Emission Standards for Hazardous Air Pollutants: Gasoline Distribution Technology Review and Standards of Performance for Bulk Gasoline Terminals Review

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Published

June 10, 2022

Issuing agencies

Environmental Protection Agency

Abstract

The U.S. Environmental Protection Agency (EPA) is proposing amendments to the National Emissions Standards for Hazardous Air Pollutants (NESHAP) for Gasoline Distribution facilities and the Standards of Performance for Bulk Gasoline Terminals. The EPA is proposing to revise NESHAP requirements for storage tanks, loading operations, and equipment leaks to reflect cost-effective developments in practices, process, or controls. The EPA is also proposing New Source Performance Standards to reflect best system of emissions reduction for loading operations and equipment leaks. In addition, the EPA is proposing revisions related to emissions during periods of startup, shutdown, and malfunction; to add requirements for electronic reporting of performance test results, performance evaluation reports, and compliance reports; to revise monitoring and operating requirements for control devices; and to make other minor technical improvements. We estimate that these proposed amendments would reduce emissions of hazardous air pollutants from this source category by 2,220 tons per year (tpy) and would reduce emissions of volatile organic compounds by 45,400 tpy.

Full Text

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[Federal Register Volume 87, Number 112 (Friday, June 10, 2022)]
[Proposed Rules]
[Pages 35608-35642]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2022-12223]

[[Page 35607]]

Vol. 87

Friday,

No. 112

June 10, 2022

Part II

Environmental Protection Agency

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40 CFR Parts 60 and 63

National Emission Standards for Hazardous Air Pollutants: Gasoline
Distribution Technology Review and Standards of Performance for Bulk
Gasoline Terminals Review; Proposed Rule

Federal Register / Vol. 87 , No. 112 / Friday, June 10, 2022 /
Proposed Rules

[[Page 35608]]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

[EPA-HQ-OAR-2020-0371; FRL-8202-01-OAR]
RIN 2060-AU97

National Emission Standards for Hazardous Air Pollutants:
Gasoline Distribution Technology Review and Standards of Performance
for Bulk Gasoline Terminals Review

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: The U.S. Environmental Protection Agency (EPA) is proposing
amendments to the National Emissions Standards for Hazardous Air
Pollutants (NESHAP) for Gasoline Distribution facilities and the
Standards of Performance for Bulk Gasoline Terminals. The EPA is
proposing to revise NESHAP requirements for storage tanks, loading
operations, and equipment leaks to reflect cost-effective developments
in practices, process, or controls. The EPA is also proposing New
Source Performance Standards to reflect best system of emissions
reduction for loading operations and equipment leaks. In addition, the
EPA is proposing revisions related to emissions during periods of
startup, shutdown, and malfunction; to add requirements for electronic
reporting of performance test results, performance evaluation reports,
and compliance reports; to revise monitoring and operating requirements
for control devices; and to make other minor technical improvements. We
estimate that these proposed amendments would reduce emissions of
hazardous air pollutants from this source category by 2,220 tons per
year (tpy) and would reduce emissions of volatile organic compounds by
45,400 tpy.

DATES: Comments must be received on or before August 9, 2022. 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 August 9, 2022.
Public hearing: If anyone contacts us requesting a public hearing
on or before June 15, 2022, we will hold a virtual public hearing. See
SUPPLEMENTARY INFORMATION for information on requesting and registering
for a public hearing.

ADDRESSES: You may send comments, identified by Docket ID No. EPA-HQ-
OAR-2020-0371, by any of the following methods:
<bullet> Federal eRulemaking Portal: <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>
(our preferred method). Follow the online instructions for submitting
comments.
<bullet> Email: <a href="/cdn-cgi/l/email-protection#07662a6669632a752a6368646c62734762776629606871">[email&#160;protected]</a>. Include Docket ID No. EPA-
HQ-OAR-2020-0371 in the subject line of the message.
<bullet> Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2020-0371.
<bullet> Mail: U.S. Environmental Protection Agency, EPA Docket
Center, Docket ID No. EPA-HQ-OAR-2020-0371, Mail Code 28221T, 1200
Pennsylvania Avenue NW, Washington, DC 20460.
<bullet> Hand/Courier Delivery: EPA Docket Center, WJC West
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004.
The Docket Center's hours of operation are 8:30 a.m.-4:30 p.m., Monday-
Friday (except federal holidays).
Instructions: All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>, including any personal information
provided. For detailed instructions on sending comments and additional
information on the rulemaking process, see the SUPPLEMENTARY
INFORMATION section of this document.

FOR FURTHER INFORMATION CONTACT: For questions about this proposed
action, contact Mr. Neil Feinberg, Sector Policies and Programs
Division (E143-01), Office of Air Quality Planning and Standards, U.S.
Environmental Protection Agency, Research Triangle Park, North Carolina
27711; telephone number: (919) 541-2214; fax number: (919) 541-0516;
and email address: <a href="/cdn-cgi/l/email-protection#bddbd8d4d3dfd8cfda93cec9d8cdd5d8d3fdd8cddc93dad2cb">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. Please note that because
of current Centers for Disease Control and Prevention (CDC)
recommendations, as well as state and local orders for social
distancing to limit the spread of COVID-19, the EPA cannot hold in-
person public meetings at this time.
To request a virtual public hearing, contact the public hearing
team at (888) 372-8699 or by email at <a href="/cdn-cgi/l/email-protection#5506050511252037393c363d3034273c3b32153025347b323a23">[email&#160;protected]</a>. If
requested, the virtual hearing will be held on June 27, 2022. The
hearing will convene at 11:00 a.m. Eastern Time (ET) and will conclude
at 7:00 p.m. ET. The EPA may close a session 15 minutes after the last
pre-registered speaker has testified if there are no additional
speakers. The EPA will announce further details at <a href="https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards">https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards</a>.
If a public hearing is requested, the EPA will begin pre-
registering speakers for the hearing no later than 1 business day after
a request has been received. To register to speak at the virtual
hearing, please use the online registration form available at <a href="https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards">https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards</a> or contact the public hearing
team at (888) 372-8699 or by email at <a href="/cdn-cgi/l/email-protection#df8c8f8f9bafaabdb3b6bcb7babeadb6b1b89fbaafbef1b8b0a9">[email&#160;protected]</a>. The
last day to pre-register to speak at the hearing will be June 22, 2022.
Prior to the hearing, the EPA will post a general agenda that will list
pre-registered speakers in approximate order at: <a href="https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards">https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards</a>.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearings to run either ahead of schedule or behind schedule.
Each commenter will have 5 minutes to provide oral testimony. The
EPA encourages commenters to provide the EPA with a copy of their oral
testimony electronically (via email) by emailing it to
<a href="/cdn-cgi/l/email-protection#2c4a4945424e495e4b025f58495c4449426c495c4d024b435a">[email&#160;protected]</a>. The EPA also recommends submitting the text
of your oral testimony as written comments to the rulemaking docket.
The EPA may ask clarifying questions during the oral presentations
but will not respond to the presentations at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as oral testimony and
supporting information presented at the public hearing.
Please note that any updates made to any aspect of the hearing will
be posted online at <a href="https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards">https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards</a>. While the EPA expects the hearing to go forward as set forth
above, please monitor our website or contact the public hearing team at
(888) 372-8699 or by email at <a href="/cdn-cgi/l/email-protection#85d6d5d5c1f5f0e7e9ece6ede0e4f7ecebe2c5e0f5e4abe2eaf3">[email&#160;protected]</a> to determine if
there are any updates. The EPA does not intend to publish a document in
the Federal Register announcing updates.
If you require the services of a translator or a special
accommodation

[[Page 35609]]

such as audio description, please pre-register for the hearing with the
public hearing team and describe your needs by June 17, 2022. The EPA
may not be able to arrange accommodations without advanced notice.
Docket. The EPA has established a docket for this rulemaking under
Docket ID No. EPA-HQ-OAR-2020-0371. All documents in the docket are
listed in <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>. Although listed, some
information is not publicly available, e.g., Confidential Business
Information (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. With the exception of such material, publicly available docket
materials are available electronically in <a href="http://Regulations.gov">Regulations.gov</a> or in hard
copy at the EPA Docket Center, Room 3334, 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-
2020-0371. 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 <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>, 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 electronically to <a href="https://www.regulations.gov">https://www.regulations.gov</a>
any information that you consider to be CBI or other information whose
disclosure is restricted by statute. This type of information should be
submitted as discussed below.
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 <a href="https://www.epa.gov/dockets/commenting-epa-dockets">https://www.epa.gov/dockets/commenting-epa-dockets</a>.
The <a href="https://www.regulations.gov/">https://www.regulations.gov/</a> website allows you to submit your
comment anonymously, 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
<a href="https://www.regulations.gov/">https://www.regulations.gov/</a>, 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
digital storage media 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 <a href="https://www.epa.gov/dockets">https://www.epa.gov/dockets</a>.
Submitting CBI. Do not submit information containing CBI to the EPA
through <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>. Clearly mark the part or all of
the information that you claim to be CBI. For CBI information on any
digital storage media that you mail to the EPA, note the docket ID,
mark the outside of the digital storage media as CBI and identify
electronically within the digital storage media 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 directly to the public docket through the procedures
outlined in Instructions section of this document. If you submit any
digital storage media that does not contain CBI, mark the outside of
the digital storage media clearly that it does not contain CBI and note
the docket ID. 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.
Our preferred method to receive CBI is for it to be transmitted
electronically using email attachments, File Transfer Protocol (FTP),
or other online file sharing services (e.g., Dropbox, OneDrive, Google
Drive). Electronic submissions must be transmitted directly to the
Office of Air Quality Planning and Standards (OAQPS) CBI Office at the
email address <a href="/cdn-cgi/l/email-protection#452a2434353626272c052035246b222a33">[email&#160;protected]</a>, and as described above, should include
clear CBI markings and note the docket ID. If assistance is needed with
submitting large electronic files that exceed the file size limit for
email attachments, and if you do not have your own file sharing
service, please email <a href="/cdn-cgi/l/email-protection#78171909080b1b1a11381d0819561f170e">[email&#160;protected]</a> to request a file transfer link.
If sending CBI information through the postal service, please send it
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-2020-0371. The
mailed CBI material should be double wrapped and clearly marked. Any
CBI markings should not show through the outer envelope. Preamble
acronyms and abbreviations. Throughout this notice the use of ``we,''
``us,'' or ``our'' is intended to refer to the EPA. 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:

AVO audio, visual, or olfactory
BSER best system of emissions reduction
CAA Clean Air Act
CBI Confidential Business Information
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CO carbon monoxide
CO<INF>2</INF> carbon dioxide
DOT U.S. Department of Transportation
EJ environmental justice
EPA Environmental Protection Agency
ERT Electronic Reporting Tool
GACT generally available control technology
HAP hazardous air pollutant(s)
ICR information collection request
km kilometer
LDAR leak detection and repair
LEL lower explosive limit
mg/L milligrams per liter
MACT maximum achievable control technology
NAICS North American Industry Classification System
NESHAP national emission standards for hazardous air pollutants
NO<INF>2</INF> nitrogen oxides
NSPS new source performance standards
OAQPS Office of Air Quality Planning and Standards
OGI optical gas imaging
OMB Office of Management and Budget
ppm parts per million
ppmv parts per million by volume
PRA Paperwork Reduction Act
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
SO<INF>2</INF> sulfur dioxide
SSM startup, shutdown, and malfunction
TOC total organic carbon

[[Page 35610]]

tpy tons per year
U.S.C. United States Code
VCU vapor combustion unit
VOC volatile organic compound(s)
VRU vapor recovery unit

Organization of this document. The information in this preamble is
organized as follows:

I. General Information
A. Executive Summary
B. Does this action apply to me?
C. Where can I get a copy of this document and other related
information?
II. Background
A. What is the statutory authority for this action?
B. What are the source categories and how do the current
standards regulate emissions?
C. What data collection activities were conducted to support
this action?
D. What other relevant background information and data are
available?
E. How does the EPA perform the NESHAP technology review and
NSPS review?
III. Proposed Rule Summary and Rationale
A. What are the results and proposed decisions based on our
technology reviews and NSPS review, and what is the rationale for
those decisions?
B. What other actions are we proposing, and what is the
rationale for those actions?
C. What compliance dates are we proposing, and what is the
rationale for the proposed compliance dates?
IV. Summary of Cost, Environmental, and Economic Impacts
A. What are the affected sources?
B. What are the air quality impacts?
C. What are the cost impacts?
D. What are the economic impacts?
E. What are the benefits?
F. What analysis of environmental justice did we conduct?
V. Request for Comments
VI. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act (NTTAA)
J. Executive Order 12898: Federal Actions to Address
Environmental Justice in Minority Populations and Low-Income
Populations

I. General Information

A. Executive Summary

1. Purpose of the Regulatory Action
The source categories that are the subject of this proposal are
Gasoline Distribution regulated under 40 CFR part 63, subparts R and
BBBBBB and Petroleum Transportation and Marketing regulated under 40
CFR part 60, subpart XX. The EPA set maximum achievable control
technology (MACT) standards for the Gasoline Distribution major source
category in 1994 and conducted the residual risk and technology review
in 2006. The sources affected by the major source National Emissions
Standards for Hazardous Air Pollutants (NESHAP) for the Gasoline
Distribution source category (part 63, subpart R) are bulk gasoline
terminals and pipeline breakout stations. The EPA set generally
available control technology (GACT) standards for the Gasoline
Distribution area source category in 2008. The sources affected by the
area source NESHAP for the Gasoline Distribution source category (part
63, subpart BBBBBB) are bulk gasoline terminals, bulk gasoline plants,
and pipeline facilities. The EPA set New Source Performance Standards
(NSPS) for the Petroleum Transportation and Marketing source category
in 1983. The sources affected by the current NSPS (part 60, subpart XX)
are bulk gasoline terminals that commenced construction or modification
after December 17, 1980.
The statutory authority for these proposed rulemakings is sections
111 and 112 of the Clean Air Act (CAA). Section 111(b)(1)(B) of the CAA
requires the EPA to ``at least every 8 years review and, if
appropriate, revise'' NSPS. Section 111(a)(1) of the CAA provides that
performance standards are to ``reflect the degree of emission
limitation achievable through the application of the best system of
emission reduction which (taking into account the cost of achieving
such reduction and any nonair quality health and environmental impact
and energy requirements) the Administrator determines has been
adequately demonstrated.'' We refer to this level of control as the
best system of emission reduction or ``BSER.'' Section 112(d)(6) of the
CAA requires the EPA to review standards promulgated under CAA section
112 and revise them ``as necessary (taking into account developments in
practices, processes, and control technologies)'' no less often than
every 8 years following promulgation of those standards. This is
referred to as a ``technology review'' and is required for all
standards established under CAA section 112(d).
The proposed Standards of Performance for Bulk Gasoline Terminals
and the proposed amendments to the NESHAP for Gasoline Distribution
facilities fulfill the Agency's requirement, respectively, to review
and, if appropriate, revise the NSPS and to review and revise as
necessary the NESHAP at least every 8 years.
2. Summary of the Major Provisions of the Regulatory Action In Question
a. NESHAP Subpart R
We are proposing to require a graduated vapor tightness
certification from 0.5 to 1.25 inches of water pressure drop over a 5-
minute period, depending on the cargo tank compartment size for
gasoline cargo tanks. We are also proposing to require fitting controls
for external floating roof tanks consistent with the requirement in
NSPS subpart Kb. In addition, we are proposing to require semiannual
instrument monitoring for major source gasoline distribution
facilities.
b. NESHAP Subpart BBBBBB
We are proposing to lower the area source emission limits for
loading racks at large bulk gasoline terminals to 35 milligrams of
total organic carbon (TOC) per liter of gasoline loaded (mg/L) and
require vapor balancing for loading storage vessels and gasoline cargo
tanks at bulk gasoline plants with maximum design capacity throughput
of 4,000 gallons per day or more. We are also proposing to require a
graduated vapor tightness certification from 0.5 to 1.25 inches of
water pressure drop over a 5-minute period, depending on the cargo tank
compartment size for gasoline cargo tanks. Additionally, we are
proposing to require fitting controls for external floating roof tanks
consistent with the requirement in NSPS subpart Kb. Also, we are
proposing to require annual instrument monitoring for area source
gasoline distribution facilities.
c. NSPS Subpart XXa
We are proposing in a new NSPS subpart XXa that facilities that
commence construction after June 10, 2022) must meet a 1 mg/L limit and
facilities that commence modification, or reconstruction after June 10,
2022 must meet a 10 mg/L limit. We are also proposing to require a
graduated vapor tightness certification from 0.5 to 1.25 inches of
water pressure drop over a 5-minute period, depending on the cargo tank
compartment size for gasoline cargo tanks. Also, we are proposing to

[[Page 35611]]

require quarterly instrument monitoring.
3. Costs and Benefits
To satisfy requirements of E.O. 12866, the EPA projected the
emissions reductions, costs, and benefits that may result from these
proposed rulemakings. These results are presented in detail in the
regulatory impact analysis (RIA) accompanying this proposal developed
in response to E.O. 12866. We present these results for each of the
three rules included in this proposed action, and also cumulatively.
This action is economically significant according to E.O. 12866
primarily due to the proposed amendments to NESHAP subpart BBBBBB. The
RIA focuses on the elements of the proposed rulemaking that are likely
to result in quantifiable cost or emissions changes compared to a
baseline without the proposal that incorporates changes to regulatory
requirements. We estimated the cost, emissions, and benefit impacts for
the 2026 to 2040 period. We show the present value (PV) and equivalent
annual value (EAV) of costs, benefits, and net benefits of this action
in 2019 dollars.
The initial analysis year in the RIA is 2026 as we assume the large
majority of impacts associated with the proposed rulemakings will be
finalized in that year. The NSPS will take effect immediately upon the
effective date of the final rule and impact sources constructed after
publication of the proposed rule, but these impacts are much lower than
those of the other two rulemakings in this action. The other two rules,
both under the provisions of section 112 of the Clean Air Act, will
take effect three years after their effective date, which will occur in
2026 given promulgation of this rulemaking in 2023. Therefore, their
impacts will begin in 2026. The final analysis year is 2040, which
allows us to provide 15 years of projected impacts after all of these
rules are assumed to take effect.
The cost analysis presented in the RIA reflects a nationwide
engineering analysis of compliance cost and emissions reductions, of
which there are two main components. The first component is a set of
representative or model plants for each regulated facility, segment,
and control option. The characteristics of the model plant include
typical equipment, operating characteristics, and representative
factors including baseline emissions and the costs, emissions
reductions, and product recovery resulting from each control option.
The second component is a set of projections of data for affected
facilities, distinguished by vintage, year, and other necessary
attributes (e.g., precise content of material in storage tanks).
Impacts are calculated by setting parameters on how and when affected
facilities are assumed to respond to a particular regulatory regime,
multiplying data by model plant cost and emissions estimates,
differencing from the baseline scenario, and then summing to the
desired level of aggregation. In addition to emissions reductions, some
control options result in gasoline recovery, which can then be sold
where possible. Where applicable, we present projected compliance costs
with and without the projected revenues from product recovery.
The EPA expects health benefits due to the emissions reductions
projected under these proposed rulemakings. We expect that hazardous
air pollutants (HAP) emission reductions will improve health and
welfare associated with exposure by those affected by these emissions.
In addition, the EPA expects that volatile organic compounds (VOC)
emission reductions that will occur concurrent with the reductions of
HAP emissions will improve air quality and are likely to improve health
and welfare associated with exposure to ozone, particulate matter 2.5
(PM<INF>2.5</INF>), and HAP. The EPA also expects disbenefits from
secondary increases of carbon dioxide (CO<INF>2</INF>), nitrogen oxides
(NO<INF>2</INF>), sulfur dioxide (SO<INF>2</INF>), and carbon monoxide
(CO) emissions associated with the control options included in the cost
analysis. Discussion of the non-monetized benefits and climate
disbenefits can be found in Chapter 4 of the RIA.
Tables 1 through 3 of this document presents the emission changes,
and PV and EAV of the projected monetized benefits, compliance costs,
and net benefits over the 2026 to 2040 period under the proposed
rulemaking for each subpart. Table 4 of this document presents the same
results for the cumulative impact of these rulemakings. All discounting
of impacts presented uses discount rates of 3 and 7 percent.

Table 1--Short-Term and Long-Term Monetized Benefits, Costs, Net Benefits, and Emissions Reductions of the Proposed NESHAP Subpart BBBBBB Amendments,
2026 Through 2040
[Dollar estimates in millions of 2019 dollars] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
3 Percent discount rate 7 Percent discount rate
------------------------------------------------------------------------------------------------------------------------
PV EAV PV EAV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Benefits \b\................... $180(ST) and $1,500(LT)...... $15(ST) and $130(LT)........ $110(ST) and $900(LT)....... $12(ST) and $99(LT).
Climate Disbenefits (3%) \c\... $28.......................... $2.3........................ $28......................... $2.0.
Net Compliance Costs \d\....... -$70......................... -$5.0....................... -$42........................ -$5.0.
Compliance Costs........... $140......................... $12......................... $98......................... $11.
Value of Product Recovery.. $210......................... $17......................... $140........................ $16.
Net Benefits................... $230(ST) and $1,500(LT)...... $18(ST) and $130(LT)........ $130(ST) and $910(LT)....... $15(ST) and $100(LT).
------------------------------------------------------------------------------------------------------------------------
Emissions Reductions (short 2026-2040 Total.
tons).
VOC........................ 605,000.
HAP........................ 31,000.
Secondary Emissions Increases 2026-2040 Total.
(short tons).
CO2........................ 490,000.
NO2........................ 290.
SO2........................ 3.5.
CO......................... 1,300.
Non-monetized Impacts in this HAP benefits from reducing 31,000 short tons of HAP from 2026-2040, VOC benefits from reductions outside of the ozone
Table. season (October-April).
Health and climate disbenefits from increasing nitrogen oxides (NO2) emissions by 290 short tons, sulfur dioxide (SO2)
by 3.5 short tons, and carbon monoxide (CO) by 1,300 short tons from 2026-2040.
Visibility benefits.
Reduced vegetation effects.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals may not appear to add correctly due to rounding. Short tons are standard English tons (2,000
pounds).

[[Page 35612]]

\b\ Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with
several point estimates and are presented at real discount rates of 3 and 7 percent for both short-(ST) and long-term (LT) benefits. The two benefits
estimates are separated by the word ``and'' to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound
estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table.
Disbenefits from additional CO2 emissions resulting from application of control options are monetized and included in the table as climate
disbenefits. Climate disbenefits are monetized at a real discount rate of 3 percent. The unmonetized effects also include disbenefits resulting from
the secondary impact of an increase in NO2, SO2, and CO emissions. Please see Section 4.6 of the RIA for more discussion of the climate disbenefits.
\c\ Climate disbenefits are based on changes (increases) in CO2 emissions and are calculated using four different estimates of the social cost of carbon
(SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). For the presentational
purposes of this table, we show the disbenefits associated with the average SC-CO2 at a 3 percent discount rate, but the Agency does not have a single
central SC-CO2 point estimate. We emphasize the importance and value of considering the disbenefits calculated using all four SC-CO2 estimates; the
additional disbenefit estimates range from PV (EAV) $5.4 million ($0.5 million) to $84 million ($7.0 million) from 2026-2040 for the proposed
amendments. Please see Table 4-7 in the RIA for the full range of SC-CO2 estimates. As discussed in Chapter 4 of the RIA, a consideration of climate
disbenefits calculated using discount rates below 3 percent, including 2 percent and lower, is also warranted when discounting intergenerational
impacts.
\d\ Net compliance costs are the rulemaking costs minus the value of recovered product. A negative net compliance costs occurs when the value of the
recovered product exceeds the compliance costs.

Table 2--Short-Term and Long-Term Monetized Benefits, Compliance Costs, Net Benefits, and Emissions Reductions of the Proposed NESHAP Subpart R
Amendments, 2026 Through 2040
[Dollar estimates in millions of 2019 dollars] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
3 Percent discount rate 7 Percent discount rate
------------------------------------------------------------------------------------------------------------------------
PV EAV PV EAV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Benefits \b\................... $9.9(ST) and $81(LT)......... $0.83(ST) and $6.8(LT)...... $5.6(ST) and $48(LT)........ $0.65(ST) and $5.3(LT).
Net Compliance Costs \c\....... $23.......................... $2.0........................ $15......................... $1.8.
Compliance Costs........... $34.......................... $2.9........................ $23......................... $2.6.
Value of Product Recovery.. $11.......................... $1.0........................ $8.......................... $0.90.
Net Benefits................... -$13(ST) and $58(LT)......... -$1.2(ST) and $4.8(LT)...... -$9.4(ST) and $33(LT)....... -$1.2(ST) and $3.5(LT).
------------------------------------------------------------------------------------------------------------------------
Emissions Reductions (short 2026-2040 Total.
tons).
VOC........................ 32,000.
HAP........................ 2,010.
Non-monetized Impacts in this HAP benefits from reducing 2,010 short tons of HAP from 2026-2040, VOC benefits from reductions outside of the ozone
Table. season (October-April).
Visibility benefits.
Reduced vegetation effects.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals may not appear to add correctly due to rounding. Short tons are standard English tons (2,000
pounds).
\b\ Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with
several point estimates and are presented at real discount rates of 3 and 7 percent for both short-(ST) and long-term (LT) benefits. The two benefits
estimates are separated by the word ``and'' to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound
estimates and should not be summed. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not
reflected in the table.
\c\ Net compliance costs are the rulemaking costs minus the value of recovered product. A negative net compliance costs occurs when the value of the
recovered product exceeds the compliance costs.

Table 3--Short-Term and Long-Term Monetized Benefits, Costs, Net Benefits, and Emissions Reductions of Proposed NSPS Subpart XXa, 2026 Through 2040
[Dollar estimates in millions of 2019 dollars] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
3 Percent discount rate 7 Percent discount rate
------------------------------------------------------------------------------------------------------------------------
PV EAV PV EAV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Benefits \b\................... $29(ST) and $240(LT)......... $2.4(ST) and $20(LT)........ $16(ST) and $130(LT)........ $1.7(ST) and $15(LT).
Climate Disbenefits (3%) \c\... $4.4......................... $0.37....................... $4.4........................ $0.37.
Net Compliance Costs \d\....... $9.0......................... $0.70....................... $5.0........................ $0.60.
Compliance Costs........... $41.......................... $3.4........................ $26......................... $2.9.
Value of Product Recovery.. $32.......................... $2.7........................ $21......................... $2.3.
Net Benefits................... $16(ST) and $230(LT)......... $1.3(ST) and $19(LT)........ $6.6(ST) and $130(LT)....... $0.73(ST) and $14(LT).
------------------------------------------------------------------------------------------------------------------------
Emissions Reductions (short 2026-2040 Total.
tons).
VOC........................ 97,000.
HAP........................ 4,020.
Secondary Emissions Increases 2026-2040 Total.
(short tons).
CO2........................ 74,000.
NO2........................ 50.
SO2........................ 42.
CO......................... 0.
Non-monetized Impacts in this HAP benefits from reducing 4,020 short tons of HAP from 2026-2040, VOC benefits from reductions outside of the ozone
Table. season (October-April).
Health and climate disbenefits from increasing NO2 emissions by 50 short tons, and SO2 by 42 short tons from 2026-2040.
Visibility benefits.
Reduced vegetation effects.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals may not appear to add correctly due to rounding. Short tons are standard English tons (2,000
pounds).
\b\ Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with
several point estimates and are presented at real discount rates of 3 and 7 percent for both short-(ST) and long-term (LT) benefits. The two benefits
estimates are separated by the word ``and'' to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound
estimates. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table.
Climate disbenefits are estimated at a real discount rate of 3 percent. The unmonetized effects also include disbenefits resulting from the secondary
impact of an increase in NO2, SO2 and CO emissions. Please see Section 4.6 of the RIA for more discussion of the climate disbenefits.

[[Page 35613]]

\c\ Climate disbenefits are based on changes (increases) in CO2 emissions and are calculated using four different estimates of the social cost of carbon
(SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). For the presentational
purposes of this table, we show the disbenefits associated with the average SC-CO2 at a 3 percent discount rate, but the Agency does not have a single
central SC-CO2 point estimate. We emphasize the importance and value of considering the disbenefits calculated using all four SC-CO2 estimates; the
additional disbenefit estimates range from PV (EAV) $0.78 million ($0.08 million) to $13 million ($1.1 million) from 2026-2040 for the proposed
amendments. Please see Table 4-7 for the full range of SC-CO2 estimates. As discussed in Chapter 4 of the RIA, a consideration of climate disbenefits
calculated using discount rates below 3 percent, including 2 percent and lower, is also warranted when discounting intergenerational impacts.
\d\ Net compliance costs are the rulemaking costs minus the value of recovered product. A negative net compliance costs occurs when the value of the
recovered product exceeds the compliance costs.

Table 4--Short-Term and Long-Term Cumulative Monetized Benefits, Costs, Net Benefits, and Emissions Reductions of the Proposed Rulemakings, 2026 Through
2040
[Dollar estimates in millions of 2019 dollars] \a\
--------------------------------------------------------------------------------------------------------------------------------------------------------
3 Percent discount rate 7 Percent discount rate
------------------------------------------------------------------------------------------------------------------------
PV EAV PV EAV
--------------------------------------------------------------------------------------------------------------------------------------------------------
Benefits \b\................... $220(ST) and $1,800(LT)...... $19(ST) and $150(LT)........ $130(ST) and $1,100(LT)..... $15(ST) and $120(LT).
Climate Disbenefits (3%) \c\... $32.......................... $2.7........................ $32......................... $2.7.
Net Compliance Costs \d\....... -$38......................... -$2.4....................... -$22........................ -$2.7.
Compliance Costs........... $220......................... $18......................... $150........................ $17.
Value of Product Recovery.. $250......................... $20......................... $170........................ $19.
Net Benefits................... $230(ST) and $1,800(LT)...... $19(ST) and $150(LT)........ $120(ST) and $1,090(LT)..... $15(ST) and $120(LT).
------------------------------------------------------------------------------------------------------------------------
Emissions Reductions (short 2026-2040 Total.
tons).
VOC........................ 730,000.
HAP........................ 37,000.
Secondary Emissions Increases 2026-2040 Total.
(short tons).
CO2........................ 560,000.
NO2........................ 340.
SO2........................ 46.
CO......................... 1,300.
Non-monetized Impacts in this HAP benefits from reducing 37,000 short tons of HAP from 2026-2040, VOC benefits from reductions outside of the ozone
Table. season (October-April).
Health and climate disbenefits from increasing NO2 emissions by 340 short tons, SO2 by 42 short tons, and CO by 1,300
short tons from 2026-2040.
Visibility benefits.
Reduced vegetation effects.
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Values rounded to two significant figures. Totals may not appear to add correctly due to rounding. Short tons are standard English tons (2,000
pounds).
\b\ Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with
several point estimates and are presented at real discount rates of 3 and 7 percent for both short-(ST) and long-term (LT) benefits. The two benefits
estimates are separated by the word ``and'' to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound
estimates and should not be summed. Benefits from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not
reflected in the table. Climate disbenefits are estimated at a real discount rate of 3 percent. The unmonetized effects also include disbenefits
resulting from the secondary impact of an increase in NO2, SO2 and CO emissions. Please see Section 4.6 of the RIA for more discussion of the climate
disbenefits.
\c\ Climate disbenefits are based on changes (increases) in CO2 emissions and are calculated using four different estimates of the social cost of carbon
(SC-CO2) (model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). For the presentational
purposes of this table, we show the disbenefits associated with the average SC-CO2 at a 3 percent discount rate, but the Agency does not have a single
central SC-CO2 point estimate. We emphasize the importance and value of considering the disbenefits calculated using all four SC-CO2 estimates; the
additional disbenefit estimates range from PV (EAV) $6.2 million ($0.6 million) to $97 million ($8.1 million) from 2026-2040 for the proposed
amendments. Please see Table 4-7 of the RIA for the full range of SC-CO2 estimates. As discussed in Chapter 4 of the RIA, a consideration of climate
disbenefits calculated using discount rates below 3 percent, including 2 percent and lower, is also warranted when discounting intergenerational
impacts.
\d\ Net compliance costs are the rulemaking costs minus the value of recovered product. A negative net compliance costs occurs when the value of the
recovered product exceeds the compliance costs.

B. Does this action apply to me?

The source categories that are the subject of this proposal are
Gasoline Distribution regulated under 40 CFR part 63, subparts R and
BBBBBB and Petroleum Transportation and Marketing regulated under 40
CFR part 60, subpart XX. The North American Industry Classification
System (NAICS) codes for the Gasoline Distribution industry are 324110,
493190, 486910, and 424710. This list of NAICS codes 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) and Documentation for Developing the Initial
Source Category List, Final Report (see EPA-450/3-91-030, July 1992),
the Gasoline Distribution (Stage 1) source category is any facility
engaged in ``the storage and transfer facilities associated with the
movement of gasoline. This category includes, but is not limited to,
the gasoline vapor emissions associated with the loading of transport
trucks or rail cars, storage tank emissions, and equipment leaks from
leaking pumps, valves, and connections at bulk terminals, bulk plants,
and pipeline facilities.'' Subsequently, on July 19, 1999, we added
this category to the list of area source categories for regulation
under a Federal Register publication for the Integrated Urban Air
Toxics Strategy (64 FR 38706). The Gasoline Distribution (Stage 1)
source category also includes storage tank filling operations that
occur at public and private gasoline dispensing facilities (e.g.,
service stations and convenience stores). Gasoline dispensing
facilities are regulated under 40 CFR part 63, subpart CCCCCC. The EPA
did not review the standards for gasoline dispensing facilities.
The EPA Priority List (40 CFR 60.16, 44 FR 49222, August 21, 1979)
included Petroleum Transportation and Marketing as a source category
for which standards of performance were to be promulgated under CAA
section 111. The New Source Performance Standards for this source
category applies to the total of all the loading racks at a bulk
gasoline terminal that deliver liquid product into gasoline tank
trucks. A bulk gasoline terminal is defined as any gasoline facility
which receives gasoline

[[Page 35614]]

by pipeline, ship or barge, and has a gasoline throughput greater than
75,700 liters per day.

C. 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
<a href="https://www.epa.gov/gasoline-distribution-mact-and-gact-national-emission-standards">https://www.epa.gov/gasoline-distribution-mact-and-gact-national-emission-standards</a>. 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 strikeout version of each standard showing the edits that
would be necessary to incorporate the changes to 40 CFR part 60,
subparts XX and XXa and Part 63, subparts R and BBBBBB proposed in this
action is available in the docket (Docket ID No. EPA-HQ-OAR-2020-0371).
Following signature by the EPA Administrator, the EPA will also post a
copy of these documents to <a href="https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards">https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards</a>.

II. Background

A. What is the statutory authority for this action?

1. National Emissions Standards for Hazardous Air Pollutants (NESHAP)
The statutory authority for this action is provided by sections 112
and 301 of the CAA, as amended (42 U.S.C. 7401 et seq.). Section 112 of
the CAA establishes a two-stage regulatory process to develop standards
for emissions of hazardous air pollutants (HAP) from stationary
sources. Generally, the first stage involves establishing technology-
based standards and the second stage involves evaluating those
standards that are based on MACT to determine whether additional
standards are needed to address any remaining risk associated with HAP
emissions. This second stage is commonly referred to as the ``residual
risk review.'' In addition to the residual risk review, the CAA also
requires the EPA to review standards set under CAA section 112 every 8
years and revise the standards as necessary taking into account any
``developments in practices, processes, or control technologies.'' This
review is commonly referred to as the ``technology review,'' and is the
subject of this proposal. The discussion that follows identifies the
most relevant statutory sections and briefly explains the contours of
the methodology used to implement these statutory requirements.
In the first stage of the CAA section 112 standard setting process,
the EPA promulgates technology-based standards under CAA section 112(d)
for categories of sources identified as emitting one or more of the HAP
listed in CAA section 112(b). Sources of HAP emissions are either major
sources or area sources, and CAA section 112 establishes different
requirements for major source standards and area source standards.
``Major sources'' are those that emit or have the potential to emit 10
tons per year (tpy) or more of a single HAP or 25 tpy or more of any
combination of HAP. All other sources are ``area sources.'' For major
sources, CAA section 112(d)(2) provides that the technology-based
NESHAP must reflect the maximum degree of emission reductions of HAP
achievable (after considering cost, energy requirements, and nonair
quality health and environmental impacts). These standards are commonly
referred to as MACT standards. CAA section 112(d)(3) also establishes a
minimum control level for MACT standards, known as the MACT ``floor.''
In certain instances, as provided in CAA section 112(h), the EPA may
set work practice standards in lieu of numerical emission standards.
The EPA must also consider control options that are more stringent than
the floor. Standards more stringent than the floor are commonly
referred to as beyond-the-floor standards. For categories of major
sources and any area source categories subject to MACT standards, the
second stage in standard-setting focuses on identifying and addressing
any remaining (i.e., ``residual'') risk pursuant to CAA section 112(f)
and concurrently conducting a technology review pursuant to CAA section
112(d)(6). The EPA set MACT standards for the Gasoline Distribution
major source category in 1994 and conducted the residual risk and
technology review in 2006.
CAA section 112(d)(6) requires the EPA to review standards
promulgated under CAA section 112 and revise them ``as necessary
(taking into account developments in practices, processes, and control
technologies)'' no less often than every 8 years following promulgation
of those standards. This is referred to as a ``technology review'' and
is required for all standards established under CAA section 112(d)
including GACT standards that apply to area sources.\1\ In conducting
this review, the EPA is not required to recalculate the MACT floors
that were established in earlier rulemakings. Natural Resources Defense
Council (NRDC) v. EPA, 529 F.3d 1077, 1084 (D.C. Cir. 2008).
Association of Battery Recyclers, Inc. v. EPA, 716 F.3d 667 (D.C. Cir.
2013). The EPA may consider cost in deciding whether to revise the
standards pursuant to CAA section 112(d)(6). The EPA is required to
address regulatory gaps, such as missing MACT standards for listed air
toxics known to be emitted from major source categories, and any new
MACT standards must be established under CAA sections 112(d)(2) and
(3), or, in specific circumstances, CAA sections 112(d)(4) or (h).
Louisiana Environmental Action Network (LEAN) v. EPA, 955 F.3d 1088
(D.C. Cir. 2020). This action constitutes the 112(d)(6) technology
review for the Gasoline Distribution major source and area source
NESHAP.
---------------------------------------------------------------------------

\1\ For categories of area sources subject to GACT standards,
CAA sections 112(d)(5) and (f)(5) provide that the CAA section
112(f)(2) residual risk review is not required. However, the CAA
section 112(d)(6) technology review is required for such categories.
---------------------------------------------------------------------------

Several additional CAA sections are relevant to this action as they
specifically address regulation of hazardous air pollutant emissions
from area sources. Collectively, CAA sections 112(c)(3), (d)(5), and
(k)(3) are the basis of the Area Source Program under the Urban Air
Toxics Strategy, which provides the framework for regulation of area
sources under CAA section 112.
Section 112(k)(3)(B) of the CAA requires the EPA to identify at
least 30 HAP that pose the greatest potential health threat in urban
areas with a primary goal of achieving a 75-percent reduction in cancer
incidence attributable to HAP emitted from stationary sources. As
discussed in the Integrated Urban Air Toxics Strategy (64 FR 38706,
38715, July 19, 1999), the EPA identified 30 HAP emitted from area
sources that pose the greatest potential health threat in urban areas,
and these HAP are commonly referred to as the ``30 urban HAP.''
Section 112(c)(3), in turn, requires the EPA to list sufficient
categories or subcategories of area sources to ensure that area sources
representing 90 percent of the emissions of the 30 urban HAP are
subject to regulation. The EPA implemented these requirements through
the Integrated Urban Air Toxics Strategy by identifying and setting
standards for categories of area sources including the Gasoline
Distribution source category that is addressed in this action.
CAA section 112(d)(5) provides that for area source categories, in
lieu of setting MACT standards (which are

[[Page 35615]]

generally required for major source categories), the EPA may elect to
promulgate standards or requirements for area sources ``which provide
for the use of generally available control technology or management
practices [GACT] by such sources to reduce emissions of hazardous air
pollutants.'' In developing such standards, the EPA evaluates the
control technologies and management practices that reduce HAP emissions
that are generally available for each area source category. Consistent
with the legislative history, we can consider costs and economic
impacts in determining what constitutes GACT.
GACT standards were set for the Gasoline Distribution area source
category in 2008. As noted above, this proposed action presents the
required CAA 112(d)(6) technology review for that source category.
2. NSPS
The statutory authority for this action is provided by section 111
of the CAA, which governs the establishment of standards of performance
for stationary sources. Section 111(b)(1)(A) of the CAA requires the
EPA Administrator to list categories of stationary sources that in the
Administrator's judgement cause or contribute significantly to air
pollution that may reasonably be anticipated to endanger public health
or welfare. The EPA must then issue performance standards for new (and
modified or reconstructed) sources in each source category pursuant to
CAA section 111(b)(1)(B). These standards are referred to as new source
performance standards, or NSPS. The EPA has the authority under CAA
section 111(b) to define the scope of the source categories, determine
the pollutants for which standards should be developed, set the
emission level of the standards, and distinguish among classes, type
and sizes within categories in establishing the standards.
Section 111(b)(1)(B) of the CAA requires the EPA to ``at least
every 8 years review and, if appropriate, revise'' new source
performance standards. Section 111(a)(1) of the CAA provides that
performance standards are to ``reflect the degree of emission
limitation achievable through the application of the best system of
emission reduction which (taking into account the cost of achieving
such reduction and any nonair quality health and environmental impact
and energy requirements) the Administrator determines has been
adequately demonstrated.'' We refer to this level of control as the
best system of emission reduction or ``BSER.'' The term ``standard of
performance'' in CAA 111(a)(1) makes clear that the EPA is to determine
both the BSER for the regulated sources in the source category and the
degree of emission limitation achievable through application of the
BSER. The EPA must then, under CAA section 111(b)(1)(B), promulgate
standards of performance for new sources that reflect that level of
stringency. Section 111(b)(5) of the CAA precludes the EPA from
prescribing a particular technological system that must be used to
comply with a standard of performance. Rather, sources can select any
measure or combination of measures that will achieve the standard.
Pursuant to the definition of new source in CAA 111(a), standards of
performance apply to facilities that begin construction,
reconstruction, or modification after the date of publication of such
proposed standards in the Federal Register.
The EPA Priority List (44 FR 49222, August 21, 1979) included
Petroleum Transportation and Marketing as a source category for which
standards of performance were to be promulgated under CAA section 111.
The NSPS for this source category was promulgated on August 18, 1983
(48 FR 37578) and applies to the total of all the loading racks at a
bulk gasoline terminal that deliver liquid product into gasoline tank
trucks. This proposed action presents the required CAA 111(b)(1)(B)
review for the bulk gasoline terminals NSPS.

B. What are the source categories and how do the current standards
regulate emissions?

1. NESHAP Subpart R
The sources affected by the current major source NESHAP for the
Gasoline Distribution source category subpart R are bulk gasoline
terminals and pipeline breakout stations. A bulk gasoline terminal is
defined at 40 CFR 63.421 as ``any gasoline facility which receives
gasoline by pipeline, ship, or barge, and has a gasoline throughput
greater than 75,700 liters per day.'' \2\ A pipeline breakout station
is defined as ``a facility along a pipeline containing storage vessels
used to relieve surges or receive and store gasoline from the pipeline
for reinjection and continued transportation by pipeline or to other
facilities.'' The HAP emitted by Gasoline Distribution sources are
benzene, hexane, toluene, xylene, ethylbenzene, 2,2,4-trimethylpentane,
cumene, and napthalene. The emission standards are the same for new
sources and existing sources. Emissions from loading racks are
controlled by vapor collection and processing systems meeting 10
milligrams (mg) total organic carbon (TOC) per liter (L) of gasoline
loaded and the cargo tanks being loaded must be certified to be vapor
tight. Emissions from storage vessels with a design capacity greater
than or equal to 75 cubic meters are controlled by equipment designed
to capture and control emissions. Equipment leaks are required to be
repaired upon detection using audio, visual, or olfactory (AVO)
methods.
---------------------------------------------------------------------------

\2\ 75,700 liters per day is equal to 20,000 gallons per day.
---------------------------------------------------------------------------

2. NESHAP Subpart BBBBBB
The sources affected by the current area source NESHAP for the
Gasoline Distribution source category subpart BBBBBB are bulk gasoline
terminals, bulk gasoline plants, and pipeline facilities. A bulk
gasoline terminal is defined at 40 CFR 63.11100 as ``any gasoline
storage and distribution facility that receives gasoline by pipeline,
ship or barge, or cargo tank and has a gasoline throughput of 20,000
gallons per day or greater.'' A bulk gasoline plant is defined as ``any
gasoline storage and distribution facility that receives gasoline by
pipeline, ship or barge, or cargo tank, and subsequently loads the
gasoline into gasoline cargo tanks for transport to gasoline dispensing
facilities, and has a gasoline throughput of less than 20,000 gallons
per day.'' A pipeline breakout station is defined as ``a facility along
a pipeline containing storage vessels used to relieve surges or receive
and store gasoline from the pipeline for re-injection and continued
transportation by pipeline or to other facilities.'' A pipeline pumping
station is defined as ``a facility along a pipeline containing pumps to
maintain the desired pressure and flow of product through the pipeline,
and not containing gasoline storage tanks other than surge control
tanks.'' The HAP emitted by Gasoline Distribution sources are benzene,
hexane, toluene, xylene, ethylbenzene, 2,24-trimethylpentane, cumene,
and napthalene. The emission standards are the same for new sources and
existing sources. Emissions from loading racks at large bulk gasoline
terminals (those with gasoline throughput of 250,000 gallons per day or
greater) are controlled by vapor collection and processing systems
meeting 80 mg TOC per L of gasoline loaded (mg/L) and the cargo tanks
being loaded must be certified to be vapor tight. Small bulk gasoline
terminals and bulk gasoline plants must use submerged filling when
loading gasoline. Emissions from storage vessels with a design capacity
greater than or equal to 75 cubic meters are required to

[[Page 35616]]

be controlled by equipment designed to capture and control emissions.
Equipment leaks are required to be repaired upon detection using AVO
methods.
3. NSPS Subpart XX
The sources affected by the current NSPS for the Bulk Gasoline
Terminals source category subpart XX are bulk gasoline terminals that
commenced construction or modification after December 17, 1980. NSPS
subpart XX at 40 CFR 60.501 defines bulk gasoline terminals as ``any
gasoline facility which receives gasoline by pipeline, ship or barge,
and has a gasoline throughput greater than 75,700 liters per day.''
Emissions from loading racks at bulk gasoline terminals are controlled
by vapor collection and processing systems meeting 35 mg/L and the
cargo tanks being loaded must be certified to be vapor tight.\3\
Equipment leaks are required to be repaired upon detection using AVO
methods. Emissions from storage vessels are regulated under a separate
NSPS (40 CFR part 60, subpart K, Ka, or Kb).
---------------------------------------------------------------------------

\3\ Allowance is provided to meet 80 mg/L for affected
facilities with an ``existing vapor processing system.''
---------------------------------------------------------------------------

C. What data collection activities were conducted to support this
action?

The EPA used several data sources to determine the facilities that
are subject to the Gasoline Distribution NESHAP and the Bulk Gasoline
Terminals NSPS. We identified facilities in the 2017 National Emissions
Inventory (NEI) and the Toxics Release Inventory system having a
primary facility NAICS code beginning with 4247, Petroleum and
Petroleum Products Merchant Wholesalers. We also used information from
the original Gasoline Distribution NESHAP, Bulk Terminal list of
petrochemical storage facilities from the Internal Revenue Service, the
Office of Enforcement and Compliance Assurance's Enforcement and
Compliance History Online tool (<a href="https://echo.epa.gov">https://echo.epa.gov</a>), and the Energy
Information Administration. To inform our reviews for these emission
sources, we reviewed the EPA's Reasonably Available Control Technology
(RACT)/Best Available Control Technology (BACT)/Lowest Achievable
Emission Rate (LAER) Clearinghouse (RBLC) and regulatory development
efforts for similar sources published after the Gasoline Distribution
NESHAP and Bulk Terminals NSPS were developed. The EPA also reviewed
air permits to determine facilities subject to the Gasoline
Distribution NESHAP and Bulk Gasoline Terminals NSPS.
We met with industry representatives from Marathon, the American
Petroleum Institute, the International Liquid Terminals Association,
and the International Fuel Terminal Operators Association to collect
data and discuss industry practices. We also met with control device
suppliers to obtain information on the cost and design of control
devices. We met with representatives of the U.S. Department of
Transportation (DOT) to discuss cargo tank requirements.

D. What other relevant background information and data are available?

We relied on certain technical reports and memoranda that the EPA
developed for flares used as air pollution control devices in the
Petroleum Refinery Sector residual risk and technology review and NSPS
rulemaking (80 FR 75178, December 1, 2015). The Petroleum Refinery
sector docket is at Docket ID No. EPA-HQ-OAR-2010-0682. For
completeness of the rulemaking record for this action and for ease of
reference in finding these items in the publicly available petroleum
refinery sector rulemaking docket, we are including the most relevant
technical support documents in the docket for this proposed action
(Docket ID No. EPA-HQ-OAR-2020-0371) and including a list of the of all
documents used to inform the original flare provision in the Petroleum
Refinery Sector residual risk and technology review and NSPS rulemaking
in Attachment 2 of the memorandum titled Monitoring Options and Costs
for Gasoline Distribution Facilities, which is available in the docket
for this rulemaking.
Additional information related to the promulgation and subsequent
amendments of the NSPS and NESHAPs is available in Docket ID Nos. A-79-
52, A-92-38, EPA-HQ-OAR-2002-0029, EPA-HQ-OAR-2004-0019, EPA-HQ-OAR-
2004-0164, and EPA-HQ-OAR-2006-0406.

E. How does the EPA perform the NESHAP technology review and NSPS
review?

1. NESHAP Technology Review
Our technology review primarily focuses on the identification and
evaluation of developments in practices, processes, and control
technologies that have occurred since the NESHAPs were promulgated.
Where we identify such developments, we analyze their technical
feasibility, estimated costs, energy implications, and nonair
environmental impacts. We also consider the emission reductions
associated with applying each development. This analysis informs our
decision of whether it is ``necessary'' to revise the CAA section 112
emissions standards. In addition, we consider the appropriateness of
applying controls to new sources versus retrofitting existing sources.
For this exercise, we consider any of the following to be a
``development:''
<bullet> Any add-on control technology or other equipment that was
not identified and considered during development of the original MACT
and GACT standards;
<bullet> Any improvements in add-on control technology or other
equipment (that were identified and considered during development of
the original MACT and GACT standards) that could result in additional
emissions reduction;
<bullet> Any work practice or operational procedure that was not
identified or considered during development of the original MACT and
GACT standards;
<bullet> Any process change or pollution prevention alternative
that could be broadly applied to the industry and that was not
identified or considered during development of the original MACT and
GACT standards; and
<bullet> Any significant changes in the cost (including cost
effectiveness) of applying controls (including controls the EPA
considered during the development of the original MACT and GACT
standards).
In addition to reviewing the practices, processes, and control
technologies that were considered at the time we originally developed
each NESHAP, we review a variety of data sources in our investigation
of potential practices, processes, or controls to consider. We also
review each NESHAP and the available data to determine if there are any
unregulated emissions of HAP within the source categories, and evaluate
these data for use in developing new emission standards. When reviewing
MACT standards, we also address regulatory gaps, such as missing
standards for listed air toxics known to be emitted from the source
category. See sections II.C and II.D of this preamble for information
on the specific data sources that were reviewed as part of the
technology review.
2. NSPS Review
As noted in the section II.A.2 of this document, CAA section 111
requires the EPA, at least every 8 years to review and, if appropriate
revise the standards of performance applicable to new, modified, and
reconstructed sources. If the EPA revises the standards of

[[Page 35617]]

performance, they must reflect the degree of emission limitation
achievable through the application of the BSER taking into account the
cost of achieving such reduction and any nonair quality health and
environmental impact and energy requirements. CAA section 111(a)(1).
In reviewing an NSPS to determine whether it is ``appropriate'' to
revise the standards of performance, the EPA evaluates the statutory
factors including the following information:
<bullet> Expected growth for the source category, including how
many new facilities, reconstructions, and modifications may trigger
NSPS in the future.
<bullet> Pollution control measures, including advances in control
technologies, process operations, design or efficiency improvements, or
other systems of emission reduction, that are ``adequately
demonstrated'' in the regulated industry.
<bullet> Available information from the implementation and
enforcement of current requirements indicating that emission
limitations and percent reductions beyond those required by the current
standards are achieved in practice.
<bullet> Costs (including capital and annual costs) associated with
implementation of the available pollution control measures.
<bullet> The amount of emission reductions achievable through
application of such pollution control measures.
<bullet> Any nonair quality health and environmental impact and
energy requirements associated with those control measures.
In evaluating whether the cost of a particular system of emission
reduction is reasonable, the EPA considers various costs associated
with the particular air pollution control measure or a level of
control, including capital costs and operating costs, and the emission
reductions that the control measure or particular level of control can
achieve. The agency considers these costs in the context of the
industry's overall capital expenditures and revenues. The agency also
considers cost-effectiveness analysis as a useful metric, and a means
of evaluating whether a given control achieves emission reduction at a
reasonable cost. A cost-effectiveness analysis allows comparisons of
relative costs and outcomes (effects) of two or more options. In
general, cost-effectiveness is a measure of the outcomes produced by
resources spent. In the context of air pollution control options, cost-
effectiveness typically refers to the annualized cost of implementing
an air pollution control option divided by the amount of pollutant
reductions realized annually.
After the EPA evaluates the factors described above, the EPA then
compares the various systems of emission reductions and determines
which system is ``best''. The EPA then establishes a standard of
performance that reflects the degree of emission limitation achievable
through the implementation of the BSER. In doing this analysis, the EPA
can determine whether subcategorization is appropriate based on
classes, types, and sizes of sources, and may identify a different BSER
and establish different performance standards for each subcategory. The
result of the analysis and BSER determination leads to standards of
performance that apply to facilities that begin construction,
reconstruction, or modification after the date of publication of the
proposed standards in the Federal Register. Because the new source
performance standards reflect the best system of emission reduction
under conditions of proper operation and maintenance, in doing its
review, the EPA also evaluates and determines the proper testing,
monitoring, recordkeeping and reporting requirements needed to ensure
compliance with the emission standards.
See section II.C of this preamble for information on the specific
data sources that were reviewed as part of this action.

III. Proposed Rule Summary and Rationale

A. What are the results and proposed decisions based on our technology
reviews and NSPS review, and what is the rationale for those decisions?

We evaluated developments in practices, processes, and control
technologies for loading operations, storage vessels, and equipment
leaks for NESHAP subpart R and NESHAP subpart BBBBBB. For the NSPS XX,
we evaluated BSER for loading operations and equipment leaks. We
analyzed costs and impacts for each emission source (e.g., loading
operations) by each subpart. We also included product recovery in the
cost calculation, where appropriate. We based the product recovery on
the average pre-tax retail price of regular conventional gasoline in
2019 at a value of gasoline recovered of $1.50 per gallon.\4\ This
yielded a product recovery of $480 per ton of VOC. For NSPS, we
determined cost-effectiveness, cost per ton of emissions reduced, on a
VOC basis. For NESHAP, we determined cost-effectiveness on a HAP basis
from the VOC emissions. In general, gasoline (liquid) is approximately
20 weight percent HAP, but gasoline vapors are only 3 to 4 weight
percent HAP. We estimated that loading operation VOC emissions were 4
weight percent HAP, storage vessel VOC emissions were 5 weight percent
HAP, and equipment leak VOC emissions were 10 weight percent HAP.
Although we considered the options cumulatively, we also calculated the
incremental cost effectiveness, which allowed us to assess the impacts
of the incremental change between the options under consideration.
---------------------------------------------------------------------------

\4\ The VOC recovery credit was calculated based on the average
retail price of regular conventional gasoline in 2019, which was
$2.50/gallon, and that 60 to 70 percent of retail price is for taxes
and distribution/marketing costs (<a href="https://www.eia.gov/petroleum/gasdiesel/">https://www.eia.gov/petroleum/gasdiesel/</a>; EIA, 2021). Therefore, we estimated the value of
gasoline recovered to be $1.50/gallon ($2.50 x 0.60). Using a
density of gasoline of 6.25 lb/gallon, this yields a VOC credit of
$480/ton [($1.50/6.25) x 2000]. The average refiner's wholesale spot
price for all gasoline types in 2019 was $1.85/gallon (<a href="https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=EMA_EPM0_PBR_NUS_DPG&f=M">https://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=PET&s=EMA_EPM0_PBR_NUS_DPG&f=M</a>; EIA, 2021).
---------------------------------------------------------------------------

1. Standards for Loading Racks
We evaluated the control efficiency and costs of common control
systems used for loading racks, including thermal/vapor combustion
units (VCUs), carbon adsorption vapor recovery units (VRUs), flares,
and refrigerated condensers. We assessed the loading rates to the
control systems based on both splash loading and submerged loading for
5 different ``model plant'' gasoline throughputs. We also assessed cost
for vapor balancing controls. Our assessment of control systems is
summarized in the memorandum ``Control Options for Loading Operations
at Gasoline Distribution Facilities'' included in EPA Docket No. EPA-
HQ-OAR-2020-0371.
We did not identify any new control technologies, but we did
identify some state and local permits that required emission limits as
low as 1 mg/L (less than the most stringent federal limit of 10 mg/L).
We therefore considered the costs for upgrades needed to retrofit a
current control system to achieve more stringent emission limits for
each of the current rules. The emission limits assessed included 80 mg/
L, 35 mg/L, 10 mg/L, and 1 mg/L, depending on the emission limits for
each subpart, which are discussed in detail in sections III.A.1.a-c. We
also assessed alternative means of expressing the loading rack
emissions limit. The emissions limit expressed in terms of mg TOC/L of
gasoline loaded is difficult to directly monitor continuously as
discussed below. As such, the emission limit is generally assessed via
an initial

[[Page 35618]]

performance test, with operating limits established as means to ensure
continuous compliance. Alternative means to express the emission limit
may make the emission limit more amenable to direct monitoring.
a. NESHAP Subpart R
We identified one development for loading racks which is an
emission limit of 1 mg/L using the same types of control that we expect
are used to meet the current major source emission limit of 10 mg/L of
gasoline loaded. Therefore, we assessed maintaining the 10 mg/L
emission limit or reducing it to 1 mg/L. For the major source NESHAP
subpart R impacts analysis, we estimated that most facilities used VRUs
and that approximately 75 percent of the facilities could comply with
the 1 mg/L emission limit by modifying their operating characteristics
(cycle times) and 25 percent would need to upgrade their control
system.
Table 5 of this document summarizes the resulting impacts for the
control option considered for 210 major source (NESHAP subpart R)
facilities. Based on the costs associated with further HAP emission
reductions, we determined it is not cost-effective to lower the 10 mg/L
standard, since the cost effectiveness of the option is over $100,000
per ton of HAP reduced--a level that is over an order of magnitude
higher than we have considered cost-effective in previous rulemakings
to limit organic HAP. Accordingly, we are not proposing any changes to
the current emission limit for loading operations for the NESHAP
subpart R. Our assessment of control options is summarized in the
memorandum ``Major Source Technology Review for Gasoline Distribution
Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations)
NESHAP'' in EPA Docket No. EPA-HQ-OAR-2020-0371.
As noted in section V of this preamble, the EPA requests public
comment on all aspects of this proposed rule, including our evaluation
of the costs and efficacy of control options for loading operations
under NESHAP subpart R. Among other issues, EPA requests comment on
whether we have accurately assessed the costs, pollution reduction
benefits, and cost-effectiveness of applying a 1 mg/L emission limit to
major sources subject to this NESHAP; experience from implementing
state regulations or local ordinances for these sources that could
inform this technology review; and whether there are other factors that
EPA should consider that would support a revision of the current NESHAP
subpart R. For example, we note that there are at least 5.9 million
people located within 5 km of these sources (see Table 18 of this
document), and the EPA is concerned that these communities may already
be overburdened by air pollution from multiple sources. Information on
the contributions that HAPs from these sources make to overall
pollution burdens in neighboring communities may be useful in
determining whether a more stringent standard is warranted.

Table 5--Control Option Impacts for Loading Operations for NESHAP Subpart R
--------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \d\ w/o TAC \d\ w/
VOC emission product product CE \e\ ($/ton CE \e\ ($/ton
Emission limit reduction \a\ TCI \b\ ($) AOC \c\ ($/yr) recovery ($/ recovery ($/ VOC) HAP) \f\
(tpy) yr) yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
1 mg/L........................... 1,686 34,160,000 5,764,000 8,677,000 7,868,000 4,667 116,700
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Compared to baseline (10 mg/L) emissions of 1,873 tpy.
\b\ Total capital investment (TCI).
\c\ Annualized operating costs (AOC).
\d\ Total annualized cost (TAC) considering annual operating costs and annualized cost of capital.
\e\ Cost effectiveness (CE) as compared to baseline (10 mg/L).
\f\ HAP content of gasoline vapors assumed to be 4% of VOC.

In our review of the developments in practices, processes, or
control technologies, we noted that there were inconsistencies
regarding continuous parameter monitoring requirements associated with
complying with the loading standard as expressed in terms of 10 mg/L of
gasoline loaded. For example, most VRUs have a continuous TOC
concentration monitor, but do not have flow meters needed to convert
the concentration limit to a mass emission rate that can be used to
calculate the emissions in terms of mg/L. State and local permitting
agencies set continuous concentration limits based on performance
tests, but also factor in more variability to account for different
loading rates and operational characteristics of the VRU. While we
noted some variability in exhaust flow rates with product loading
rates, the exhaust flow rate is well correlated with the product
loading rates, such that a direct concentration limit can be
established that is equivalent to the 10 mg/L standard. We determined
that the concentration limit for VRU has several advantages to the 10
mg/L emission limit. First, a concentration limit could be directly and
continuously monitored. In this case, the TOC monitor would be used as
a continuous emission monitoring system (CEMS) and exceedances of the
concentration limit would be a violation of the emission limit. When
the emission limit is expressed in mg/L, the TOC monitor is used as a
continuous parameter monitoring system (CPMS) and exceedance of the
concentration limit is a deviation of the operating limit. Thus, the
concentration-based standard provides improved enforceability of the
emission limit. Second, providing a concentration limit directly in the
rule reduces the variability in the way the operating limits are
established in different states and localities. Thus, it provides
consistent implementation of the federal standard when considering
continuous compliance requirements. The potential disadvantage of a
concentration limit is the ability to draw in ambient air to dilute the
exhaust gas concentration.
Upon careful consideration of the potential options to improve
continuous compliance monitoring requirements, we are proposing to
express the emission limit for VRUs in terms of a concentration limit
of 5,500 parts per million by volume (ppmv) TOC as propane on a three-
hour rolling average. As noted previously, this provides a more
enforceable and consistent continuous compliance requirement that is
directly related to the emissions limit. To prevent dilution, we are
proposing that only vacuum breaker valves can be used to introduce
ambient air into the VRU control system.
Because of the need for combustion air and products of combustion,
this concentration limit is not directly applicable for VCUs. We
considered developing an equivalent concentration limit for VCUs, but
this would require

[[Page 35619]]

both a TOC monitor and an oxygen monitor, to correct the concentration
limit to 0 percent excess oxygen. This standard becomes problematic at
low TOC loading rates, where the oxygen concentration may approach that
of the ambient air. We consider that periodic performance test along
with continuous monitoring of combustion zone temperature provides
adequate assurance that the VCU is operating in a manner consistent
with the TOC emissions limit. NESHAP subpart R already includes
requirements for using a temperature operating limit to demonstrate
continuous compliance with the 10 mg/L emission limit; however, these
requirements do not provide adequate instructions on how to establish
the operating limit, particularly with respect to the averaging time.
For example, the performance test requires readings be taken every 5
minutes over a 6-hour test period, but there are no instructions on how
to develop the temperature operating limit from these readings. At
times, the 5-minute temperature readings can fluctuate significantly,
particularly during periods of low loading rates. Establishing the
operating limit based on the lowest 5-minute reading during a time of
little or no loading of product into gasoline cargo tanks can lead to
erroneously low temperature operating limits that do not ensure
adequate combustion efficiencies. We considered establishing a minimum
operating temperature, such as 1,400 [deg]F or 1,500 [deg]F as required
for VCU in general standards for closed vent system and control devices
[see 40 CFR 63.985(b)(1)(i)(B) or 40 CFR 60.482-10a(c)]. However, we
recognized that there is a wide variety of VCU designs and that a
single set temperature operating limit may not be appropriate for all
applications. Therefore, we elected to maintain that the temperature
operating limit be set during the performance test, but we are
proposing additional instructions on how to develop and assess the
temperature operating limit. First, we are proposing the temperature
operating limit be established and evaluated on a 3-hour rolling
average basis. We are proposing that, for each 5-minute block of the
performance test, the combustion (flame) zone must be determined,
either via a single temperature reading or an average temperature of
all readings during the 5-minute block), and a record of the volume of
liquid product loading into gasoline cargo tanks must be kept. We are
proposing that hourly average combustion zone temperatures be developed
from the 5-minute measurements using only those 5-minute periods when
product is loaded into gasoline cargo tanks. From those hourly
averages, 3-hour rolling averages are to be determined. During the 6-
hour performance test, 4 different 3-hour rolling averages will be
determined. We are proposing that the temperature operating limit be
established as the lowest of the 3-hour averages. We consider that this
approach will establish a temperature operating limit that is
indicative of VCU performance while accounting for variability in
loading operations. We are proposing that compliance with the operating
limit will be determined on a 3-hour rolling average basis following
the same procedures used during the performance tests (5-minute
measurements used to calculate 1-hour average values considering only
5-minute periods when product was loaded into gasoline cargo tanks).
We also determined that periodic emission testing should be
required to help ensure continuous compliance. Currently, facilities
conduct a one-time performance test and then monitor operating limits.
We are proposing to require on-going performance tests at a minimum
frequency of once every 5 years to supplement the parameter monitoring
and ensure emission controls continue to operate as demonstrated during
the initial performance test. Our assessment of monitoring options is
summarized in the memorandum ``Monitoring Options and Costs for
Gasoline Distribution Facilities'' in EPA Docket No. EPA-HQ-OAR-2020-
0371.
Finally, we expect all or nearly all facilities use submerged
loading as they fill product into cargo tanks. However, the NESHAP
subpart R does not require submerged filling. The lack of a direct
requirement for submerged loading may cause problems for several
reasons. First, organic loading rates to the control system when using
splash loading are expected to be more than double that of the organic
loading rates when using submerged loading. With the preponderance of
use of submerged loading, performance tests would almost certainly be
conducted when the cargo tanks are loaded via submerged fill. The
periodic performance test and operating limits may not be adequate to
ensure compliance while splash loading is used. We also note that the
10 mg/L emission limit is essentially equivalent to 98 percent TOC
control efficiency when using submerged fill, but requires over 99
percent control efficiency when splash loading is used. Because the
flare requirements were specifically developed to ensure a 98 percent
flare destruction efficiency, the flare operating limits are not
considered adequate to ensure compliance with the 10 mg/L emissions
limit when splash loading is used. Therefore, we are proposing to
expressly include submerged fill requirements as an integral part of
the loading rack standards.
b. NESHAP Subpart BBBBBB
The requirements for loading racks at area source gasoline
distribution facilities are dependent on the total throughput capacity
of all racks. Large gasoline bulk terminals have loading racks with a
combined throughput of 250,000 gallons per day or greater and are
required to reduce emissions of TOC to less than or equal to 80 mg/L of
gasoline loaded. Small gasoline bulk terminals, which have loading
racks with a combined throughput between 20,000 and 250,000 gallons per
day, are required to use submerged filling with a submerged fill pipe
that is no more than 6 inches from the bottom of the cargo tank. Bulk
gasoline plants are facilities with gasoline throughput of 20,000
gallons per day or less and are required to use submerged filling in
all gasoline storage tanks with a capacity of greater than 250 gallons
and in all cargo tanks.
For large bulk gasoline terminals at area sources (i.e., combined
throughput of 250,000 gallons per day or greater), we evaluated control
options of either maintaining the current 80 mg/L control option or
lowering that limit to either 35 mg/L, 10 mg/L, or 1 mg/L. Table 6 of
this document presents the estimated nationwide impacts of these
alternative emission limits for 232 large bulk gasoline terminals at
area sources. The cost-effectiveness and incremental cost-effectiveness
of reducing the area source emission limit for large bulk gasoline
terminals to 35 mg/L are $9,700 per ton of HAP emissions reduced, which
we determined is cost-effective. The cost-effectiveness and incremental
cost effectiveness of reducing the area source emission limit for large
bulk gasoline terminals to 10 mg/L are approximately $12,000 and
$13,000 per ton of HAP emissions reduced, respectively, which we
determined is not cost-effective. Therefore, we are proposing to lower
the area source emission limits for loading racks at large bulk
gasoline terminals to 35 mg/L.
We note, however, that there are at least 35.7 million people
located within 5 km of these sources (see Table 19 of this document),
and EPA is concerned that this population has the potential to be
overburdened from air pollution from multiple sources. In this case, we
have

[[Page 35620]]

identified a more stringent standard (i.e., 10 mg/L) that could further
reduce HAP emissions exposure in communities near these large bulk
terminals. We project that this more stringent standard would impose
slightly higher, but not unreasonable, capital and annualized costs on
these terminals. EPA seeks comment on whether this more protective
standard, although it is less cost effective for these type of HAP
emissions controls than we would typically find acceptable, is
nevertheless appropriate given the reductions in HAPs that would occur
in potentially over-burdened communities surrounding these large bulk
terminals. EPA also requests information on the costs, efficacy, and
feasibility of control options for loading racks at area source
gasoline distribution facilities, and the contributions of these
sources to overall pollution burdens in surrounding communities, to
inform our consideration of whether a more protective area source
standard is warranted. Our assessment of control options is summarized
in the memorandum ``Area Source Technology Review for the Gasoline
Distribution Bulk Terminals, Bulk Plants, and Pipeline Facilities
NESHAP'' in EPA Docket No. EPA-HQ-OAR-2020-0371.
As in the major source rule, we are proposing to replace the
current mass-based limits with a direct concentration limit for
facilities operating VRUs because it provides consistent implementation
of the federal standard when considering continuous compliance
requirements. The corresponding concentration limit equivalent to a 35
mg/L emission limit is 19,200 ppmv as propane. Therefore, we are
proposing to express the emission limit for VRUs in terms of a
concentration limit of 19,200 ppmv TOC as propane on a three-hour
rolling average. As noted previously, a concentration limit provides a
more enforceable and consistent continuous compliance requirement that
is directly related to the emissions limit. To prevent dilution, we are
proposing that only vacuum breaker valves can be used to introduce
ambient air into the VRU control system. Our assessment of monitoring
options is summarized in the memorandum ``Monitoring Options and Costs
for Gasoline Distribution Facilities'' in EPA Docket No. EPA-HQ-OAR-
2020-0371.
Because of the need for combustion air, this concentration limit is
not directly applicable for VCUs. We considered developing an
equivalent concentration limit for VCUs, but this would require both a
TOC monitor and an oxygen monitor, to correct the concentration limit
to 0 percent excess oxygen. This standard becomes problematic at low
TOC loading rates, where the oxygen concentration may approach that of
the ambient air.\5\ Because most VCUs used at area source gasoline
distribution facilities are enclosed, air-assisted flares, we
determined that operating limits, either temperature operating limits
(as described for the major sources NESHAP subpart R) or flare
operating limits (net combustion zone heating value and air-assist
dilution parameter values, as provided in the Petroleum Refinery MACT
rule: 40 CFR part 63, subpart CC) are the most appropriate. We
anticipate that facilities electing to meet the flare operating limits
for their VCU would conduct two-week sampling to assess the variability
of heat content while loading gasoline and develop minimum natural gas
assist rates as a means of demonstrating continuous compliance.
Alternatively, facilities may elect to install a calorimeter to monitor
heat content and only add natural gas as needed if the vent gas stream
falls below the minimum required heat content. We are proposing to
require VCUs at area source facilities to monitor temperature or meet
the flare operating limits in 40 CFR part 63, subpart CC.
---------------------------------------------------------------------------

\5\ Some VCU are essentially enclosed flares that do not have a
means to reduce air inlet draft at low TOC loading rates.

Table 6--Control Option Impacts for Loading Operations at Large Area Source Bulk Gasoline Terminals
--------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \d\ w/o TAC \d\ w/
VOC emission TCI \b\ AOC \c\ ($/ product product CE \e\ ($/ton ICE \g\ ($/
Emission limit reduction \a\ ($1,000) yr) recovery ($/ recovery ($/ HAP) \f\ ton HAP) \f\
(tpy) yr) yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
35 mg/L................................. 820 0 385,000 385,000 319,000 9,742 9,742
10 mg/L................................. 2,619 1,878 1,371,000 1,531,000 1,275,000 12,170 13,270
1 mg/L.................................. 3,945 68,400 15,560,000 21,400,000 20,990,000 133,000 371,900
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Compared to baseline (80 mg/L) emissions of 4,097 tpy.
\b\ Total capital investment (TCI).
\c\ Annual operating costs (AOC).
\d\ Total annualized costs (TAC) considering annual operating costs and annualized cost of capital.
\e\ Cost effectiveness (CE) compared to baseline (80 mg/L).
\f\ HAP content assumed to be 4% of VOC.
\g\ Incremental cost effectiveness (ICE) compared to previous option in table.

Similarly, for small bulk gasoline terminals at area sources (i.e.,
combined throughput between 20,000 and 250,000 gallons per day), we
evaluated control options of maintaining the current submerged loading
requirements and potentially adding loading rack emission limits of
either 80 mg/L, 35 mg/L, 10 mg/L, or 1 mg/L. Table 7 of this document
presents the estimated nationwide impacts of these alternative emission
limits for 858 small bulk gasoline terminals at area sources. We
evaluated the 80 mg/L emission limit for loading racks, but the cost-
effectiveness of this option exceeds $24,000 per ton of HAP emissions
reduced. The other options are less cost-effective. Based on this
analysis, we are not proposing any changes to the current area source
provisions for small bulk gasoline terminals subject to NESHAP subpart
BBBBBB.
However, as noted above in the context of large bulk gasoline
terminals at area sources, EPA is concerned about the large number of
people living within 5 km of these facilities and the potential for
these affected populations to be located in communities that already
face a significant burden of air pollution from multiple sources.
Although we estimate that a standard of 80 mg/L or less would have a
cost per ton that is higher than we have traditionally

[[Page 35621]]

considered to be acceptable for organic HAP, it is also possible that
other cost metrics we have discretion to consider--such as total
capital and operating costs--could support the reasonableness of such
an emissions limit. EPA therefore seeks comment on whether an emissions
limit of 80 mg/L or less would be appropriate in light of these
alternative cost metrics and the reductions in HAPs that would occur in
potentially over-burdened communities surrounding these small bulk
terminals. EPA also requests information on the costs, efficacy, and
feasibility of control options for these sources, and the contributions
of these sources to overall pollution burdens in surrounding
communities, to inform our consideration of whether it is appropriate
to establish an emissions limit for loading operations at small area
source bulk gasoline terminals. Our assessment of control options is
summarized in the memorandum ``Area Source Technology Review for the
Gasoline Distribution Bulk Terminals, Bulk Plants, and Pipeline
Facilities NESHAP'' in EPA Docket No. EPA-HQ-OAR-2020-0371.

Table 7--Control Option Impacts for Loading Operations at Small Area Source Bulk Gasoline Terminals
--------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \d\ w/o TAC \d\ w/
VOC emission TCI \b\ AOC \c\ ($/ product product CE \e\ ($/ton ICE \g\ ($/
Emission limit reduction \a\ ($1,000) yr) recovery ($/ recovery ($/ HAP) \f\ ton HAP) \f\
(tpy) yr) yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
80 mg/L................................. 2,015 11,870 1,909,000 2,922,000 1,954,000 24,250 24,250
35 mg/L................................. 2,974 12,370 3,758,000 4,813,000 4,457,000 37,460 65,240
10 mg/L................................. 5,056 38,470 9,579,000 12,860,000 12,260,000 60,600 93,650
1 mg/L.................................. 5,789 326,400 43,310,000 71,140,000 70,450,000 304,200 1,984,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Compared to baseline (submerged loading) emissions of 5,870 tpy.
\b\ Total capital investment (TCI).
\c\ Annual operating costs (AOC).
\d\ Total annualized costs (TAC) considering annual operating costs and annualized cost of capital.
\e\ Cost effectiveness (CE) compared to baseline (submerged loading).
\f\ HAP content assumed to be 4% of VOC.
\g\ Incremental cost effectiveness (ICE) compared to previous option in table.

We expect that storage tanks at bulk gasoline plants typically have
fixed roofs. As such, vapor balancing is a potential control option for
bulk gasoline plants. In reviewing state and local requirements, we
found that a number of state requirements include requirements for
vapor balancing at bulk gasoline plants but have a minimum
applicability threshold of 4,000 gallons per day. Therefore, we
evaluated the costs of requiring vapor balancing for a variety of
differently-sized bulk gasoline plants. Vapor balancing is projected to
result in a net cost savings relative to submerged loading (when
considering the value of gasoline vapors not emitted) for bulk gasoline
plants with throughput of about 8,000 to 10,000 gallons per day or
more. The cost effectiveness of vapor balancing begins to diminish at
smaller bulk gasoline plants, exceeding $10,000 per ton of HAP reduced
at bulk plants with throughputs less than 4,000 gallon per day.
Considering the state rules and diminishing cost effectiveness for
small bulk gasoline plants, we are proposing to require vapor balancing
both for loading storage vessels and for loading cargo tanks, for bulk
gasoline plants with maximum design capacity throughput of 4,000
gallons per day or more. Bulk gasoline plants with capacities below
4,000 gallons per day would retain the requirement to use submerge
fill.
We also considered including loading rack emission limits of either
80 mg/L, 35 mg/L, 10 mg/L, or 1 mg/L. Table 8 of this document presents
the estimated nationwide impacts of the alternative emission limits
considered for 5,913 bulk gasoline plants. Note that vapor balancing is
projected to achieve emission reductions similar to that achieved by an
emission limit of 35 mg/L, but at much lower costs. Each loading rack
emission limit option at bulk gasoline plants had a cost-effectiveness
exceeding $275,000 per ton of HAP emissions reduced. Based on this
analysis, we are not proposing to add an emission limit for bulk
gasoline plants subject to NESHAP subpart BBBBBB. Our assessment of
control options is summarized in the memorandum ``Area Source
Technology Review for the Gasoline Distribution Bulk Terminals, Bulk
Plants, and Pipeline Facilities NESHAP'' in EPA Docket No. EPA-HQ-OAR-
2020-0371.

Table 8--Control Option Impacts for Loading Operations at Area Source Bulk Plants
--------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \d\ w/o TAC \d\ w/
VOC emission TCI \b\ AOC \c\ product product CE \e\ ($/ton ICE \g\ ($/
Emission limit reduction \a\ ($1,000) ($1,000/yr) recovery ($/ recovery ($/ HAP) \f\ ton HAP) \f\
(tpy) yr) yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Vapor Balancing......................... 23,739 42,310 2,116 7,140 -4,255 -4,481 -4,481
80 mg/L................................. 20,215 455,800 247,900 286,800 277,100 342,600 \h\ 342,600
35 mg/L................................. 23,100 455,800 247,900 286,800 275,700 298,400 -12,000
10 mg/L................................. 24,969 455,800 247,900 286,800 274,800 275,100 -12,000
1 mg/L.................................. 25,627 1,367,000 297,500 414,100 401,800 392,000 4,824,000
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Compared to baseline (uncontrolled) emissions of 25,700 tpy.
\b\ Total capital investment (TCI).
\c\ Annual operating costs (AOC).
\d\ Total annualized costs (TAC) considering annual operating costs and annualized cost of capital.
\e\ Cost effectiveness (CE) compared to baseline (uncontrolled).
\f\ HAP content assumed to be 4% of VOC.
\g\ Incremental cost effectiveness (ICE) compared to previous option in table.
\h\ ICE compared to submerged fill rather than previous option of vapor balancing.

[[Page 35622]]

c. NSPS Subpart XXa
The current NSPS (40 CFR part 60, subpart XX \6\) that applies to
bulk gasoline terminals (gasoline throughput exceeding 20,000 gallons
per day) has a loading rack emission limit of 35 mg/L of gasoline
loaded.\7\ We are proposing to add a new subpart at part 60, subpart
XXa that would be applicable to bulk gasoline terminals that commenced
construction, modification or reconstruction after June 10, 2022.
---------------------------------------------------------------------------

\6\ Part 60, subpart XX applies to bulk gasoline terminals that
commenced construction, modification or construction after December
17, 1980. This proposal would modify subpart XX so that it applies
to bulk gasoline terminals that commenced construction, modification
or reconstruction after December 17, 1980 and on or before the
publication date of the proposed part 60, subpart XXa.
\7\ Allowance is provided to meet 80 mg/L for affected
facilities with an ``existing vapor processing system.''
---------------------------------------------------------------------------

In 40 CFR 60.501``gasoline tank'' is defined as ``. . . a delivery
tank truck. . . .'' The major and area source NESHAP definition of
``gasoline cargo tank'' includes loading of tank trucks and railcars.
In NSPS subpart XXa, we are proposing nomenclature revisions to
generalize the loading requirements similar to the NESHAP definitions
which apply to a ``gasoline cargo tank'' rather than just a ``gasoline
tank'' to expressly include railcar loading operations. The control
techniques and costs of control for loading operations apply equally to
tank truck and rail car loading racks and we therefore find no basis
for excluding rail car loading operations at bulk gasoline terminals
from the NSPS requirements.
Additionally, we assessed either maintaining the current NSPS 35
mg/L emission limit for loading operations or reducing it to either 10
mg/L or 1 mg/L. We assessed costs differently between facilities that
are new versus modified or reconstructed, because the incremental cost
of designing a system to meet 1 mg/L versus 10 mg/L for a new system is
small, but the costs for upgrading an existing control system that
currently meets a 10 mg/L or 35 mg/L emissions limit to meet 1 mg/L can
be high and may require complete replacement of the existing controls.
We projected nationwide impacts for different control options in
the fifth year of the NSPS considering separately 5 newly constructed
bulk gasoline terminals and 15 modified or reconstructed facilities
that currently meet a 35 or 80 mg/L emission limit. These costs are
summarized in Table 9 of this document. Considering the expected range
of throughputs for newly constructed bulk gasoline terminals, the
incremental cost to meet a 1 mg/L limit rather than a 10 mg/L limit is
about $1,300 per ton of VOC reduced, which we determined is cost-
effective. As shown in Table 9 of this document, the incremental cost
for modified or reconstructed facilities to meet a 1 mg/L limit rather
than a 10 mg/L limit exceeds $8,300 per ton of VOC reduced, which we
determined is not cost-effective. The incremental cost for modified or
reconstructed facilities to meet a 10 mg/L limit, on the other hand,
rather than a 35 mg/L limit is about $350 per ton of VOC reduced, which
we determined is cost-effective. Therefore, we are proposing in the
proposed subpart XXa that facilities that commence construction after
June 10, 2022) must meet a 1 mg/L limit and facilities that commence
modification, or reconstruction after June 10, 2022 must meet a 10 mg/L
limit. Our assessment of control options is summarized in the
memorandum ``New Source Performance Standards Review for Bulk Gasoline
Terminals'' in EPA Docket No. EPA-HQ-OAR-2020-0371.

Table 9--Control Option Impacts for Loading Operations at NSPS Bulk Gasoline Terminals
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \c\ w/o TAC \c\ w/
VOC emissions VOC emission TCI \a\ AOC \b\ ($/ product product CE \d\ ($/ ICE \e\ ($/
Emission limit (tpy) reduction ($1,000) yr) recovery ($/ recovery ($/ ton VOC) ton VOC)
(tpy) yr) yr)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
New:
Submerged Loading.............................................. 2,402
35 mg/L........................................................ 171 2,231 5,900 671,000 1,170,000 103,000 46 46
10 mg/L........................................................ 48 2,354 6,210 706,000 1,240,000 106,000 45 23
1 mg/L......................................................... 5 2,397 6,830 730,000 1,310,000 162,000 67 1,290
Modified/Reconstructed:
Submerged Loading.............................................. 332
35 mg/L........................................................ 286 46 0 19,500 19,500 -2,330 -51 -51
10 mg/L........................................................ 144 188 351 107,000 137,000 46,900 250 346
1 mg/L......................................................... 14 317 6,530 725,000 1,280,000 1,130,000 3,560 8,350
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Total capital investment (TCI).
\b\ Annual operating costs (AOC).
\c\ Total annualized costs (TAC) considering annual operating costs and annualized cost of capital.
\d\ Cost effectiveness (CE) compared to the first option listed.
\e\ Incremental cost effectiveness (ICE) compared to previous option in table.

2. Standards for Cargo Tank Vapor Tightness
The area source NESHAP subpart BBBBBB and the NSPS subpart XX both
have vapor tightness requirements for cargo tanks that allow up to 3
inches of water pressure drop over a 5-minute period. The major source
NESHAP subpart R has a graduated vapor tightness certification that
allows from 1 to 2.5 inches ('') of water pressure drop over a 5-minute
period, depending on the compartment size in the cargo tank. Further,
DOT requirements that were last amended in 2003 (see 68 FR 19285, April
18, 2003) indicate ``A cargo tank used to transport a petroleum
distillate fuel that is equipped with vapor recovery equipment may be
leakage tested in accordance with 40 CFR 63.425(e)'' [49 CFR 178.346-
5]. As such, it appears that most cargo tanks (those less than 18 years
of age) are minimally required to comply with the major source NESHAP
vapor tightness requirements pursuant to the DOT requirements. In
discussion with industry representatives, facility operators indicated
there generally is a single vapor-tightness certification and cargo
tanks are not certified for NSPS subpart XX or the area source NESHAP
separate from cargo tanks certified for the major source NESHAP. Since
cargo tanks can be used across gasoline distribution facilities subject
to different standards, we considered cargo tank vapor-tightness
requirements consistently across all rules.
Another development we identified is state requirements for vapor
tightness that have allowable pressure drops that

[[Page 35623]]

are half those allowed under the major source NESHAP subpart R. As
such, we assessed options ranging from maintaining current requirements
(which has different requirements for facilities subject to NESHAP
subpart BBBBBB and NSPS subpart XX than for NESHAP subpart R);
requiring NESHAP subpart R limits for all gasoline distribution
facilities (including facilities subject to NESHAP subpart BBBBBB and
NSPS subpart XX); and requiring more stringent vapor tightness
requirements based on state requirements (half those in NESHAP subpart
R) for all gasoline distribution facilities (across all three rules).
Table 10 of this document summarizes the results of these analyses.
Based on these results, we concluded that the state rule requirements
(one-half the current NESHAP subpart R requirements) are cost-effective
developments that would further harmonize certification requirements
across all gasoline distribution facilities and cargo tank operators.
We also considered requiring even more stringent vapor tightness
requirements, at about one-quarter of those in NESHAP subpart R, but
these required allowable pressure drop limits that were less than the
allowable precision of EPA Method 27. As such, we determined that
further reductions of the vapor tightness requirements beyond those
identified in state requirements have not been demonstrated in
practice. Therefore, we are proposing to require a graduated vapor
tightness certification from 0.5 to 1.25 inches of water pressure drop
over a 5-minute period, depending on the cargo tank compartment size
for gasoline cargo tanks subject to NSPS subpart XXa, NESHAP subpart R
and NESHAP subpart BBBBBB. Our assessment of control options is
summarized in the memorandum ``Control Options for Loading Operation at
Gasoline Distribution Facilities'' in EPA Docket No. EPA-HQ-OAR-2020-
0371.

Table 10--Impacts for 10,000 Cargo Tanks Under Different Control Options
--------------------------------------------------------------------------------------------------------------------------------------------------------
VOC TAC \a\ w/ TAC \a\ w/
VOC emission o product product CE \b\ ($/ CE \b\ ($/ ICE \d\ ($/ ICE \d\ ($/
Option emissions reduction recovery recovery ton VOC) ton HAP) ton VOC) ton HAP)
(tpy) (tpy) ($/year) ($/year) \c\ \c\
--------------------------------------------------------------------------------------------------------------------------------------------------------
3'' water....................................... 33,602 0 250,000 250,000
NESHAP Subpart R (1''-2.5'' water).............. 28,047 5,555 997,375 -1,669,14 -300 -7,512 -345 -8,637
State Rule (0.5''-1.25'' water)................. 25,718 7,883 1,766,000 -2,017,984 -256 -6,400 -150 -3,746
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Total annualized costs (TAC) considering annualized operating costs.
\b\ Cost effectiveness (CE) compared to baseline (3'' water).
\c\ HAP content assumed to be 4% of VOC.
\d\ Incremental cost effectiveness (ICE) compared to previous option in table.

3. Standards for Gasoline Storage Vessels
The area source and major source NESHAP (subparts R and BBBBBB)
have standards for storage vessels that are largely based on the
requirements for volatile organic liquid storage vessels in 40 CFR part
60, subpart Kb (NSPS subpart Kb), but include some exceptions to the
NSPS subpart Kb requirements, primarily related to floating roof deck
fitting controls. Because VOC emissions from storage vessels are
regulated under NSPS subpart Kb, storage vessels are not part of
affected facilities under NSPS subpart XX.
We reviewed Federal, state, and local requirements for gasoline
storage vessels. We identified potential improvements in the
requirements for primary seals, secondary seals (for internal floating
roofs), and improved fitting controls (particularly for guidepoles) as
developments in practices and processes. Additionally, we identified a
new practice for monitoring internal floating roof storage vessels
using a lower explosive limit (LEL) monitor to identify floating roofs
with poorly functioning seals or fitting controls. We assessed the cost
and impacts of moving from the current standards to full compliance
with NSPS subpart Kb requirements and for including LEL monitoring. Our
assessments for each subpart are detailed in the following subsections.
For more information on the storage vessel assessments, see memorandum
``Control Options for Storage Tanks at Gasoline Distribution
Facilities'' available in Docket No. EPA-HQ-OAR-2020-0371.
a. NESHAP Subpart R
The major source rule contains standards for gasoline storage
vessels at bulk gasoline terminals and pipeline breakout stations. The
standards cross-reference NSPS subpart Kb requirements but exclude
fitting control requirements in NSPS subpart Kb provided the storage
vessel was already equipped with a floating roof meeting the seal
requirements in NSPS subpart Kb. We estimated that about 95 percent of
storage vessels in the gasoline distribution industry are equipped with
internal floating roofs based on review of NEI data. We assessed costs
and impacts of requiring fitting controls separately for internal and
external floating roofs. Specifically, we evaluated the control options
of (1) requiring upgrades of fitting requirements for external floating
roofs and (2) requiring upgrades of fitting requirements for both
external and internal floating roofs. Table 11 of this document
summarizes the national impacts projected for major source gasoline
distribution facilities. Based on our analysis, we determined
installing/upgrading fitting controls for external floating roof tanks
is cost effective. On the other hand, the projected cost-effectiveness
of installing/upgrading fitting controls for internal floating roof
tanks is approximately $350,000 per ton of HAP emissions reduced
(incremental costs between Option 1 and 2), and therefore, we
determined these controls are not cost effective. Accordingly, we are
proposing to require fitting controls for external floating roof tanks
consistent with the requirements in NSPS subpart Kb and are not
proposing to require fitting controls for internal floating roof tanks.
Our assessment of control options is summarized in the memorandum
``Major Source Technology Review for Gasoline Distribution Facilities
(Bulk Gasoline Terminals and Pipeline Breakout Stations) NESHAP'' in
EPA Docket No. EPA-HQ-OAR-2020-0371.

[[Page 35624]]

Table 11--Control Option Impacts for Storage Vessels at Major Source Gasoline Distribution Facilities
[Bulk terminals and pipeline breakout stations]
--------------------------------------------------------------------------------------------------------------------------------------------------------
VOC TAC \c\ w/o TAC \c\ w/
emission TCI \b\ product product CE \d\ ($/ CE \d\ ($/ ICE \f\ ($/ ICE \f\ ($/
Control option reduction ($1,000) recovery recovery ton VOC) ton HAP) ton VOC) ton HAP)
\a\ (tpy) ($1,000/yr) ($1,000/yr) \e\ \e\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Upgrade EFRT fittings \g\....................... 546 1,857 173 -89 -164 -3,272 -164 -3,272
Upgrade IFRT and EFRT fittings \g\.............. 772 45,240 4,205 3,835 4,966 99,320 17,330 346,500
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Compared to baseline emissions of 4,977 tpy.
\b\ Total capital investment (TCI).
\c\ Total annualized costs (TAC) considering annual operating costs and annualized cost of capital.
\d\ Cost effectiveness (CE) compared to baseline.
\e\ HAP content assumed to be 5% of VOC.
\f\ Incremental cost effectiveness (ICE) compared to previous option in table.
\g\ EFRT = external floating roof tank; IFRT = internal floating roof tank.

While we are not directly proposing additional fitting controls for
internal floating roof tanks, we identified the use of LEL monitoring
within the headspace of an internal floating roof tank as a means to
enhance the annual inspections and more readily identify malfunctioning
internal floating roofs. We estimated the cost of the LEL monitoring
requirement based on the additional time needed to monitor LEL during
the annual inspections. We estimated the impacts of annual LEL
monitoring based on the number of internal floating roof tanks at major
source gasoline distribution facilities and assuming LEL monitoring
identifies defects in about 2 percent of internal floating roofs
resulting in a 2 percent reduction in baseline emissions of internal
floating roofs. Based on our review of available LEL monitoring data,
we expect that this is a conservative estimate of the emission
reductions that would be achieved. Table 12 of this document summarizes
the projected impact of requiring annual LEL monitoring for internal
floating roof tanks as part of the annual roof-top inspections.
The added cost for conducting LEL monitoring is under $70 per year
per tank and LEL monitoring is expected to result in cost-effective
emission reductions for major source gasoline distribution facilities
(costs of $4,200 per ton of HAP reduced). Therefore, we are proposing
to require LEL monitoring as part of the annual visual inspections
conducted for internal floating roof tanks at major source gasoline
distribution facilities. Our assessment of LEL monitoring at major
sources is summarized in the memorandum ``Major Source Technology
Review for Gasoline Distribution Facilities (Bulk Gasoline Terminals
and Pipeline Breakout Stations) NESHAP'' in EPA Docket No. EPA-HQ-OAR-
2020-0371.

Table 12--LEL Monitoring Impacts at Nationwide Major Source Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \a\ w/o TAC \a\ w/
VOC emission product product CE \b\ ($/ton CE \b\ ($/ton
Facility type reduction recovery ($/ recovery ($/ VOC) HAP) \c\
(tpy) yr) yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Major Source Facilities...................................... 82 56,290 17,130 210 4,200
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Total annualized cost (TAC) considering annual operating costs; there are no annualized cost of capital for this option.
\b\ Cost effectiveness (CE).
\c\ HAP content assumed to be 5% of VOC.

b. NESHAP Subpart BBBBBB
The area source rule contains standards for gasoline storage tanks
at bulk gasoline plants, bulk gasoline terminals, and pipeline breakout
stations. The current requirements for bulk gasoline plants require the
use of submerged filling for all gasoline storage tanks with a capacity
of greater than 250 gallons. As noted in section III.A.1.b of this
preamble, we are proposing to require vapor balancing at bulk plants,
both when filling cargo tanks and when unloading cargo tanks (i.e.,
filling storage tanks). The use of vapor balancing when unloading cargo
tanks into the storage tanks will reduce the working losses from the
storage tanks. Several state and local agencies already require the use
of vapor balancing when filling storage tanks at bulk plants with a
maximum design capacity throughput of 4,000 gallons per day or more.
Bulk plants with capacities below 4,000 gallons per day would retain
the requirement to use submerge fill.
The storage tank standards for area source bulk gasoline terminals
and pipeline breakout stations cross-reference NSPS subpart Kb
requirements or the National Emission Standards for Storage Vessels at
40 CFR part 63, subpart WW, but exclude the floating roof fitting
control requirements for both internal and external floating roofs and
secondary seal requirements for internal floating roofs with a vapor-
mounted primary seal. We assessed costs and impacts of requiring
fitting controls separately for internal and external floating roofs.
Specifically, we evaluated the control options of (1) requiring
upgrades of fitting requirements for external floating roofs consistent
with NSPS subpart Kb requirements and (2) requiring upgrades of fitting
requirements for external floating roof tanks plus requiring upgrades
of fitting and seal requirements for internal floating roofs tanks
consistent with NSPS subpart Kb requirements. Table 13 of this document
summarizes the national impacts projected for area source gasoline
distribution facilities. Again, based on our analysis, we consider
adding fitting controls for external floating roof tanks at area source
gasoline distribution facilities to be cost effective. Alternatively,
the projected cost effectiveness of installing secondary seals and
fitting controls for internal floating roof tanks is approximately
$45,000 per ton of HAP emissions reduced (incremental costs between
Option 1 and 2) and therefore, we determined these controls are not
cost effective. Accordingly, we are proposing to require fitting
controls for external

[[Page 35625]]

floating roof tanks consistent with the requirements in NSPS subpart Kb
and are not proposing to revise the secondary seal and fitting control
requirements for internal floating roof tanks. Our assessment of
control options is summarized in the memorandum ``Area Source
Technology Review for the Gasoline Distribution Bulk Terminals, Bulk
Plants, and Pipeline Facilities NESHAP'' in EPA Docket No. EPA-HQ-OAR-
2020-0371.

Table 13--Control Option Impacts for Storage Vessels at Area Source Gasoline Distribution Facilities
[Bulk terminals and pipeline breakout stations]
--------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \c\ w/o TAC \c\ w/
VOC emission TCI \b\ product product CE \d\ ($/ CE \d\ ($/ ICE \f\ ($/ ICE \f\ ($/
Control option reduction \a\ ($1,000) recovery recovery ton VOC) ton HAP) \e\ ton VOC) ton HAP) \e\
(tpy) ($1,000/yr) ($1,000/yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
(1) Upgrade EFRT fittings \g\... 3,338 9,488 882 -720 -216 -4,315 -216 -4,315
(2) Upgrade IFRT and EFRT 10,143 211,100 19,630 14,760 1,455 29,100 2,275 45,500
fittings \g\...................
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Compared to baseline emissions of 26,510 tpy.
\b\ Total capital investment (TCI).
\c\ Total annualized costs (TAC) considering annual operating costs and annualized cost of capital.
\d\ Cost effectiveness (CE) compared to baseline.
\e\ HAP content assumed to be 5% of VOC.
\f\ Incremental cost effectiveness (ICE) compared to previous option in table.
\g\ EFRT = external floating roof tank; IFRT = internal floating roof tank.

As noted for major source gasoline distribution facilities, we
identified the use of LEL monitoring within the headspace of an
internal floating roof tank as a means to enhance the annual
inspections and more readily identify malfunctioning internal floating
roofs. We estimated the cost of the LEL monitoring requirement based on
the additional time needed to monitor LEL during the annual
inspections. We estimated the impact of annual LEL monitoring based on
the number of internal floating roof tanks at area source gasoline
distribution facilities and assuming LEL monitoring identifies defects
in 2 percent of internal floating roofs resulting in a 2 percent
reduction in the baseline emissions for internal floating roof tanks.
Based on our review of available LEL monitoring data, we expect that
this is a conservative estimate of the emission reductions that would
be achieved. Table 14 of this document summarizes the projected impact
of requiring annual LEL monitoring for internal floating roof tanks as
part of the annual roof-top inspections for different types of area
source gasoline distribution facilities. Our assessment of LEL
monitoring at area sources is summarized in the memorandum ``Area
Source Technology Review for the Gasoline Distribution Bulk Terminals,
Bulk Plants, and Pipeline Facilities NESHAP'' in EPA Docket No. EPA-HQ-
OAR-2020-0371.

Table 14--Nationwide LEL Monitoring Impacts for Area Source Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \a\ w/o TAC \a\ w/
VOC emission product product CE \b\ ($/ton CE \b\ ($/ton
Facility type reduction recovery ($/ recovery ($/ VOC) HAP) \c\
(tpy) yr) yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Area Source Facilities....................................... 430 353,200 146,700 341 6,820
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Total annualized costs (TAC) considering annual operating costs; there are no annualized cost of capital for this option.
\b\ Cost effectiveness (CE).
\c\ HAP content assumed to be 5% of VOC.

Because area source gasoline distribution facilities are expected
to have smaller storage tanks on average than major source facilities,
LEL monitoring is expected to be somewhat less cost-effective for area
source facilities than major source facilities. Nonetheless, LEL
monitoring is projected to have costs of $6,800 per ton of HAP reduced
when applied to internal floating roof tanks at area source gasoline
distribution facilities. We consider these costs to be reasonable.
Therefore, we are proposing to require LEL monitoring as part of the
annual visual inspections conducted for internal floating roof tanks at
area source bulk gasoline terminals and pipeline breakout stations.
4. Standards for Equipment Leaks
All gasoline distribution rules (40 CFR part 60, subpart XX; 40 CFR
part 63, subparts R and BBBBBB) have standards for equipment leaks from
equipment components in gasoline or gasoline vapor service. The current
leak detection and repair (LDAR) program requirements rely on
identifying leaks using AVO methods. We reviewed Federal, state, and
local requirements for identifying and repairing equipment leaks.
Although the option to use optical gas imaging (OGI) for monitoring
equipment leaks has been available since 2008 in the General Provisions
to 40 CFR parts 60 and 63 as part of an alternative work practice to
EPA Method 21 monitoring, the EPA has only recently proposed the use of
OGI in leak detection surveys (40 CFR part 60, Appendix K; see 86 FR
63110, November 15, 2021). Therefore, we considered OGI monitoring as a
potential development in equipment leak monitoring. For each subpart,
we assessed LDAR programs based on AVO, EPA Method 21, and OGI. We
developed a Monte Carlo model to randomly initiate leaks from
individual equipment components present at gasoline distribution
facilities. We assumed no leaks were present initially and randomly
generated leaks at the facility on a monthly basis for a period of 5
years. We assessed the emissions that occurred in the 5th year of the
simulation to assess the relative performance of different LDAR
programs. For more information on the Monte Carlo model and modeling
assumptions used to assess alternative

[[Page 35626]]

equipment LDAR programs, see memorandum entitled ``Control Options for
Equipment Leaks at Gasoline Distribution Facilities'' available in
Docket No. EPA-HQ-OAR-2020-0371.
Based on our Monte Carlo simulations, we found that periodic
monitoring using EPA Method 21 with a leak definition of 10,000 ppmv
achieved similar emission reductions as OGI monitoring at the same
frequency. We evaluated options of (1) maintaining the monthly AVO
inspections, (2) using instrument monitoring (EPA Method 21 or OGI
following Appendix K) on an annual basis, (3) using instrument
monitoring on a semiannual basis, and (4) using instrument monitoring
on a quarterly basis. The periodic instrument requirement also includes
a requirement to fix any readily identified leaks observed using AVO
methods during the normal duties. The results of our assessment of
alternative LDAR programs by rule are detailed in the following
subsections.
Costs for EPA Method 21 monitoring and OGI monitoring were
developed based on information collected from equipment leak monitoring
contractors. OGI monitoring contractors commonly include a daily
instrument rental charge, but they can monitor many more components per
day than EPA Method 21 monitoring contractors. For facilities with a
large number of equipment components to be monitored, OGI monitoring
costs less than EPA Method 21 monitoring (the savings in time to
conduct OGI monitoring more than makes up for the equipment rental
charge). However, for facilities with a small number of equipment
components to be monitored, EPA Method 21 monitoring costs less than
OGI monitoring because the time saving to conduct OGI monitoring is not
significant enough to cover the added equipment rental charge. When
evaluating ``instrument monitoring'' costs for different types of
gasoline distribution facilities, we assumed facilities would elect to
use the lowest cost instrument monitoring option between EPA Method 21
and OGI. For more information on the cost assumptions used to assess
alternative equipment LDAR programs, see memorandum ``Control Options
for Equipment Leaks at Gasoline Distribution Facilities'' available in
Docket No. EPA-HQ-OAR-2020-0371.
a. NESHAP Subpart R
The major source rule contains equipment leak standards for bulk
gasoline terminals and pipeline breakout stations. Prior to the initial
performance test, the major source rule requires equipment leak
monitoring to be conducted using EPA Method 21 using a leak definition
of 500 parts per million (ppm). The major source rule also requires
subsequent monitoring monthly and allows the use of any leak
identification method, including AVO techniques. We evaluated the
current monthly AVO inspection requirements with LDAR programs based on
periodic instrument monitoring.
Table 15 of this document summarizes the projected impacts of
requiring periodic instrument monitoring combined with a general
requirement to fix any leaks identified (via AVO methods) during normal
duties. For the major source gasoline distribution facilities (bulk
gasoline terminals and pipeline breakout stations), OGI is the least
costly of the instrument monitoring alternatives. Annual OGI instrument
monitoring was projected to result in cost savings compared to monthly
AVO inspections and semi-annual instrument monitoring was projected to
be about the same cost as monthly AVO inspections. Even with
uncertainty in the relative performance of monthly AVO monitoring, we
conclude that periodic instrument monitoring along with a general
requirement to fix any readily identified leaks during the normal
course of activities yields similar to better reductions at a net cost
savings. Our assessment of control options is summarized in the
memorandum ``Major Source Technology Review for Gasoline Distribution
Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations)
NESHAP'' in EPA Docket No. EPA-HQ-OAR-2020-0371.

Table 15--Estimated Emissions and Cost Impacts of Equipment Leak Control Options for Major Source Gasoline Distribution Facilities
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \b\ w/o TAC \b\ w/
VOC emissions VOC emission TCI \a\ product product CE \c\ ($/ CE \c\ ($/ ICE \e\ ($/ ICE \e\ ($/
Option (tpy) reduction ($1000) recovery recovery ton VOC) ton HAP) \d\ ton VOC) ton HAP) \d\
(tpy) ($1000/yr) ($1000/yr)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
AVO (monthly inspection)....................................... 1,124
Annual instrument \f\.......................................... 664 461 217.5 -380 -602 -1,310 -13,100 -1,310 -13,100
Semiannual instrument \f\...................................... 439 686 217.5 -47.8 -377 -550 -5,550 999 9,990
Quarterly instrument \f\....................................... 309 816 217.5 557 166 203 2,030 4,170 41,700
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Total capital investment (TCI).
\b\ Total annualized costs (TAC) considering annual operating costs and annualized cost of capital.
\c\ Cost effectiveness (CE) compared to baseline (AVO).
\d\ HAP content assumed to be 10% of VOC.
\e\ Incremental cost effectiveness (ICE) compared to previous option in table.
\f\ Facilities would be allowed to select EPA Method 21 or OGI monitoring. If EPA Method 21 is selected, valves and pumps would be required to be monitored at the frequency specified, however,
connectors are only monitored annually. If OGI is selected, all applicable valves, pumps, and connectors would be required to be monitored at the frequency specified.

The semiannual instrument monitoring is projected to yield a net
cost savings compared to monthly AVO inspections. The incremental cost-
effectiveness from going from annual to semiannual instrument
monitoring is just under $10,000 per ton of HAP emissions reduced.
Taken together, we determined that semiannual instrument monitoring is
cost effective. The incremental cost-effectiveness of going to
quarterly instrument monitoring is over $40,000 per ton of HAP
emissions reduced; therefore, we determined this option is not cost-
effective. Considering the developments in equipment leak monitoring
practices, we are proposing to require semiannual instrument monitoring
for major source gasoline distribution facilities.
b. NESHAP Subpart BBBBBB
The area source rule contains equipment leak standards for bulk
gasoline terminals, pipeline breakout stations, bulk gasoline plants,
and pipeline pumping stations. Prior to the initial performance test,
the area source

[[Page 35627]]

rule requires equipment leak monitoring to be conducted using EPA
Method 21 using a leak definition of 500 ppm. The area source rule
requires subsequent monitoring monthly and allows the use of any leak
identification method, including AVO techniques. We evaluated the
current monthly AVO inspection requirements with LDAR programs based on
periodic instrument monitoring.
Table 16 of this document shows the estimated impacts of applying
instrument monitoring for equipment leaks at area source gasoline
distribution facilities. For the smaller area source facilities, EPA
Method 21 was generally less costly than OGI as an instrument
monitoring method. For the larger area sources, we expect facilities to
use OGI. The annual instrument monitoring requirement combined with a
general requirement to fix any leaks identified (via AVO methods)
during the normal course of activities is projected to be less costly
than monthly AVO and yield additional emission reductions. Thus, we
determined that annual instrument monitoring is cost effective. The
relative cost of moving from annual monitoring to semi-annual
monitoring is approximately $18,000 per ton of HAP removed which we
determined is not cost-effective. Therefore, semi-annual instrument
monitoring was rejected because of the high incremental cost-
effectiveness compared to annual instrument monitoring and we are
proposing to require annual instrument monitoring combined with a
requirement to repair any leaks identified (i.e., observed using AVO
methods) during the course of regular business activities. Again, EPA
is seeking comment on adopting more protective standards at costs above
levels that we generally consider to be cost effective for these type
of HAP given that many of these sources are located in highly populated
areas where the communities surrounding these facilities already have
the potential to be overburdened from multiple sources of air
pollution. Our assessment of control options is summarized in the
memorandum ``Area Source Technology Review for the Gasoline
Distribution Bulk Terminals, Bulk Plants, and Pipeline Facilities
NESHAP'' in EPA Docket No. EPA-HQ-OAR-2020-0371.

Table 16--Estimated Emissions and Cost Impacts of Equipment Leak Control Options for Area Source Gasoline Distribution Facilities
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \b\ w/o TAC \b\ w/
VOC emissions VOC emission TCI \a\ product product CE \c\ ($/ CE \c\ ($/ ICE \e\ ($/ ICE \e\ ($/
Option (tpy) reduction ($1000) recovery recovery ton VOC) ton HAP) \d\ ton VOC) ton HAP) \d\
(tpy) ($1000/yr) ($1000/yr)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
AVO............................................................ 17,080
Annual instrument \f\.......................................... 9,800 7,280 5,750 -4,180 -7,670 -1,050 -10,500 -1,050 -10,500
Semiannual instrument \f\...................................... 6,950 10,100 5,750 2,290 -2,570 -254 -2,540 1,790 17,900
Quarterly instrument \f\....................................... 5,320 11,800 5,750 14,600 8,980 764 7,640 7,100 71,000
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Total capital investment (TCI).
\b\ Total annualized costs (TAC) considering annual operating costs and annualized cost of capital.
\c\ Cost effectiveness (CE) compared to baseline (AVO).
\d\ HAP content assumed to be 10% of VOC.
\e\ Incremental cost effectiveness (ICE) compared to previous option in table.
\f\ Facilities would be allowed to select EPA Method 21 or OGI monitoring. If EPA Method 21 is selected, valves and pumps would be required to be monitored at the frequency specified, however,
connectors are only monitored annually. If OGI is selected, all applicable valves, pumps, and connectors would be required to be monitored at the frequency specified.

c. NSPS Subpart XXa
The NSPS subpart XX contains equipment leak standards for bulk
gasoline terminals. Prior to the initial performance test, the NSPS
requires monitoring to be conducted of the vapor collection system
using EPA Method 21 using a leak definition of 10,000 ppm. The NSPS
also requires subsequent monitoring of the loading racks, vapor
collection system and vapor processing system monthly using any leak
identification method, including AVO techniques.
Regarding monitoring requirements prior to performance tests, we
determined that these requirements are effective requirements for the
closed vent system used to transfer vapors from the loading racks to
the control system. Generally, the EPA requires these closed vent
systems to operate with no detectable emissions (which is defined as
less than 500 ppmv above background using EPA Method 21). Both major
and area source NESHAP subparts R and BBBBBB require the monitoring of
the vapor collection system prior to a performance test using this no
detectable emissions threshold (500 ppmv using EPA Method 21).
Consistent with current practices for closed vent systems, we are
proposing in subpart XXa to require that monitoring of the vapor
collection system prior to a performance test be conducted using EPA
Method 21 and that the vapor collection system be operated with no
detectable emissions (no leaks greater than 500 ppmv).
For the ongoing leak monitoring requirements, we evaluated the
current monthly AVO inspection requirements compared to LDAR programs
based on periodic instrument monitoring along with a general
requirement to fix any leaks identified (via AVO methods) during the
normal course of activities. Table 17 of this document provides
estimated costs for newly affected bulk gasoline terminals. When
considering VOC emission impacts, the overall cost effectiveness of the
quarterly monitoring option is $259 per ton VOC reduced and the
incremental cost effectiveness of quarterly monitoring compared to
semi-annual monitoring is $4,020 per ton of VOC reduced. Taken
together, we determined that quarterly instrument monitoring is cost
effective for reducing VOC emissions. Therefore, we are proposing to
require quarterly monitoring for bulk gasoline terminals in NSPS
subpart XXa along with a general requirement to fix any leaks
identified (via AVO methods) during normal duties. Our assessment of
control options is summarized in the memorandum ``New Source
Performance Standards Review for Bulk Gasoline Terminals'' in EPA
Docket No. EPA-HQ-OAR-2020-0371.

[[Page 35628]]

Table 17--Estimated Emissions and Cost Impacts of Equipment Leak Control Options per Newly Affected Bulk Gasoline Terminal
--------------------------------------------------------------------------------------------------------------------------------------------------------
TAC \b\ w/o TAC \b\ w/
VOC emissions VOC emission product product CE \c\ ($/ton ICE \d\ ($/
Option (tpy) reduction TCI \a\ ($) recovery ($/ recovery ($/ VOC) ton VOC)
(tpy) yr) yr)
--------------------------------------------------------------------------------------------------------------------------------------------------------
AVO (monthly inspection)................ 4.47
Annual instrument \e\................... 2.64 1.83 1,000 -1,240 -2,120 -1,160 -1,160
Semiannual instrument \e\............... 1.74 2.73 1,000 60 -1,250 -458 962
Quarterly instrument \e\................ 1.22 3.25 1,000 2,405 843 259 4,020
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ Total capital investment (TCI).
\b\ Total annualized costs (TAC) considering annual operating costs and annualized cost of capital.
\c\ Cost effectiveness (CE) compared to baseline (AVO).
\d\ Incremental cost effectiveness (ICE) compared to previous option in table.
\e\ Facilities would be allowed to select EPA Method 21 or OGI monitoring. If EPA Method 21 is selected, valves and pumps would be required to be
monitored at the frequency specified, however, connectors are only monitored annually. If OGI is selected, all applicable valves, pumps, and
connectors would be required to be monitored at the frequency specified.

B. What other actions are we proposing, and what is the rationale for
those actions?

In addition to the proposed actions described above, we are
proposing to remove exemptions from the requirement to comply during
periods of startup, shutdown, and malfunction (SSM). We also are
proposing changes to the recordkeeping and reporting requirements to
require the use of electronic reporting of performance test reports and
semiannual reports. We also are proposing to correct section reference
errors and make other minor editorial revisions. Our rationale and
proposed changes related to these issues are discussed below.
1. SSM
In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (DC Cir.
2008), the United States Court of Appeals for the District of Columbia
Circuit (the court) vacated portions of two provisions in the EPA's CAA
section 112 regulations governing the emissions of HAP during periods
of SSM. Specifically, the court vacated the SSM exemption contained in
40 CFR 63.6(f)(1) and (h)(1), holding that under section 302(k) of the
CAA, emissions standards or limitations must be continuous in nature
and that the SSM exemption violates the CAA's requirement that some
section 112 standards apply continuously. With the issuance of the
mandate in Sierra Club v EPA, the exemption language in 63.6(f)(1) and
(h)(1) are null and void and any cross reference to those provisions
have no effect.
In March 2021, the EPA issued a rule \8\ to reflect the court
vacatur that revised the 40 CFR part 63 General Provisions to remove
the SSM exemptions at 40 CFR 63.6(f)(1) and (h)(1). In this action, we
are proposing to eliminate references to these SSM exemptions that are
null and void, remove any additional SSM exemptions or references to
SSM exemptions, and remove any cross-references to provisions in 40 CFR
part 63 (General Provisions) that are unnecessary, inappropriate or
redundant in the absence of the SSM exemption. The EPA determined the
reasoning in the court's decision in Sierra Club applies equally to CAA
section 111. Consistent with Sierra Club v. EPA, the standards that we
are proposing in NSPS subpart XXa would apply at all times.
---------------------------------------------------------------------------

\8\ U.S. EPA, Court Vacatur of Exemption From Emission Standards
During Periods of Startup, Shutdown, and Malfunction. (86 FR 13819,
March 11, 2021).
---------------------------------------------------------------------------

a. Proposed Elimination of the SSM Exemption in NESHAP Subpart R
We are proposing the elimination of the vacated exemption provision
and several revisions to Table 1 of this document, (the General
Provisions Applicability Table to subpart R of part 63, hereafter
referred to as the ``General Provisions table to subpart R'') as is
explained in more detail below. For example, we are proposing to
eliminate the incorporation of the General Provisions' requirement that
the source develop an SSM plan. We also are proposing to eliminate and
revise certain recordkeeping and reporting requirements related to the
SSM exemption. The EPA has attempted to ensure that the provisions we
are proposing to eliminate are inappropriate, unnecessary, or redundant
in the absence of the SSM exemption.
The EPA considers that processes at Gasoline Distribution
facilities are not continuous and that there will be variation in
emission stream characteristics over time. The standards consider this
variation and provide sources the ability to meet the standards at all
times. Therefore, we have not proposed alternate standards for startup
and shutdown.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. Malfunctions,
in contrast, are neither predictable nor routine. Instead, they are, by
definition, sudden, infrequent, and not reasonably preventable failures
of emissions control, process, or monitoring equipment. (40 CFR 60.2
and 63.2) (definition of malfunction). The EPA interprets CAA section
112 as not requiring emissions that occur during periods of malfunction
to be factored into development of CAA section 112 standards and this
reading has been upheld as reasonable by the D.C. Circuit in U.S. Sugar
Corp. v. EPA, 830 F.3d 579, 606-610 (2016). Therefore, the standards
that apply during normal operation apply during periods of malfunction.
We are also proposing the following revisions to the General
Provisions table to subpart R as detailed below.
1. General Duty
We are proposing to revise the General Provisions table to subpart
R entry for 40 CFR 63.6(e) by changing the ``yes'' in column 2 to
``no.'' Section 63.6(e) describes the general duty to minimize
emissions and requirements for an SSM plan. Some of the language in
that section is no longer necessary or appropriate in light of the
elimination of the SSM exemption. We are proposing instead to add
general duty regulatory text at 40 CFR 63.420(k) that reflects the
general duty to minimize emissions while eliminating the reference to
periods covered by an SSM exemption. The current language in 40 CFR
63.6(e)(1)(i) characterizes what the

[[Page 35629]]

general duty entails during periods of SSM. With the elimination of the
SSM exemption, there is no need to differentiate between normal
operations, startup and shutdown, and malfunction events in describing
the general duty. Section 63.6(e)(1)(ii) imposes requirements that are
not necessary with the elimination of the SSM exemption or are
redundant with the general duty requirement being added at 40 CFR
63.420(k). Therefore, in addition to changing the applicability of
63.6(e) from ``yes'' to ``no'' in the table, the language the EPA is
proposing for 40 CFR 63.420(k) does not include the language from 40
CFR 63.6(e)
2. SSM Plan
As noted in the previous paragraph, the proposed revisions to the
General Provisions table to subpart R for 40 CFR 63.6(e) will also
remove provisions to that require an SSM plan. Generally, the
paragraphs under 40 CFR 63.6(e)(3) require development of an SSM plan
and specify SSM recordkeeping and reporting requirements related to the
SSM plan. As noted, the EPA is proposing to remove the SSM exemptions.
Therefore, affected units are subject to an emission standard during
such events. The applicability of a standard during such events will
ensure that sources have ample incentive to plan for and achieve
compliance and thus the SSM plan requirements are no longer necessary.
3. Compliance With Standards
We are proposing to revise the General Provisions table to subpart
R entry for 40 CFR 63.6(f)(1) from ``yes'' in column 2 to ``no.'' As
noted above, with the issuance of the mandate in Sierra Club v EPA, the
exemption language in 63.6(f)(1) and (h)(1) are null and void and any
cross reference to those provisions have no effect. The EPA amended 40
CFR 63.6(f)(1) and (h)(1) on March 11, 2021, to reflect the court order
and revise the CFR to remove the SSM exemption. However, the second
sentence of 40 CFR 63.6(f)(1) contains language that is premised on the
existence of an exemption and is inappropriate in the absence of the
exemption. Thus, rather than cross-referencing 63.6(f)(1), we are
adding the language of 63.6(f)(1) that requires compliance with
standards at all times to the regulatory text at 40 CFR 63.420(k). The
court in Sierra Club vacated the exemptions contained in this provision
and held that the CAA requires that some CAA section 112 standards
apply continuously.
As noted in the General Provisions table to subpart R entry for 40
CFR 63.6(h), there are no opacity standards in NESHAP subpart R, so the
General Provisions at 40 CFR 63.6(h) were marked as ``no'' in column 2.
There are visible emissions observations for flares, so we are
proposing to revise the comment in column 3 to note that NESHAP subpart
R specifies the requirements for visible emissions observations for
flares.
4. Performance Testing
We are proposing to revise the General Provisions table to subpart
R of Part 63 entry for 40 CFR 63.7(e)(1) by changing the ``yes'' in
column 2 to a ``no.'' Section 63.7(e)(1) describes performance testing
requirements. The EPA is instead proposing to add a performance testing
requirement at 40 CFR 63.425(a). The performance testing requirements
we are proposing to add differ from the General Provisions performance
testing provisions in several respects. The regulatory text does not
include the language in 40 CFR 63.7(e)(1) that restated the SSM
exemption and language that precluded startup and shutdown periods from
being considered ``representative'' for purposes of performance
testing. The proposed performance testing provisions specifically note
the batch operation of gasoline loading operations and include periods
when cargo tanks are being changed out when a full cargo tank is
disconnected, and a new cargo tank is moved into position for loading.
As in 40 CFR 63.7(e)(1), performance tests conducted under this subpart
should not be conducted during malfunctions because conditions during
malfunctions are often not representative of normal operating
conditions. The EPA is proposing to add language that requires the
owner or operator to record the process information that is necessary
to document operating conditions during the test and include in such
record an explanation to support that such conditions represent normal
operation. Section 63.7(e)(1) requires that the owner or operator make
such records ``as may be necessary to determine the condition of the
performance test'' available to the Administrator upon request but does
not specifically require the information to be recorded. The regulatory
text the EPA is proposing to add to this provision builds on that
requirement and makes explicit the requirement to record the
information.
5. Monitoring
We are proposing to revise the General Provisions table to subpart
R of Part 63 by adding separate entries for 40 CFR 63.8(c)(1)(i) and
(iii) and including a ``no'' in column 2. The cross-references to the
general duty and SSM plan requirements in those subparagraphs are not
necessary in light of other requirements of 40 CFR 63.8 that require
good air pollution control practices (40 CFR 63.8(c)(1)) and that set
out the requirements of a quality control program for monitoring
equipment (40 CFR 63.8(d)).
We are proposing to revise the major source General Provisions
table to subpart R of Part 63 by splitting the entry for 40 CFR 63.8(d)
into two separate entries, one for 40 CFR 63.8(d)(1) and (2) and
retaining the ``yes'' in column 2 and one for 40 CFR 63.8(d)(3) and
including a ``no'' in column 2. The final sentence in 40 CFR 63.8(d)(3)
refers to the General Provisions' SSM plan requirement which is no
longer applicable. The EPA is proposing to add provisions to subpart R
at 40 CFR 63.428(d)(4) that is identical to 40 CFR 63.8(d)(3) except
that the final sentence is replaced with the following sentence: ``The
program of corrective action should be included in the plan as required
under Sec. 63.8(d)(2).''
6. Recordkeeping
We are proposing to revise the General Provisions table to subpart
R of Part 63 by adding a separate entry for 40 CFR 63.10(b)(2)(i),
(ii), (iv) and (v) and including a ``no'' in column 2.
<bullet> Section 63.10(b)(2)(i) describes the recordkeeping
requirements for startup and shutdown periods when the source exceeds
any applicable emission limitation in a relevant standard and section
63.10(b)(2)(ii) describes the recordkeeping requirements for
malfunctions. We are instead proposing to add recordkeeping and
reporting requirements of for all exceedances.
The EPA is proposing to add such requirements to 40 CFR 63.428(g).
The regulatory text we are proposing to add differs from the General
Provisions it is replacing in that the General Provisions requires the
creation and retention of a record of the occurrence and duration of
each malfunction of process, air pollution control, and monitoring
equipment. The EPA is proposing that this requirement apply to any
failure to meet an applicable standard and is requiring that the source
record the date, time, and duration of the failure rather than the
``occurrence.'' The EPA is also proposing to add requirements to 40 CFR
63.428(g) that sources keep records that include a list of the affected
source or equipment and actions taken to minimize emissions, an
estimate of the quantity of each regulated pollutant emitted over the
standard for which the source failed to meet the standard, and

[[Page 35630]]

a description of the method used to estimate the emissions. Examples of
such methods would include product-loss calculations, mass balance
calculations, measurements when available, or engineering judgment
based on known process parameters. The EPA is proposing to require that
sources keep records of this information to ensure that there is
adequate information to allow the EPA to determine the severity of any
failure to meet a standard, and to provide data that may document how
the source met the general duty to minimize emissions when the source
has failed to meet an applicable standard.
<bullet> We are proposing to revise the General Provisions table to
subpart R of Part 63 entry for 40 CFR 63.10(b)(2)(iv) by changing the
``yes'' in column 2 to a ``no.'' Section 63.10(b)(2)(iv), when
applicable, requires sources to record actions taken during SSM events
when actions were inconsistent with their SSM plan. The requirement is
no longer appropriate because SSM plans will no longer be required. The
requirement previously applicable under 40 CFR 63.10(b)(2)(iv)(B) to
record actions to minimize emissions and record corrective actions is
now applicable by the proposed requirements in 40 CFR 63.428(g).
<bullet> We are proposing to revise the General Provisions table to
subpart R of Part 63 entry for 40 CFR 63.10(b)(2)(v) by changing the
``yes'' in column 2 to a ``no.'' Section 63.10(b)(2)(v), when
applicable, requires sources to record actions taken during SSM events
to show that actions taken were consistent with their SSM plan. The
requirement is no longer appropriate because SSM plans will no longer
be required.
<bullet> We are proposing to revise the General Provisions table to
subpart R of Part 63 by adding a separate entry for 40 CFR 63.10(c)(15)
and including a ``no'' in column 2. The EPA is proposing that 40 CFR
63.10(c)(15) no longer apply. When applicable, the provision allows an
owner or operator to use the affected source's SSM plan or records kept
to satisfy the recordkeeping requirements of the SSM plan, specified in
40 CFR 63.6(e), to also satisfy the requirements of 40 CFR 63.10(c)(10)
through (12). The EPA is proposing to eliminate this requirement
because SSM plans would no longer be required, and, therefore, 40 CFR
63.10(c)(15) no longer serves any useful purpose for affected units.
7. Reporting
We are proposing to revise the General Provisions table to subpart
R of Part 63 entry for 40 CFR 63.10(d)(5) by changing the ``yes'' in
column 2 to a ``no.'' Section 63.10(d)(5) describes the reporting
requirements for SSM. To replace the General Provisions reporting
requirement, the EPA is proposing to add reporting requirements to 40
CFR 63.428(m). The replacement language differs from the General
Provisions requirement in that it eliminates periodic SSM reports as a
stand-alone report. We are proposing language that requires sources
that fail to meet an applicable standard at any time to report the
information concerning such events in the semiannual report already
required under this rule. We are proposing that the report must contain
the number, date, time, duration, and the cause of such events
(including unknown cause, if applicable), a list of the affected source
or equipment, an estimate of the quantity of each regulated pollutant
emitted over any emission limit, and a description of the method used
to estimate the emissions.
Examples of such methods would include product-loss calculations,
mass balance calculations, measurements when available, or engineering
judgment based on known process parameters. The EPA is proposing this
requirement to ensure that there is adequate information to determine
compliance, to allow the EPA to determine the severity of the failure
to meet an applicable standard, and to provide data that may document
how the source met the general duty to minimize emissions during a
failure to meet an applicable standard.
We will no longer require owners or operators to determine whether
actions taken to correct a malfunction are consistent with an SSM plan,
because plans would no longer be required. The proposed amendments at
63.10(d)(5), therefore, eliminate the cross-reference to 40 CFR
63.10(d)(5)(i) that contains the description of the previously required
SSM report format and submittal schedule from this section. These
specifications are no longer necessary because the events will be
reported in otherwise required reports with similar format and
submittal requirements.
The proposed amendments at 63.10(d)(5) will also eliminate the
cross-reference to 40 CFR 63.10(d)(5)(ii). Section 63.10(d)(5)(ii)
describes an immediate report for startups, shutdown, and malfunctions
when a source failed to meet an applicable standard but did not follow
the SSM plan. We will no longer require owners or operators to report
when actions taken during a startup, shutdown, or malfunction were not
consistent with an SSM plan, because plans would no longer be required.
b. Proposed Revisions To Address SSM Provisions in NESHAP Subpart
BBBBBB
We are proposing to remove references to malfunction throughout
NESHAP subpart BBBBBB. Specifically, we are removing the requirements
at 40 CFR 63.11092(b)(1)(i)(B)(2)(iv), 63.11092(b)(1)(iii)(B)(2)(iv),
63.11092(d)(4), 63.11095(b)(4), and 63.11095(d) and revising the
requirements at 40 CFR 63.11092(b)(1)(i)(B)(2)(v),
63.11092(b)(1)(iii)(B)(2)(v), 63.11092(d), 63.11092(d)(3),
63.11094(f)(4), and 63.11094(g). We are also proposing limited
revisions to Table 4 of this document (as proposed, formerly Table 3),
the General Provisions Applicability Table to subpart BBBBBB of part
63, hereafter referred to as the ``General Provisions table to subpart
BBBBBB'' to address selected SSM provisions. NESHAP subpart BBBBBB was
amended on January 24, 2011 (76 FR 4156) to address SSM provisions. We
are proposing one additional SSM revision. Specifically, we are
proposing to revise the area source General Provisions table to subpart
BBBBBB by splitting the entry for 40 CFR 63.8(d) into two separate
entries, one for 40 CFR 63.8(d)(1)-(2) and retaining the ``yes'' in
column 2 and one for 40 CFR 63.8(d)(3) and including a ``no'' in column
2. The final sentence in 40 CFR 63.8(d)(3) refers to the General
Provisions' SSM plan requirement which is no longer applicable. The EPA
is proposing to add provisions to subpart BBBBBB at 40 CFR 63.11094(h)
that is identical to 40 CFR 63.8(d)(3) except that the final sentence
is replaced with the following sentence: ``The program of corrective
action should be included in the plan as required under Sec.
63.8(d)(2).''
c. Proposal of NSPS Subpart XXa Without SSM Exemptions
We are proposing standards in the NSPS subpart XXa that apply at
all times. We are proposing that emission limits will apply at all
times, including during SSM. The NSPS general provisions in 40 CFR
60.8(c) contains an exemption from non-opacity standards. We are
proposing in NSPS subpart XXa specific requirements at 40 CFR
60.500a(c) that override the general provisions for SSM. We are
proposing that all standards in NSPS subpart XXa apply at all times.
In proposing the standards in this rule, the EPA has taken into
account startup and shutdown periods and, for the reasons explained
below, has not proposed alternate standards for those periods. Startups
and shutdowns are part of normal operations at Bulk

[[Page 35631]]

Gasoline Terminals. The proposed emission standards adequately control
emissions during these startup and shutdown periods.
Periods of startup, normal operations, and shutdown are all
predictable and routine aspects of a source's operations. Malfunctions,
in contrast, are neither predictable nor routine. Instead they are, by
definition, sudden, infrequent, and not reasonably preventable failures
of emissions control, process, or monitoring equipment. (40 CFR 60.2).
The EPA interprets CAA section 111 as not requiring emissions that
occur during periods of malfunction to be factored into development of
CAA section 111 standards. Nothing in CAA section 111 or in case law
requires that the EPA consider malfunctions when determining what
standards of performance reflect the degree of emission limitation
achievable through ``the application of the best system of emission
reduction'' that the EPA determines is adequately demonstrated. While
the EPA accounts for variability in setting emissions standards, the
EPA is not required to treat a malfunction in the same manner as the
type of variation in performance that occurs during routine operations
of a source. A malfunction is a failure of the source to perform in a
``normal or usual manner'' and no statutory language compels EPA to
consider such events in setting section 111 standards of performance.
The EPA's approach to malfunctions in the analogous circumstances
(setting ``achievable'' standards under section 112) has been upheld as
reasonable by the D.C. Circuit in U.S. Sugar Corp. v. EPA, 830 F.3d
579, 606-610 (D.C. Cir. 2016).
2. Electronic Reporting
The EPA is proposing that owners and operators of gasoline
distribution facilities submit electronic copies of required
performance test reports, performance evaluation reports, and semi-
annual reports through the EPA's Central Data Exchange (CDX) using the
Compliance and Emissions Data Reporting Interface (CEDRI). A
description of the electronic data submission process is provided in
the memorandum Electronic Reporting Requirements for New Source
Performance Standards (NSPS) and National Emission Standards for
Hazardous Air Pollutants (NESHAP) Rules, available in the docket for
this action.
The proposed rules require that performance test results collected
using test methods that are supported by the EPA's Electronic Reporting
Tool (ERT) as listed on the ERT website \9\ at the time of the test be
submitted in the format generated through the use of the ERT or an
electronic file consistent with the xml schema on the ERT website, and
other performance test results be submitted in portable document format
(PDF) using the attachment module of the ERT. Similarly, performance
evaluation results of CEMS measuring relative accuracy test audit
pollutants that are supported by the ERT at the time of the test must
be submitted in the format generated through the use of the ERT or an
electronic file consistent with the xml schema on the ERT website, and
other performance evaluation results be submitted in PDF using the
attachment module of the ERT.
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\9\ <a href="https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert">https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert</a>.
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For semi-annual reports, the proposed rules require that owner and
operators use the appropriate spreadsheet template to submit
information to CEDRI. A draft version of the proposed templates for
these reports are included in the docket for this action.\10\ The EPA
specifically requests comment on the content, layout, and overall
design of the templates.
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\10\ See Gasoline Distribution Semiannual Reporting Template,
available at Docket ID. No. EPA-HQ-OAR-2020-0371.
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Additionally, the EPA has identified two broad circumstances in
which electronic reporting extensions may be provided. These
circumstances are (1) outages of the EPA's CDX or CEDRI which preclude
an owner or operator from accessing the system and submitting required
reports and (2) force majeure events, which are defined as events that
will be or have been caused by circumstances beyond the control of the
affected facility, its contractors, or any entity controlled by the
affected facility that prevent an owner or operator from complying with
the requirement to submit a report electronically. Examples of force
majeure events are acts of nature, acts of war or terrorism, or
equipment failure or safety hazards beyond the control of the facility.
The EPA is providing these potential extensions in NSPS subpart XXa to
protect owners and operators from noncompliance in cases where they
cannot successfully submit a report by the reporting deadline for
reasons outside of their control. In both circumstances, the decision
to accept the claim of needing additional time to report is within the
discretion of the Administrator, and reporting should occur as soon as
possible. These potential extensions are not necessary to add to NESHAP
subpart R and NESHAP subpart BBBBBB, because they were recently added
to the part 63, subpart A, General Provisions at 40 CFR 63.9(k).
The electronic submittal of the reports addressed in these proposed
rulemakings will increase the usefulness of the data contained in those
reports, is in keeping with current trends in data availability and
transparency, will further assist in the protection of public health
and the environment, will improve compliance by facilitating the
ability of regulated facilities to demonstrate compliance with
requirements and by facilitating the ability of delegated state, local,
tribal, and territorial air agencies and the EPA to assess and
determine compliance, and will ultimately reduce burden on regulated
facilities, delegated air agencies, and the EPA. Electronic reporting
also eliminates paper-based, manual processes, thereby saving time and
resources, simplifying data entry, eliminating redundancies, minimizing
data reporting errors, and providing data quickly and accurately to the
affected facilities, air agencies, the EPA, and the public. Moreover,
electronic reporting is consistent with the EPA's plan \11\ to
implement Executive Order 13563 and is in keeping with the EPA's
Agency-wide policy \12\ developed in response to the White House's
Digital Government Strategy.\13\ For more information on the benefits
of electronic reporting, see the memorandum Electronic Reporting
Requirements for New Source Performance Standards (NSPS) and National
Emission Standards for Hazardous Air Pollutants (NESHAP) Rules,
referenced earlier in this section.
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\11\ EPA's Final Plan for Periodic Retrospective Reviews, August
2011. Available at: <a href="https://www.regulations.gov/document?D=EPA-HQ-OA-2011-0156-0154">https://www.regulations.gov/document?D=EPA-HQ-OA-2011-0156-0154</a>.
\12\ E-Reporting Policy Statement for EPA Regulations, September
2013. Available at: <a href="https://www.epa.gov/sites/production/files/2016-03/documents/epa-ereporting-policy-statement-2013-09-30.pdf">https://www.epa.gov/sites/production/files/2016-03/documents/epa-ereporting-policy-statement-2013-09-30.pdf</a>.
\13\ Digital Government: Building a 21st Century Platform to
Better Serve the American People, May 2012. Available at: <a href="https://obamawhitehouse.archives.gov/sites/default/files/omb/egov/digital-government/digital-government.html">https://obamawhitehouse.archives.gov/sites/default/files/omb/egov/digital-government/digital-government.html</a>.
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3. Technical and Editorial Changes
We are proposing several technical amendments and definition
revisions to improve the clarity and enforceability of the provision of
the gasoline distribution facility standards. These additional proposed
revisions and our rationale for the proposed revisions are described in
this section.

[[Page 35632]]

a. Applicability Equations in NESHAP Subpart R
The current major source rule includes applicability equations that
can be used to exempt facilities from the major source requirements.
The equations exclude all bulk gasoline terminals or pipeline breakout
stations with an emissions screening factor (E<INF>t</INF> or
E<INF>p</INF>, respectively) of less than one. Upon reviewing the
applicability equations, we determined the equations can potentially
exempt facilities that are major sources of HAP emissions.
Specifically, it is possible for gasoline storage tanks to be larger
and have higher emissions than the model tanks used to derive the
applicability equation. Additionally, the terms used in the different
equations, particularly the fixed roof tank term, are different. A
combination of tanks that exceeds 1 (indicating major source facility)
using the equation in paragraph 40 CFR 63.420(b) for pipeline breakout
stations can be below 1 (suggesting an area source facility) using the
equation in paragraph 40 CFR 63.420(a) for bulk gasoline terminals.
Thus, it appears some true major source facilities may only need to
comply with major equipment counts associated with these applicability
equations and not have ongoing requirements to ensure, for example,
their floating roof seals are intact. Additionally, facilities that
used these equations to become exempt from the major source rule are
not covered by the area source rule if they are truly major sources of
HAP emissions. In meeting with industry representatives, none of the
industry representatives indicated that they used these equations to
determine applicability with the rule. Therefore, we are proposing to
remove the applicability equations in the major source rule to ensure
that all major sources are subject to the emission limitations in
NESHAP subpart R.
b. Definitions of Bulk Gasoline Terminal, Pipeline Breakout Station,
and Pipeline Pumping Station
The major source rule applies to bulk gasoline terminals and to
pipeline breakout stations. These terms are defined, but there appears
to be significant potential overlap in these definitions. Based on the
applicability equations and the fact that the loading rack requirements
apply only to bulk gasoline terminals, the key difference between a
bulk gasoline terminal and a pipeline breakout station is the presence
(or absence) of gasoline loading racks. Application of subpart R
requirements to ``pipeline breakout station'' facilities that have
loading racks is inconsistent. We identified a title V permit that
considers these separate affected facilities, with one portion of the
facility regulated as a pipeline breakout station and the loading racks
(and perhaps associated tanks and equipment) regulated as a bulk
gasoline terminal. We also identified a title V permit where the
loading racks at a pipeline breakout station were listed as having no
applicable Federal requirements. To ensure consistent application of
the rule and to clarify that all loading racks at major source
facilities are to comply with the loading rack requirements in 40 CFR
63.422, we are proposing to clarify the definitions of ``bulk gasoline
terminal'' to clearly delineate that these facilities load gasoline
into cargo tanks (i.e., have gasoline loading racks). Similarly, we are
proposing to clarify the definitions of ``pipeline breakout stations''
to clearly delineate that these facilities do not have gasoline loading
racks and that if a facility loads gasoline into cargo tanks, that
facility is a bulk gasoline terminal. Since the requirements for
storage vessels and equipment leak are the same for these facility
types, the only difference the proposed revisions make is to clarify
that loading racks at facilities that primarily transport gasoline via
pipeline are still required to be meet the emission limitations for
gasoline loading racks.
We are also proposing similar definitions for area source standards
(NESHAP subpart BBBBBB) and for NSPS subpart XXa. At 40 CFR 63.11088 of
the area source NESHAP, the header includes bulk gasoline terminals,
pipeline breakout stations and pipeline pumping stations. However,
Table 2 to subpart BBBBBB only specifies loading rack control
requirements for ``bulk gasoline terminal loading rack(s).'' The
proposed revisions to bulk gasoline terminals, pipeline breakout
stations and pipeline pumping stations clarify that pipeline breakout
stations and pipeline pumping stations do not contain loading racks. We
are also proposing to revise the header of 40 CFR 63.11088 to delete
reference to pipeline breakout stations or pipeline pumping stations.
For the NSPS subpart XXa, we are simply proposing the definition of
bulk gasoline terminals consistent with the definitions being proposed
in the major and area source NESHAP.
c. Definition of Gasoline
We are also proposing to add a definition of gasoline to NESHAP
subpart R to clarify the definition of gasoline that applies to this
subpart. The proposed definition is based on the definition in NSPS
subpart XX and is consistent with the definition of gasoline in both
NSPS subpart XXa and NESHAP subpart BBBBBB.
d. Definition of Submerged Filling
Because we are proposing in NSPS subpart XXa and NESHAP subpart R
to require submerged filling when loading cargo tanks, we are also
proposing to add a definition of ``submerged filling'' similar to the
definition include in NESHAP subpart BBBBBB to clearly define this term
for use in complying with the proposed requirements for submerged
filling. Specifically, submerged filling is either the use of a pipe
whose discharge is no more than the 6 inches from the bottom of the
tank or the use of bottom filling. The proposed definitions of
``submerged filling'' in NSPS subpart XXa and NESHAP subpart R do not
include references to stationary storage tanks that are included in the
NESHAP subpart BBBBBB definition of ``submerged filling'' because NSPS
subpart XXa and NESHAP subpart R do not require submerged filling of
storage tanks (although the floating roof requirements essentially
demand use of submerged filling).
e. Definition of Flare and Thermal Oxidation System
We are proposing to further clarify the distinction between a flare
and a thermal oxidation system. For the gasoline distribution rules,
the term flare refers to thermal combustion system using an open flame
(without enclosure), whereas a thermal oxidation system has an enclosed
combustion chamber. Some flares may have shrouds or other ``partial''
enclosures, which make it difficult to classify these devices based on
the current definitions. We are proposing to clarify the definition of
a flare to include shrouded flares or flares with partial enclosures
that are insufficient to capture the emitted pollutants and convey them
to the atmosphere in a conveyance that can be used to conduct a
performance test to determine the emissions. Thus, a performance test
cannot be performed on a flare. We are also proposing to clarify that
thermal oxidation systems are enclosed to the point that the pollutants
are emitted through a conveyance that affords quantification of
emissions through application of performance tests. This clarification
is consistent with the current requirements to conduct initial
performance tests for thermal oxidation systems but not for flares.

[[Page 35633]]

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