Rule2024-04629
National Emission Standards for Hazardous Air Pollutants: Gasoline Distribution Technology Reviews and New Source Performance Standards Review for Bulk Gasoline Terminals
Primary source
Metadata and text below are from the Federal Register, a public-domain U.S. government work. Always verify the official published version before relying on it for any legal matter.
Published
May 8, 2024
Effective
July 8, 2024
Issuing agencies
Environmental Protection Agency
Abstract
The Environmental Protection Agency (EPA) is finalizing the technology reviews (TR) conducted for the national emission standards for hazardous air pollutants (NESHAP) for gasoline distribution facilities and the review of the new source performance standards (NSPS) for bulk gasoline terminals pursuant to the requirements of the Clean Air Act (CAA). The final NESHAP amendments include revised requirements for storage vessels, loading operations, and equipment to reflect cost-effective developments in practices, processes, or controls. The final NSPS reflect the best system of emission reduction for loading operations and equipment leaks. In addition, the EPA is: finalizing revisions related to emissions during periods of startup, shutdown, and malfunction (SSM); adding requirements for electronic reporting; revising monitoring and operating requirements for control devices; and making other minor technical improvements. The EPA estimates that this final action will reduce hazardous air pollutant emissions from gasoline distribution facilities by over 2,200 tons per year (tpy) and volatile organic compound (VOC) emissions by 45,400 tpy.
Full Text
<html>
<head>
<title>Federal Register, Volume 89 Issue 90 (Wednesday, May 8, 2024)</title>
</head>
<body><pre>
[Federal Register Volume 89, Number 90 (Wednesday, May 8, 2024)]
[Rules and Regulations]
[Pages 39304-39390]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2024-04629]
[[Page 39303]]
Vol. 89
Wednesday,
No. 90
May 8, 2024
Part VI
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Parts 60 and 63
National Emission Standards for Hazardous Air Pollutants: Gasoline
Distribution Technology Reviews and New Source Performance Standards
Review for Bulk Gasoline Terminals; Final Rule
Federal Register / Vol. 89 , No. 90 / Wednesday, May 8, 2024 / Rules
and Regulations
[[Page 39304]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 60 and 63
[EPA-HQ-OAR-2020-0371; FRL-8202-02-OAR]
RIN 2060-AU97
National Emission Standards for Hazardous Air Pollutants:
Gasoline Distribution Technology Reviews and New Source Performance
Standards Review for Bulk Gasoline Terminals
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
-----------------------------------------------------------------------
SUMMARY: The Environmental Protection Agency (EPA) is finalizing the
technology reviews (TR) conducted for the national emission standards
for hazardous air pollutants (NESHAP) for gasoline distribution
facilities and the review of the new source performance standards
(NSPS) for bulk gasoline terminals pursuant to the requirements of the
Clean Air Act (CAA). The final NESHAP amendments include revised
requirements for storage vessels, loading operations, and equipment to
reflect cost-effective developments in practices, processes, or
controls. The final NSPS reflect the best system of emission reduction
for loading operations and equipment leaks. In addition, the EPA is:
finalizing revisions related to emissions during periods of startup,
shutdown, and malfunction (SSM); adding requirements for electronic
reporting; revising monitoring and operating requirements for control
devices; and making other minor technical improvements. The EPA
estimates that this final action will reduce hazardous air pollutant
emissions from gasoline distribution facilities by over 2,200 tons per
year (tpy) and volatile organic compound (VOC) emissions by 45,400 tpy.
DATES: The final rule is effective July 8, 2024.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2020-0371. All documents in the docket are
listed on the <a href="https://www.regulations.gov/">https://www.regulations.gov/</a> website. 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. Publicly available docket materials are available electronically
through <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>.
FOR FURTHER INFORMATION CONTACT: For questions about this final action,
contact U.S. EPA, Attn: Ms. Jennifer Caparoso, Mail Drop: E143-01, 109
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711; telephone number:
(919) 541-4063; and email address: <a href="/cdn-cgi/l/email-protection#0f6c6e7f6e7d607c6021656a616166696a7d4f6a7f6e21686079"><span class="__cf_email__" data-cfemail="80e3e1f0e1f2eff3efaeeae5eeeee9e6e5f2c0e5f0e1aee7eff6">[email protected]</span></a>.
SUPPLEMENTARY INFORMATION:
Preamble acronyms and abbreviations. Throughout this document the
use of ``we,'' ``us,'' or ``our'' is intended to refer to the EPA. The
EPA uses 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
BACT best available control technology
BSER best system of emission reduction
CAA Clean Air Act
CDX Central Data Exchange
CEDRI Compliance and Emissions Data Reporting Interface
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CO carbon monoxide
CO<INF>2</INF> carbon dioxide
CPMS continuous parametric monitoring system
EAV equivalent annual value
EJ environmental justice
E.O. Executive Order
EPA Environmental Protection Agency
ERT Electronic Reporting Tool
FR Federal Register
GACT generally available control technology
HAP hazardous air pollutant(s)
ICR information collection request
km kilometer
LAER lowest achievable emission rate
LDAR leak detection and repair
LEL lower explosive limit
MACT maximum achievable control technology
mg/L milligrams per liter
mph miles per hour
NAICS North American Industry Classification System
NESHAP national emission standards for hazardous air pollutants
NHV<INF>cz</INF> combustion zone net heating value
NHV<INF>dil</INF> net heating value dilution
NO<INF>X</INF> nitrogen oxides
NSPS new source performance standards
O<INF>3</INF> ozone
OGI optical gas imaging
OMB Office of Management and Budget
ppmv parts per million volume
psig pounds per square inch gauge
PRA Paperwork Reduction Act
PV present value
RACT reasonably available control technology
RFA Regulatory Flexibility Act
RIA regulatory impact analysis
RTR risk and technology review
SO<INF>2</INF> sulfur dioxide
SSM startup, shutdown, and malfunction
TOC total organic carbon
tpy tons per year
TR technology review
U.S. United States
U.S.C. United States Code
VOC volatile organic compound(s)
VRU vapor recovery unit
Background information. On June 10, 2022, the EPA proposed
revisions to both the major source and area source Gasoline
Distribution NESHAP and the Bulk Gasoline Terminals NSPS based on the
TR and NSPS review. In this action, the EPA is finalizing decisions and
revisions for these rules. The EPA summarized some of the more
significant comments we timely received regarding the proposed rules
and provides responses in this preamble. A summary of all other public
comments on the proposals and the EPA's responses to those comments is
available in National Emission Standards for Hazardous Air Pollutants
for Gasoline Distribution Facilities and New Source Performance
Standards for Bulk Gasoline Terminals, Background Information for Final
Amendments, Summary of Public Comments and Responses, Docket ID No.
EPA-HQ-OAR-2020-0371. ``Track changes'' versions of the regulatory
language that incorporates the changes in these rules are available in
the docket.
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?
D. Judicial Review and Administrative Review
II. Background
A. What is the statutory authority for this action?
B. What are the source categories regulated in this final
action?
C. What changes were proposed for the gasoline distribution
NESHAP and for the bulk gasoline terminals NSPS in the June 10,
2022, proposal?
D. What outreach was conducted following the proposal?
III. What is included in these final rules and what is the rationale
for the final decisions and amendments?
A. What are the final rule amendments based on the technology
reviews for the gasoline distribution NESHAP and NSPS review for
bulk gasoline terminals?
B. Other Actions the EPA is Finalizing and the Rationale
C. What are the effective and compliance dates of the standards?
IV. Summary of Cost, Environmental, and Economic Impacts and
Additional Analyses Conducted
A. What are the affected facilities?
[[Page 39305]]
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 the EPA conduct?
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 14094: Modernizing Regulatory Review
B. Paperwork Reduction Act (PRA)
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act of 1995 (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 and Executive Order 14096: Revitalizing Our Nation's
Commitment to Environmental Justice for All
K. Congressional Review Act (CRA)
I. General Information
A. Executive Summary
1. Purpose of the Regulatory Action
The source categories that are the subject of this final action are
Gasoline Distribution regulated under 40 CFR part 63, subparts R and
BBBBBB, and Bulk Gasoline Terminals \1\ regulated under 40 CFR part 60,
subparts XX and XXa. 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 (RTR) in
2006. The sources affected by the major source NESHAP for the gasoline
distribution source category (40 CFR 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 (40 CFR part 63, subpart BBBBBB) are bulk gasoline terminals,
bulk gasoline plants, and pipeline facilities. The EPA set the first
NSPS for bulk gasoline terminals in 1983. Bulk gasoline terminals that
commenced construction or modification after December 17, 1980, and on
or before June 10, 2022, are regulated under the NSPS codified at 40
CFR part 60, subpart XX. Bulk gasoline terminals that commenced
construction or modification after June 10, 2022, will be regulated
under the NSPS codified at 40 CFR part 60, subpart XXa.
---------------------------------------------------------------------------
\1\ Petroleum Transportation and Marketing is the listed source
category. Bulk Gasoline Terminals are the affected facilities
regulated by the NSPS addressing the Petroleum Transportation and
Marketing source category.
---------------------------------------------------------------------------
The statutory authority for these final rulemakings is sections 111
and 112 of the CAA. Section 111(b)(1)(B) of the CAA requires the EPA to
``at least every 8 years review and, if appropriate, revise'' the 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(d) 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.''
The NSPS for Bulk Gasoline Terminals and the amendments to the
NESHAP for Gasoline Distribution facilities finalized in this action
fulfill the Agency's requirements, 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
The EPA is finalizing the requirement of 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. The EPA is also finalizing the requirement of
fitting controls for external floating roof tanks consistent with the
requirements in 40 CFR part 60, subpart Kb (NSPS subpart Kb). In
addition, the EPA is finalizing the requirement of semiannual
instrument monitoring for equipment leaks at major source gasoline
distribution facilities.
b. NESHAP Subpart BBBBBB
The EPA is finalizing an area source emission limit of 35
milligrams of total organic carbon (TOC) per liter of gasoline loaded
(mg/L) at large bulk gasoline terminals and vapor balancing \2\
requirements for loading storage vessels and gasoline cargo tanks at
bulk gasoline plants with actual throughput of 4,000 gallons per day or
more. The EPA is also finalizing the requirement of 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, the EPA is finalizing the
requirement of fitting controls for external floating roof tanks
consistent with the requirements in NSPS subpart Kb. Also, the EPA is
finalizing the requirement of annual instrument monitoring for
equipment leaks at area source gasoline distribution facilities.
---------------------------------------------------------------------------
\2\ When using a vapor balancing system, displaced vapors from a
cargo tank are captured and routed through piping back to a storage
vessel or vice-a-versa.
---------------------------------------------------------------------------
c. NSPS Subpart XXa
The EPA is finalizing a new NSPS subpart XXa applicable to affected
facilities that commence construction, modification, or reconstruction
after June 10, 2022. For loading operations, the EPA is finalizing
standards of performance for VOC that require new facilities to meet a
1.0 mg/L TOC emission limit and modified and reconstructed facilities
to meet a 10 mg/L TOC emission limit. The EPA is also finalizing the
requirement for gasoline cargo tanks of 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. In
addition, the EPA is finalizing the requirement of quarterly instrument
monitoring for equipment leaks.
3. Costs and Benefits
In accordance with Executive Order (E.O.) 12866 and 13563, the
guidelines of the Office of Management and Budget (OMB) Circular A-4,
and the EPA's Guidelines for Preparing Economic Analyses, the EPA
prepared a Regulatory Impact Analysis (RIA) for the proposal of the
rules included in this action. The RIA analyzed the benefits and costs
associated with the projected emissions reductions under the proposed
requirements, a less stringent set of requirements, and a more
stringent set of requirements. Prior to the amendments made by E.O.
14094, the proposal of the area source NESHAP
[[Page 39306]]
rule was significant under E.O. 12866, section 3(f)(1) due to its
likely annual effect on the economy of $100 million or more in any one
year on the economy, a sector of the economy, productivity,
competition, jobs, the environment, public health or safety, or State,
local, or Tribal governments or communities. Specifically, monetized
health benefits from projected VOC reductions associated with the
proposed area source NESHAP rule amendments exceeded $100 million per
year.
On April 6, 2023, President Biden issued E.O. 14094, Modernizing
Regulatory Review, which increased the annual effect threshold for
significance under E.O. 12866, section 3(f)(1) from $100 million to
$200 million. This final action is significant under E.O. 12866,
section 3(f)(1) as amended by E.O. 14094. Accordingly, the EPA has
prepared a Regulatory Impact Analysis (RIA).
The EPA projected the emissions reductions, costs, and benefits
that may result from the rules included in this final action, which are
presented in detail in the RIA. We present these results for each of
the three rules included in this final action, and also cumulatively.
The RIA focuses on the elements of the final action that are likely to
result in quantifiable cost or emissions changes compared to a baseline
without the final NESHAP and NSPS amendments. We estimated the cost,
emissions, and benefit impacts for the 2027 to 2041 period. We also
show the present value (PV) and equivalent annual value (EAV) of costs,
benefits, and net benefits of this action in 2021 dollars. The year
2019 was used as the base year in the cost analyses at proposal.
However, based on comments received, we updated our analyses to use
2021 as the base year.
The EPA also updated costs and emissions impacts in the RIA to
incorporate changes to the economic environment since the proposal.
Specifically, the interest rate used to annualize capital costs rose
from 3.25 percent to 7.75 percent to reflect changes in the bank prime
rate, the VOC recovery credit used to value gasoline product recovery
was updated to reflect the 2021 wholesale price of gasoline, and the
dollar-year was updated from 2019 to 2021 to reflect recent
inflation.\3\
---------------------------------------------------------------------------
\3\ The EPA used the wholesale price of gasoline in this
analysis to provide a focus on the rulemaking's cost impacts to
affected firms, including the impact of product recovery upon the
cost to these firms. Use of the consumer price of gasoline would
introduce market interactions that may make analysis of product
recovery more difficult to estimate given passthrough of costs by
firms to consumers. More explanation on the use of wholesale price
of gasoline is found in Chapter 3 of the RIA.
---------------------------------------------------------------------------
The initial analysis year in the RIA is 2027, as we assume the
large majority of impacts associated with the final action will begin
in that year. The most significant impacts of this final action are due
to the regulation of existing sources under the major and area source
NESHAP rules. These two rules, NESHAP subparts R and BBBBBB, require
compliance with the existing source standards 3 years after the
promulgation date of these final rules. As a result, compliance with
the standards for existing sources will occur in 2027. The final
analysis year is 2041, which allows us to present 15 years of projected
impacts after all three 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 a model plant include
typical equipment, operating characteristics, and representative
factors including baseline emissions and the costs, emissions
reductions, and product recovery of gasoline 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
vessels). 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 recovered gasoline, 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 as a result of the emissions
reductions projected under this final action. We expect that hazardous
air pollutants (HAP) emission reductions will improve health and
welfare associated with those affected by these emissions. In addition,
the EPA expects that 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 reduced exposure
to ozone, particulate matter with a diameter less than 2.5 microns
(PM<INF>2.5</INF>), and HAP. The EPA expects disbenefits from secondary
increases of carbon dioxide (CO<INF>2</INF>), nitrogen oxides
(NO<INF>X</INF>), sulfur dioxide (SO<INF>2</INF>), and carbon monoxide
(CO) emissions associated with the control options included in the cost
analysis. The benefits of reduced premature mortality and morbidity
associated with reduced exposure to VOC emissions and climate
disbenefits associated with increased CO<INF>2</INF> emissions have
been monetized for this final action. Our discussion of both the
benefits and disbenefits, monetized and non-monetized, associated with
this action are included in chapter 4 of the RIA.
Tables 1 through 3 of this document present the emission changes
and the PV and EAV of the projected monetized benefits, compliance
costs, and net benefits over the 2027 to 2041 period under the final
action for each subpart. Table 4 of this document presents the same
results for the cumulative impact of these rulemakings. Climate
disbenefits are discounted using a 3 percent social discount rate. All
other discounting of impacts presented uses social discount rates of 3
and 7 percent.
[[Page 39307]]
[GRAPHIC] [TIFF OMITTED] TR08MY24.008
[[Page 39308]]
[GRAPHIC] [TIFF OMITTED] TR08MY24.009
[GRAPHIC] [TIFF OMITTED] TR08MY24.010
[[Page 39309]]
[GRAPHIC] [TIFF OMITTED] TR08MY24.011
[[Page 39310]]
[GRAPHIC] [TIFF OMITTED] TR08MY24.012
[[Page 39311]]
[GRAPHIC] [TIFF OMITTED] TR08MY24.013
[[Page 39312]]
[GRAPHIC] [TIFF OMITTED] TR08MY24.014
B. Does this action apply to me?
The source categories that are the subject of this final action are
Gasoline Distribution regulated under 40 CFR part 63, subparts R and
BBBBBB, and Bulk Gasoline Terminals regulated under 40 CFR part 60,
subparts XX and XXa. The 2022 North American Industry Classification
System (NAICS) codes for the gasoline distribution industry are 324110,
493190, 486910, and 424710. The NAICS codes are not intended to be
exhaustive but rather to serve as a guide for readers regarding
entities likely to be affected by this final action. The NSPS codified
in 40 CFR part 60, subpart XXa, are directly applicable to affected
facilities that begin construction, reconstruction, or modification
after June 10, 2022. If you have any questions regarding the
applicability of these rules to a particular entity, you should
carefully examine the applicability criteria found in the appropriate
NESHAP and NSPS, and consult with the person listed in the FOR FURTHER
INFORMATION CONTACT section of this preamble, your State air pollution
control agency with delegated authority, or your EPA Regional Office.
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 final action is available on the internet 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>. Following publication in the Federal
Register, the EPA will post the Federal Register version and key
technical documents at this same website.
Additional information is available on the RTR website at <a href="https://www.epa.gov/stationary-sources-air-pollution/risk-and-technology-review-national-emissions-standards-hazardous">https://www.epa.gov/stationary-sources-air-pollution/risk-and-technology-review-national-emissions-standards-hazardous</a>. This information
includes an overview of the RTR program and links to project websites
for the RTR source categories.
D. Judicial Review and Administrative Review
Under CAA section 307(b)(1), judicial review of this final action
is available only by filing a petition for review in the United States
Court of Appeals for the District of Columbia Circuit by July 8, 2024.
Under CAA section 307(b)(2), the requirements established by these
final rules may not be challenged separately in any civil or criminal
proceedings brought by the EPA to enforce the requirements.
Section 307(d)(7)(B) of the CAA further provides that ``[o]nly an
objection to a rule or procedure which was raised with reasonable
specificity during the period for public comment (including any public
hearing) may be raised during judicial review.'' This section also
provides a mechanism for the EPA to reconsider the rules, ``[i]f the
person raising an objection can demonstrate to the Administrator that
it was impracticable to raise such objection within [the period for
public comment] or if the grounds for such objection arose after the
period for public comment (but within the time specified for judicial
review) and if such objection is of central relevance to the outcome of
the rule.'' Any person seeking to make such a demonstration should
submit a Petition for Reconsideration to the Office of the
Administrator, U.S. Environmental Protection Agency, Room 3000, WJC
West Building, 1200 Pennsylvania Ave. NW, Washington, DC 20460, with a
copy to both the person listed in the preceding FOR FURTHER INFORMATION
CONTACT section and the Associate General Counsel for the Air and
Radiation Law Office, Office of General Counsel (Mail Code 2344A), U.S.
Environmental Protection Agency, 1200 Pennsylvania Ave. NW, Washington,
DC 20460.
II. Background
A. What is the statutory authority for this action?
1. NESHAP
The statutory authority for this action is provided by CAA sections
112 and 301, as amended (42 U.S.C. 7401 et seq.). Section 112 of the
CAA establishes a two-stage regulatory process to develop standards for
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 final action. The discussion that
[[Page 39313]]
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). For categories of area sources subject to GACT standards,
there is no requirement to address residual risk, but, similar to the
major source categories, the technology review is required.
A technology review is required for all standards established under
CAA section 112(d) including GACT standards that apply to area
sources.\4\ In conducting the technology 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
the major source category, 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). For
information on how EPA conducts a technology review, see 87 FR 35616
(June 10, 2022).
---------------------------------------------------------------------------
\4\ For categories of area sources subject to GACT standards,
CAA sections 112(d)(5) and (f)(5) provide that the EPA is not
required to conduct a residual risk review under CAA section
112(f)(2). However, the EPA is required to conduct periodic
technology reviews under CAA section 112(d)(6).
---------------------------------------------------------------------------
Several additional CAA sections are relevant 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 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. MACT standards were set for the Gasoline Distribution
major source category in 1994 and the residual risk review and initial
technology review for the major source category were completed in 2006.
As noted above, this action finalizes the required CAA section
112(d)(6) technology reviews for the standards for major and area
sources in that source category.
2. NSPS
The EPA's authority for the final NSPS rule is CAA section 111,
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 judgment 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 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, types, and sizes within categories in
establishing the standards.
CAA section 111(b)(1)(B) requires the EPA to ``at least every 8
years review and, if appropriate, revise'' new source performance
standards. However, the Administrator need not review any such standard
if the ``Administrator determines that such review is not appropriate
in light of readily available information on the efficacy'' of the
standard. When conducting a review of an existing performance standard,
the EPA has the discretion and authority to add emission limits for
pollutants or emission sources not currently regulated for that source
category.
In setting or revising a performance standard, CAA section
111(a)(1) 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
[[Page 39314]]
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.'' The term
``standard of performance'' in CAA section 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, pursuant to CAA
section 111(b)(1)(B), promulgate standards of performance for new
sources that reflect that level of stringency. CAA section 111(b)(5)
generally 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. CAA section 111(h)(1) authorizes the
Administrator to promulgate ``a design, equipment, work practice, or
operational standard, or combination thereof'' if in his or her
judgment, ``it is not feasible to prescribe or enforce a standard of
performance.'' CAA section 111(h)(2) provides the circumstances under
which prescribing or enforcing a standard of performance is ``not
feasible,'' such as when the pollutant cannot be emitted through a
conveyance designed to emit or capture the pollutant or when there is
no practicable measurement methodology for the particular class of
sources.
Pursuant to the definition of ``new source'' in CAA section
111(a)(2), standards of performance apply to facilities that begin
construction, reconstruction, or modification after the date of
publication of the proposed standards in the Federal Register. Under
CAA section 111(a)(4), ``modification'' means any physical change in,
or change in the method of operation of, a stationary source which
increases the amount of any air pollutant emitted by such source or
which results in the emission of any air pollutant not previously
emitted. Changes to an existing facility that do not result in an
increase in emissions are not considered modifications. Under the
provisions in 40 CFR 60.15, ``reconstruction'' means the replacement of
components of an existing facility such that: (1) The fixed capital
cost of the new components exceeds 50 percent of the fixed capital cost
that would be required to construct a comparable entirely new facility;
and (2) it is technologically and economically feasible to meet the
applicable standards.
The NSPS were promulgated for Bulk Gasoline Terminals in 1983. As
noted earlier in this preamble, this action finalizes the required NSPS
review for that source category. For information on how the EPA
conducts a NSPS review, see 87 FR 35616 (June 10, 2022).
B. What are the source categories regulated in this final action?
1. NESHAP Subpart R
The EPA promulgated the major source Gasoline Distribution NESHAP
on December 14, 1994 (59 FR 64303). The standards are codified at 40
CFR part 63, subpart R. The major source gasoline distribution industry
consists of bulk gasoline terminals and pipeline breakout stations. The
source category covered by this MACT standard currently includes 210
facilities.
The primary sources of HAP emissions at bulk gasoline terminals are
gasoline loading racks, gasoline cargo tanks, gasoline storage vessels,
and equipment in gasoline service. The primary sources of HAP emissions
at pipeline breakout stations are gasoline storage vessels and
equipment in gasoline service. Emissions from loading racks at major
source gasoline terminals under NESHAP subpart R are required to be
controlled by a vapor collection and processing system to meet a TOC
emission limit of 10 mg/L. Gasoline cargo tanks must be certified to be
vapor tight using a graduated vapor tightness requirement of 1.0 to 2.5
inches of water pressure drop over a 5-minute period, depending on the
cargo tank compartment size for gasoline cargo tanks. Emissions from
storage vessels with a design capacity greater than or equal to 75
cubic meters must be controlled by equipment designed to suppress
emissions (i.e., use an internal or external floating roof meeting
certain requirements) or must capture and control emissions to a device
achieving 95 percent reduction efficiency. Equipment leaks are subject
to a leak detection and repair (LDAR) program using monthly inspections
to identify leaks via audio, visual, or olfactory (AVO) methods and
repair the leak identified.
2. NESHAP Subpart BBBBBB
The EPA promulgated the area source Gasoline Distribution NESHAP on
January 10, 2008 (73 FR 1916). The standards are codified at 40 CFR
part 63, subpart BBBBBB. The area source gasoline distribution industry
consists of bulk gasoline terminals, bulk gasoline plants, pipeline
breakout stations, and pipeline pumping stations. The source category
covered by this GACT standard currently includes approximately 9,000
facilities.
The primary sources of HAP emissions at bulk gasoline plants and
bulk gasoline terminals are gasoline loading racks, gasoline cargo
tanks, gasoline storage vessels, and equipment components in gasoline
service. The primary sources of HAP emissions at pipeline breakout
stations are gasoline storage vessels and equipment components in
gasoline service; the HAP emissions at pipeline pumping stations are
from equipment components in gasoline service. Emissions from loading
racks at area source gasoline terminals with throughput of 250,000
gallons per day or greater are required under NESHAP subpart BBBBBB to
reduce emissions of TOC to less than or equal to 80 mg/L of gasoline.
Small bulk gasoline terminals (terminals with a combined throughput
between 20,000 and 250,000 gallons per day) and bulk gasoline plants
(facilities with gasoline throughput of 20,000 gallons per day or less)
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. Gasoline
cargo tanks must be certified to be vapor tight using a maximum
allowable pressure loss of 3 inches of water pressure drop over a 5-
minute period.
At bulk gasoline terminals and pipeline breakout stations,
emissions from storage vessels with a design capacity greater than or
equal to 75 cubic meters and a gasoline throughput greater than 480
gallons per day and all storage vessels with a design capacity greater
than or equal to 151 cubic meters must be controlled by equipment
designed to suppress emissions (i.e., use an internal or external
floating roof meeting certain requirements) or must capture and control
emissions to a device achieving 95 percent reduction efficiency.
Storage vessels below these thresholds must have fixed roofs and must
maintain all openings in a closed position at all times when not in
use.
Equipment leaks at all area source gasoline distribution facilities
are subject to an LDAR program using monthly AVO methods.
3. NSPS
The EPA first promulgated new source performance standards for Bulk
Gasoline Terminals on August 18, 1983 (48 FR 37578). These standards of
performance are codified in 40 CFR part 60, subpart XX, and are
applicable to sources that commence construction, modification, or
reconstruction after December 17, 1980, and on or before June 10, 2022.
These standards of
[[Page 39315]]
performance regulate VOC emissions from bulk gasoline terminals.
The affected facility to which the provisions of NSPS subpart XX
apply is the total of all the loading racks at a bulk gasoline
terminal. The primary sources of VOC emissions subject to NSPS subpart
XX are gasoline loading racks, gasoline cargo tanks, and equipment
associated with the loading rack and associated vapor collection and
processing system. Emissions from gasoline storage vessels are subject
to separate NSPS (see 40 CFR part 60, subparts K, Ka, and Kb). VOC
emissions from loading racks at gasoline terminals subject to NSPS
subpart XX must meet a TOC emission limit of 35 mg/L, except for
modified affected facilities with an existing vapor processing system
(as of December 17, 1980), which must meet a TOC emission limit of 80
mg/L. Gasoline cargo tanks must be certified to be vapor tight using a
maximum allowable pressure loss of 3 inches of water pressure drop over
a 5-minute period. Leaks from equipment associated with the loading
rack and associated vapor collection and processing system are subject
to an LDAR program using monthly AVO methods.
C. What changes were proposed for the gasoline distribution NESHAP and
for the bulk gasoline terminals NSPS in the June 10, 2022, proposal?
On June 10, 2022, the EPA published proposed rules in the Federal
Register for the Gasoline Distribution NESHAP, 40 CFR part 63, subparts
R and BBBBBB, and Bulk Gasoline Terminal NSPS, 40 CFR part 60, subpart
XXa, that took into consideration the TR and NSPS review and respective
analyses.
1. NESHAP Subpart R
In the proposed rule for the major source Gasoline Distribution
NESHAP, 40 CFR part 63, subpart R, the EPA for new and existing sources
proposed to:
<bullet> Retain the 10 mg/L TOC emission limit for gasoline loading
racks controlled by thermal oxidation systems.
<bullet> Provide a 5,500 ppmv TOC emission limit for gasoline
loading racks controlled by vapor recovery units (VRUs), which was
determined to be equivalent to the 10 mg/L emission limit.
<bullet> Reduce the allowable pressure drop for certifying gasoline
cargo tanks as vapor tight to a graduated vapor tightness requirement
of 0.5 to 1.25 inches of water, depending on the cargo tank compartment
size for gasoline cargo tanks.
<bullet> Include additional fitting requirements for storage
vessels with external floating roofs.
<bullet> Add a requirement for storage vessels with internal
floating roofs to maintain the concentrations of vapors inside a
storage vessel above the floating roof to less than 25 percent of the
lower explosive limit (LEL).
<bullet> Require semiannual monitoring using either optical gas
imaging (OGI) or EPA Method 21 and repair leaks identified from these
monitoring events or leaks identified by AVO methods during normal
duties.
<bullet> Revise certain requirements to clarify that the emission
limits apply at all times.
<bullet> Add electronic reporting requirements.
2. NESHAP Subpart BBBBBB
In the proposed rule for the area source Gasoline Distribution
NESHAP, 40 CFR part 63, subpart BBBBBB, the EPA proposed for new and
existing sources to:
<bullet> Reduce the TOC emission limit for loading racks at large
bulk gasoline terminals from 80 mg/L to 35 mg/L.
<bullet> Provide a 19,200 ppmv TOC emission limit for loading racks
at large bulk gasoline terminals controlled by VRUs, which was
determined to be equivalent to the 35 mg/L emission limit.
<bullet> Reduce the allowable pressure drop for certifying gasoline
cargo tanks as vapor tight to a graduated vapor tightness requirement
of 0.5 to 1.25 inches of water, depending on the cargo tank compartment
size for gasoline cargo tanks.
<bullet> Include additional fitting requirements for storage
vessels with external floating roofs.
<bullet> Add a requirement for storage vessels with internal
floating roofs to maintain the concentrations of vapors inside a
storage vessel above the floating roof to less than 25 percent of the
LEL.
<bullet> Add requirements for bulk gasoline plants with a capacity
over 4,000 gallons per day to use vapor balancing between gasoline
cargo tanks and gasoline storage vessels.
<bullet> Require pressure relief valves on fixed roof tanks to have
opening pressures set to no less than 2.5 pounds per square inch gauge
(psig).
<bullet> Require annual monitoring using either OGI or EPA Method
21 and repair leaks identified from these monitoring events or leaks
identified by AVO methods during normal duties.
<bullet> Revise certain requirements to clarify that the emission
limits apply at all times.
<bullet> Add electronic reporting requirements.
3. NSPS Subpart XXa
In the proposed rule for Bulk Gasoline Terminal NSPS, 40 CFR part
60, subpart XXa, the EPA proposed for new, modified, and reconstructed
sources to:
<bullet> Define the affected facility to include all equipment in
gasoline service at the bulk gasoline terminal.
<bullet> Limit VOC emissions as TOC from loading racks at new bulk
gasoline terminals controlled with thermal oxidation systems to 1.0 mg/
L and limit TOC emissions from loading racks controlled with thermal
oxidation systems at modified or reconstructed bulk gasoline terminals
to 10 mg/L.
<bullet> Provide 550 ppmv and 5,500 ppmv TOC emission limits for
loading racks at bulk gasoline terminals controlled with VRUs, which
were determined to be equivalent to the 1.0 mg/L and 10 mg/L proposed
TOC emission limits, respectively.
<bullet> Require certification of gasoline cargo tanks as vapor
tight using a graduated vapor tightness requirement 0.5 to 1.25 inches
of water, depending on the cargo tank compartment size for gasoline
cargo tanks.
<bullet> Require quarterly monitoring using either OGI or EPA
Method 21 and repair leaks identified from these monitoring events or
leaks identified by AVO methods during normal duties.
<bullet> Clarify that the emission limits apply at all times.
<bullet> Include electronic reporting requirements.
D. What outreach was conducted following the proposal?
As part of these rulemakings and pursuant to multiple EOs
addressing environmental justice (EJ), the EPA engaged and consulted
with pertinent stakeholders and the public, including communities with
environmental justice concerns. The EPA provided interactions such as
conducting a public hearing, offering information on the websites for
these rules, and informing the public of the proposed action by sending
notifications with summaries of the action and information on how to
comment to pertinent stakeholders. These opportunities gave the EPA a
chance to hear directly from pertinent stakeholders and the public,
especially communities potentially impacted by this final action.
Summaries of the public hearing and comments received can be found in
the docket for this action.
III. What is included in these final rules and what is the rationale
for the final decisions and amendments?
This action finalizes the EPA's determinations pursuant to the TR
[[Page 39316]]
provisions of CAA section 112 for the Gasoline Distribution major and
area source categories and amends both Gasoline Distribution NESHAPs
based on those determinations. This action also finalizes the removal
of SSM exemptions in the NESHAP. The EPA is further finalizing
determinations of its review of the Bulk Gasoline Terminals NSPS
pursuant to CAA section 111(b)(1)(B). In addition, this action
finalizes electronic reporting, monitoring and operating requirements
for control devices, and other minor technical improvements. This
action also reflects several changes to the June 10, 2022, proposal in
consideration of comments received during the public comment period.
For each issue, this section provides a description of what the EPA
proposed and what the EPA is finalizing for the issue, the EPA's
rationale for the final decisions and amendments, and a summary of key
comments and responses. For all comments not discussed in this
preamble, comment summaries and the EPA's responses can be found in the
comment summary and response document available in the docket.
A. What are the final rule amendments based on the technology reviews
for the gasoline distribution NESHAP and NSPS review for bulk gasoline
terminals?
The EPA determined that there are developments in practices,
processes, and control technologies for loading operations, storage
vessels, and equipment leaks that warrant revisions to NESHAP subpart R
and NESHAP subpart BBBBBB.
Therefore, to satisfy the requirements of CAA section 112(d)(6),
the EPA is revising the NESHAP to include: a more stringent standard
for gasoline loading racks at area sources, including requirements for
vapor balancing for bulk gasoline plants with actual throughput of
greater than 4,000 gallons per day; for both major and area sources,
more stringent requirements for gasoline cargo tank vapor tightness;
more stringent fitting control requirements for guidepoles on external
floating roofs; the use of LEL monitoring to ensure the effectiveness
of internal floating roofs; and instrument monitoring for equipment
leaks. The final revisions are similar to those proposed. The most
significant change from what was proposed is that we revised the
throughput threshold requirement for which bulk gasoline plants must
use vapor balancing to be determined by actual throughput rather than
by maximum design capacity. Considering the analysis conducted to
develop the 4,000 gallons per day threshold, provisions in NESHAP
subpart BBBBBB, and comments received, the use of actual daily
throughput and an annual averaging time is consistent with the analysis
conducted and other provisions in NESHAP subpart BBBBBB. Upon
consideration of public comments received, we also included an
allowance to subtract methane from the TOC emission limit.
Pursuant to the requirements of CAA section 111(b)(1)(B), the EPA
determined that updates to the BSER are warranted and is revising the
standards of performance for loading operations and equipment leaks.
The EPA is finalizing the revisions to the NSPS in a new subpart, 40
CFR part 60, subpart XXa, applicable to affected sources constructed,
modified, or reconstructed after June 10, 2022. The NSPS subpart XXa
includes: more stringent VOC standards (as TOC emission limits) for
new, modified, or reconstructed gasoline loading racks; more stringent
requirements for gasoline cargo tank vapor tightness; and instrument
monitoring for equipment leaks. The final requirements in NSPS subpart
XXa are similar to those proposed. The most significant change from
what was proposed, after considering public comments received, is to
define separate affected facilities: one specific to the loading rack
and one specific to the equipment. Upon consideration of public
comments received, we are also including an allowance to subtract
methane from the TOC emission limit consistent with the most stringent
emission limitations identified for new sources.
1. Standards for Loading Racks
Because most of the standards proposed for loading racks were
primarily in NSPS subpart XXa, we discuss our review of the loading
racks NSPS provisions first, and then cover additional technology
review issues specific to NESHAP subparts R and BBBBBB.
a. NSPS Subpart XXa
i. What did the EPA propose pursuant to CAA section 111 for loading
racks at new, modified, or reconstructed bulk gasoline terminals?
Based on the review of NSPS subpart XX requirements for loading
racks at bulk gasoline terminals, we proposed to revise the TOC
emission limit from loading racks at new bulk gasoline terminals
controlled with thermal oxidation systems to 1.0 mg/L and to revise the
TOC emission limit from loading racks at modified or reconstructed bulk
gasoline terminals controlled with thermal oxidation systems to 10 mg/
L. For thermal oxidation systems, we proposed continuous compliance
with a temperature operating limit established as the lowest 3-hour
average temperature from a compliant performance test. We also proposed
enhanced provisions for flares to ensure good combustion efficiency.
For loading racks controlled with VRUs, we proposed corresponding
emission limits of 550 ppmv and 5,500 ppmv TOC (as propane) for loading
racks at new bulk gasoline terminals and for loading racks at modified
or reconstructed bulk gasoline terminals, respectively. We determined
that these concentration emission limits are, respectively, equivalent
to the 1.0 mg/L and 10 mg/L proposed TOC emission limits for bulk
gasoline terminals controlled with thermal oxidation systems. We
proposed to express the concentration limit of 550 ppmv and 5,500 ppmv
TOC (as propane) on a 3-hour rolling average because this provides an
equivalent emission limit that is directly enforceable with the common
monitoring systems used for VRUs. To prevent dilution, we proposed that
only vacuum breaker valves can be used to introduce ambient air into
the VRU control system.
We also proposed revisions to the affected facility defined in NSPS
subpart XXa at 40 CFR 60.500a to include additional equipment at the
gasoline distribution facility beyond just that at the loading racks or
vapor processing system.
ii. How did the NSPS review change for gasoline loading racks at new,
modified, or reconstructed bulk gasoline terminals?
We are finalizing the standards of performance for gasoline loading
racks as proposed, except that we are including provisions to exclude
the contribution of methane from the measured TOC emissions (as
propane). As such, the final emission limits in NSPS subpart XXa are
effectively 1.0 mg/L non-methane TOC for new sources and 10 mg/L non-
methane TOC for modified and reconstructed sources, but facilities may
choose to comply using direct TOC measurements without correcting for
methane content.
We are also finalizing in the NSPS subpart XXa separate affected
facility definitions for the loading racks and equipment. However, the
loading rack affected facility definition in NSPS subpart XXa is
similar to the provisions of NSPS subpart XX.
[[Page 39317]]
iii. What key comments did the EPA receive and what are the EPA's
responses?
(A) Proposed Affected Facility
Comment: Several commenters recommended that the EPA retain the
NSPS subpart XX affected facility definition and not expand the
affected facility under NSPS subpart XXa to include pumps and lines
from storage vessels or the vapor collection and processing systems.
One commenter stated that NSPS subpart XXa should be revised to clarify
that a modification is triggered only by changes to the facility that
result in an emissions increase associated with the loading rack
itself, and not by changes to other equipment at the bulk gasoline
terminal.
Response: At proposal, we expanded the affected facility definition
in NSPS subpart XXa to ensure that all gasoline service equipment at
the bulk gasoline terminal is subject to the equipment leak monitoring
requirements. However, we did not intend the result of adding a pump or
valve in gasoline service to trigger additional loading rack control
requirements. Therefore, in the final rule, we are instead defining two
separate affected facilities: a ``gasoline loading rack affected
facility'' and a ``collection of equipment at a bulk gasoline terminal
affected facility.'' First, the gasoline loading rack affected facility
is being defined as ``the total of all the loading racks at a bulk
gasoline terminal that deliver liquid product into gasoline cargo tanks
including the gasoline loading racks, the vapor collection systems, and
the vapor processing system.'' This definition is similar to the
affected facility definition in NSPS subpart XX. The loading rack
emission limits apply specifically to the gasoline loading rack
affected facility; therefore, new equipment in the tank farm area would
not trigger NSPS applicability for the loading rack requirements. The
collection of equipment at a bulk gasoline terminal affected facility
is being defined as ``all equipment associated with the loading of
gasoline at a bulk gasoline terminal including the lines and pumps
transferring gasoline from storage vessels, the gasoline loading racks,
the vapor collection systems, and the vapor processing system.'' This
definition is consistent with our proposal and will ensure that all
equipment associated with loading of gasoline at the bulk gasoline
terminal is subject to the equipment leak provisions. The result of
this finalized definition is that new equipment in the tank farm area
would trigger NSPS subpart XXa applicability for the equipment leak
requirements.
(B) Proposed Emission Limits
Comment: Several commenters suggested that the 1 mg/L TOC emission
limit for new facilities in NSPS subpart XXa is not cost-effective and
has not been adequately demonstrated in practice. The commenters stated
that the limit has not been demonstrated in practice because the
permits impose a 1 mg/L non-methane hydrocarbon standard and the EPA
did not propose to exclude methane from the TOC measurement. The
commenters recommended that the EPA adopt a 10 mg/L TOC emission limit
(or some lower limit but higher than 1 mg/L) that has been adequately
demonstrated. According to one commenter, the only permits that they
identified with a 1 mg/L limit were for sources in nonattainment areas
subject to ``lowest achievable emission rate'' (LAER) requirements,
which do not consider cost. The BSER, on the other hand, allows costs
to be considered and the commenter stated that the 1 mg/L emission
limit is not cost-effective. A commenter provided an example cost
estimate, calculated cost effectiveness for each model plant, then
averaged those to indicate that the ``average'' cost effectiveness was
approximately $35,000 per ton VOC. Because the EPA noted that a cost of
$8,300 per ton VOC is not cost-effective, the commenter concluded that
the 1 mg/L emission limit is not cost-effective. One commenter
suggested that the assumption of 8,760 hours of operation for the RACT/
BACT/LAER Clearinghouse facility used to establish the 1.0 mg/L
emission limit for new sources is overly conservative and should be re-
evaluated and a lower new source emission limit should be established.
Response: First, we recognize that NSPS subpart XX allows methane
and ethane to be excluded from TOC as they are not VOC. However, based
on the typical composition of gasoline, we did not expect that there
would be appreciable quantities of methane or ethane in the gasoline
vapors and thus concluded that the emission limit would be the same
with or without the allowance to exclude methane and ethane. We also
understand that the non-dispersive infrared (NDIR) monitor, which is a
commonly used monitoring system for VRUs, can correct for methane
concentration but not for ethane concentration. In reviewing the test
and monitoring data for facilities meeting the 1.0 mg/L emission limit
as well as the 10 mg/L emission limit, we concluded that it is
possible, if not likely, that the reported TOC emissions already
exclude methane, because the applicable limits allow the exclusion of
methane from the TOC value and the instrument used to make the TOC
measurements can simultaneously assess methane concentration and output
non-methane TOC. These data are available in the docket. Because the
source test summaries we have likely do not report the methane
concentration measured, we cannot assess the impacts of including
methane in the TOC. However, given the high removal efficiencies of
VRUs achieving the 1.0 mg/L or 10 mg/L emission limit and the fact that
methane is not well-controlled by carbon adsorption, it is possible
that small quantities of methane in the gasoline vapors can
significantly contribute to the TOC in the VRU exhaust. We also
recognize that the 1.0 mg/L permit limit, upon which the new source
emission limit in the proposed NSPS subpart XXa was established, is in
terms of total non-methane hydrocarbon. While the contribution of
ethane can be excluded from TOC based on provisions in NSPS subpart XX,
the instruments commonly used to measure TOC cannot independently
measure and correct for the contribution of ethane in TOC. Considering
all of these factors, we are finalizing that the TOC emission limits
may exclude methane content if measured according to EPA approved
methods. We are not including provisions to exclude ethane content from
measured TOC. We are also finalizing recordkeeping and reporting
requirements that correspond to the revisions for excluding methane
content from the TOC emission limits.
With the allowance to exclude methane, we disagree that the 1.0 mg/
L TOC emission limit is not achievable. For example, the Buckeye Perth
Amboy Terminal's U24 gasoline loading racks have had a 1 mg/L emission
limit for nearly 10 years and we have two different source tests
conducted several years apart that indicate that the system readily
achieves a level of less than 1.0 mg/L non-methane TOC. In fact, while
the facility is achieving the 1.0 mg/L emission limit, one of the tests
indicated emissions of 0.6 mg/L non-methane TOC. However, considering
process and ambient temperature variability, this source test suggests
that a limit lower than 1.0 mg/L may not be achievable at all times. As
such, we conclude that the 1.0 mg/L (non-methane) TOC limit is
achievable and appropriate for new sources.
With respect to our cost analysis, we maintain, as detailed in the
June 10, 2022, proposal (87 FR 35622), that the 1.0 mg/L TOC emission
limit for new sources is cost-effective. The commenter
[[Page 39318]]
indicated that a VRU used to meet 1 mg/L rather than 10 mg/L would be
$300,000 more for all model plants. We disagree this is accurate for
all model plants. The information we received from a control device
manufacturer \5\ indicates that the smallest unit they make is
essentially for model plant 3. Nonetheless, we added $100,000 to the
cost of these smaller units when projecting the costs to meet 1 mg/L.
Additionally, we note that smaller facilities will likely use a thermal
oxidation system or flare instead of a VRU. For the largest facility
(model plant 5), we estimated increased costs of $150,000. If we accept
that a VRU for the largest model plant would cost an extra $300,000,
the cost effectiveness from 10 mg/L to 1 mg/L is under $3,000 per ton
of VOC, which we find cost-effective. We also note that the method used
by the commenter to calculate the average cost effectiveness is not the
way we calculate average cost effectiveness. We assess the total costs
across all affected facilities and divide by the cumulative emission
reductions across all affected facilities. Due to recent trends in
inflation, interest rates, and gasoline prices, we re-evaluated our
costs from 2019 dollars to 2021 dollars (the most recent year for which
wage and other cost factors are available). While costs increased,
product recovery credits also increased so the reanalysis did not alter
our conclusions (see memorandum Updated New Source Performance
Standards Review for Bulk Gasoline Terminals included in Docket ID No.
EPA-HQ-OAR-2020-0371). Therefore, we maintain that 1.0 mg/L (non-
methane) TOC is the standard of performance that reflects the BSER for
new sources.
---------------------------------------------------------------------------
\5\ See Docket ID No. EPA-HQ-OAR-2020-0371-0041.
---------------------------------------------------------------------------
Comment: One commenter noted that the EPA-proposed loading rack TOC
emission limit of 10 mg/L for modified and reconstructed sources is
less stringent than requirements for reconstructed sources that have
been successfully implemented in some States, such as Massachusetts
where loading rack emissions are limited to 2 mg/L in the permits for
five reconstructed bulk gasoline terminals. According to the commenter,
these standards should be viewed by the EPA as evidence of the cost
effectiveness of those requirements. On the other hand, one commenter
suggested that 35 mg/L is an appropriate standard for modified sources.
The commenter noted that the EPA concluded that it was not cost-
effective to require area source facilities to upgrade to 10 mg/L for
the NESHAP and the EPA failed to demonstrate why it would be cost-
effective for modified sources subject to the NSPS.
Response: Based on our cost analysis as provided in the proposal
(June 10, 2022; 87 FR 35622), we determined that it was not cost-
effective to require existing sources that are modified or
reconstructed to meet a 1 mg/L TOC emission limit. While we did not
specifically evaluate a 2 mg/L limit, we expect that the upgrades
needed to meet a 2 mg/L limit would be essentially the same as those
needed to meet a 1 mg/L limit and would likewise not be cost-effective.
With respect to differences in conclusion for modified and
reconstructed sources in NSPS subpart XXa as compared to the revised
standards for NESHAP subpart BBBBBB, the assessment that a 35 mg/L
limit was the appropriate level for NESHAP subpart BBBBBB was based on
the cost effectiveness of the HAP emission reductions, which were
estimated to be only 4 percent of the VOC emission reductions. However,
for the NSPS subpart XXa analysis, we found, when considering the VOC
emission reductions, that it was cost-effective for modified and
reconstructed sources to require control system upgrades to meet a 10
mg/L TOC limit. We therefore maintain that, when considering VOC
emission reductions, a 10 mg/L TOC limit is cost-effective and is the
standard of performance that reflects the BSER for modified and
reconstructed sources.
(C) Proposed Monitoring Requirements
Comment: Several commenters stated that the flare monitoring
provisions to meet the requirements in the Refinery NESHAP at 40 CFR
63.670 and that were proposed as an alternative for NESHAP subpart
BBBBBB are also appropriate for meeting the 10 mg/L TOC limit for
modified and reconstructed sources and therefore should be allowed as a
compliance alternative to continuous temperature monitoring for thermal
oxidation systems in NSPS subpart XXa and NESHAP subpart R subject to
the 10 mg/L emission limit. One commenter recommended that the
following revisions be made for ``flare provisions'' if added for
thermal oxidation systems meeting the 10 mg/L limit:
<bullet> Eliminate the flare tip velocity limit or allow its
determination using an engineering assessment.
<bullet> Eliminate the net heating value dilution
(NHV<INF>dil</INF>) operating parameter requirement because of
differences in refinery flares and gasoline distribution thermal
oxidation systems.
On the other hand, one commenter stated that the proposed flare
monitoring requirements were inadequate to demonstrate continuous
compliance. According to the commenter, net heating values of the gas
streams at gasoline distribution facilities exhibit significant
variability and 2 weeks of sampling cannot capture this variability.
Furthermore, the commenter noted, the proposed sampling allowance
incentivizes gasoline distribution facilities to sample when net
heating values are higher than normal to minimize (or eliminate) the
need to add supplemental fuel. Similarly, the commenter noted, the
proposed single sample collected when loading a single gasoline cargo
tank was not sufficient to determine compliance with the
NHV<INF>dil</INF> parameter. According to the commenter, continuous
composition or net heating value monitoring must be required for flares
(or grab sampling every 8 hours).
Response: We agree with the commenters who suggest that the flare
monitoring provisions are appropriate and can be allowed for thermal
oxidation systems subject to the 10 mg/L TOC emission limit, because
the thermal oxidation systems used in the gasoline distribution
industry are largely enclosed combustors. The flare monitoring
provisions are commensurate with meeting a 10 mg/L emission limit and
that is why we proposed that flares could be used to meet the 10 mg/L
emission limit for modified and reconstructed sources, but not for new
sources subject to the 1 mg/L emission limit.
We also agree that, because gasoline loading must be conducted at
low pressures (less than 18 inches of water pressure), it is very
unlikely that the flare tip velocity limits would ever be exceeded and
that a design evaluation could be conducted to assess the maximum
loading rate (vapor displacement rate) to determine if, based on the
flare tip diameter (and number of flare tips, if staged flare tip
design is used), the flare tip velocity would always be below 60 feet
per second. If so, net heating value measurements and continuous flow
monitoring would not be needed to demonstrate compliance with the flare
tip velocity limit. Therefore, we are including in the final NSPS
subpart XXa at 40 CFR 60.502a(c)(3)(ix) provisions to comply with the
flare tip velocity limit using the provisions as described earlier. We
are also specifying that records of these one-time flare tip velocity
assessment must be maintained for as long as the owner or operator is
using this compliance provision.
[[Page 39319]]
We disagree that these enclosed combustors cannot be over-assisted
and maintain that the proposed NHV<INF>dil</INF> operating limit is
needed. The air-assist operating parameter was developed based on a
flare manufacturer testing facility using propane or propylene as the
fuel with flare tips ranging from 1.5 inches to 24 inches in diameter.
As such, we consider these test data to be widely applicable to a
variety of industrial flares. We understand that the burner tips in
most thermal oxidation systems are staged with air-assist at each tip.
This would be similar to the 1.5-inch flare tip included in the study
data. The wind speeds during the test of this small flare were low,
typically under 5 miles per hour (mph), and the performance of the
flare was not a function of wind speed. The commenter provided no data
or reasonable argument to support the idea that enclosed combustors
cannot be over-assisted. Therefore, we are retaining the requirements
to meet the NHV<INF>dil</INF> operating limit.
While we agree that the flare monitoring requirements in the
Refinery NESHAP at 40 CFR 63.670 are reasonable for sources subject to
the 10 mg/L TOC emission limit, we also agree that the operating limits
included in 40 CFR 63.670 must be met at all times when liquid product
is loaded into gasoline cargo tanks. Based on the comments received, we
considered the impacts of different relative loading rates of gasoline
and diesel fuel (or other non-gasoline products) and agree that the net
heating value of vapors directed to the flare or thermal oxidation
system can vary significantly based on the types and the relative
volumes of products loaded. We expect that the provisions in 40 CFR
63.670(j)(6) are reasonable for flare gas streams that ``. . . have
consistent composition (or a fixed minimum net heating value) . . .''
and we expect that gasoline loading operations (loading only gasoline
products) would meet this criterion regardless of the grade of gasoline
loaded (regular, premium, or non-ethanol) as the net heating value of
the vapors would always be well above 270 Btu/scf. However, if other
liquid products are loaded into non-gasoline cargo tanks and the
displaced vapors from these loading operations are also sent to the
same flare, then the vapors discharged to the flare would not have a
consistent composition or a fixed minimum net heating value. Therefore,
we are clarifying in 40 CFR 60.502a(c)(3)(vii) that, for the purposes
of NSPS subpart XXa, the application for an exemption from monitoring
required under 40 CFR 63.670(j)(6) must include a minimum ratio of
gasoline loaded to total liquid product loaded and, if perimeter air-
assisted, a minimum gasoline loading rate. We consider this to be part
of the explanation of conditions that ensure that the flare gas net
heating value is consistent and of conditions expected to produce the
flare gas with lowest net heating value as required in 40 CFR
63.670(j)(6)(i)(C). We are also clarifying that, as required in 40 CFR
63.670(j)(6)(i)(D), samples must be collected at the conditions
expected to produce the flare gas with lowest net heating value as
identified in 40 CFR 63.670(j)(6)(i)(C), which includes the applicable
minimum gasoline loading rates identified in the application.
Furthermore, we are specifying that the affected source must
operate at or above the minimum values specified in its application at
all times when liquid product is loaded into cargo tanks for which
vapors collected are sent to the flare or, if applicable, to a thermal
oxidation system. We consider that the provisions of 40 CFR
63.670(j)(6) are reasonable and can be used to demonstrate that the net
heating value of the vapors collected and sent to the flare (or thermal
oxidation system) are sufficient to comply with the flare net heating
value operating limits. However, given the variability in net heating
values expected with the loading of different liquid products, we
determined that clarifying how the provisions of 40 CFR 63.670(j)(6)
should be applied for the gasoline distribution industry was
appropriate. We also concluded that it was critical to set these
minimum gasoline loading rates as operating limits to ensure continuous
compliance with the conditions tested as part of the application. For
flares (or thermal oxidation systems) that are unassisted or perimeter
air-assisted, the vent gas net heating value is the same as the
combustion zone net heating value (NHV<INF>cz</INF>). If the testing
conducted under 40 CFR 63.670(j)(6) as specified in 40 CFR
60.502a(c)(3)(vii) shows that the vent gas net heating value meets or
exceeds the NHV<INF>cz</INF> operating limit, compliance with the
minimum ratio of the volume of gasoline loaded to total liquid products
loaded can be used directly to demonstrate compliance with the
NHV<INF>cz</INF> operating limit. Similarly, for perimeter air-assisted
flares (or thermal oxidation systems), if the testing conducted under
40 CFR 63.670(j)(6) as specified in 40 CFR 60.502a(c)(3)(vii) shows
that the device meets or exceeds the NHV<INF>dil</INF> operating limit
at the highest fixed or highest air-assist rate used, then compliance
with the minimum gasoline loading rate can be used directly to
demonstrate compliance with the NHV<INF>dil</INF> operating limit.
We considered using the 15-minute block periods as specified in the
cross-referenced requirements in 40 CFR 63.670(e) and (f) for these
loading ratio or loading rate operating limits. However, we expected
there may be issues at the end of a loading event if gasoline loading
ended 1-minute into the next 15-minute block if the owner or operator
was required to meet a minimum gasoline loading rate for that 15-minute
block. Considering comments received on the 3-hour rolling average,
which suggested using 36 5-minute periods, we are finalizing provisions
at 40 CFR 60.502a(c)(3)(vii)(E) that the loading rate operating limit
will be monitored on 5-minute block periods and calculated on a rolling
15-minute period across three contiguous 5-minute block periods. We
used the term ``contiguous'' here to highlight that these periods are
connected without a break, unlike the ``consecutive'' periods used in
the definition of 3-hour rolling average. We also note that the
operating limits in 40 CFR 63.670(e) and (f), as modified in 40 CFR
60.502a(c)(3)(i), apply when ``vapors displaced from gasoline cargo
tanks during product loading is routed to the flare for at least 15-
minutes.'' For the liquid product loading operating limits used as an
alternative to meet 40 CFR 63.670(e) and (f), we are requiring these
limits be calculated on a rolling 15-minute period basis considering
only those periods when liquid product is loaded into gasoline cargo
tanks for any portion of three contiguous 5-minute block periods. The
phrase ``any portion of three contiguous 5-minute block periods''
reflects, in practice, how one would determine when ``vapors displaced
from gasoline cargo tanks during product loading is routed to the flare
for at least 15-minutes.'' If there is a 5-minute block when no liquid
product was loaded into gasoline cargo tanks, then the previous rolling
15-minute period would end and the next rolling 15-minute period would
not be calculated until there are three contiguous 5-minute block
periods in which liquid product was loaded into gasoline cargo tanks
for at least some portion of each of the three contiguous 5-minute
block periods. With these clarifications and added operating limits, we
conclude that the provisions allowing a one-time net heating value
determination according to the provisions of 40 CFR 63.670(j)(6) are
sufficient for demonstrating continuous
[[Page 39320]]
compliance with the net heating value operating limits.
With respect to the comment received opposing the proposed use of a
single sample while loading only gasoline to assess the
NHV<INF>dil</INF> operating limit, we note that this operating
parameter is an issue primarily when the waste gas flow rate is low.
Therefore, we sought to assess whether auxiliary fuel was needed to
ensure combustion at these low flow rates, which would occur when
loading a single gasoline cargo tank. However, upon further review, we
expect the NHV<INF>dil</INF> operating limit to be most difficult to
meet when the gasoline loading rate is at its minimum and the net
heating value is low (as when the ratio of the volume of gasoline
loaded to total liquid product loaded is at its minimum). Therefore, we
stipulated that facility owners or operators would have to establish
these minimums in their application and test the net heating value of
the vent gas under those circumstances. With these conditions clearly
delineated in the final provisions at 40 CFR 60.502a(c)(3)(vii), no
additional sampling requirements are needed in the proposed
requirements at 40 CFR 60.502a(c)(3)(ix), which are now included within
40 CFR 60.502a(c)(3)(viii) of the final rule. Consistent with the flare
provisions at 40 CFR 63.670(j)(6)(i)(F), a single value for the vent
gas net heating value (either the lowest single value or the 95th
percent confidence value) must be used for all vent gas flow rates.
Therefore, consistent with the provisions at 40 CFR 63.670(j)(6)(i)(F),
flare (or thermal oxidation system) owners or operators must use the
net heating value as determined based on the sampling conducted
consistent with their application under 40 CFR 63.670(j)(6). With the
elimination of the separate sampling protocol, we are combining the
revisions proposed at 40 CFR 60.502a(c)(3)(ix) with those proposed at
40 CFR 60.502a(c)(3)(viii). Thus, 40 CFR 60.502a(c)(3)(viii) now
contains a single assessment of the quantity of natural gas needed in
order to demonstrate continuous compliance with the NHV<INF>cz</INF>
operating limit and, if applicable, with the NHV<INF>dil</INF>
operating limit. Because the net heating value parameter used under 40
CFR 60.502a(c)(3)(viii) is now the one determined under 40 CFR
60.502a(c)(3)(vii), facilities electing this option would also have to
monitor and comply with the minimum ratio of gasoline to total liquid
products loaded and, if applicable, the minimum gasoline loading rate.
We also note that we expect far fewer facilities will use the minimum
supplemental gas addition rate option in 40 CFR 60.502a(c)(3)(viii)
because this option would only be needed if the owner or operator
cannot demonstrate compliance with the flare operating limits based
solely on the vent gas net heating value and the minimum ratio of
gasoline to total liquid products loaded and, if applicable, the
minimum gasoline loading rate as determined under 40 CFR
60.502a(c)(3)(vii).
Because the provisions in the final rule more clearly account for
the variability of the net heating value of the vapors sent to the
flare based on the different liquid products loaded, we consider the
final provisions to be more robust than those initially proposed and we
consider them reasonable and appropriate for demonstrating continuous
compliance with the flare provisions or for a thermal oxidation system
subject to a 10 mg/L TOC emission limit. Therefore, we are finalizing
the flare monitoring alternative for thermal oxidation systems for
modified or reconstructed gasoline loading rack affected facilities
under NSPS subpart XXa. Because NESHAP subpart R also has a 10 mg/L
emission limit, we determined that the flare monitoring alternative in
NSPS subpart XXa can be used for thermal oxidation systems used to
control emissions from loading racks at bulk gasoline terminals subject
to NESHAP subpart R. We are also retaining the proposed provisions that
thermal oxidation systems used to control emissions from loading racks
at bulk gasoline terminals subject to NESHAP subpart BBBBBB can use
these flare monitoring alternatives in NSPS subpart XXa.
Comment: Several commenters objected to the proposed definition of
a ``3-hour rolling average.'' According to the commenters, regulated
parties cannot comply with the proposed definition because they cannot
determine the point in time when ``all emissions from the loading event
have cleared the control device'' particularly for VRUs. According to
the commenter, vapors from loading may be processed and recovered in a
VRU well after active loading is completed. The commenters recommended
that this phrase be deleted from the proposed definition of ``3-hour
rolling average.'' One commenter noted that the proposed definition of
``3-hour rolling average'' differs significantly from industry practice
and, thus, would require a reprogramming of the programmable logic
controllers for virtually all existing units, as well as likely
revision of thousands of permits. One commenter noted that the clause,
``periods when gasoline loading is not being conducted are not
considered valid data,'' is inconsistent with the definition of
gasoline cargo tank, where diesel fuel loading into a cargo tank that
previously had gasoline should be counted, and so the entire sentence
should be deleted. The commenter also suggested that the 3-hour average
should be clarified to consist of thirty-six 5-minute periods of valid
data. One commenter noted that data from periods when gasoline loading
is not being conducted may be necessary to demonstrate compliance with
permit or other requirements. Commenters also recommended that, because
the performance test is a 6-hour test, the EPA should use a 6-hour
rolling average for the proposed concentration limits for VRUs (rather
than a 3-hour rolling average). According to commenters, the 3-hour
averaging time makes the standard more stringent, and the longer 6-hour
averaging period for the emission limit (or operating parameter) would
be more representative of the conditions seen throughout the day.
According to some commenters, the 3-hour average combined with the
numerical limit established for VRUs will either require upgrades of
control systems or result in either slowdowns or shutdowns of gasoline
loading during the heat of the day, creating artificial fuel
availability constraints.
Response: First, we agree with commenters that it is difficult to
know when all vapors have cleared the control device system,
particularly when a vapor recovery system is used. When a vapor
recovery system is used, there may be emissions during carbon bed
regeneration even when there is no liquid product being loaded into
gasoline cargo tanks. For thermal oxidation systems, on the other hand,
the vapors clear the control device in a matter of a minute or two.
Therefore, rather than using this general phrase within the definition
of ``3-hour rolling average,'' we are specifying within the control
device-specific requirements in 40 CFR 60.502a what constitutes valid
data that must be included in the 3-hour rolling average. For vapor
recovery systems, the 3-hour rolling average concentration emission
limit applies during all periods when the vapor recovery system is
operating, which may include times when no liquid product is being
loaded but the system is still online and capable of processing
gasoline vapors. We also note that the vapor recovery system must be
operating, at a minimum, whenever liquid product is loaded into
gasoline cargo tanks. For thermal oxidation
[[Page 39321]]
systems, where the gasoline vapors quickly pass through the control
system, the 3-hour rolling average applies specifically when liquid
product is loaded into gasoline cargo tanks.
We agree with the commenter who noted that the definition of
gasoline cargo tank includes tank trucks or railcars into which
gasoline is being loaded or that contained gasoline on the immediately
previous load. There are several places in the proposed rules where we
used ``loading gasoline'' when the correct term is ``loading liquid
product into a gasoline cargo tank.'' We are revising this terminology
throughout each of the gasoline distribution rules. We also are
clarifying (in the description of the monitored parameter, i.e.,
combustion zone temperature) how the ``previous load'' impacts the
valid data for the operating limit. If an owner or operator has
information on previous cargo tank contents, then they may exclude from
the 3-hour rolling average those periods when there is liquid product
being loaded but there are no gasoline cargo tanks being loaded. If an
owner or operator does not have information on previous cargo tank
contents, then they must assume that liquid product loading is loaded
into a gasoline cargo tank and must meet the operating limit during
periods of liquid product loading, because the cargo tank could have
contained gasoline on the immediately previous load. All owners or
operators of thermal oxidizer systems must exclude from the 3-hour
rolling average those periods when there is no liquid product being
loaded. Because we acknowledge that liquid product loading can be very
intermittent, we agree that the operating limit should be evaluated on
5-minute periods. If any liquid product is loaded into a gasoline cargo
tank during a 5-minute period, that 5-minute period must be included in
the 3-hour rolling average.
With respect to the stringency of the 3-hour rolling average
combined with the concentration limit established for VRUs, we first
note that we used direct calculation of vapors displaced during loading
to determine the concentration limit equivalent to the 1.0 and 10 mg/L
TOC emission limits. We also note that the current rules do not specify
an averaging time for the operating parameters. As discussed in the
preamble of the June 10, 2022, proposal (87 FR 35618), part of our
motivation in setting numerical concentration standards and
establishing specific timeframes for operating limits is to make
requirements for all gasoline distribution facilities consistent. While
we recognize that the performance test is 6 hours in duration for
thermal oxidation systems, there is no longer a performance test for
VRUs. Owners or operators of VRUs must conduct performance evaluations
of their TOC continuous emission monitoring system (CEMS). The
performance evaluation consists of a minimum of nine test runs, with
each test run being a sampling traverse of a minimum of 21 minutes in
duration. Thus, the performance evaluation is a minimum of 189 minutes
in duration, which is approximately 3 hours. We selected a 3-hour
average to be consistent with the duration of the performance
evaluation. We also proposed that the temperature operating limit for
thermal oxidation systems will be determined on a 3-hour rolling
average basis and provided specific requirements on how that 3-hour
rolling average temperature operating limit must be developed.
Upon consideration of the comments received, we are maintaining the
use of a 3-hour rolling average for CEMS and operating parameters used
to demonstrate continuous compliance. However, we are revising and
clarifying the definition of ``3-hour rolling average'' to more clearly
delineate data that must be included in the 3-hour rolling average
based on the type of control system used and more appropriately to use
the phrase ``gasoline cargo tank'' and account for periods when a non-
gasoline product is loaded into a cargo tank that contained gasoline
during its previous load.
(D) Proposed VRU Operation To Minimize Air Intrusion
Comment: Several commenters expressed concern over the EPA's
proposed requirement that only vacuum breaker valves can be used to
introduce ambient air into the VRU control system in order to prevent
dilution of the emissions measurement. According to the commenters, the
proposed rule could, if misinterpreted, impact the design and operation
of carbon-based vapor recovery units. The use of pressure swing
adsorption is the underlying basis for most, if not all, VRUs in
operation in the U.S. According to the commenters, the use of purge air
at the completion of a regeneration cycle (while the system is under
vacuum) is a critical step in the operation of a VRU and is integral to
its effectiveness.
Response: We understand the concern commenters have with the
proposed requirements that only vacuum breaker valves can be used to
introduce ambient air into the VRU. Both operators and control device
manufacturers have indicated that the introduction of some purge air
(or nitrogen) while the unit is under vacuum is critical for effective
VRU performance. Upon review of the information provided by commenters,
we are revising 40 CFR 60.502a(b)(2)(iii) and (c)(2)(iii) to require
the facility to ``[o]perate the vapor recovery system to minimize air
or nitrogen intrusion except as needed for the system to operate as
designed for the purpose of removing VOC from the adsorption media or
to break vacuum in the system and bring the system back to atmospheric
pressure. Consistent with Sec. 60.12, the use of gaseous diluents to
achieve compliance with a standard which is based on the concentration
of a pollutant in the gases discharged to the atmosphere is
prohibited.''
iv. What is the rationale for the EPA's final approach for the NSPS
review?
As described in the preamble to the June 2022 proposal (87 FR
35622; June 10, 2022), we determined that the BSER was VRU with
submerged loading for new bulk gasoline terminals and the TOC emission
limitation that reflects the application of the BSER is 1.0 mg/L. For
systems with a VRU, this is a concentration of 550 ppmv TOC (as
propane), which we determined was equivalent to an emission limit of
1.0 mg/L. We also determined in the June 2022 proposal that the BSER
for modified or reconstructed bulk gasoline terminals was VRU with
submerged loading and the TOC emission limitation that reflects the
application of the BSER is 10 mg/L. For systems using a VRU, this is a
concentration of 5,500 ppmv TOC (as propane), which we determined was
equivalent to an emission limit of 10 mg/L. Consistent with our
proposed BSER analysis, we are finalizing our determination that the
BSER is VRU and the loading rack TOC emission limits are 1.0 mg/L, or
550 ppmv TOC (as propane) for facilities controlled with vapor recovery
systems, for new bulk gasoline terminals and 10 mg/L, or 5,500 ppmv TOC
(as propane) for facilities controlled with vapor recovery systems, for
modified or reconstructed bulk gasoline terminals, as proposed except
that we are allowing the exclusion of methane from the measured TOC for
reasons discussed in section III.A.1.a.iii of this preamble. With the
exclusion of methane, we are finalizing additional test methods
applicable for non-methane organic carbon and additional reporting
requirements to indicate whether the measurement method used in the
performance test or CEMS corrects for methane concentration. We are
also finalizing recordkeeping and reporting requirements that
correspond to the
[[Page 39322]]
revisions for excluding methane content from the TOC emission limits.
For reasons discussed in section III.A.1.a.iii of this preamble, we
are finalizing two separate affected facilities definitions for NSPS
subpart XXa: ``gasoline loading rack affected facility'' and
``collection of equipment at a bulk gasoline terminal affected
facility.'' The ``gasoline loading rack affected facility'' definition
being finalized is similar to the affected facility definition in NSPS
subpart XX. We are providing separate affected facilities definitions
to expand the equipment leak provisions to all equipment in gasoline
service at the bulk gasoline terminal, so that the equipment changes
that are remote from the loading racks and associated vapor processing
system do not trigger a modification to the loading rack affected
facility.
Because flares can be used to comply with the 10 mg/L TOC emission
limit and because many thermal oxidation systems used in the gasoline
distribution industry are enclosed combustors, we find that the flare
monitoring alternatives are appropriate for thermal oxidation systems
required to meet the 10 mg/L emission limit. We are clarifying in the
final rule at 40 CFR 60.502a(c)(3)(vii) the requirements for using one-
time assessment of net heating value for vapors with consistent
composition or a minimum net heating value as provided in 40 CFR
63.670(j)(6) when vapors from loading of different liquid products are
processed by the flare or thermal oxidation system. We are requiring
facilities using this one-time assessment to monitor gasoline and total
liquid product loading rates and maintain the ratio of gasoline to
total liquid product loaded above the levels in their application under
40 CFR 63.670(j)(6). For perimeter air-assisted flares or thermal
oxidation systems, gasoline loading rates must also be maintained as
levels at or above the minimum gasoline loading rates specified in
their application under 40 CFR 63.670(j)(6). We are also finalizing
recordkeeping and reporting requirements that correspond to the
requirements to maintain a minimum ratio of gasoline to total liquid
product loaded and, if applicable, a minimum gasoline loading rate.
For reasons described in section III.A.1.a.iii.C of this preamble,
we are finalizing a provision at 40 CFR 60.502a(c)(3)(ix) for
conducting a one-time engineering assessment as a means to demonstrate
compliance with the flare tip velocity operating limits. We are also
finalizing recordkeeping requirements related to this one-time
assessment when this compliance method is used.
We are finalizing revised provisions at 40 CFR 60.502a(b)(2)(iii)
and (c)(2)(iii) to allow some purge air or nitrogen to be introduced
while the system is under vacuum and being regenerated as needed to
effectively remove VOC from the adsorption media, based on evaluation
of comments received. We based the final NSPS limits largely on the
emission limits achieved by VRUs in practice. We found the description
of the process, especially from the carbon adsorption system vendors,
compelling, and we did not intend for our proposal to alter the
regeneration methods used for the control systems upon which the BSER
was established. Our final provision regarding the vacuum purge retains
the limitation that, consistent with 40 CFR 60.12, the use of gaseous
diluents to achieve compliance with a standard which is based on the
concentration of a pollutant in the gases discharged to the atmosphere
is prohibited.
After a review of all the comments, we are adding details of the
time periods that must be included or excluded from the 3-hour rolling
average as part of the requirements of the monitoring operating
parameters. This allows us to specify the time periods applicable to
different control devices rather than using the general phrase ``all
emissions from the loading event have cleared the control device.'' For
thermal oxidation systems, we are clarifying that the operating limits
apply at all times when liquid product is loaded into gasoline cargo
tanks. We are also finalizing requirements that, if the immediately
previous load of a cargo tank is not known, then the cargo tank must be
assumed to be a gasoline cargo tank. We are also finalizing
requirements that periods when there is no liquid product loading must
be excluded from the 3-hour rolling average. For vapor recovery
systems, we are clarifying that the operating limits apply at all times
that the vapor system is operating, because emissions can come from the
regeneration of a carbon bed even though there is no liquid product
loading. We are also adding recordkeeping and reporting requirements
related to periods when gasoline cargo tanks are being loaded as well
as an indication as to whether cargo tanks are assumed to be gasoline
cargo tanks because the previous load of the cargo tank being loaded is
unknown.
With these specific time frames moved to the description of the
monitoring requirements for the monitored parameters, we are finalizing
the definition at 40 CFR 60.501a of ``3-hour rolling average'' as
follows:
3-hour rolling average means the arithmetic mean of the previous
thirty-six 5-minute periods of valid operating data collected, as
specified, for the monitored parameter. Valid data excludes data
collected during periods when the monitoring system is out of control,
while conducting repairs associated with periods when the monitoring
system is out of control, or while conducting required monitoring
system quality assurance or quality control activities. The thirty-six
5-minute periods should be consecutive, but not necessarily continuous
if operations or the collection of valid data were intermittent.
b. NESHAP Subpart R
i. What did the EPA propose pursuant to CAA section 112(d)(6) for the
major source gasoline distribution source category?
Based on our technology review for loading racks at major sources,
we proposed to retain the 10 mg/L TOC emission limit currently required
in NESHAP subpart R. However, we proposed that the 10 mg/L TOC emission
limit would apply to loading racks controlled by thermal oxidation
systems or flares. For thermal oxidation systems, we proposed
continuous compliance with a temperature operating limit established as
the lowest 3-hour average temperature from a compliant performance
test. For flares, we proposed enhanced provisions to ensure good
combustion efficiency. For loading racks controlled by VRUs, we
proposed to express this emission limit in terms of a concentration
limit of 5,500 ppmv TOC (as propane) on a 3-hour rolling average
because this provides an equivalent emission limit that is directly
enforceable with the common monitoring systems used for VRUs. To
prevent dilution, we proposed that only vacuum breaker valves can be
used to introduce ambient air into the VRU control system.
ii. How did the technology review change for gasoline loading racks at
major source gasoline distribution facilities?
The are no significant changes in the technology review conclusions
for loading racks at major source gasoline distribution facilities.
iii. What key comments did the EPA receive and what are the EPA's
responses?
Several commenters supported the conclusion to maintain the 10 mg/L
[[Page 39323]]
TOC emission limit for major source gasoline distribution facilities.
iv. What is the rationale for the EPA's final approach for the
technology review?
We are finalizing the loading rack emission limits as proposed.
Because many of the specific monitoring requirements cross-reference
provisions in NSPS subpart XXa, revisions related to allowing the
exclusion of methane from measured TOC, allowance for thermal oxidation
systems to use the flare monitoring provisions, use of vacuum purge gas
for VRUs, and revisions to the definition of 3-hour rolling average
also impact the final requirements and associated recordkeeping and
reporting requirements for gasoline loading operations at major source
facilities. Our rationale for these revisions is summarized in section
III.A.1.a.iv of this preamble.
At proposal, we specifically excluded reference to 40 CFR
60.504a(d) at proposed 40 CFR 63.428(d) because we did not intend to
require facilities subject to NESHAP subpart R to install pressure CPMS
on existing loading racks. However, we note that the cross-referenced
standards at 40 CFR 60.502(h) indicate that pressure must be monitored
continuously as specified in 40 CFR 60.504a(d). In reviewing the final
requirements, we determined that it was reasonable to allow facilities
that have a pressure CPMS to use it for this compliance, but that
additional language was needed to expressly provide pressure monitoring
during performance tests or performance evaluations that we intended to
allow. Therefore, we are adding an alternative monitoring provision at
40 CFR 63.427(f) that allows pressure monitoring during performances
tests or performance evaluations following the provisions in 40 CFR
60.503(d) to determine that the system is appropriately designed and
operated at or below a pressure of 18 inches of water during product
loading as an alternative to using a pressure CPMS.
c. NESHAP Subpart BBBBBB
i. What did the EPA propose pursuant to CAA section 112(d)(6) for the
area source gasoline distribution source category?
Based on our technology review for loading racks at area sources,
we proposed to lower the allowable TOC emission limit from 80 mg/L to
35 mg/L for large bulk gasoline terminals in NESHAP subpart BBBBBB. We
proposed that the 35 mg/L TOC emission limit would apply to loading
racks controlled by thermal oxidation systems or flares. For thermal
oxidation systems, we proposed continuous compliance with a temperature
operating limit established as the lowest 3-hour average temperature
from a compliant performance test and proposed enhanced provisions for
flares to ensure good combustion efficiency. We proposed to allow the
use of a ``flare monitoring alternative'' as an alternative to the
temperature operating limit for thermal oxidation systems. For loading
racks controlled by VRUs, we proposed to express this emission limit in
terms of a concentration limit of 19,200 ppmv TOC as propane on a 3-
hour rolling average because this provides an equivalent emission limit
that is directly enforceable with the common monitoring systems used
for VRUs. To prevent dilution, we proposed that only vacuum breaker
valves can be used to introduce ambient air into the VRU control
system. For loading racks at small bulk terminals, we proposed to
retain submerged filling currently required in NESHAP subpart BBBBBB.
For bulk gasoline plants, we proposed to add requirements to use
vapor balancing between gasoline cargo tanks and gasoline storage
vessels for bulk gasoline plants with a gasoline throughput over 4,000
gallons per day. We proposed to require pressure relief valves on fixed
roof tanks used in vapor balancing to have opening pressures set no
less than 2.5 psig.
ii. How did the technology review change for gasoline loading racks at
area source gasoline distribution facilities?
We did not revise our proposed technology review for bulk gasoline
terminals. We revised the proposed vapor balancing provisions to apply
to bulk gasoline plants that have an actual throughput of 4,000 gallons
per day or more on an annual average basis rather than using maximum
calculated design throughput. We also revised the vapor balancing
storage tank provisions regarding the minimum pressure relief device
opening pressure, reducing it from 2.5 psig to 18 inches of water (0.65
psig).
iii. What key comments did the EPA receive and what are the EPA's
responses?
Comment: Several commenters supported the EPA's proposal to reduce
the emission limit for gasoline loading racks at large bulk gasoline
terminals from 80 mg/L TOC to 35 mg/L TOC, noting that control systems
to meet 35 mg/L TOC are ``generally available'' and cost-effective. One
commenter further noted that area source facilities are not large HAP
emitters (by definition) and should not be subject to the 10 mg/L TOC
emission limit that the EPA considered. Another commenter agreed that
it is not cost-effective to require vapor collection and control for
``small bulk gasoline terminals'' and provided cost estimates for four
example small terminals. A couple commenters also suggested that the
EPA underestimated the costs for ``large bulk gasoline terminals'' to
meet a 10 mg/L emission limit, so the EPA should retain the proposed 35
mg/L limit and not reduce it to 10 mg/L.
Response: The EPA appreciates the support for reducing the TOC
emission limit for gasoline loading racks at large bulk gasoline
terminals from 80 mg/L to 35 mg/L. As discussed in our June 2022
proposal, we agree that further reducing the emission limits for area
source bulk gasoline terminals is not cost-effective (87 FR 35620; June
10, 2022). We are finalizing the 35 mg/L TOC emission limit for large
bulk gasoline terminals at area source gasoline distribution
facilities.
Comment: One commenter stated that the EPA significantly
underestimated the economic impact of the proposed rule on small
business energy marketers. Based on survey results presented in the
comment, the commenter stated that dropping the current compliance
threshold from a 20,000 gallon maximum daily design threshold to 4,000
gallons would pull virtually every small bulk gasoline plant into vapor
balancing requirements, forcing small energy marketers out of the
wholesale gasoline market. The commenter stated that using a maximum
daily design throughput as a threshold for compliance is not an
accurate or meaningful method to control emissions from bulk gasoline
plants, which may be assessed based on the size of the storage tank at
the facility, and suggested the actual daily throughput averaged over a
longer time period, like a month, is a better method to establish a
compliance threshold without placing a heavier burden on small bulk
gasoline plants than necessary.
Response: We identified several states with these requirements and
expected that many existing cargo tanks would be fitted with
appropriate piping to accommodate vapor balancing, which would minimize
the impacts of the proposed requirements. We note that the State
requirements we reviewed each applied the vapor balancing requirement
to bulk gasoline plants with daily throughputs of 4,000 gallons per day
or more. In reviewing these requirements more closely, we found
[[Page 39324]]
that these daily averages were to be calculated on a monthly or annual
average basis. When we evaluated the costs and cost effectiveness of
requiring smaller bulk gasoline plants to use submerged loading and
concluded that it was not cost-effective for them to do so, we based
our analysis on the actual average throughput values, not design
capacity values.
We used the maximum calculated design throughput to use consistent
terminology with how a facility determines their gasoline distribution
facility type (e.g., bulk gasoline plant or bulk gasoline terminal).
Based on previous analyses, we estimated that there were 5,913 bulk
gasoline plants, 1,715 of which already had vapor balancing for both
deliveries and loading. We estimated that 270 bulk gasoline plants
would need to add vapor balancing to either deliveries or loading, and
2,095 bulk gasoline plants would need to add vapor balancing to both
deliveries and loading. The remaining 1,833 bulk gasoline plants were
projected to be exempt from the vapor balancing requirement since their
throughput is less than 4,000 gallons per day. Thus, we projected that
at least 30 percent of bulk gasoline plants could use the throughput
exemption. Consistent with our analysis and the State rule requirements
used to support our proposal (87 FR 35621; June 10, 2022), we are
revising the 4,000 gallon per day threshold to be based on an actual
throughput basis. We note that table 1, item 1(ii), of NESHAP subpart
BBBBBB contains a provision to calculate the average daily throughput
of gasoline storage tanks using an annual averaging time. In addition,
table 2 of NESHAP subpart BBBBBB uses annual averaging time to
determine control requirements for bulk gasoline terminals. Therefore,
because the State requirements we reviewed used an annual averaging
time, and because NESHAP subpart BBBBBB already contains provisions
using an annual averaging time, we are finalizing the requirement to
use an annual averaging time. Additionally, we selected the annual
averaging time because we expected an annual average to be more
consistent, with less chance of facilities fluctuating from below to
above the threshold than when a monthly or daily averaging time is
used.
We also added requirements to maintain records of gasoline
throughput and the time frame in which to add vapor balancing controls
if a bulk gasoline plant newly triggers the requirement. With the
revision to use actual throughput rather than capacity, we determined
that the economic impacts we estimated at proposal for bulk gasoline
plants are reasonable and accurate. That is, we expected that a
significant number of bulk gasoline plants will be below the
applicability threshold we proposed, but our evaluations were based
largely on applicability to State rules and other assessments that were
based on actual throughputs. Therefore, we agree that we likely
understated the impact of the proposed provisions for vapor balancing
at bulk gasoline plants based on a maximum calculated design
throughput. However, with the revision of the thresholds to an actual
throughput basis, our previous projections of the number of facilities
impacted by the vapor balancing requirements are now accurate and
commensurate with the final rule requirements. Therefore, we are
finalizing the proposed vapor balancing requirements, but only for bulk
gasoline plants that have an actual throughput of 4,000 gallons per day
assessed on an annual average basis.
Comment: Some commenters stated that the pressure relief device
setting of no less than 2.5 psig for fixed roof storage tanks would
exceed safe pressure for some storage tanks and should be removed from
both the vapor balancing and fixed roof storage tank requirements in
proposed NESHAP subpart BBBBBB.
Response: We understood most conservation (pressure relief) vents
on atmospheric tanks use a release pressure of 2.5 psig or less.
Considering the storage of gasoline, which has a partial pressure of
over 3 psia, it would seem that fixed roof tanks would vent frequently
if the conservation vents open at a pressure under 2.5 psig. In the
proposal, we therefore expected 2.5 psig to be a reasonable requirement
for pressure relief devices used for vapor balancing and on fixed roof
storage tanks. However, based on our research concerning this comment,
we now understand that ``atmospheric tanks'' are generally designed to
operate between atmospheric pressure up to 2.5 psig and that ``low
pressure tanks'' are designed to operate between 2.5 and 15 psig. Thus,
the proposed requirement would be readily achievable for low-pressure
tanks, but pressure relief devices on atmospheric tanks would generally
begin to relieve pressure below 2.5 psig (typically between 0.8 and 1.5
psig). Essentially, the proposed requirement would require storage
tanks at bulk gasoline plants subject to the proposed vapor balancing
requirement and small, low throughput tanks at area source gasoline
distribution facilities to replace some atmospheric storage tanks with
low-pressure tanks. It is unclear what fraction of existing gasoline
storage tanks are of low-pressure design that may be able to meet this
pressure requirement, but it is expected that a significant number of
existing gasoline storage tanks are atmospheric tanks and would thus
need to be replaced to meet this requirement. We had not considered
these additional costs at proposal. Equipment costs are estimated to be
about $50,000 per tank, so installed costs (including removal of the
old tank) are about $100,000 per tank not considering business
interruptions during tank replacement. We project that, for a 10,000
gallon per day throughput bulk gasoline plant, the vapor balancing
requirement with a tank replacement to meet the 2.5 psig minimum
pressure relief limit would have cost $70,000 per ton of HAP reduced.
This would not be cost-effective for the HAP emitted by these sources.
The existing requirements in the gasoline distribution rules require
that no pressure relief device open at pressures less than 18 inches of
water, which is 0.65 psia. Based on this existing requirement, we
expect that atmospheric storage vessels used at gasoline distribution
facilities would not have devices opening at less than 0.65 psia.
Therefore, we agree with commenters that the 2.5 psig requirement for
pressure relief devices associated with fixed roof tanks and vapor
balancing is not technically feasible without replacing numerous
atmospheric storage tanks. We determined that replacing these
atmospheric storage tanks is not cost-effective for the HAP emitted by
these sources. Because our proposed standards required the vapor
balancing system to be operated at pressures less than 18 inches of
water column with no pressure relief device opening at pressures less
than 18 inches of water column, and because fixed roof storage tanks
are part of the vapor balancing system, we are finalizing that the
appropriate minimum pressure relief device opening pressure for fixed
roof storage tanks should be 18 inches of water column (0.65 psia).
Comment: Several commenters recommended that area sources using
thermal oxidation systems should be able to utilize alternative
monitoring protocols to temperature continuous parametric monitoring
systems (CPMS) currently in NESHAP subpart BBBBBB. While temperature
CPMS are required for major sources complying with the 10 mg/L TOC
emission limit, according to the commenters, a temperature CPMS is not
needed to demonstrate compliance with a 35 mg/L limit. The commenters
[[Page 39325]]
suggested that there would be no, or very small, emission reductions
gained by a temperature CPMS, the emission reductions would not be
worth the costs, and there would be additional secondary emissions
resulting from increased fuel use to maintain temperatures during
periods of low loading rates. The commenters stated that stack
temperature monitoring is inappropriate and unnecessary to meet a 35
mg/L TOC limit. Temperatures often decrease during periods of low
loading, but these low temperatures do not signal poor combustion
efficiency, rather, low heat release rates due to lower flows. One
commenter further indicated that temperature is not indicative of
thermal oxidation system performance, providing a 2006 performance
test, which, according to the commenter, demonstrated that high
combustion efficiency and low emissions were achieved at low (as well
as high) temperatures. The commenters suggested that the EPA should
allow for the use of the existing thermal oxidation system monitoring
alternative in NESHAP subpart BBBBBB.
According to the commenters, the EPA is on record indicating that
pilot flame monitoring is sufficient for area sources [to meet 80 mg/L]
and has not provided justification why it is not sufficient now. One
commenter also stated that the EPA provided no justification as to why
the flare requirements are applicable to these thermal oxidation
systems or why they provide better assurance than the current
alternative provisions. The commenter also stated that the cost impacts
for this proposed ``flare'' alternative were understated. The commenter
suggested that, if the EPA believes more continuous monitoring of
proper operation of the air-assist blower and vapor line valve is
needed, the EPA could revise existing language at 40 CFR
63.11092(b)(1)(iii)(B)(2)(ii) to require only automated alarms and
shutdown (rather than to perform daily visual observations).
One trade organization requested source test data from member
facilities that are subject to emission limits above 10 mg/L and that
do not use auxiliary fuel. Over 60 source tests were submitted and each
one showed emissions meeting the 35 mg/L limit. The commenter concluded
that this demonstrates that gasoline vapors are highly combustible and
auxiliary fuel is not needed.
Response: While several commenters appeared to oppose the
temperature operating limit, we note that the existing NESHAP subpart
BBBBBB also has a temperature operating limit as a compliance option.
We disagree with the commenters suggesting that temperature is not a
good indicator of performance. Based on the data provided by the
commenter, while there are periods of high combustion efficiency and
low emissions when the temperature is low, the temperature versus
emission rate and temperature versus efficiency graphs showed that all
exceedances of 35 mg/L (or control efficiencies less than 98 percent)
were at temperatures under 900 [deg]F. Thus, one can conclude from the
data presented that operating at a minimum combustion temperature of
900 [deg]F would ensure that the source would meet the 35 mg/L emission
limit at all times. We therefore conclude that setting a minimum
operating temperature is a reasonable continuous compliance method.
Second, we note that we proposed an alternative compliance option
to the temperature operating limit. The key difference between the
existing and our proposed alternative to temperature monitoring in
NESHAP subpart BBBBBB is that the proposed alternative is designed to
ensure that the combustion unit is not over assisted. We proposed this
more rigorous compliance alternative because the applicable emission
limit was lowered from 80 mg/L to 35 mg/L and due to our improved
understanding of air-assisted combustion devices gained over the past
10 years. The proposed monitoring alternative is similar to the
previous NESHAP subpart BBBBBB requirements with respect to continuous
pilot flame monitoring. However, we found that the previous NESHAP
subpart BBBBBB requirements, which included daily visual inspection to
verify the proper operation of the air-assist blower and the vapor line
valve, would not ensure good combustion during periods of low flow if
the air blower is set at a high, fixed level to prevent smoking during
periods of high gasoline vapor flow. That is, many of the vapor
combustors used at gasoline distribution facilities are essentially
enclosed air-assisted flares and the existing requirements in NESHAP
subpart BBBBBB did not prevent over-assisting the combustor during low
flow events. Therefore, we proposed a more substantive alternative to
direct temperature monitoring to ensure that these combustors are
meeting the applicable emission limit at all times, including periods
of low gasoline vapor flow.
While the proposed requirements are more substantive, there are
parallels with the existing requirements. For example, proper
functioning of the air-assist blower could be simply an assessment of
whether the blower is on or not. This requirement would not prevent
over-assisting the combustor. However, if a multispeed air blower is
used, proper functioning of the air-assist blower could consider that
the air-assist rates are low during low gasoline vapor flow rates and
higher at higher vapor flow rates, which could help to prevent over-
assisting. Proper functioning of the vapor line valve should prevent
very low flows to the combustion unit, since the vapor line valve would
remain closed until a set pressure is exceeded. Without the vapor line
valve, the vapor flow rate could approach zero, such that the allowable
air-assist rate would also approach zero. However, with the vapor line
valve, the minimum vapor line flow is a step function above zero. This
means the air-assist blower can remain on at some low flow setting
because gasoline vapor flow will always be some step above zero based
on the pressure setting for the vapor line valve. One can consider the
proposed requirements to be a more detailed requirement of the
provisions in 40 CFR 63.11092(b)(1)(iii)(B)(2)(ii) ``. . . the proper
operation of the assist-air blower and the vapor line valve.'' For low
gasoline vapor flows, low air-assist rates are needed to prevent over-
assisting the combustor. For higher gasoline vapor flows, higher air-
assist rates may be needed to prevent smoking from the combustor. Thus,
in context of the proposed rule, proper operation of the air-assist
blower would translate to using an appropriate air-assist rate relative
to the gasoline vapor flow rate, and the proper operation of the vapor
line valve should prevent very low flows to the combustion unit,
allowing a lower air-assist flow rate to be determined.
We proposed to allow an initial assessment of net heating values of
gasoline vapors to see if auxiliary fuel is needed to meet the
combustion zone net heating value. For unassisted or air-assisted
flares, we expect gasoline vapors will routinely exceed the minimum
required combustion zone net heating value. The combustion zone net
heating value operating limit becomes more important if steam assist is
used. For gasoline distribution facilities that use air-assisted
thermal oxidation systems or flares, it is possible that the air-assist
rate may be too high during periods of low gasoline vapor flow and
overdilute the gasoline vapors prior to effective combustion. We
proposed that facilities could use an assessment of the flow rate when
only loading one cargo tank to project the low flow rate by which to
assess whether the air-assist
[[Page 39326]]
flow rate is low enough not to over-assist the flare during low flow
events. As noted in response to comments regarding the monitoring
provisions for thermal oxidation systems and flares in section
III.A.1.a.iii.C of this preamble, we have revised and clarified the
requirements for the initial assessment of net heating values at 40 CFR
60.502a(c)(3)(vii) and allow owners or operators to establish a minimum
gasoline loading rate operating limit, in addition to a minimum ratio
of gasoline to total product loading rate, that can be used to ensure
vapor flow rates are high enough for a set air-assist rate to
demonstrate compliance with the NHV<INF>dil</INF> operating parameter.
If the air-assist rate is too high, facilities can lower the air-assist
rate or add auxiliary fuel according to the provisions in 40 CFR
60.502a(c)(3)(viii) to ensure that enough heat release is provided to
ensure high combustion efficiencies at low flow rates.
We appreciate the data collected and provided by the commenter that
showed many facilities could meet the 35 mg/L TOC emission limit
without the use of auxiliary fuel. We expect some facilities will
conduct sampling of their heat content and assess their air addition
rates and determine that no additional fuel is needed. Thus, we expect
many facilities will be able to meet the 35 mg/L TOC emission limit
without auxiliary fuel. However, the performance tests are typically
done with high loading rates, and may not adequately reflect the
performance for air-assisted combustion units when operated at low
loading rates. Therefore, we are finalizing requirements to either
continuously monitor the net heating value of the vapors discharged to
the flare or thermal oxidation system or to perform an initial
assessment to determine a minimum gasoline loading rate operating limit
that ensures high combustion efficiencies. As proposed, facilities that
cannot meet the NHV<INF>dil</INF> operating limit based on the minimum
gasoline loading rate operating limit can determine a minimum auxiliary
fuel addition rate (perhaps with a dual speed or variable speed blower)
needed to ensure good combustion efficiencies at these lower flow rates
that might not be well-represented during the performance test. Without
this assessment, we remain unconvinced that the mere presence of a
pilot flame, along with daily inspections of the vapor line valve and
air blower, are adequate to ensure a 35 mg/L TOC emission limit is met
at all times.
Comment: One commenter recommended that sources using VRU should be
able to implement alternative monitoring protocols as set forth under
40 CFR 63.11092(b)(1)(i)(B)(1)(i)-(iii). According to the commenter,
the EPA has not referenced any data suggesting that the alternative
monitoring options would not be sufficient to ensure compliance with a
35 mg/L (or 19,200 parts per million by volume (ppmv) as propane) TOC
emission limit. Alternatively, if the EPA believes that CEMS must be
required at all bulk gasoline terminal facilities subject to NESHAP
subpart BBBBBB, then the EPA should allow the alternative monitoring
protocols for periods of shutdown or repairs to CEMS rather than
requiring the loading racks to be taken out of service. A few
additional commenters did not object to the requirement to use a CEMS,
but similarly stated that the current alternative monitoring protocols
should be allowed for periods of shutdown or repairs to CEMS. According
to the commenter, there would be cost impacts that were not considered
by the EPA if no alternative is provided when the CEMS is inoperable or
out-of-control.
Response: We proposed the concentration limit specifically so that
a CEMS could be used to demonstrate continuous compliance with the TOC
emission limit for VRU. We proposed to require CEMS for all rules,
including NESHAP subpart BBBBBB, because a CEMS can directly assess
compliance with the emission limit and the design and operating
parameters cannot provide this direct assessment. However, we did not
estimate costs for back-up CEMS nor facility disruptions for periods of
CEMS outages. Therefore, we sought to provide an alternative to using a
CEMS that could be used for limited periods of CEMS outages, but not
one that could be used indefinitely as an ongoing alternative to a
CEMS.
In the cited alternative monitoring protocols in NESHAP subpart
BBBBBB, the regeneration cycles were based largely on design
considerations, with monthly measurements of the carbon bed outlet to
ensure breakthrough had not occurred near the end of an adsorption
cycle. With facilities using CEMS, they will have recent data on
regeneration cycle times (that can be normalized by product loading
quantities) by which to base the regeneration cycle times to use during
CEMS outages. This method follows many of the requirements in the
existing NESHAP subpart BBBBBB alternative, but the operating
parameters are based on those used to meet the emission limit when the
CEMS was operating, which provides better assurance that the VRU is
meeting the emission limit than cycle times and other operating
parameters that are based solely on design considerations. We are
providing specific provisions on how cycle times and other operating
limits will be established based on operations just prior to the CEMS
outages. We are setting a maximum number of hours for which the
alternative monitoring method can be used at 240 hours in a calendar
year. We consider this time period to be adequate to conduct
maintenance on or to replace the CEMS, as needed. Because the operating
parameters are specific to recent carbon adsorption system operating
conditions, we determined that this alternative would provide
compliance assurance during a 2-week period. We also selected this time
period to emphasize that this is a limited use alternative and that
CEMS should be used as the compliance method for all VRU. While most
commenters requesting an alternative to CEMS cited the NESHAP subpart
BBBBBB provisions, we find this limited alternative to the use of a
CEMS would also provide adequate short-term compliance assurance for
VRUs meeting more stringent emission limits in NESHAP subpart R and
NSPS subpart XXa. Therefore, we are finalizing this alternative in all
of the gasoline distribution rules as a temporary means to demonstrate
compliance during periods of CEMS outages.
iv. What is the rationale for the EPA's final approach for the
technology review?
We are finalizing the loading rack emission limits for area source
bulk gasoline terminals as proposed. Because many of the specific
monitoring requirements cross-reference provisions or contain similar
provisions as in NSPS subpart XXa, revisions related to allowing the
exclusion of methane from measured TOC, use of vacuum purge gas for
VRUs, revisions to the definition of 3-hour rolling average, and
associated revisions to the recordkeeping and reporting requirements
also impact the final requirements for gasoline loading operations at
area source facilities. Our rationale for these revisions is summarized
in section III.A.1.a.iv of this preamble.
We are revising the proposed requirements for vapor balancing at
bulk gasoline plants. First, for reasons discussed in section
III.A.1.c.iii of this preamble, we are revising the threshold for bulk
gasoline plants required to use vapor balancing from a maximum
calculated design throughput of 4,000 gallons per day or more to an
annual average actual throughput of 4,000 gallons per day or more, to
better align
[[Page 39327]]
with the analysis conducted regarding the cost effectiveness of this
threshold and other provisions in NESHAP subpart BBBBBB. We are also
revising the minimum pressure setting for fixed roof storage vessels
used in vapor balancing from 2.5 psig to 18 inches of water column.
For reasons as explained in section III.A.1.b.iv, we specifically
referenced vapor tight provisions at 40 CFR 63.422(c) and (e) in
proposed item 1(g) of table 2 to subpart BBBBBB because we did not
intend to require facilities subject to NESHAP subpart BBBBBB to
install pressure CPMS on existing loading racks. However, as discussed
in section III.A.2.b.iii of this preamble, we received comment that the
cross-referenced sections to the NESHAP subpart R requirements were
incomplete and incorrect. As such, we are finalizing the vapor-
tightness requirements by cross-referencing the provisions in NSPS
subpart XXa. Therefore, similar to the final requirements we added in
NESHAP subpart R, we are adding a monitoring alternative at 40 CFR
63.11092(h) to allow pressure measurements made during performances
tests or performance evaluations following the provisions in 40 CFR
60.503(d) as an alternative to using a pressure CPMS to determine that
the system is appropriately designed and operated at or below a
pressure of 18 inches of water during product loading. We are also
adding a cross-reference to 40 CFR 63.11092(h) in item 1(f) of table 2
(corresponding to proposed item 1(g) of table 2) to clarify that
existing sources under NESHAP subpart BBBBBB have the option to either
install a pressure CPMS or to periodically verify the appropriate
design and operation of the system by measuring pressure of the system
during performance tests or evaluations following the requirements in
40 CFR 60.503(d).
We are maintaining the compliance methods, as proposed, including
provision for thermal oxidation systems to either monitor combustion
zone temperature or use the flare monitoring alternative and for VRU to
use a CEMS. However, in response to comments, as discussed in section
III.A.1.c.iii of this preamble, we are providing a limited, short-term
alternative to using a CEMS for bulk gasoline terminals using a VRU
that can be used for periods of CEMS outages.
2. Standards for Cargo Tank Vapor Tightness
a. NESHAP Subpart R
i. What did the EPA propose pursuant to CAA section 112(d)(6) for the
major source gasoline distribution source category?
The EPA proposed a graduated vapor tightness certification
requirement ranging from 0.50 to 1.25 inches of water pressure drop
over a 5-minute period, depending on the cargo tank compartment size
for gasoline cargo tanks. The existing requirement in NESHAP subpart R
is a graduated vapor tightness certification requirement ranging from
1.0 to 2.5 inches of water pressure drop over a 5-minute period,
depending on the cargo tank compartment size for gasoline cargo tanks.
We proposed that cargo tanks certified prior to 3 years from the
promulgation date would have to certify to the existing levels and that
cargo tanks certified on or after 3 years from the promulgation date
would have to certify to the proposed lower levels.
ii. How did the technology review change for gasoline cargo tanks at
major source gasoline distribution facilities?
We did not revise our proposed technology review for cargo tank
vapor tightness requirement. However, we revised the timing of the new
requirements so that all cargo tanks undergoing annual certification
would be certified at the lower allowable pressure drop level within 3
years of promulgation of the final rule.
iii. What key comments did the EPA receive and what are the EPA's
responses?
We received general support for the proposed cargo tank vapor
tightness requirements, particularly the harmonizing of requirements
across the three rules (NESHAP subparts R and BBBBBB and NSPS subpart
XXa).
Comment: One commenter stated that compliance with a CAA section
112(d) rule must be ``as expeditiously as practicable'' and ``in no
event later than 3 years after the effective date of such standard.''
With respect to cargo tanks, the commenter stated that the Agency did
not demonstrate why 3 years was needed to comply with the revised vapor
tightness requirements. Specifically, the commenter noted that, if 3
years are provided before the new vapor tightness certification limits
become effective and an additional year is then required for the entire
fleet of gasoline cargo tanks to be certified at that lower level, then
the proposal is effectively providing a 4-year compliance schedule,
which is not provided under CAA section 112(d). The commenter
recommended that no more than 2 years be provided to implement the new
limits and no more than 3 years provided to implement and certify the
cargo tanks at that lower level.
Response: For cargo tanks, we agree that compliance with the
revised vapor tightness requirements and annual certification can be
implemented in 3 years. Therefore, within 3 years from the promulgation
date of the rule, we are requiring that all cargo tanks loaded must be
certified at the lower vapor tightness values. That way, the entire
fleet of gasoline cargo tanks would have certifications at the lower
level within 3 years of the promulgation date of this final rule rather
than requiring that certifications at the lower level begin at 3 years
after the promulgation date. Therefore, we have eliminated provisions
that would allow an additional year to test and fully implement the new
cargo tank vapor tightness requirements.
iv. What is the rationale for the EPA's final approach for the
technology review?
We are finalizing the graduated vapor tightness certification
requirement ranging from 0.50 to 1.25 inches of water pressure drop
over a 5-minute period, depending on the cargo tank compartment size
for gasoline cargo tanks, as proposed. We are finalizing a compliance
schedule that ensures that all gasoline cargo tanks are certified at
the lower levels within 3 years of the promulgation date of the final
rule because the CAA requires compliance as expeditiously as
practicable and no later than 3 years after the promulgation date.
b. NESHAP Subpart BBBBBB
i. What did the EPA propose pursuant to CAA section 112(d)(6) for the
area source gasoline distribution source category?
The EPA proposed a graduated vapor tightness certification
requirement ranging from 0.50 to 1.25 inches of water pressure drop
over a 5-minute period, depending on the cargo tank compartment size
for gasoline cargo tanks to harmonize gasoline cargo tank requirements
with those in NESHAP subpart R.
ii. How did the technology review change for gasoline cargo tanks at
area source gasoline distribution facilities?
We did not revise our proposed technology review for cargo tank
vapor tightness requirement. However, since we cross-reference the
vapor-tight certification requirements in NESHAP
[[Page 39328]]
subpart R, the timing of the final requirements was revised such that
gasoline cargo tanks must be certified at the lower levels in order to
be loaded no later 3 years from the promulgation date of the final
rule.
iii. What key comments did the EPA receive and what are the EPA's
responses?
Comment: One commenter noted that the revisions to table 2 result
in NESHAP subpart BBBBBB no longer expressly requiring the annual
certification testing, in that table 2 item 1(g) now references
paragraphs 40 CFR 63.422(c) and (e), neither of which specify
conducting the annual certification test. The commenter recommended
that the text of table 2 item 1(g) be edited to read, ``. . . into
vapor-tight gasoline cargo tanks using the procedures specified in
Sec. 63.11094(b).''
Response: We agree that the references to 40 CFR 63.422(c) and (e)
are incorrect. However, 40 CFR 63.11094(b) addresses only recordkeeping
requirements and not the requirements to not load non-vapor tight cargo
tanks. Upon further review, the provisions in table 2, item 1(g) were
intended to be similar to the current requirements in item 1(e).
Therefore, we are revising the entry in table 2, proposed item 1(g)
(which is now 1(f) in the final rule) to reference the NSPS subpart XXa
requirements at 40 CFR 60.502a(e) through (i) and are also adding a
cross-reference to 40 CFR 63.11092(g) and (h), which specifies the test
methods for the annual certification and alternative monitoring
requirements for pressure of the loading rack system, respectively. In
addition, we are revising the provisions in table 2, item 2(c) to limit
loading to vapor-tight gasoline cargo tanks using the procedures
specified in 40 CFR 60.502a(e) and adding a cross reference to 40 CFR
63.11092(g).
iv. What is the rationale for the EPA's final approach for the
technology review?
We are finalizing the graduated vapor tightness certification
requirement ranging from 0.50 to 1.25 inches of water pressure drop
over a 5-minute period, depending on the cargo tank compartment size
for gasoline cargo tanks, as proposed. We are revising the entry in
table 2, items 1(f) and 2(c), to reference the correct NSPS subpart XXa
requirements and also adding a cross-reference to 40 CFR 63.11092(g),
which specifies the test methods for the annual certification. Through
these cross-references, we are finalizing requirements that
certification of a gasoline cargo tank at the lower levels be conducted
within 3 years from the promulgation date of the final rule to ensure
that all gasoline cargo tanks are certified at the lower levels within
3 years of the promulgation date of the final rule because the CAA
requires compliance as expeditiously as practicable and no later than 3
years after the promulgation date.
c. NSPS Subpart XXa
i. What did the EPA propose pursuant to CAA section 111 for new,
modified, or reconstructed bulk gasoline terminals?
The EPA proposed a graduated vapor tightness certification
requirement ranging from 0.50 to 1.25 inches of water pressure drop
over a 5-minute period, depending on the cargo tank compartment size
for gasoline cargo tanks to harmonize gasoline cargo tank requirements
with those in NESHAP subparts R and BBBBBB.
ii. How did the NSPS review change for gasoline cargo tanks at new,
modified, or reconstructed bulk gasoline terminals?
We did not revise our proposed NSPS review for cargo tank vapor
tightness requirement.
iii. What key comments did the EPA receive and what are the EPA's
responses?
We received general support for the proposed cargo tank vapor
tightness requirements, particularly the harmonizing of requirements
across the three rules (NESHAP subparts R and BBBBBB and NSPS subpart
XXa).
iv. What is the rationale for the EPA's final approach for the NSPS
review?
For reasons detailed in our June 2022 proposal (87 FR 35622; June
10, 2022), we are finalizing the graduated vapor tightness
certification requirement ranging from 0.50 to 1.25 inches of water
pressure drop over a 5-minute period, depending on the cargo tank
compartment size for gasoline cargo tanks, as proposed. We are
finalizing requirements, as proposed, that all gasoline cargo tanks
loaded at gasoline loading rack affected facilities subject to NSPS
subpart XXa must be certified at the lower levels upon startup of the
affected facility, as required under section 111 of the CAA. We are
clarifying in 40 CFR 60.502a(e) that these provisions apply to the
``gasoline loading rack affected facility'' and that the applicable
vapor-tight gasoline cargo certification methods are in 40 CFR
60.503a(f), consistent with the definition of ``vapor-tight gasoline
cargo tanks'' in 40 CFR 60.501a. We are also clarifying that if the
previous contents of a cargo tank are not known, you must assume that
cargo tank is a gasoline cargo tank. These revisions are being made to
be consistent with the nomenclature revisions for the loading racks as
described in section III.A.1.iv of this preamble. These revisions also
help clarify the requirements that ensure loading occurs only in vapor-
tight gasoline cargo tanks as defined in NSPS subpart XXa.
3. Standards for Gasoline Storage Vessels
a. NESHAP Subpart R
i. What did the EPA propose pursuant to CAA section 112(d)(6) for the
major source gasoline distribution source category?
The EPA proposed additional fitting requirements for storage
vessels with external floating roofs as specified in 40 CFR
60.112b(a)(2)(ii). We also proposed requirements for storage vessels
with internal floating roofs to maintain the concentrations of vapors
inside a storage vessel above the floating roof to less than 25 percent
of the LEL. We proposed test method procedures for determining the LEL
inside a storage vessel above the internal floating roof and
corresponding recordkeeping and reporting requirements.
ii. How did the technology review change for gasoline storage vessels
at major source gasoline distribution facilities?
We did not revise our proposed technology review for storage
vessels. However, we have made minor revisions to the test method
procedures associated with the 25 percent of the LEL level.
iii. What key comments did the EPA receive and what are the EPA's
responses?
Comment: Several commenters opposed the 25 percent of the LEL level
for various reasons. Two commenters stated that the EPA did not
adequately demonstrate that LEL monitoring is an effective defect
detection practice, and it should not be required. Two commenters
stated that the EPA evaluated LEL as a monitoring enhancement, but
proposed it as a standard and did not adequately identify controls,
costs, or emission reductions for this standard. To assess if the LEL
monitoring is warranted, the commenters recommended that the EPA fully
account for costs of replacing the internal floating roof, not just the
cost of
[[Page 39329]]
monitoring. One commenter cited the NSPS subpart Kb final rule preamble
(52 FR 11420; April 8, 1987) that stated that ``[t]he Agency is not
aware of any method by which an annual concentration measurement could
be used to establish the condition of the control equipment.''
According to the commenters, the EPA has not provided sufficient data
to alter that conclusion and should withdraw the proposed LEL
monitoring requirement.
Response: As part of the notice of data availability (87 FR 49795;
August 12, 2022) the EPA provided the background information used in
the LEL analysis. It is clear that internal floating roofs that had
visible inspection issues (e.g., liquid on top of the floating roof)
had high LEL concentrations in the headspace (well over 25 percent of
the LEL) and those that did not have visible inspection issues had
lower LEL concentrations (generally well below 25 percent of the LEL).
Our emission estimates from various storage vessel requirements assume
proper seals and other equipment are in-place and operating as
required. If these controls are not operating as intended, the
emissions from these storage vessels can be much higher. We found that
the visual inspections are subjective and may, at times, not be
performed well. For example, although a hired contractor for BP's
Carson Refinery had reported no problems with the facility's 26
floating roof storage vessels from 1994 to 2002, a South Coast Air
Quality Management District inspection ``revealed that more than 80
percent of the tanks had numerous leaks, gaps, torn seals, and other
defects that caused excess emissions.'' \6\ Therefore, at proposal, we
sought a less subjective means to verify performance of the floating
roofs. We concluded that, given the preponderance of internal floating
roof storage vessels in this source category, periodic LEL monitoring
could be used to ensure the floating roofs are performing as intended.
---------------------------------------------------------------------------
\6\ Mokhiber, Russell. Multinational Monitor; Washington Vol.
24, Iss. 4, (April 2003): 30.
---------------------------------------------------------------------------
We acknowledge that it is difficult to estimate the emission
impacts of these LEL requirements because we do not have data on the
number of poorly functioning floating roofs. We note that the storage
vessel standards for NESHAP subpart R (as well as NESHAP subpart
BBBBBB) rely heavily on the NSPS subpart Kb requirements. NSPS subpart
Kb already requires repair of floating roofs that fail inspection and
failure of the LEL monitoring triggers the same repairs. As such, we
consider that these repairs are already required and the LEL
requirement predominately makes the required inspections less
subjective. In the worst-case scenario, a poorly operated internal
floating roof can have emissions similar to those of a fixed roof
storage vessel. In establishing the floating roof requirements, we
already determined that installing a floating roof was cost-effective
and that the costs of replacing a poorly functioning floating roof is
not significantly different from the costs of retrofitting a fixed roof
storage vessel. In our analysis, we used a 15-year life for the
internal floating roof storage vessel. Thus, replacement of the
internal floating roof every 15 years to ensure the emission reductions
are achieved are inherent in the original costing assessment.
Therefore, if an internal floating roof has failed to the point that 25
percent of the LEL is exceeded, and the LEL level cannot be reduced
without making repairs to the internal floating roof, we see no reason
that these storage vessels should remain in service. Thus, we have
already considered that replacement of the internal floating roof, if
it has reached its end of life and is no longer reducing emissions as
intended, is reasonable. While most poorly performing floating roofs
can be repaired, rather than replaced, we maintain that replacing a
failing internal floating roof is a reasonable requirement when repairs
are ineffective.
Since our statement in 1987 and as noted in our memorandum Review
of LEL Testing Requirements for Internal Floating Roof Tanks, two
States have developed rules that use LEL monitoring as a means to
ensure that floating roofs are controlling emissions as intended. We
note that these rules effectively set a maximum LEL limit that must be
met--essentially an ``emission limitation,'' not just a monitoring
requirement--and we modeled our proposed provision following these
State rules. Furthermore, the National Fire Protection Association
(NFPA) standard sets a maximum LEL limit of 25 percent for explosion
prevention for internal floating roof storage vessels. Based on these
developments, we concluded that establishing a maximum LEL level for
internal floating roofs was reasonable and necessary when taking into
account developments in practices, processes, and control technologies.
Comment: Several commenters suggested that, if the EPA finalizes
the LEL monitoring requirement, the following revisions be made to the
LEL monitoring requirements as proposed:
(1) Adopt higher LEL action levels: 50 percent for storage vessels
installed prior to the effective date of the NSPS in part 60, subpart
Kb, and 30 percent for storage vessels constructed, reconstructed or
modified after the effective date of NSPS subpart Kb. According to the
commenter, these limits would be more consistent with State
requirements.
(2) Allow calibration according to the manufacturer's
recommendations, which may specify a different calibration gas (other
than methane) or different calibration methods. Some instruments use
docking stations for calibration, so cannot attach tubing.
(3) Shorten LEL measurement period to a total of 10 minutes with 5
minutes of recorded measurement data (concentrations do not change
significantly and minimize time needed to be on the roof). In addition,
facilities should have the option to record the highest measured value
in lieu of recording a 5-minute rolling average or allow operators
flexibility in their recordkeeping based on their internal systems and
operations.
(4) LEL should be a monitoring requirement, not a standard, so
corrective action should be specified. Recommended that a failed LEL
inspection should trigger the obligation to conduct a second
confirmatory test within 30 days. If the second test shows that the
initial inspection was an anomaly, no further action should be
required. If the second inspection confirms an exceedance of the
percentage LEL limit, then a third confirmatory test must be conducted
within 30 days. If all inspections confirm the presence of gasoline
vapors above the percentage LEL limit, then the tank must undergo
repairs during the next regularly scheduled degassing event or
inspected as specified in 40 CFR 63.1063(d)(1).
(5) Remove the requirement that LEL measurements not be taken when
wind speeds exceed 10 mph, as this is unworkable for some locations
according to the commenters. One commenter recommended that the EPA
only require regulated entities to use best efforts to block wind from
the inspection area, document wind speed and direction, and use best
engineering judgment regarding whether wind speed would affect the
validity of the measurements. Another commenter suggested revising the
provision to be the greater of 10 mph or the average monthly wind speed
at the site.
(6) State that the LEL monitoring is to be conducted while the
internal floating roof is floating and with no product movement.
Response: Regarding the action level of the LEL requirement (item
1), we considered the State rule requirements
[[Page 39330]]
in establishing the threshold. However, we expect these rules were
established prior to the NFPA standard establishing a 25 percent of the
LEL limit. From the data we collected, there were very few measurements
that exceeded 25 percent of the LEL that did not also exceed 50 percent
of the LEL. Thus, when failures occurred, the LEL was often very high.
In the LEL measurements that we have, there were cases where LEL levels
of 30 percent were observed, but the facilities conducted corrective
actions and reduced the emissions from these tanks. Based on these
observations and considering the NFPA standard, we maintain that the
appropriate limit for LEL levels for internal floating roof storage
vessels is 25 percent.
Regarding the calibration requirements (item 2), we agree that the
use of other calibration gases is acceptable, provided appropriate
correction factors are applied specifically to the calibration gas
used. We have modified the monitoring method to incorporate this
flexibility and added a corresponding recordkeeping and reporting
requirement to indicate the gas used for calibration. However, we
maintain that the calibration should be made with tubing attached. This
will help to ensure no leaks in the tubing or other issues that may
impact the LEL measurements when the tubing is attached. Therefore, we
are not revising the proposed requirement to perform calibration with
the tubing attached.
Regarding reducing the duration of the LEL monitoring (item 3), we
find that a 10-minute testing period (5-minute stabilization + 5
minutes of reading) only provides one 5-minute average and is not as
representative as the proposed 20-minute test period. However, if the
LEL level is clearly exceeded in the first 5-minute average, we agree
that continued monitoring is not necessary. Therefore, we have added a
provision to the duration of the test provisions in 40 CFR
63.425(j)(3)(ii) that allows discontinuing testing when one 5-minute
average exceeds the 25 percent of the LEL level.
Regarding an exceedance of the LEL requirement triggering
corrective action (item 4), we note that the LEL monitoring does
trigger corrective action as specified in 40 CFR 63.423(b)(2), ``A
deviation of the LEL level is considered an inspection failure under
Sec. 60.113b(a)(2) of this chapter or Sec. 63.1063(d)(2) and must be
remedied as such.'' These sections require the storage vessels be
repaired or taken out of service. We agree that re-monitoring should be
done to confirm the repair has been successful, but some corrective
action is needed on the floating roof prior to the second monitoring
event. We do not agree with the commenter that the only corrective
action needed is to re-monitor the LEL in the storage vessel. As such,
we are revising 40 CFR 63.423(b)(2) to clearly require re-monitoring of
the LEL to confirm repair. Specifically, we are adding the following
sentence at the end of 40 CFR 63.423(b)(2): ``Any repairs made must be
confirmed effective through re-monitoring of the LEL and meeting the
level in this paragraph (b)(2) within the timeframes specified in Sec.
60.113b(a)(2) or Sec. 63.1063(e), as applicable.''
Regarding the maximum wind speed for the LEL monitoring test (item
5), we reviewed average wind speed data for various locations and agree
that the 10 mph limit may be too restrictive at some locations.
However, the inspections should be performed when the wind speeds are
typically low, as in the morning hours. After review of the annual
average wind speeds, as well as daily fluctuations in wind speed,\7\ we
considered whether the inspections could be performed at wind speeds
under 15 mph, even when the annual average wind speed exceeds this
level. After considering the comment and wind speed data, we agree to
amend the wind speed requirement as follows: ``LEL measurements shall
be taken when the wind speed at the top of the tank is 5 mph or less to
the extent practicable, but in no case shall LEL measurements be taken
when the sustained wind speed at top of tank is greater than the annual
average wind speed at the site or 15 mph, whichever is less.''
---------------------------------------------------------------------------
\7\ <a href="https://windexchange.energy.gov/maps-data/325">https://windexchange.energy.gov/maps-data/325</a> for annual
averages; <a href="https://www.visualcrossing.com/weather-data">https://www.visualcrossing.com/weather-data</a> for hourly and
daily averages.
---------------------------------------------------------------------------
Regarding specifications for the floating roof when the LEL
monitoring test is performed (item 6), the test should be conducted
under normal operations and the roof should not be resting on the
support legs. Thus, we agree with the commenter that the roof should be
floating and that testing should not be conducted when either the
storage vessel is empty or the roof landed on the support legs. We
recognize potential safety issues may occur if the storage vessel is
being filled and significant vapors are being expelled, but we do not
want to forbid any movement of liquid during the test, as that may
disrupt plant operations. Therefore, we have included language in the
final rule that outline that the test ``. . . should be conducted when
the internal floating roof is floating with limited product movement .
. .''
In considering the regulatory language proposed along with various
needs to potentially re-monitor (due to high winds or to confirm
repair) or to time inspections during periods of limited product
movement, we found that the proposed requirement to monitor during each
visual inspection required under 40 CFR 60.113b(a)(2) or 63.1063(d)(2)
to be unnecessary. We intended that LEL monitoring would be conducted
annually. While we anticipate that LEL monitoring would generally be
conducted as part of the visual inspection requirements, mandating that
they be conducted together will likely increase the number of LEL re-
monitoring events required. Therefore, we are also revising 40 CFR
63.425(j)(1), as part of the revisions in response to these comments,
to replace the proposed phrase ``during each visual inspection required
under Sec. 60.113b(a)(2) or Sec. 63.1063(d)(2)'' with ``at least once
every 12 months'' to clarify that the LEL monitoring is to be conducted
annually, and that it may, but is not required to, be conducted during
the visual inspection.
iv. What is the rationale for the EPA's final approach for the
technology review?
We are finalizing additional fitting requirements for storage
vessels with external floating roofs as proposed because we determined
these fitting requirements were cost-effective. We are also finalizing
requirements for storage vessels with internal floating roofs to
maintain the concentrations of vapors inside a storage vessel above the
floating roof to less than 25 percent of the LEL, as proposed, because
we determined that LEL monitoring is a development in practices that
helps ensure the internal floating roof is operating effectively to
reduce emissions. For reasons discussed in section III.A.3.a.iii of
this preamble, we are making minor revisions to the proposed test
method procedures for determining the LEL for storage vessels with
internal floating roofs to clarify the test procedures and make them
more flexible in response to public comments received. We are also
adding and revising corresponding recordkeeping and reporting
requirements.
b. NESHAP Subpart BBBBBB
i. What did the EPA propose pursuant to CAA section 112(d)(6) for the
area source gasoline distribution source category?
We proposed requirements for storage vessels with internal floating
roofs to
[[Page 39331]]
maintain the concentrations of vapors inside a storage vessel above the
floating roof to less than 25 percent of the LEL. We cross-referenced
the proposed test method procedures for determining the LEL in NESHAP
subpart R. We also proposed that fixed roof storage vessels must have
pressure relief valves with opening pressures set no less than 2.5
psig.
ii. How did the technology review change for gasoline storage vessels
at area source gasoline distribution facilities?
We did not revise our proposed technology review regarding the
maximum 25 percent of the LEL for internal floating roof storage
vessels. However, because we cross-reference the LEL testing
requirements in NESHAP subpart R, there are minor revisions in the
proposed LEL test method. We also revised the proposed fixed roof
storage vessel provisions regarding the minimum pressure relief device
opening pressure, reducing it from 2.5 psig to 18 inches of water (0.65
psig).
iii. What key comments did the EPA receive and what are the EPA's
responses?
The key comments received regarding the LEL requirement are
summarized in section III.A.3.a.iii of this preamble. The key comments
received regarding the proposed 2.5 psig minimum pressure relief device
opening pressure requirement for fixed roof storage vessels are
summarized in section III.A.1.c.iii of this preamble.
iv. What is the rationale for the EPA's final approach for the
technology review?
We are finalizing requirements for storage vessels with internal
floating roofs to maintain the concentrations of vapors inside a
storage vessel above the floating roof to less than 25 percent of the
LEL, as proposed, because we determined that LEL monitoring is a
development in practices that helps ensure the internal floating roof
is operating effectively to reduce emissions. For reasons discussed in
section III.A.3.a.iii of this preamble, we are making minor revisions
to the proposed test method procedures for determining the LEL for
storage vessels with internal floating roofs to clarify the test
procedures and make them more flexible in response to public comments
received. We are also adding and revising corresponding recordkeeping
and reporting requirements. For reasons discussed in section
III.A.1.c.iii of this preamble, we are revising the minimum pressure
setting for fixed roof storage vessels from 2.5 psig to 18 inches of
water column.
4. Standards for Equipment Leaks
a. NESHAP Subpart R
i. What did the EPA propose pursuant to CAA section 112(d)(6) for the
major source gasoline distribution source category?
We proposed to require semiannual instrument monitoring of all
equipment in gasoline service using either OGI according to proposed
appendix K to 40 CFR part 60 (appendix K) or EPA Method 21. We also
proposed to require repair of any leaks identified from a monitoring
event or any leaks identified by AVO methods during normal duties.
ii. How did the technology review change for equipment leaks at
major source gasoline distribution facilities?
There are no significant changes in our proposed technology review
conclusions for equipment leaks at major source gasoline distribution
facilities.
iii. What key comments did the EPA receive and what are the EPA's
responses?
Comment: Several commenters stated that the EPA's cost estimates
for the proposed instrument monitoring provisions are understated for
the reasons outlined below. If the EPA used the cost assumptions
outlined below, the instrument cost effectiveness compared to AVO
monitoring, using the EPA's emission estimates, would be $40,000 to
$50,000 per ton HAP reduced, so instrument monitoring is not a cost-
effective alternative to AVO.
<bullet> AVO inspections are part of normal walk around
inspections, which would occur in the absence of the rule, so no cost
savings should be applied for discontinuing monthly AVO inspections.
<bullet> Method 21 monitoring costs are low.
[cir] Startup cost for a Method 21 instrument monitoring program is
about $15,000 to $30,000. According to the commenter, the EPA did not
include connectors in the number of components in the startup cost
estimate.
[cir] Quarterly leak detection and repair (LDAR) monitoring costs
are typically $10,000 to $20,000 per year (2 to 4 times the EPA
estimate). This may be due, in part, to the EPA using an idealized
component monitoring rate of 75 components an hour (commenter suggested
80 percent of this rate, or 60 components per hour, is more realistic).
[cir] Costs do not include license fees for enterprise software,
which costs about $5,000 per year nor additional costs for monitoring
difficult-to-monitor components (lifts, etc.).
<bullet> Optical gas imaging (OGI) monitoring costs are low:
[cir] Startup costs are likely $5,000 to $10,000, (not $1,000 to
$1,500).
[cir] Monitoring rate of 750 components an hour is idealized and at
the minimum time per component specified in proposed appendix K.
Considering viewing from 2 angles and required breaks specified in
appendix K, a more realistic average monitoring rate is 192 components
per hour.
One commenter also stated that it may be technically infeasible
with so many facilities having to do monitoring in 3 years. Also, the
high demand for this service will likely increase costs.
Response: Regarding the commenter's note that AVO inspections are a
part of normal walk around inspections, the EPA recognizes that this
type of equipment leak monitoring is part of standard operations at
gasoline distribution facilities. However, through discussions with
industry, it was understood that the routine walk throughs are not
performed with the same level of thoroughness as the monthly
inspections. Additionally, the monthly inspections require time to
document the inspection. To account for these more thorough AVO
inspections, the EPA determined that it is appropriate to apply a cost
savings for discontinuing the monthly AVO inspection requirement.
With respect to EPA Method 21 startup costs, we used the equipment
counts for the model plant to estimate the startup costs. We assumed
that only pumps and valves would need to be tagged, so connectors were
excluded from the component count used in the startup costs. Facilities
must know all equipment that need to be inspected via the current
monthly AVO requirements, so the startup cost for Method 21 at gasoline
distribution facilities is expected to be less than for facilities that
have not had any LDAR requirements. As such, we consider the Method 21
startup costs we estimated to be reasonable for these facilities.
The EPA appreciates the commenter's feedback on lowering the
monitoring rate used for Method 21 to 80 percent of the proposed value
of 75 components per hour. The EPA notes that the comment does not
include a rationale for why 80 percent of the proposed value is
appropriate. The monitoring rate used in our analysis is based on
discussions with LDAR contractors and is considered reasonable for
these facilities.
[[Page 39332]]
If an owner or operator decided to perform instrument monitoring
in-house, then we recognize that a software license would need to be
purchased to manage the LDAR program. In our analysis, however, we
assumed that all instrument monitoring is performed by an external
contractor based on the size of typical gasoline distribution
facilities (i.e., considering equipment costs and number of equipment
components to be monitored). We assumed that these contractors already
have a software license for an LDAR management program and the LDAR
contractor can output data for the facility in Excel or as a comma-
separated values (CSV) file. As such, we assumed the cost of using the
license is already built into the contractor's LDAR monitoring cost.
With respect to OGI startup costs, as noted previously, facilities
must know all equipment that needs to be inspected via the current
monthly AVO requirements, so the startup cost for OGI at gasoline
distribution facilities is expected to be less than for facilities that
have not had any LDAR requirements. We consider the OGI startup costs
we estimated at proposal to be reasonable for these facilities.
The commenter's feedback on the OGI monitoring rate was based on
the proposed appendix K; however, in light of public comments, the EPA
subsequently issued a supplemental proposal with revised requirements
in appendix K. Therefore, the EPA reviewed the OGI monitoring rate used
in the equipment leak model compared to the requirements in appendix K,
as reflected in the supplemental proposal. The OGI monitoring rate in
the equipment leaks model was kept at 750 components per hour, which
accounts for the amount of time needed to view each component (assumed
4 seconds per component based on the appendix K requirements in the
supplemental proposal to view each component at 2 angles for 2 seconds
per component per angle, and the breaks required for technicians, which
require a 5-minute break after 30 minutes of viewing).
Based on our updated cost analysis in 2021 dollars, we determined
that savings from not conducting monthly AVO monitoring and the value
of the product not lost offsets the cost of semiannual instrument
monitoring. We also found that the incremental cost of semiannual
instrument monitoring compared to annual instrument monitoring was
$6,700 per ton of HAP reduced, which we consider to be reasonable.
Therefore, we maintain that semiannual instrument monitoring is cost-
effective for major source gasoline distribution facilities. For more
information regarding our revised costs analysis for instrument
monitoring, see memorandum Updated Control Options for Equipment Leaks
at Gasoline Distribution Facilities in Docket ID No. EPA-HQ-OAR-2020-
0371.
With respect to the comment suggesting it may be technically
infeasible to conduct monitoring in 3 years due to demand, we see no
basis for this claim. The leak inspection service industry is mature
and while there may be many gasoline distribution facilities, a
semiannual monitoring requirement for these facilities will not overly
stretch the capacity of the service providers. We provide up to 3 years
to comply with the instrument monitoring requirements. Facilities may
begin instrument monitoring prior to the end of the 3-year period to
avoid any potential contractor supply issues if that is a concern.
iv. What is the rationale for the EPA's final approach for the
technology review?
We are finalizing the equipment leak requirements for major source
gasoline distribution facilities as proposed because we determined that
semiannual instrument monitoring is cost-effective for major source
gasoline distribution facilities. Facilities will have 3 years from the
promulgation date of the rule to comply with the semi-annual equipment
leaks instrument monitoring requirement.
b. NESHAP Subpart BBBBBB
i. What did the EPA propose pursuant to CAA section 112(d)(6) for the
area source gasoline distribution source category?
We proposed to require annual instrument monitoring of all
equipment in gasoline service using either OGI according to proposed
appendix K or EPA Method 21. We also proposed to require repair of any
leaks identified from a monitoring event or any leaks identified by AVO
methods during normal duties.
ii. How did the technology review change for equipment leaks at area
source gasoline distribution facilities?
There are no significant changes in the proposed technology review
conclusions for equipment leaks at area source gasoline distribution
facilities.
iii. What key comments did the EPA receive and what are the EPA's
responses?
In addition to the general key comments received regarding the
equipment leaks monitoring as summarized in section III.A.4.a.iii of
this preamble, the following comment was received specific to area
source gasoline distribution facilities:
Comment: One commenter stated that the proposed LDAR requirement is
particularly burdensome for bulk gasoline plants and pipeline pumping
stations. These facilities have limited staff and are often remote.
Also, many of the EPA's costs are assumed to be linear by number of
components and some may be less linear, so the costs are further
understated for these small facilities.
Response: With respect to higher burden for bulk gasoline plants
and pipeline pumping stations, our cost estimates for instrument
monitoring have two elements. One element is fixed costs per monitoring
event; the second element is variable costs associated with the number
of equipment components monitored. When considering both of these cost
elements, we agree that the overall cost of monitoring (on a per
component basis) is higher for bulk gasoline plants and pipeline
pumping stations than it is for bulk gasoline terminals and pipeline
breakout stations. However, our cost estimates take this into account
because they consider the fixed costs associated with having a
contractor perform instrument monitoring.
Based on our updated cost analysis in 2021 dollars, we determined
that savings from not conducting monthly AVO monitoring and the value
of the product not lost offsets the cost of annual instrument
monitoring and results in a net cost savings compared to monthly AVO
monitoring. We also found that the incremental cost of semiannual
instrument monitoring compared to annual instrument monitoring was
$12,500 per ton of HAP reduced, which we determined was unreasonable.
Therefore, we maintain that annual instrument monitoring is cost-
effective for area source gasoline distribution facilities. For more
information regarding our revised costs analysis for instrument
monitoring, see memorandum Updated Control Options for Equipment Leaks
at Gasoline Distribution Facilities in Docket ID No. EPA-HQ-OAR-2020-
0371.
iv. What is the rationale for the EPA's final approach for the
technology review?
We are finalizing the equipment leak requirements for area source
gasoline distribution facilities as proposed because we determined that
annual instrument monitoring is cost-effective for area source gasoline
distribution facilities. Facilities will have 3 years from the
promulgation date of the final
[[Page 39333]]
rule to comply with the annual equipment leak instrument monitoring
requirement.
c. NSPS Subpart XXa
i. What did the EPA propose pursuant to CAA section 111 at new,
modified, or reconstructed bulk gasoline terminals?
We proposed to require quarterly instrument monitoring of all
equipment in gasoline service using OGI according to proposed appendix
K or quarterly instrument monitoring of pumps, valves, and pressure
relief devices and annual monitoring of connectors using EPA Method 21.
We also proposed to require repair of any leaks identified from a
monitoring event or any leaks identified by AVO methods during normal
duties.
ii. How did the NSPS review change for equipment leaks at new,
modified, or reconstructed bulk gasoline terminals?
There are no significant changes in the proposed BSER conclusions
for equipment leaks at facilities subject to NSPS subpart XXa.
iii. What key comments did the EPA receive and what are the EPA's
responses?
Key comments received regarding the NSPS affected facility
definition for the equipment leak monitoring requirements are
summarized in section III.A.1.a.iii of this preamble. General comments
received on the cost assumptions used in the equipment leaks analysis
are summarized in section III.A.4.a.iii of this preamble.
Comment: Several commenters stated that OGI monitoring cannot rely
on appendix K because that has not been finalized and the gasoline
distribution rules must have a public comment period after the
finalization of appendix K on which to evaluate its inclusion in the
rules.
Response: Appendix K was proposed prior to the proposal of the
gasoline distribution technology and NSPS reviews, so it was available
for comment. Commenters had both the opportunity to comment on appendix
K by submitting comments to the Oil and Natural Gas Sector Climate
review docket, Docket ID No. EPA-HQ-OAR-2021-0317, which it appears
that the commenters did, and on our proposed use of appendix K in the
gasoline distribution sector. Since commenters had the opportunity to
comment on appendix K and on our proposed use of appendix K, we see no
reason not to finalize the use of appendix K as proposed.
iv. What is the rationale for the EPA's final approach for the NSPS
review?
We are finalizing the equipment leak monitoring frequency for NSPS
subpart XXa as quarterly monitoring because, as described in the June
2022 proposal (87 FR 35627; June 10, 2022), we found this monitoring
frequency cost-effective for VOC emission reductions at new, modified,
and reconstructed affected facilities. We have also revised the
affected facility definition, as described in section III.A.1.a.iv of
this preamble, to separate the NSPS subpart XXa affected facility into
a ``gasoline loading rack affected facility'' and a ``collection of
equipment at a bulk gasoline terminal affected facility.''
B. Other Actions the EPA is Finalizing and the Rationale
1. SSM
In its 2008 decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C.
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 40 CFR 63.6(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.
The EPA has determined the reasoning in the court's decision in Sierra
Club applies equally to CAA section 111 because the definition of
emission or standard in CAA section 302(k), and the embedded
requirement for continuous standards, also applies to the NSPS.
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). As explained in the June 10, 2022,
proposal preamble (87 FR 35628), the EPA interprets CAA sections 111
and 112 as not requiring emissions that occur during periods of
malfunction to be factored into development of CAA sections 111 and 112
standards.
a. Elimination of the SSM Exemption in NESHAP Subpart R
The EPA proposed amendments to NESHAP subpart R to remove
provisions related to SSM that are not consistent with the requirement
that the standards apply at all times. More information concerning the
elimination of SSM provisions is in the preamble to the proposed rule
(87 FR 35628; June 10, 2022). The EPA is finalizing removal of the SSM
provisions in NESHAP subpart R as proposed with the exception that we
are including language that follows the language in 40 CFR 63.8(d)(3)
in two paragraphs instead of just one as proposed and revising the
language to align with the language more closely in 40 CFR 63.8(d)(3).
The EPA had proposed to add language at 40 CFR 63.428(d)(4), as
renumbered in the proposal, that followed the language in 40 CFR
63.8(d)(3) with the last sentence replaced to eliminate reference to
SSM plan. As described in section III.B.3.g.i of this preamble, the EPA
is finalizing existing and new recordkeeping provisions for the loading
rack provisions in 40 CFR 63.428(c) and (d), so the EPA is including
this added language in both 40 CFR 63.428(c)(4) and (d)(4) in the final
rule so that it applies to bulk gasoline terminals regardless of
whether they are complying with the current or new loading rack
provisions.
b. Revisions To Address SSM Provisions in NESHAP Subpart BBBBBB
The EPA proposed amendments to NESHAP subpart BBBBBB to remove
references to malfunction and revise certain entries to Table 4 to
Subpart BBBBBB of Part 63--Applicability of General Provisions (table 4
to subpart BBBBBB) that are not consistent with the requirement that
the standards apply at all times. More information concerning the
proposed amendments is available in the preamble to the proposed rule
(87 FR 35630; June 10, 2022). The EPA is finalizing the amendments in
NESHAP subpart BBBBBB as proposed with the exception that we are
revising the language in 40 CFR 63.11094(m), which was proposed at 40
CFR 63.11094(k), to align with the language more closely in 40 CFR
63.8(d)(3).
c. Finalize NSPS Subpart XXa Without SSM Exemptions
The EPA proposed standards in NSPS subpart XXa that apply at all
times. The EPA is finalizing in 40 CFR part 60, subpart XXa, specific
requirements at 40 CFR 60.500a(c) that override the 40 CFR part 60
general provisions for SSM requirements. In finalizing the standards in
this rule, the EPA has taken into account startup and shutdown periods
and, for the reasons explained in the
[[Page 39334]]
preamble to the proposed rule (87 FR 35630; June 10, 2022), has not
finalized alternate standards for those periods.
2. Electronic Reporting
To increase the ease and efficiency of data submittal and data
accessibility, the EPA is finalizing, as proposed, a requirement that
owners and operators of bulk gasoline terminals subject to the new NSPS
at 40 CFR part 60, subpart XXa, and gasoline distribution facilities
subject to NESHAP at 40 CFR part 63, subparts R and BBBBBB, submit
electronic copies of required performance test reports, performance
evaluation reports, semiannual reports, and Notification of Compliance
Status 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 final 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 \8\ 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 that 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 must be
submitted in PDF using the attachment module of the ERT. For semiannual
reports under NSPS subpart XXa and semiannual compliance reports under
NESHAP subparts R and BBBBBB, the final rules require that owners and
operators use the appropriate spreadsheet template to submit
information to CEDRI. The final version of the template for these
reports will be located on the CEDRI website.\9\ The final rules
require that Notification of Compliance Status reports be submitted as
a PDF upload in CEDRI.
---------------------------------------------------------------------------
\8\ <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>.
\9\ <a href="https://www.epa.gov/electronic-reporting-air-emissions/cedri">https://www.epa.gov/electronic-reporting-air-emissions/cedri</a>.
---------------------------------------------------------------------------
Furthermore, the EPA is finalizing, as proposed, provisions in NSPS
subpart XXa that allow owners and operators the ability to seek
extensions for submitting electronic reports for circumstances beyond
the control of the facility, i.e., for a possible outage in CDX or
CEDRI or for a force majeure event, in the time just prior to a
report's due date, as well as the process to assert such a claim. These
extensions were not added specifically to NESHAP subparts R and BBBBBB
because they are codified in 40 CFR part 63, subpart A, General
Provisions, at 40 CFR 63.9(k).
3. Technical and Editorial Changes
a. Applicability Equations in NESHAP Subpart R
The EPA proposed amendments to NESHAP subpart R to remove
applicability equations in 40 CFR 63.420 and have applicability
determined solely based on major source determination. The EPA proposed
a 3-year period for the removal of the use of the applicability
equations. The Agency also proposed to remove two related definitions
for ``controlled loading rack'' and ``uncontrolled loading rack.'' The
EPA received comment that the definitions of ``controlled loading
rack'' and ``uncontrolled loading rack,'' should not be deleted until
the applicability equations can no longer be used. The EPA reviewed the
use of these terms in NESHAP subpart R and confirmed those terms are
only used in the applicability equations. The EPA agrees with
commenters that the definitions of ``controlled loading rack'' and
``uncontrolled loading rack'' should remain in NESHAP subpart R to
define the terms used in the applicability equations while they are
still available for use. Therefore, the EPA is not finalizing the
proposed deletion of the terms ``controlled loading rack'' and
``uncontrolled loading rack'' from 40 CFR 63.421. Otherwise, we are
finalizing the transition away from using the applicability equations
as proposed.
b. Definitions of Bulk Gasoline Terminal, Pipeline Breakout Station,
and Pipeline Pumping Station
In NESHAP subparts R and BBBBBB, the EPA proposed to transition to
new definitions of ``bulk gasoline terminal'' and ``pipeline breakout
station'' over a 3-year period. We also proposed to revise the
definition of ``pipeline pumping station'' in NESHAP subpart BBBBBB,
effective on the effective date. The proposed revision to the
definition of ``bulk gasoline terminal'' was minor, clarifying that the
facility ``. . . subsequently loads all or a portion of the gasoline
into gasoline cargo tanks for transport to bulk gasoline plants or
gasoline dispensing facilities . . .'' We did not receive any comments
on the proposed definition of ``bulk gasoline terminal,'' and we are
finalizing the definition as proposed with the exception of the
definition in NESHAP subpart BBBBBB. We are finalizing the definition
of ``bulk gasoline terminal'' in NESHAP subpart BBBBBB to be consistent
with the gasoline throughput requirements currently in the rule. The
definition of ``bulk gasoline terminal'' in NESHAP subpart BBBBB is
``any gasoline facility which . . . has a gasoline throughput of 20,000
gallons per day (75,700 liter per day) or greater.'' The revisions to
the definition of ``pipeline pumping station'' were proposed to clarify
that pipeline pumping stations do not have gasoline loading racks. We
did not receive any comments on the proposed definition of ``pipeline
pumping station,'' and we are finalizing the definition as proposed.
The proposed revisions to the ``pipeline breakout station''
definition added two sentences to clarify that facilities that have
gasoline loading racks are to be considered bulk gasoline terminals
rather than pipeline breakout stations. These two added sentences were:
``Pipeline breakout stations do not have loading racks. If any gasoline
is loaded into cargo tanks, the facility is a bulk gasoline terminal
for the purposes of this subpart provided the facility-wide gasoline
throughput (including pipeline throughput) exceeds the limits specified
for bulk gasoline terminals.''
Comment: A commenter stated that pipeline facilities may have
loading racks, but these may not be used for gasoline loading (i.e.,
for diesel fuel loading or other materials) or rarely used for gasoline
loading (e.g., used only when conducting maintenance on storage tanks).
According to the commenter, these limited loading operations should not
trigger the loading rack control requirements for bulk gasoline
terminals. The commenter also indicated that the parenthetical phrase
``including pipeline throughput'' is confusing and suggested that the
throughput threshold consider only the ``gasoline loading design
throughput.''
Response: We agree that the first sentence added to the definition
of ``pipeline breakout station'' was overly broad and should be revised
to specify that the loading racks are for loading gasoline into cargo
tanks. If only diesel fuel loading is conducted at the facility,
[[Page 39335]]
the facility should be considered a pipeline station. With respect to
the parenthetical phrase ``. . . (including pipeline throughput) . .
.,'' we intentionally included this phrase to require all pipeline
breakout stations to use their total facility gasoline throughput so
that facilities that have both pipeline breakout operations and co-
located gasoline loading operations would be considered bulk gasoline
terminals. We note that the definition of bulk gasoline terminal also
refers to the facility and does not limit the referenced throughput to
just that of the loading operations. We consider the parenthetical
helps to clarify the definition and is consistent with our
interpretation that the 20,000 gallon per day throughput threshold
within the definition of ``bulk gasoline terminal'' is a facility-level
throughput and not limited to the throughput of only the gasoline
loading racks. If all of the gasoline managed by the facility is not
loaded into cargo tanks, as in the case of co-located pipeline breakout
operations and gasoline loading operations, then the 20,000-gallon
throughput threshold is to be evaluated based on the facility's total
gasoline throughput and not just the throughput of the loading
operations. For major sources of HAP emissions, this would require the
loading operations to meet the 10 mg/L TOC limit in NESHAP subpart R.
For area sources, the provisions for bulk gasoline terminals in NESHAP
subpart BBBBBB have separate requirements based on the actual gasoline
throughput of all loading racks at the facility. As such, area source
facilities with co-located pipeline breakout operations and gasoline
loading operations would be either subject to the proposed 35 mg/L TOC
emission limit or the submerged fill requirements in NESHAP subpart
BBBBBB based on the gasoline throughput of all loading racks.
We note that if only the loading rack throughput was used as
suggested by the commenter, some co-located loading operations could be
considered bulk gasoline plants. For major sources subject to NESHAP
subpart R, these loading operations would have no control requirements,
not even a submerged fill requirement. For area sources, the loading
operations would be considered subject to the vapor balancing
requirements proposed for bulk gasoline plants in NESHAP subpart BBBBBB
if the gasoline throughput is 4,000 gallons per day or more. Because
storage tanks at pipeline breakout stations are large and predominately
controlled using floating roofs, the proposed vapor balancing
requirement would not be appropriate. We find that the 20,000-gallon
per day threshold for bulk gasoline terminals is most appropriately
determined based on the total gasoline throughput of the facility and
that treating facilities that may have been previously considered a
pipeline breakout station with gasoline loading operations as a bulk
gasoline terminal in all cases provides a reasonable method to ensure
all loading operations have an applicable requirement.
After considering the comments received, we are finalizing the
definitions of ``bulk gasoline terminal,'' ``pipeline breakout
station,'' and ``pipeline pumping station'' as proposed with an
additional clarification in the definition of ``pipeline breakout
station'' through the addition of the underlined phrase: ``Pipeline
breakout stations do not have loading racks where gasoline is loaded
into cargo tanks.''
c. Definition of Gasoline
We proposed a minor revision to the definition of ``gasoline'' in
NESHAP subpart BBBBBB to include the Reid vapor pressure in units of
pounds per square inch (in addition to kilopascals) because those are
the units of measure commonly used in the U.S. gasoline distribution
industry. We proposed to directly include this same definition of
``gasoline'' in NESHAP subpart R, rather than rely on the definition of
``gasoline'' in NSPS subpart XX or XXa. We received no comment on these
proposed revisions related to the definition of ``gasoline'' and are
finalizing the revised or added definition as proposed.
d. Definition of Submerged Filling
Because we proposed to add submerged fill requirements in NESHAP
subpart R, we also proposed to add a definition of ``submerged
filling'' to NESHAP subpart R. The proposed definition of ``submerged
filling'' was similar to the definition already included in NESHAP
subpart BBBBBB. We received no comment on the proposed definition of
``submerged filling'' and are finalizing the added definition as
proposed with the exception that we are removing the phrase ``for the
purposes of this subpart'' from NSPS subpart XXa and NESHAP subpart R.
e. Definition of Flare and Thermal Oxidation System
We proposed a revision to the definitions of ``flare'' and
``thermal oxidation system'' in NESHAP subpart R. We proposed to
include these same definitions of ``flare'' and ``thermal oxidation
system'' to NESHAP subpart BBBBBB. These proposed revisions were to
clarify the distinction between control systems subject to performance
testing as thermal oxidation systems because they emit pollutants
through a conveyance suitable for performance testing and flares are
exempt from performance testing because they do not emit pollutants
through a conveyance suitable for performance testing.
Comment: Several commenters requested that the EPA change the
definition and phrasing in the rule from ``thermal oxidation system''
to ``vapor combustion unit'' because this is the term commonly used by
the industry. One commenter noted that the use of ``thermal oxidation
system'' is broadly inconsistent with the way gasoline vapor combustion
units, flares, and thermal oxidation systems have been treated
previously in these and other rules and how they are treated by States
and in facility permits. One commenter recommended that in the
definition of ``thermal oxidation system'' the EPA replace ``Auxiliary
fuel may be used to heat air pollutants to combustion temperatures''
with ``Auxiliary fuel may be used to sustain combustion.'' One
commenter recommended revising ``. . . device used to mix and ignite
fuel, air pollutants, and air to provide a flame to heat and oxidize
air pollutants . . .'' to more simply state ``device designed to mix
air and vapors in direct contact with a flame to oxidize air
pollutants'' because vapor combustion units commonly do not use
auxiliary fuel and because effective combustion does not require
heating.
Response: These gasoline distribution rules have long used the term
``thermal oxidation system.'' As such, facilities complying with these
regulations must already be familiar with this term. We reviewed the
revisions that would be needed to change this term to ``vapor
combustion unit'' and were concerned by the possibility of missing all
references to this term. However, during our review, we identified that
we had not revised the phrase ``thermal oxidation system other than a
flare'' in 40 CFR 63.427(a)(3) and 63.11092(b)(1)(iii) and (e)(1) and
(2), an
[…truncated; see source link]Indexed from Federal Register on May 8, 2024.
This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.