[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 [www.gpo.gov]
[FR Doc No: 2024-04629]



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Vol. 89

Wednesday,

No. 90

May 8, 2024

Part VI





Environmental Protection Agency





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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  

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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.

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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 https://www.regulations.gov/ 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 https://www.regulations.gov/.

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: [email protected].

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
CO2 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
NHVcz combustion zone net heating value
NHVdil net heating value dilution
NOX nitrogen oxides
NSPS new source performance standards
O3 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
SO2 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?

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    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.
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    \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.
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    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.
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    \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.
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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\
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    \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.
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    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 
(PM2.5), and HAP. The EPA expects disbenefits from secondary 
increases of carbon dioxide (CO2), nitrogen oxides 
(NOX), sulfur dioxide (SO2), 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 CO2 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.

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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 https://www.epa.gov/stationary-sources-air-pollution/gasoline-distribution-mact-and-gact-national-emission-standards. 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 https://www.epa.gov/stationary-sources-air-pollution/risk-and-technology-review-national-emissions-standards-hazardous. 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).
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    \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).
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    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:
     Retain the 10 mg/L TOC emission limit for gasoline loading 
racks controlled by thermal oxidation systems.
     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.
     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.
     Include additional fitting requirements for storage 
vessels with external floating roofs.
     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).
     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.
     Revise certain requirements to clarify that the emission 
limits apply at all times.
     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:
     Reduce the TOC emission limit for loading racks at large 
bulk gasoline terminals from 80 mg/L to 35 mg/L.
     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.
     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.
     Include additional fitting requirements for storage 
vessels with external floating roofs.
     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.
     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.
     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).
     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.
     Revise certain requirements to clarify that the emission 
limits apply at all times.
     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:
     Define the affected facility to include all equipment in 
gasoline service at the bulk gasoline terminal.
     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.
     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.
     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.
     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.
     Clarify that the emission limits apply at all times.
     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:
     Eliminate the flare tip velocity limit or allow its 
determination using an engineering assessment.
     Eliminate the net heating value dilution 
(NHVdil) 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 
NHVdil 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 NHVdil 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 NHVdil 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 (NHVcz). 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 NHVcz 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 
NHVcz 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 NHVdil 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 NHVdil 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 
NHVdil 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 NHVdil 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 NHVcz 
operating limit and, if applicable, with the NHVdil 
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 NHVdil 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 NHVdil 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\ https://windexchange.energy.gov/maps-data/325 for annual 
averages; https://www.visualcrossing.com/weather-data 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.
     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.
     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.).
     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\ https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert.
    \9\ https://www.epa.gov/electronic-reporting-air-emissions/cedri.
---------------------------------------------------------------------------

    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), and in item 1 of table 3 to NESHAP subpart BBBBBB. We are revising 
these references by deleting ``other than a flare'' from this phrase. 
With respect to comments suggesting further revisions to the definition 
of ``thermal oxidation system,'' we did not propose to revise the 
phrasing within the definition of ``thermal oxidation system'' that 
describes the device largely because we did not want to change the 
long-used description of the system in order to minimize potential 
inconsistencies with

[[Page 39336]]

permits and other ancillary requirements for these control systems. Our 
proposed revisions were focused on including the phrase that 
``[t]hermal oxidation systems emit pollutants through a conveyance 
suitable to conduct a performance test.'' Because we had not proposed 
additional revisions and did not intend to alter the historically used 
terms, we decided to not make additional revisions to the definition of 
``thermal oxidation system.''
    Upon considering the comments received, we are finalizing the 
revisions to the definitions of ``flare'' and ``thermal oxidation 
system'' as proposed. We are also revising the instances where 
``thermal oxidation system other than a flare'' was used to simply say 
``thermal oxidation system'' because flares are not a subset of thermal 
oxidation systems based on the final definitions.
f. Additional Part 63 General Provision Revisions
    We proposed to revise a number of entries in Table 1 to Subpart R 
of Part 63--General Provisions Applicability to This Subpart (table 1 
to subpart R) and to table 4 to subpart BBBBBB in the proposed rule to 
correct paragraph references, correct a typographical error, and update 
certain entries to reflect proposed revisions to the rules. Upon 
further review of table 1 to subpart R, we are revising the entry for 
40 CFR 63.9(f) to ``no.'' This provision is a notification for 
conducting visible emission observations. There is not a requirement in 
NESHAP subpart R to conduct routine visible emission observations. Upon 
further review of table 4 to subpart BBBBBB, we are revising the entry 
for 40 CFR 63.7(e)(3) to also include an exception for 40 CFR 
63.11092(e). The performance test requirements in NSPS subpart XXa, 
which are referenced in NESHAP subpart BBBBBB, specify the test run 
duration. We are also revising the entry for 40 CFR 63.10(b)(2)(ii) to 
correct the cross-reference.
    Comment: One commenter stated the addition of 40 CFR 63.11(c) 
through (e) to table 4 to subpart BBBBBB should be changed to ``yes'' 
because some bulk gasoline terminals may be using these equipment leak 
alternative monitoring provisions and they should not be required to 
change until appendix K provisions are finalized. The commenter noted 
that the NESHAP subpart R table includes ``yes'' for these paragraphs.
    Response: We reviewed the alternative work practice equipment leak 
provisions in 40 CFR 63.11(c) through (e) and see no reason why these 
provisions would apply after the full implementation of the revisions 
requiring OGI monitoring using the procedures in appendix K. We also 
note that the current Method 21 monitoring in NESHAP subparts R and 
BBBBBB is primarily limited to monitoring of the vapor collection 
system prior to a performance test to ensure the vapor collection 
system is operated with no detectable emissions. OGI is not approved as 
an alternative to Method 21 for no detectable emissions monitoring 
events. With that said, we agree that there is a discrepancy between 
the entries in table 1 to subpart R and table 4 to subpart BBBBBB and 
there should not be. There may be facilities, particularly for gasoline 
terminals co-located with other facilities, that may have Method 21 
monitoring provisions for which this OGI alternative is applicable. As 
such, it is possible that some facilities could use the alternative 
work practice standards in 40 CFR 63.11(c) through (e) in lieu of the 
monthly AVO monitoring requirements. Considering these conditions, we 
are revising the entry for 40 CFR 63.11(c) through (e) in table 4 to 
subpart BBBBBB to ``yes, except . . .'' and indicating that the 
equipment leak alternative work practice is not applicable to Method 21 
monitoring associated with performance testing and is not applicable 
upon compliance with the instrument monitoring equipment leak 
provisions in 40 CFR 63.11089(c). We are also adding a similar comment 
to the entry for 40 CFR 63.11(c), (d), and (e) in table 1 to subpart R 
to indicate that the equipment leak alternative work practice is not 
applicable to Method 21 monitoring associated with performance testing 
and is not applicable upon compliance with the instrument monitoring 
equipment leak provisions in 40 CFR 63.424(c).
    Comment: One commenter stated that the proposed revision to the 
note for the entry at 40 CFR 63.11(b) in table 4 to subpart BBBBBB and 
for the entry 40 CFR 63.11(a) through (b) in table 1 to subpart R 
should not be finalized. According to the commenter, the provision is 
unnecessary for flares controlling loading, because the rule specifies 
the flare requirements for those flares, but the facility may have 
other flares not used to control gasoline loading, and those flares can 
still comply with the provisions at 40 CFR 63.11(b). A commenter also 
noted a cross-reference error for the entry 40 CFR 63.11(a) through (b) 
in table 1 to subpart R.
    Response: The note helps to clarify the flare provisions applicable 
to the sources covered under NESHAP subparts R and BBBBBB. We are 
revising the entry for 40 CFR 63.11(b) in table 4 to subpart BBBBBB by 
replacing ``until compliance'' with ``except these provisions no longer 
apply for flares used to comply'' and ``Item 2.b'' with ``Item 2'' to 
indicate that the exception applies for flares complying with the flare 
provisions in NSPS subpart XXa, which are referenced in NESHAP subpart 
BBBBBB. For table 4 to subpart BBBBBB, we are finalizing the table as 
proposed except for the revisions to the entries for 40 CFR 63.7(e)(3), 
63.10(b)(2)(ii), 63.11(b), and 63.11(c) through (e).
    In NESHAP subpart R, upon transition to the flare provisions in 
NSPS subpart XXa, which are referenced in NESHAP subpart R, flares at 
major source gasoline distribution facilities will no longer comply 
with the flare provisions in 40 CFR 63.11(b). We are retaining the note 
except, based on the comment about a cross-reference error in table 1 
to subpart R, we are revising the reference to ``. . . Sec.  
63.425(b)(2) . . .'' in the note for the entry for 40 CFR 63.11(a) and 
(b) to ``. . . Sec. Sec.  63.422(b)(2) and 63.425(d)(2) . . .''
    Comment: One commenter noted a typographical error in table 1 to 
subpart R, ``. . . specifices . . .'' in the row included for the entry 
for 40 CFR 63.8(d)(3).
    Response: Based on the comments received, we are correcting the 
typographical error in the comment included for the entry for 40 CFR 
63.8(d)(3) to ``. . . specifies . . .'' Except for the revisions to the 
entries for 40 CFR 63.8(d)(3), 63.9(f), 63.11(c), (d), and (e), and 
63.11(a) and (b), we are finalizing table 1 to subpart R as proposed.
g. Editorial Corrections
    We proposed a number of editorial and typographical corrections. We 
are finalizing these revisions as proposed. We are also making 
clarifying revisions to spell out acronyms at first use or to replace 
words with acronyms. In addition, we are making clarifying revisions to 
consistently refer to ``liquid product'' loaded into ``gasoline cargo 
tanks.'' We are also making conforming revisions between the three 
rules to ensure similar requirements. Additionally, we are clarifying 
current requirements and those requirements that take effect by the 
compliance date. We received comment regarding several cross-reference 
errors or other editorial corrections. After reviewing these comments, 
we are revising cross-references and also making the following 
corrections in the final rules:

[[Page 39337]]

i. NESHAP Subpart R
     At 40 CFR 63.422(a)(2), we are revising the term 
``affected facility'' to ``gasoline loading rack affected facility'' 
commensurate with the final terms used in NSPS subpart XXa. We are also 
adding a sentence at the end of the paragraph based on a clarification 
requested by comments that, for the purposes of NESHAP subpart R, the 
definition of ``vapor-tight gasoline cargo tanks'' in 40 CFR 63.421 
applies to the cross-referenced provisions in NSPS subpart XXa. 
Specifically, the added sentence reads: ``For purposes of this subpart, 
the term ``vapor-tight gasoline cargo tanks'' used in Sec.  60.502a(e) 
of this chapter shall have the meaning given in Sec.  63.421.''
     At 40 CFR 63.422(c)(1), we are adding ``or'' after the 
semicolon as requested by a commenter to better clarify that the 
provisions in this paragraph are alternatives to those in 40 CFR 
63.422(c)(2) and (3).
     At 40 CFR 63.425(d), we are adding the phrase ``. . . and, 
if applicable, the provisions in paragraph (j) of this section'' to the 
end of the first sentence to clarify that annual LEL monitoring must 
also be conducted for internal floating roof storage vessels in 
addition to the requirements in 40 CFR 60.113b.
     At 40 CFR 63.425(e)(1), we are redesignating the table as 
table 1 to paragraph (e)(1) because it is the first table in the 
section and immediately follows paragraph (e)(1).
     At 40 CFR 63.425(f), we are deleting the phrase, ``except 
omit section 4.3.2 of Method 21'' because Method 21 does not contain 
section 4.3.2.
     At 40 CFR 63.425(g)(3), we are revising the definition of 
the term ``N'' to refer to the fourth column of table 1 to paragraph 
(e)(1) because we added a column to table 1 to paragraph (e)(1) and did 
not update this cross-reference.
     We received comment that the proposed paragraph at 40 CFR 
63.427(d) is confusing and appears to make operating both above and 
below the operating limits a deviation. We are revising 40 CFR 
63.427(d) to indicate that the vapor processing system should be 
operated in a manner consistent with the minimum and/or maximum 
operating parameter value or required procedures. Operation in a manner 
that constitutes a period of excess emission or failure to perform 
required procedures are considered a deviation of the emissions 
standard.
     One commenter noted that 40 CFR 63.428(c) was renumbered 
as 40 CFR 63.428(d), but no new paragraph (c) was added. The commenter 
noted that a new paragraph (c) should be added and marked as 
``Reserved.'' Upon review, we noted that the paragraph we intended to 
add as paragraph (d) was not included in the redline/strikeout version 
of the regulatory text. Therefore, we are not revising the paragraph 
numbering at 40 CFR 63.428(c) as proposed. We are revising the 
introductory text in 40 CFR 63.428(c) to clarify that the recordkeeping 
requirements in that paragraph (c) are for bulk gasoline terminals 
subject to the provisions of 40 CFR 63.422(b)(1), which contains the 
current requirements that expire in 3 years. We are adding a new 
paragraph (d) that provides the recordkeeping requirements specific to 
40 CFR 63.422(b)(2), which contains the updated monitoring requirements 
for thermal oxidation systems, vapor recovery systems, and flares used 
to control emissions from loading operations analogous to the 
recordkeeping requirements in NSPS subpart XXa.
     We are revising 40 CFR 63.428(h) by replacing ``delegated 
air agency'' with ``delegated authority.''
     We are revising 40 CFR 63.428(l)(2)(ii) to clarify that 
the periodic reports referenced are those required as specified in 40 
CFR 60.115b based on a comment received suggesting there was a cross-
referencing error.
ii. NESHAP Subpart BBBBBB
     At 40 CFR 63.11083(c), we are adding ``. . . Sec.  
63.11086(a) or in . . .'' after ``as specified in'' to note that the 3-
year compliance schedule also applies to bulk gasoline plants with an 
increase in daily throughput that exceeds the 4,000 gallons per day 
threshold for vapor balancing.
     We are revising 40 CFR 63.11092(i) to align the conduct of 
performance tests with the requirements in NESHAP subpart R and clarify 
how performance tests should be conducted.
     We are clarifying in 40 CFR 63.11094 that records must be 
maintained for at least 5 years unless otherwise specified.
     One commenter noted that inconsistencies in the phrasing 
of vapor tightness recordkeeping requirements between NESHAP subparts R 
and BBBBBB and NSPS XXa. The commenter suggested consistently adding 
the phrasing used at proposed 40 CFR 63.11094(b) with respect to 
provision that vapor tightness documentation may be made available ``. 
. . during the course of a site visit, or within a mutually agreeable 
time frame'' to all rules. Upon review, we find that this phrasing is a 
hold-over from when hardcopy documentation was required, and an 
electronic record provided as an alternative. We have proposed the use 
of electronic records and have found that access to electronic records 
is sufficient. If an inspector wants to view the electronic records, 
these should be available for review at the time of the inspection and 
provided to the inspector. We are not requiring facilities to provide 
hardcopies of the records. The owner or operator may elect to use 
hardcopy records, but we not requiring these. For consistency, we are 
not finalizing the proposed additions to 40 CFR 63.11094(b) in NESHAP 
subpart BBBBBB which includes the phrase cited by the commenter.
     One commenter noted that 40 CFR 63.11094(c) was deleted 
and no new paragraph (c) was added. The commenter recommended that a 
new paragraph (c) should be added and marked as ``Reserved.'' Upon 
review, we decided to renumber proposed 40 CFR 63.11094(d) to 40 CFR 
63.11094(c) and similarly renumber the other paragraphs in this section 
in a sequential manner.
     One commenter noted that proposed 40 CFR 63.11094(e)(1) 
and (e)(2)(i) contain citations to 40 CFR 63.11092(f), which pertains 
to storage while 40 CFR 63.11094(e) pertains to control devices for the 
loading racks. Upon review, we are rewording proposed 40 CFR 
63.11094(e), now paragraph (f), to include the storage vessel 
provisions in 40 CFR 63.11092(f).
     One commenter noted that 40 CFR 63.11094(f) cites 
paragraphs (f)(1) through (7) but the text only contains paragraphs 
(f)(1) through (4). With respect to the missing paragraphs in 40 CFR 
63.11094(f)(5) through (7), these were intended to be the recordkeeping 
requirements for facilities complying with the new emission limits when 
using different control technologies. Through a clerical error, these 
requirements were not included in the proposed redline of the rule. We 
are adding these requirements to the final rule to specify the 
recordkeeping requirements for these control scenarios. These 
recordkeeping requirements are similar to those in NSPS subpart XXa and 
are commensurate with the reporting requirements that were included in 
the NESHAP subpart BBBBBB proposal.
iii. NSPS Subpart XXa
     At 40 CFR 60.501a, we are deleting the duplicative 
definition of ``flare'' that was inadvertently included at the end of 
the definition of ``equipment.''
     At 40 CFR 60.502a(b) and (c), we are adding ``. . . no 
later than the date on which Sec.  60.8(a) requires a performance test 
to be completed'' at the

[[Page 39338]]

end of the first sentence to clarify that, for sources for which a 
performance test or evaluation is required, full compliance cannot be 
assessed until the performance test or performance evaluation is 
conducted.
     One commenter noted that 40 CFR part 63, subpart BBBBBB, 
cross-references the provisions at 40 CFR 60.502a(c)(3) as an 
alternative for use for thermal oxidation systems, but the cross-
referenced provisions appear to only apply to flares. The commenter 
recommended adding language at 40 CFR 60.502a(c)(3) to indicate that 
the paragraph also applies to thermal oxidation systems for which these 
provisions are specified. We agree with the commenter and note that 
this language is also needed based on the expanded use of these flare 
monitoring provisions as detailed in sections III.A.1.a.iii and iv of 
this preamble. We are adding ``. . . or if a thermal oxidation system 
for which these provisions are specified as a monitoring alternative is 
used . . .'' to 40 CFR 60.502a(c)(3) to clearly indicate that these 
provisions apply to certain thermal oxidation systems.
     At 40 CFR 60.502a(c)(3)(vi), we are deleting the word 
``gasoline'' in reference to cargo tanks because the flow rate of 
vapors to the vapor collection systems is based on the total liquid 
loading rates of all cargo tanks for which vapors are displaced to the 
vapor collection systems and not just those that meet the definition of 
``gasoline cargo tank.'' We are also rephrasing the introduction to 
more clearly indicate that ``you may elect'' to use this alternative to 
determine flare waste gas flow rates.
     At 40 CFR 60.502a(h), we are revising ``450 millimeters'' 
to ``460 millimeters'' to correct unit conversion from 18 inches.
     At 40 CFR 60.503a(a)(1), we are adding the sentence, ``The 
three-run requirement of Sec.  60.8(f) does not apply to this 
subpart.'' to clarify that only one 6-hour test as described in 40 CFR 
60.503a(c) must be conducted.
     At 40 CFR 60.503a(a)(2), we are replacing ``. . . 
potential sources in the terminal's vapor collection system equipment . 
. .'' with ``. . . equipment, including loading arms, in the gasoline 
loading rack affected facility . . .'' to require that the pre-
performance test leak monitoring include all equipment in the gasoline 
loading rack affected facility, which includes equipment at the loading 
racks and the vapor processing system.
     At 40 CFR 60.505a(a)(6), we are adding a requirement to 
maintain records for leaks identified under 40 CFR 60.503a(a)(2) 
similar to the requirement to maintain records for leaks identified 
under 40 CFR 60.502a(j).
     At 40 CFR 60.505a(c)(6)(ii)(A) and (B), we are removing a 
redundant reference to 40 CFR 60.502a(j)(2); 40 CFR 60.505a(c)(6)(ii) 
already indicated that the applicability of these paragraphs is limited 
to leaks identified under 40 CFR 60.502a(j)(2), which are leaks 
identified using AVO methods during normal activities.
iv. NSPS Subpart XX
     We are revising NSPS subpart XX at 40 CFR 60.500(b) to 
finalize the proposed amendments so that NSPS subpart XX applies to 
affected facilities that commence construction or modification after 
December 17, 1980, and on or before June 10, 2022.

C. What are the effective and compliance dates of the standards?

1. NESHAP Subpart R
    The revisions to the MACT standards being promulgated in this 
action are effective on July 8, 2024.
    The compliance date for existing gasoline distribution facilities 
subject to NESHAP subpart R is May 10, 2027, with the exception of the 
changes to table 1 of subpart R, the removal of the SSM exemptions, the 
finalized external floating roof storage vessel fitting controls, and 
performance test and performance evaluation reporting requirements. As 
explained in the preamble of the proposed action (87 FR 35634; June 10, 
2022) and in section III.A.2.a.iv of this preamble, the EPA considers 3 
years after the promulgation date of the final rule to be as expedient 
as practicable to implement the final requirements. The EPA does not 
expect any of the final revisions to table 1 of subpart R to increase 
burden to any facility and can be implemented without delay. For the 
removal of the SSM exemptions, we are finalizing that facilities must 
comply by the effective date of the final rule. The compliance times we 
are finalizing will ensure that the regulations are consistent with the 
decision in Sierra Club v. EPA, 551 F.3d 1019 (D.C. Cir. 2008) in which 
the court vacated portions of two provisions in the EPA's CAA section 
112 regulations governing the emissions of hazardous air pollutants 
during periods of SSM. Specifically, the court vacated the SSM 
exemption contained in 40 CFR 63.6(f)(1) and (h)(1). The EPA removed 
these SSM exemptions from the CFR in March 2021 to reflect the court's 
decision (86 FR 13819). The EPA does not expect any of the final 
revisions pertaining to SSM in table 1 of subpart R to increase burden 
to any facility and can be implemented without delay. In addition, we 
do not expect additional time is necessary generally for facilities to 
comply with changes to SSM provisions because we have concluded that 
the sources can meet the standards at all times, as described in 
section III.B.1.a. We are therefore finalizing that facilities must 
comply no later than the effective date of this final rule.
    As explained in the preamble of the proposed action (87 FR 35635; 
June 10, 2022), the EPA is finalizing the requirements to install 
fitting controls for external floating roof storage vessels the next 
time the storage vessel is completely emptied and degassed or 10 years 
after the promulgation date of the final rule, whichever occurs first, 
to align the installation of controls with a planned degassing event, 
to the extent practicable to minimize the offsetting emissions that 
occur due to a degassing event. The reporting requirements for 
performance tests and performance evaluations are required to be 
submitted following the procedures in 40 CFR 63.9(k) 180 days after the 
promulgation date. New sources must comply with all of the standards 
immediately upon the effective date of the standard, July 8, 2024, or 
upon startup, whichever is later.
2. NESHAP Subpart BBBBBB
    The revisions to the GACT standards being promulgated in this 
action are effective on July 8, 2024.
    The compliance date for existing gasoline distribution facilities 
subject to NESHAP subpart BBBBBB is May 10, 2027, with the exception of 
the changes to table 4 of subpart BBBBBB, revisions to SSM provisions, 
the finalized external floating roof storage vessel fitting controls, 
and performance test and performance evaluation reporting requirements. 
As explained in the preamble of the proposed action (87 FR 35635; June 
10, 2022) and in section III.A.2.b.iv of this preamble, the EPA 
considers 3 years after the promulgation date of the final rule to be 
as expedient as practicable to implement the final requirements.
    The EPA does not expect any of the final revisions to table 4 of 
subpart BBBBBB to increase burden to any facility and can be 
implemented without delay. For the revisions to table 4 of subpart 
BBBBBB that remove references to vacated provisions and the removal of 
references to malfunction, we are finalizing that facilities must 
comply by the effective date of the final rule. We do not expect 
additional time is necessary generally for facilities to

[[Page 39339]]

comply with changes to SSM provisions because we have concluded that 
the sources can meet the standards at all times, as described in 
section III.B.1.c.
    As explained in the preamble of the proposed action (87 FR 35635; 
June 10, 2022), the EPA is finalizing the requirements to install 
fitting controls for external floating roof storage vessels the next 
time the storage vessel is completely emptied and degassed or 10 years 
after the promulgation date of the final rule, whichever occurs first, 
to align the installation of controls with a planned degassing event, 
to the extent practicable to minimize the offsetting emissions that 
occur due to a degassing event. The reporting requirements for 
performance tests and performance evaluations are required to be 
submitted following the procedures in 40 CFR 63.9(k) 180 days after the 
promulgation date. New sources must comply with all of the standards 
immediately upon the effective date of the standard, July 8, 2024, or 
upon startup, whichever is later.
3. NSPS Subpart XXa
    The effective date of the final rule requirements in 40 CFR part 
60, subpart XXa, will be July 8, 2024. Affected sources that commence 
construction, reconstruction, or modification after June 10, 2022, must 
comply with all requirements of 40 CFR part 60, subpart XXa, no later 
than the effective date of the final rule or upon startup, whichever is 
later. This proposed compliance schedule is consistent with CAA section 
111(e).

IV. Summary of Cost, Environmental, and Economic Impacts and Additional 
Analyses Conducted

A. What are the affected facilities?

    There are approximately 9,500 facilities subject to the Gasoline 
Distribution NESHAPs and the Bulk Gasoline Terminals NSPS. An estimated 
210 facilities are classified as major sources, and 9,260 are area 
sources. The EPA estimated that there will be 5 new facilities and 15 
modified/reconstructed facilities subject to NSPS subpart XXa in the 
next 5 years.

B. What are the air quality impacts?

    This final action will reduce HAP and VOC emissions from Gasoline 
Distribution NESHAP and Bulk Gasoline Terminals NSPS sources. In 
comparison to baseline emissions of 6,110 tpy HAP and 121,000 tpy VOC, 
the EPA estimates HAP and VOC emission reductions of approximately 
2,220 and 45,400 tpy, respectively, based on our analysis of the final 
rules in this action as described in sections III.A and B in this 
preamble. Emission reductions and secondary impacts (e.g., emission 
increases associated with supplemental fuel or additional electricity) 
by rule are listed below.
1. NESHAP Subpart R
    For the major source rule, the EPA estimates HAP and VOC emission 
reductions of approximately 134 and 2,160 tpy, respectively, compared 
to baseline HAP and VOC emissions of 845 and 18,200 tpy. The EPA 
estimates that the final rule will not have any secondary pollutant 
impacts. More information about the estimated emission reductions and 
secondary impacts of this final action for the major source rule can be 
found in the document, Updated Major Source Technology Review for 
Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline 
Breakout Stations) NESHAP.
2. NESHAP Subpart BBBBBB
    For the area source rule, the EPA estimates HAP and VOC emission 
reductions of approximately 2,090 and 40,300 tpy, respectively, 
compared to baseline HAP and VOC emissions of 5,260 and 99,400 tpy. The 
EPA estimates that the final rule will result in additional emissions 
of 32,400 tpy of carbon dioxide, 19 tpy of nitrogen oxides, and 86 tpy 
of carbon monoxide. More information about the estimated emission 
reductions and secondary impacts of this final action for the area 
source rule can be found in the document, Updated Area Source 
Technology Review for Gasoline Distribution Bulk Terminals, Bulk 
Plants, and Pipeline Facilities NESHAP.
3. NSPS Subpart XXa
    For the NSPS, the EPA estimates VOC emission reductions of 
approximately 2,950 tpy compared to baseline emissions of 3,890 tpy. 
The EPA estimates that the final rule will result in additional 
emissions of 2,140 tpy of carbon dioxide, 1.3 tpy of nitrogen oxides, 
and 1.3 tpy of sulfur dioxide. More information about the estimated 
emission reductions and secondary impacts of this final action for the 
NSPS can be found in the document, Updated New Source Performance 
Standards Review for Bulk Gasoline Terminals.

C. What are the cost impacts?

    This final action will cost (in 2021 dollars) approximately $75.8 
million in total capital costs and result in total annualized cost 
savings of $3.77 million per year (including product recovery) based on 
our analysis of the final action described in sections III.A and B of 
this preamble. Costs by rule are listed below.
1. NESHAP Subpart R
    For the major source rule, the EPA estimates this final rule will 
cost approximately $2.38 million in total capital costs and $1.91 
million per year in total annualized costs (including product 
recovery). More information about the estimated cost of this final 
action for the major source rule can be found in the document, Updated 
Major Source Technology Review for Gasoline Distribution Facilities 
(Bulk Gasoline Terminals and Pipeline Breakout Stations) NESHAP.
2. NESHAP Subpart BBBBBB
    For the area source rule, the EPA estimates this final rule will 
cost approximately $66.2 million in total capital costs and have cost 
savings of $5.74 million per year in total annualized costs (including 
product recovery). More information about the estimated cost of this 
final action for the area source rule can be found in the document, 
Updated Area Source Technology Review for Gasoline Distribution Bulk 
Terminals, Bulk Plants, and Pipeline Facilities NESHAP.
3. NSPS Subpart XXa
    For the NSPS, the EPA estimates this final rule will cost 
approximately $7.20 million in total capital costs and $66,000 per year 
in total annualized costs (including product recovery). More 
information about the estimated cost of this final action for the NSPS 
can be found in the document, Updated New Source Performance Standards 
Review for Bulk Gasoline Terminals.

D. What are the economic impacts?

    The EPA conducted economic impact analyses, contained in the RIA, 
for this final action. The RIA is available in the docket for this 
action. The economic impact analyses contain two parts. The economic 
impacts of the final action on small entities are calculated as the 
percentage of total annualized costs incurred by affected ultimate 
parent owners to their revenues. This ratio provides a measure of the 
direct economic impact to ultimate parent owners of gasoline 
distribution facilities while presuming no impact on consumers. We 
estimate that the average small entity impacted by the final action 
will incur total annualized costs of 0.40 percent of their revenue, 
with none exceeding 6.56 percent. We estimate that fewer than 9 percent 
of impacted small entities will incur total annualized costs greater 
than 1 percent of their revenue and that fewer than 3

[[Page 39340]]

percent will incur total annualized costs greater than 3 percent of 
their revenue. This is based on a conservative estimate of costs 
imposed on ultimate parent companies, where total annualized costs 
imposed on a facility are at the upper bound of what is possible under 
the rule and do not include product recovery as a credit. More 
explanation of these economic impacts can be found in section V.C, the 
Regulatory Flexibility Act (RFA), and in the RIA for this final action. 
The RIA also contains a supplementary analysis of small business 
impacts using data from the U.S. Census Bureau.
    The EPA also prepared a partial equilibrium model of the U.S. 
gasoline market in order to project changes caused by this final action 
to the price and quantity of gasoline sold from 2027 to 2041. Using 
this model, the price of gasoline is projected to rise by less than 
0.006 percent (less than two hundredths of a cent) in all years from 
2027 to 2041, whereas the quantity of gasoline consumed is projected to 
fall by less than 0.002 percent in all years from 2027 to 2041. These 
projections consider the costs imposed by amendments to NESHAP subpart 
BBBBBB, NESHAP subpart R, and amendments to the NSPS promulgated in 
subpart XXa.
    Thus, economic impacts are expected to be low for affected 
companies and industries impacted by this final action, and there are 
not likely to be substantial impacts on the markets for affected 
products. The costs of the final action are not expected to result in a 
significant market impact, regardless of whether they are passed on to 
the purchaser or absorbed by the firms. We note that these economic 
impacts do not include the expected product recovery of gasoline under 
each of these final rules. The RIA for this final action includes more 
details and discussion of these projected impacts.

E. What are the benefits?

    The emission controls installed to comply with the final action are 
expected to reduce VOC emissions which, in conjunction with nitrogen 
oxides and in the presence of sunlight, form ground-level ozone 
(O3). This section reports the estimated ozone-related 
benefits of reducing VOC emissions in terms of the number and value of 
avoided ozone-attributable deaths and illnesses.
    As a first step in quantifying O3-related human health 
impacts, the EPA consults the Integrated Science Assessment for Ozone 
(Ozone ISA) \10\ as summarized in the Technical Support Document for 
the Final Revised Cross State Air Pollution Rule Update.\11\ This 
document synthesizes the toxicological, clinical, and epidemiological 
evidence to determine whether each pollutant is causally related to an 
array of adverse human health outcomes associated with either acute 
(i.e., hours or days-long) or chronic (i.e., years-long) exposure. For 
each outcome, the Ozone ISA reports this relationship to be causal, 
likely to be causal, suggestive of a causal relationship, inadequate to 
infer a causal relationship, or not likely to be a causal relationship.
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    \10\ U.S. EPA (2020). Integrated Science Assessment for Ozone 
and Related Photochemical Oxidants. U.S. Environmental Protection 
Agency. Washington, DC. Office of Research and Development. EPA/600/
R-20/012. Available at: https://www.epa.gov/isa/integrated-science-assessment-isa-ozone-and-related-photochemical-oxidants.
    \11\ U.S. EPA. 2021. Technical Support Document (TSD) for the 
Final Revised Cross-State Air Pollution Rule Update for the 2008 
Ozone Season NAAQS Estimating PM2.5- and Ozone-Attributable Health 
Benefits. https://www.epa.gov/sites/default/files/2021-03/documents/estimating_pm2.5-_and_ozone-attributable_health_benefits_tsd.pdf.
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    In brief, the Ozone ISA found short-term (less than one month) 
exposures to ozone to be causally related to respiratory effects, a 
``likely to be causal'' relationship with metabolic effects and a 
``suggestive of, but not sufficient to infer, a causal relationship'' 
for central nervous system effects, cardiovascular effects, and total 
mortality. The Ozone ISA reported that long-term exposures (one month 
or longer) to ozone are ``likely to be causal'' for respiratory effects 
including respiratory mortality, and a ``suggestive of, but not 
sufficient to infer, a causal relationship'' for cardiovascular 
effects, reproductive effects, central nervous system effects, 
metabolic effects, and total mortality.
    For all estimates, we summarized the monetized ozone-related health 
benefits using discount rates of 3 percent and 7 percent for both 
short-term and long-term effects for the 15-year analysis period of 
these rules discounted back to 2024 rounded to 2 significant figures. 
All estimates are presented in 2021 dollars. For the full set of 
underlying calculations see the Gasoline Distribution Benefits 
workbook, available in the docket for this action as an attachment to 
the RIA. In addition, we include the monetized disbenefits from 
additional CO2 emissions using a 3 percent rate, which occur 
with NESHAP subpart BBBBBB and NSPS subpart XXa but not NESHAP subpart 
R since there are no additional CO2 emissions as a result of 
the NESHAP subpart R final rule. The EPA has prepared a benefits 
analysis, contained in the RIA and summarized here, to provide the 
public the same extent of analysis, including monetized benefits and 
disbenefits, for the rules in this final action as was provided for the 
proposal RIA.
    Due to methodology and data limitations, we did not attempt to 
monetize the health benefits of reductions in HAP in this analysis. 
Monetization of the benefits of reductions in cancer incidences 
requires several important inputs, including central estimates of 
cancer risks, estimates of exposure to carcinogenic HAP, and estimates 
of the value of an avoided case of cancer (fatal and non-fatal). A 
qualitative discussion of the health effects associated with HAP 
emitted from sources subject to control under the final action is 
included in the RIA.
1. NESHAP Subpart R
    The PV of the benefits for the final amendments to NESHAP subpart R 
range from $11 million at a 3 percent discount rate to $6.3 million at 
a 7 percent discount rate for short-term effects and $87 million at a 3 
percent discount rate to $52 million at a 7 percent discount rate for 
long-term effects. The EAV of the benefits for the final amendments to 
NESHAP subpart R range from $0.89 million at a 3 percent discount rate 
to $0.70 million at a 7 percent discount rate for short-term effects 
and $7.3 million at the 3 percent discount rate to $5.8 million at a 7 
percent discount rate for long-term effects.
2. NESHAP Subpart BBBBBB
    The PV of the net benefits (monetized health benefits minus 
monetized climate disbenefits) for the final amendments to NESHAP 
subpart BBBBBB range from $170 million at a 3 percent discount rate to 
$90 million at a 7 percent discount rate for short-term effects and 
$1,600 million at a 3 percent discount rate to $950 million at a 7 
percent discount rate for long-term effects. The EAV of the net 
benefits for the final amendments to NESHAP subpart BBBBBB range from 
$15 million at a 3 percent discount rate to $11 million at a 7 percent 
discount rate for short-term effects and $140 million at the 3 percent 
discount rate to $110 million at a 7 percent discount rate for long-
term effects.
3. NSPS Subpart XXa
    The PV of the net benefits (monetized health benefits minus 
monetized

[[Page 39341]]

climate disbenefits) for the final NSPS subpart XXa range from $29 
million at a 3 percent discount rate to $14 million at a 7 percent 
discount rate for short-term effects and $280 million at a 3 percent 
discount rate to $160 million at a 7 percent discount rate for long-
term effects. The EAV of the net benefits for the final NSPS subpart 
XXa range from $2.4 million at a 3 percent discount rate to $1.7 
million at a 7 percent discount rate for short-term effects and $24 
million at the 3 percent discount rate to $17 million at a 7 percent 
discount rate for long-term effects.
4. Cumulative Benefits Across Rules
    The PV of the net benefits (monetized health benefits minus 
monetized climate disbenefits) for all three rules cumulatively range 
from $210 million at a 3 percent discount rate to $110 million at a 7 
percent discount rate for short-term effects and $2,000 million at a 3 
percent discount rate to $1,200 million at a 7 percent discount rate 
for long-term effects. The EAV of the net benefits for all three rules 
cumulatively range from $17 million at a 3 percent discount rate to $13 
million at a 7 percent discount rate for short-term effects and $170 
million at the 3 percent discount rate to $130 million at a 7 percent 
discount rate for long-term effects.

F. What analysis of environmental justice did the EPA conduct?

    The EPA defines EJ as ``the just treatment and meaningful 
involvement of all people, regardless of income, race, color, national 
origin, Tribal affiliation, or disability, in agency decision-making 
and other Federal activities that affect human health and the 
environment so that people: (i) Are fully protected from 
disproportionate and adverse human health and environmental effects 
(including risks) and hazards, including those related to climate 
change, the cumulative impacts of environmental and other burdens, and 
the legacy of racism or other structural or systemic barriers; and (ii) 
have equitable access to a healthy, sustainable, and resilient 
environment in which to live, play, work, learn, grow, worship, and 
engage in cultural and subsistence practices.'' \12\ In recognizing 
that communities with EJ concerns often bear an unequal burden of 
environmental harms and risks, the EPA continues to consider ways of 
protecting them from adverse public health and environmental effects of 
air pollution. For purposes of analyzing regulatory impacts, the EPA 
relies upon its June 2016 Technical Guidance for Assessing 
Environmental Justice in Regulatory Analysis,\13\ which provides 
recommendations that encourage analysts to conduct the highest quality 
analysis feasible, recognizing that data limitations, time, resource 
constraints, and analytical challenges will vary by media and 
circumstance.
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    \12\ 88 FR 25251 (April 26, 2023); https://www.federalregister.gov/documents/2023/04/26/2023-08955/revitalizing-our-nations-commitment-to-environmental-justice-for-all.
    \13\ See https://www.epa.gov/environmentaljustice/technical-guidance-assessing-environmental-justice-regulatory-analysis.
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1. NESHAP Subpart R
    To examine the potential for any EJ issues that might be associated 
with gasoline distribution major source facilities subject to NESHAP 
subpart R, we performed a proximity demographic analysis at proposal, 
which is an assessment of individual demographic groups of the 
populations living within 5 kilometers (km, ~3.1 miles) and 50 km (~31 
miles) of the facilities. The EPA then compared the data from this 
analysis to the national average for each of the demographic groups. We 
have determined that the affected facilities did not change as a result 
of public comments. Therefore, the analysis from the proposed rule is 
still applicable for this final action.
    In summary, the results of the demographic proximity analysis 
indicate that, for populations within 5 km (~3.1 miles) of the 117 
major source gasoline distribution facilities,\14\ the percent of the 
population that is Hispanic or Latino is significantly higher than the 
national average (33 percent versus 19 percent). Specifically, 
populations around 12 facilities are more than three times the national 
average for the percent that is Hispanic/Latino (greater than 56 
percent). The percent of the population that is African American (15 
percent) and Other and Multiracial (10 percent) are slightly above the 
national averages (12 percent and 8 percent, respectively). The percent 
of people living below the poverty level (17 percent) and those over 25 
without a high school diploma (18 percent) are higher than the national 
averages (13 percent and 12 percent, respectively). The percent of 
people living in linguistic isolation is higher than the national 
average (9 percent versus 5 percent).
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    \14\ The EPA estimates there are approximately 210 major source 
gasoline distribution facilities; however, we had location 
information for only 117 of the facilities.
---------------------------------------------------------------------------

    More detailed results of the demographic proximity analysis can be 
found in section IV.F. of the proposed rule's preamble (see 87 FR 
35638; June 10, 2022) and in the technical report, Analysis of 
Demographic Factors for Populations Living Near Gasoline Distribution 
Facilities, available in Docket ID No. EPA-HQ-OAR-2020-0371.
    As noted earlier in this preamble, the EPA determined that the 
standards should be revised to reflect cost-effective developments in 
practices, process, or controls. Because we based the analysis of the 
impacts and emission reductions on model plants, we are not able to 
ascertain specifically how the potential benefits will be distributed 
across the population. Thus, we are limited in our ability to estimate 
the potential EJ impacts of this rule. However, we anticipate that the 
changes to NESHAP subpart R will generally improve human health 
exposures for populations in surrounding communities. The EPA estimates 
that NESHAP subpart R will reduce HAP emissions from gasoline 
distribution facilities by 130 tpy and VOC emissions by 2,200 tpy. The 
changes will have beneficial effects on air quality and public health 
for populations exposed to emissions from gasoline distribution 
facilities that are major sources and will provide additional health 
protection for most populations, including communities already 
overburdened by pollution, which are often people of color, low-income, 
and indigenous communities.
2. NESHAP Subpart BBBBBB
    To examine the potential for any EJ issues that might be associated 
with gasoline distribution area source facilities subject to NESHAP 
subpart BBBBBB, we performed a proximity demographic analysis at 
proposal, which is an assessment of individual demographic groups of 
the populations living within 5 km and 50 km of the facilities. The EPA 
then compared the data from this analysis to the national average for 
each of the demographic groups. We have determined that the affected 
facilities did not change as a result of public comments. Therefore, 
the analysis from the proposed rule is still applicable for this final 
action.
    In summary, the results of the demographic analysis indicate that, 
for populations within 5 km of 1,229 area source gasoline distribution 
facilities,\15\ the Hispanic or Latino (26 percent) and African 
American (18 percent) populations are significantly larger than the 
national averages (19 percent and 12 percent, respectively). 
Specifically,

[[Page 39342]]

populations around 102 facilities are more than three times the 
national average for the percent that is Hispanic/Latino (greater than 
56 percent) and the populations around 218 facilities are more than 
three times the national average for the percent that is African 
American (greater than 36 percent).
---------------------------------------------------------------------------

    \15\ The EPA estimates there are approximately 9,260 area source 
gasoline distribution facilities; however, we had location 
information for only 1,229 of the facilities.
---------------------------------------------------------------------------

    The percent of the population that is Other and Multiracial (10 
percent) is slightly above the national average (8 percent). The 
percent of people living below the poverty level (18 percent) and those 
over 25 without a high school diploma (16 percent) are higher than the 
national averages (13 percent and 12 percent, respectively). The 
percent of people living in linguistic isolation was higher than the 
national average (9 percent versus 5 percent).
    More detailed results of the demographic proximity analysis can be 
found in section IV.F. of the proposed rule's preamble (see 87 FR 
35639; June 10, 2022) and in the technical report, Analysis of 
Demographic Factors for Populations Living Near Gasoline Distribution 
Facilities, available in Docket ID No. EPA-HQ-OAR-2020-0371.
    As noted earlier, the EPA determined that the standards should be 
revised to reflect cost-effective developments in practices, process, 
or controls. Because we based the analysis of the impacts and emission 
reductions on model plants, we are not able to ascertain specifically 
how the potential benefits will be distributed across the population. 
Thus, we are limited in our ability to estimate the potential EJ 
impacts of this rule. However, we anticipate that the changes to NESHAP 
subpart BBBBBB will generally improve human health exposures for 
populations in surrounding communities. The EPA estimates that NESHAP 
subpart BBBBBB will reduce HAP emissions from gasoline distribution 
facilities by 2,100 tpy and VOC emissions by 40,300 tpy. The changes 
will have beneficial effects on air quality and public health for 
populations exposed to emissions from gasoline distribution facilities 
that are area sources and will provide additional health protection for 
most populations, including communities already overburdened by 
pollution, which are often people of color, low-income, and indigenous 
communities.
3. NSPS Subpart XXa
    As indicated in the proposal, the locations of any new Bulk 
Gasoline Terminals that will be subject to NSPS subpart XXa are not 
known. In addition, it is not known which existing Bulk Gasoline 
Terminals may be modified or reconstructed and subject to NSPS subpart 
XXa. Thus, we are limited in our ability to estimate the potential EJ 
impacts of this rule. However, we anticipate that the changes to NSPS 
subpart XXa will generally minimize future emissions to levels of BSER 
and human health exposures for populations in surrounding communities 
of new, modified, or reconstructed facilities, including those 
communities with higher percentages of people of color, low income, and 
indigenous communities. Specifically, the EPA determined that the 
standards should be revised to reflect BSER. The EPA estimates that 
NSPS subpart XXa will reduce VOC emissions by 3,000 tpy. The changes 
will have beneficial effects on air quality and public health for 
populations exposed to emissions from gasoline distribution facilities 
with new, modified or reconstructed sources and will provide additional 
health protection for most populations, including communities already 
overburdened by pollution, which are often people of color, low-income, 
and indigenous communities.

V. Statutory and Executive Order Reviews

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

A. Executive Order 12866: Regulatory Planning and Review and Executive 
Order 14094: Modernizing Regulatory Review

    This action is a ``significant regulatory action'' as defined under 
section 3(f)(1) of Executive Order 12866, as amended by Executive Order 
14094. Accordingly, the EPA submitted this action to the Office of 
Management and Budget (OMB) for Executive Order 12866 review. 
Documentation of any changes made in response to the Executive Order 
12866 review is available in the docket. The EPA prepared an analysis 
of the potential costs and benefits associated with this action. This 
analysis, Regulatory Impact Analysis for the Final National Emission 
Standards for Hazardous Air Pollutants: Gasoline Distribution 
Technology Review and Standards of Performance for Bulk Gasoline 
Terminals Review (Ref. EPA-452/R-24-022), is also available in the 
docket.\16\
---------------------------------------------------------------------------

    \16\ A discussion of the market failure that this rulemaking 
action addresses can be found in Chapter 1 of the Regulatory Impact 
Analysis.
---------------------------------------------------------------------------

B. Paperwork Reduction Act (PRA)

1. NESHAP Subpart R
    The information collection activities in this rule have been 
submitted for approval to OMB under the PRA. The Information Collection 
Request (ICR) document that the EPA prepared has been assigned EPA ICR 
number 1659.12. You can find a copy of the ICR in the docket, and it is 
briefly summarized here. The information collections requirements are 
not enforceable until OMB approves them.
    The EPA is finalizing amendments that revise provisions pertaining 
to emissions during periods of SSM, add requirements for electronic 
reporting of periodic reports and performance test results, and make 
other minor clarifications and corrections. This information will be 
collected to assure compliance with NESHAP subpart R.
    Respondents/affected entities: Owners or operators of gasoline 
distribution facilities.
    Respondent's obligation to respond: Mandatory (40 CFR part 63, 
subpart R).
    Estimated number of respondents: 210 (assumes no new respondents 
over next 3 years).
    Frequency of response: Initially, semiannually, and annually.
    Total estimated burden: 16,300 hours (per year) to comply with the 
promulgated amendments in the NESHAP. Burden is defined at 5 CFR 
1320.3(b).
    Total estimated cost: $ 972,013 (per year), including no annualized 
capital or operation and maintenance costs, to comply with the 
promulgated amendments in the NESHAP.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB 
approves this ICR, the Agency will announce that approval in the 
Federal Register and publish a technical amendment to 40 CFR part 9 to 
display the OMB control number for the approved information collection 
activities contained in this final rule.
2. NESHAP Subpart BBBBBB
    The information collection activities in this rule have been 
submitted for approval to OMB under the PRA. The ICR document that the 
EPA prepared has been assigned EPA ICR number 2237.07. You can find a 
copy of the ICR in the docket, and it is briefly summarized here. The 
information collections requirements are not enforceable until OMB 
approves them.

[[Page 39343]]

    The EPA is finalizing amendments that revise provisions to add 
requirements for electronic reporting of periodic reports and 
performance test results, and make other minor clarifications and 
corrections. This information will be collected to assure compliance 
with NESHAP subpart BBBBBB.
    Respondents/affected entities: Owners or operators of gasoline 
distribution facilities.
    Respondent's obligation to respond: Mandatory (40 CFR part 63, 
subpart BBBBBB).
    Estimated number of respondents: 9,263 (assumes no new respondents 
over the next 3 years).
    Frequency of response: Initially, semiannually, and annually.
    Total estimated burden: 83,882 hours (per year) to comply with the 
promulgated amendments in the NESHAP. Burden is defined at 5 CFR 
1320.3(b).
    Total estimated cost: $ 5,001,981 (per year), including no 
annualized capital or operation and maintenance costs, to comply with 
the promulgated amendments in the NESHAP.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB 
approves this ICR, the Agency will announce that approval in the 
Federal Register and publish a technical amendment to 40 CFR part 9 to 
display the OMB control number for the approved information collection 
activities contained in this final rule.
3. NSPS Subpart XXa
    The information collection activities in this rule have been 
submitted for approval to OMB under the PRA. The ICR document that the 
EPA prepared has been assigned EPA ICR number 2720.01. You can find a 
copy of the ICR in the docket, and it is briefly summarized here. The 
information collections requirements are not enforceable until OMB 
approves them.
    The EPA is finalizing provisions to require electronic reporting of 
periodic reports and performance test results. This information will be 
collected to assure compliance with NSPS subpart XXa.
    Respondents/affected entities: Owners or operators of bulk gasoline 
terminals.
    Respondent's obligation to respond: Mandatory (40 CFR part 60, 
subpart XXa).
    Estimated number of respondents: 12 (assumes four new respondents 
each year over the next 3 years).
    Frequency of response: Initially, semiannually, and annually.
    Total estimated burden: 1,132 hours (per year) to comply with all 
of the requirements in the NSPS. Burden is defined at 5 CFR 1320.3(b).
    Total estimated cost: $ 66,930 (per year), including no annualized 
capital or operation and maintenance costs, to comply with all of the 
requirements in the NSPS.
    An agency may not conduct or sponsor, and a person is not required 
to respond to, a collection of information unless it displays a 
currently valid OMB control number. The OMB control numbers for the 
EPA's regulations in 40 CFR are listed in 40 CFR part 9. When OMB 
approves this ICR, the Agency will announce that approval in the 
Federal Register and publish a technical amendment to 40 CFR part 9 to 
display the OMB control number for the approved information collection 
activities contained in this final rule.

C. Regulatory Flexibility Act (RFA)

    I certify that this action will not have significant economic 
impacts on a substantial number of small entities under the RFA. The 
small entities subject to the requirements of these rules are small 
businesses that own gasoline distribution facilities. For NESHAP 
subpart R, the EPA determined that two small entities are affected by 
the amendments, which is 5 percent of all affected ultimate parent 
companies. Neither of these small entities is projected to incur costs 
from this rule greater than 1 percent of their sales. For NESHAP 
subpart BBBBBB, the EPA determined that 116 small entities are affected 
by these amendments, which is 42 percent of all affected ultimate 
parent companies. Less than 9 percent of these small entities (10 
total) are projected to incur costs from this rule greater than 1 
percent of their annual sales, and less than 3 percent (3 total) are 
project to incur costs greater than 3 percent of their annual sales 
(with a maximum economic impact of 6.56 percent) without including 
expected gasoline product recovery. Finally, for NSPS subpart XXa, the 
EPA did not identify any small entities that are affected by NSPS 
subpart XXa and does not project that any entities affected by the NSPS 
will incur costs greater than 1 percent of their annual sales. 
Inclusion of expected gasoline product recovery will reduce these small 
entity impact estimates. Details of the analyses for each rule are 
presented in the RIA available in the docket.

D. Unfunded Mandates Reform Act of 1995 (UMRA)

    This action does not contain an unfunded mandate of $100 million or 
more as described in UMRA, 2 U.S.C. 1531-1538, and does not 
significantly or uniquely affect small governments. While this action 
creates an enforceable duty on the private sector, the cost does not 
exceed $100 million or more.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. This action will 
not have substantial direct effects on the States, on the relationship 
between the National Government and the States, or on the distribution 
of power and responsibilities among the various levels of government.

F. Executive Order 13175: Consultation and Coordination with Indian 
Tribal Governments

    This action does not have Tribal implications, as specified in 
Executive Order 13175. The EPA estimates there are approximately 210 
major source and 9,260 area source gasoline distribution facilities; 
however, we had location information for only 117 of the major source 
facilities and 1,229 of the area source facilities. None of the 
facilities that have been identified as being affected by this action 
are owned or operated by Tribal governments or located within Tribal 
lands. Thus, Executive Order 13175 does not apply to this action. 
However, consistent with the EPA Policy on Consultation with Indian 
Tribes, the EPA offered government-to-government consultation with 
Tribes by sending a letter dated June 24, 2022, inviting all federally 
recognized Tribes to request a consultation. No Tribes requested a 
consultation.

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

    Executive Order 13045 directs Federal agencies to include an 
evaluation of the health and safety effects of the planned regulation 
on children in Federal health and safety standards and explain why the 
regulation is preferable to potentially effective and reasonably 
feasible alternatives. This action is not subject to Executive Order 
13045 because the EPA does not believe the environmental health or 
safety risks addressed by this action present a disproportionate risk 
to children. The final rules lower gasoline vapors and are projected to 
improve overall health including children.

[[Page 39344]]

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

    This action is not a ``significant energy action'' because it is 
not likely to have a significant adverse effect on the supply, 
distribution, or use of energy. The EPA expects these rules will not 
reduce crude oil supply, fuel production, coal production, natural gas 
production, or electricity production. The EPA estimates these rules 
will have minimal impact on the amount of imports or exports of crude 
oils, condensates, or other organic liquids used in the energy supply 
industries. Given the minimal impacts on energy supply, distribution, 
and use as a whole nationally, no significant adverse energy effects 
are expected to occur. For more information on these estimates of 
energy effects, please refer to Chapter 5 of the RIA available in the 
docket.

I. National Technology Transfer and Advancement Act (NTTAA)

    This action involves technical standards. The EPA has decided to 
use EPA Method 18. While the EPA identified ASTM 6420-18 as being 
potentially applicable, the Agency decided not to use it. The use of 
this voluntary consensus standard would be impractical because it has a 
limited list of analytes and is not suitable for analyzing many 
compounds that are expected to occur in gasoline vapor.

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

    For NESHAP subparts R and BBBBBB, the EPA believes that the human 
health or environmental conditions that exist prior to this action 
result in or have the potential to result in disproportionate and 
adverse human health or environmental effects on communities with 
environmental justice concerns. The percent Hispanic or Latino 
population, African American, and Other and Multiracial are above the 
national averages for these demographic groups. The percent of people 
living below the poverty level and those over 25 without a high school 
diploma, and people living in linguistic isolation are also higher than 
the national averages. The EPA believes that this action is likely to 
reduce existing disproportionate and adverse effects on communities 
with environmental justice concerns. The EPA estimates that these 
NESHAP final rules will reduce HAP emissions from gasoline distribution 
facilities by over 2,200 tpy and VOC emissions by 42,500 tpy.
    For NSPS subpart XXa, the EPA believes that it is not practicable 
to assess whether this action is likely to result in new 
disproportionate and adverse effects on communities with environmental 
justice concerns, because the location and number of new, modified, or 
reconstructed sources is unknown. Because NSPS subpart XXa applies to 
future new facilities, the locations of such Bulk Gasoline Terminals 
that will be subject to NSPS subpart XXa are not known. In addition, it 
is not known which existing Bulk Gasoline Terminals may be modified or 
reconstructed and subject to NSPS subpart XXa. Thus, we are limited in 
our ability to estimate the potential EJ impacts of this subpart, but 
we note that future emission increases associated with construction of 
any new, modified, or reconstructed sources will be minimized to levels 
of BSER.
    The information supporting this Executive order review is contained 
in section IV.F. of this action, with additional details in section 
IV.F. of the proposed rules' preamble (87 FR 35637; June 10, 2022), and 
in the technical report, Analysis of Demographic Factors for 
Populations Living Near Gasoline Distribution Facilities, available in 
Docket ID No. EPA-HQ-OAR-2020-0371.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. This action is a ``major rule'' as defined by 5 
U.S.C. 804(2).

List of Subjects in 40 CFR Parts 60 and 63

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

Michael S. Regan,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, parts 
60 and 63 of the Code of Federal Regulations are amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

0
1. The authority citation for part 60 continues to read as follows:

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

Subpart XX--Standards of Performance for Bulk Gasoline Terminals 
That Commenced Construction, Modification, or Reconstruction After 
December 17, 1980, and On or Before June 10, 2022

0
2. The heading for subpart XX is revised to read as set forth above.

0
3. Section 60.500 is amended by revising paragraph (b) to read as 
follows:


Sec.  60.500  Applicability and designation of affected facility.

* * * * *
    (b) Each facility under paragraph (a) of this section, the 
construction or modification of which is commenced after December 17, 
1980, and on or before June 10, 2022, is subject to the provisions of 
this subpart.
* * * * *

0
4. Subpart XXa is added to read as follows:
Subpart XXa--Standards of Performance for Bulk Gasoline Terminals that 
Commenced Construction, Modification, or Reconstruction After June 10, 
2022
Sec.
60.500a Applicability and designation of affected facility.
60.501a Definitions.
60.502a Standard for volatile organic compound (VOC) emissions from 
bulk gasoline terminals.
60.503a Test methods and procedures.
60.504a Monitoring requirements.
60.505a Reporting and recordkeeping.

Subpart XXa--Standards of Performance for Bulk Gasoline Terminals 
that Commenced Construction, Modification, or Reconstruction After 
June 10, 2022


Sec.  60.500a  Applicability and designation of affected facility.

    (a) You are subject to the applicable provisions of this subpart if 
you are the owner or operator of one or more of the affected facilities 
listed in paragraphs (a)(1) and (2) of this section.
    (1) Each gasoline loading rack affected facility, which is 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.
    (2) Each collection of equipment at a bulk gasoline terminal 
affected facility, which is the total of 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

[[Page 39345]]

systems, and the vapor processing system.
    (b) Each affected facility under paragraph (a) of this section for 
which construction, modification (as defined in Sec.  60.2 and detailed 
in Sec.  60.14), or reconstruction (as detailed in Sec.  60.15 and 
paragraph (e) of this section) is commenced after June 10, 2022, is 
subject to the provisions of this subpart.
    (c) All standards including emission limitations shall apply at all 
times, including periods of startup, shutdown, and malfunction. As 
provided in Sec.  60.11(f), this paragraph (c) supersedes the 
exemptions for periods of startup, shutdown, and malfunction in subpart 
A of this part.
    (d) A newly constructed gasoline loading rack affected facility 
that was subject to the standards in Sec.  60.502a(b) will continue to 
be subject to the standards in Sec.  60.502a(b) for newly constructed 
gasoline loading rack affected facilities if they are subsequently 
modified or reconstructed.
    (e) For purposes of this subpart:
    (1) The cost of the following frequently replaced components of the 
gasoline loading rack affected facility shall not be considered in 
calculating either the ``fixed capital cost of the new components'' or 
the ``fixed capital cost that would be required to construct a 
comparable entirely new facility'' under Sec.  60.15: pump seals, 
loading arm gaskets and swivels, coupler gaskets, overfill sensor 
couplers and cables, flexible vapor hoses, and grounding cables and 
connectors.
    (2) Under Sec.  60.15, the ``fixed capital cost of the new 
components'' includes the fixed capital cost of all depreciable 
components, except components specified in paragraph (e)(1) of this 
section which are or will be replaced pursuant to all continuous 
programs of component replacement which are commenced within any 2-year 
period following June 10, 2022. For purposes of this paragraph (e)(2), 
``commenced'' means that an owner or operator has undertaken a 
continuous program of component replacement or that an owner or 
operator has entered into a contractual obligation to undertake and 
complete, within a reasonable time, a continuous program of component 
replacement.


Sec.  60.501a  Definitions.

    The terms used in this subpart are defined in the Clean Air Act, in 
Sec.  60.2, or in this section 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.
    Bulk gasoline terminal means any gasoline facility which receives 
gasoline by pipeline, ship, barge, or cargo tank and subsequently loads 
all or a portion of the gasoline into gasoline cargo tanks for 
transport to bulk gasoline plants or gasoline dispensing facilities and 
has a gasoline throughput greater than 20,000 gallons per day (75,700 
liters per day). Gasoline throughput shall be the maximum calculated 
design throughput for the facility as may be limited by compliance with 
an enforceable condition under Federal, State, or local law and 
discoverable by the Administrator and any other person.
    Continuous monitoring system is a comprehensive term that may 
include, but is not limited to, continuous emission monitoring systems, 
continuous parameter monitoring systems, or other manual or automatic 
monitoring that is used for demonstrating compliance on a continuous 
basis.
    Equipment means each valve, pump, pressure relief device, open-
ended valve or line, sampling connection system, and flange or other 
connector in the gasoline liquid transfer and vapor collection systems. 
This definition also includes the entire vapor processing system except 
the exhaust port(s) or stack(s).
    Flare means a thermal combustion device using an open or shrouded 
flame (without full enclosure) such that the pollutants are not emitted 
through a conveyance suitable to conduct a performance test.
    Gasoline means any petroleum distillate or petroleum distillate/
alcohol blend having a Reid vapor pressure of 4.0 pounds per square 
inch (27.6 kilopascals) or greater which is used as a fuel for internal 
combustion engines.
    Gasoline cargo tank means a delivery tank truck or railcar which is 
loading gasoline or which has loaded gasoline on the immediately 
previous load.
    In gasoline service means that a piece of equipment is used in a 
system that transfers gasoline or gasoline vapors.
    Loading rack means the loading arms, pumps, meters, shutoff valves, 
relief valves, and other piping and valves necessary to fill gasoline 
cargo tanks.
    Submerged filling means the filling of a gasoline cargo tank 
through a submerged fill pipe whose discharge is no more than the 6 
inches from the bottom of the tank. Bottom filling of gasoline cargo 
tanks is included in this definition.
    Thermal oxidation system means an enclosed combustion device used 
to mix and ignite fuel, air pollutants, and air to provide a flame to 
heat and oxidize air pollutants. Auxiliary fuel may be used to heat air 
pollutants to combustion temperatures. Thermal oxidation systems emit 
pollutants through a conveyance suitable to conduct a performance test.
    Total organic compounds (TOC) means those compounds measured 
according to the procedures in Method 25, 25A, or 25B of appendix A-7 
to this part. The methane content may be excluded from the TOC 
concentration as described in Sec.  60.503a.
    Vapor collection system means any equipment used for containing 
total organic compounds vapors displaced during the loading of gasoline 
cargo tanks.
    Vapor processing system means all equipment used for recovering or 
oxidizing total organic compounds vapors displaced from the affected 
facility.
    Vapor recovery system means processing equipment used to absorb 
and/or condense collected vapors and return the total organic compounds 
for blending with gasoline or other petroleum products or return to a 
petroleum refinery or transmix facility for further processing. Vapor 
recovery systems include but are not limited to carbon adsorption 
systems or refrigerated condensers.
    Vapor-tight gasoline cargo tank means a gasoline cargo tank which 
has demonstrated within the 12 preceding months that it meets the 
annual certification test requirements in Sec.  60.503a(f).


Sec.  60.502a  Standard for volatile organic compound (VOC) emissions 
from bulk gasoline terminals.

    (a) Each gasoline loading rack affected facility shall be equipped 
with a vapor collection system designed and operated to collect the 
total organic compounds vapors displaced from gasoline cargo tanks 
during product loading.
    (b) For each newly constructed gasoline loading rack affected 
facility, the facility owner or operator must meet the applicable 
emission limitations in paragraph (b)(1) or (2) of this section no 
later than the date on which Sec.  60.8(a) requires a performance test 
to be completed. A flare cannot be used to

[[Page 39346]]

comply with the emission limitations in this paragraph (b).
    (1) If a thermal oxidation system is used, maintain the emissions 
to the atmosphere from the vapor collection system due to the loading 
of liquid product into gasoline cargo tanks at or below 1.0 milligram 
of total organic compounds per liter of gasoline loaded (mg/L). 
Continual compliance with this requirement must be demonstrated as 
specified in paragraphs (b)(1)(i) and (ii) of this section.
    (i) Conduct initial and periodic performance tests as specified in 
Sec.  60.503a(a) through (c) and meet the emission limitation in this 
paragraph (b)(1).
    (ii) Maintain combustion zone temperature of the thermal oxidation 
system at or above the 3-hour rolling average operating limit 
established during the performance test when loading liquid product 
into gasoline cargo tanks. Valid operating data must exclude periods 
when there is no liquid product being loaded. If previous contents of 
the cargo tanks are known, you may also exclude periods when liquid 
product is loaded but no gasoline cargo tanks are being loaded provided 
that you excluded these periods in the determination of the combustion 
zone temperature operating limit according to the provisions in Sec.  
60.503a(c)(8)(ii).
    (2) If a vapor recovery system is used:
    (i) Maintain the emissions to the atmosphere from the vapor 
collection system at or below 550 parts per million by volume (ppmv) of 
TOC as propane determined on a 3-hour rolling average when the vapor 
recovery system is operating;
    (ii) Operate the vapor recovery system during all periods when the 
vapor recovery system is capable of processing gasoline vapors, 
including periods when liquid product is being loaded, during carbon 
bed regeneration, and when preparing the beds for reuse; and
    (iii) Operate 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.
    (c) For each modified or reconstructed gasoline loading rack 
affected facility, the facility owner or operator must meet the 
applicable emission limitations in paragraphs (c)(1) through (3) of 
this section no later than the date on which Sec.  60.8(a) requires a 
performance test to be completed.
    (1) If a thermal oxidation system is used, maintain the emissions 
to the atmosphere from the vapor collection system due to the loading 
of liquid product into gasoline cargo tanks at or below 10 mg/L. 
Continual compliance with this requirement must be demonstrated as 
specified in paragraphs (c)(1)(i) through (iii) of this section.
    (i) Conduct initial and periodic performance tests as specified in 
Sec.  60.503a(a) through (c) and meet the emission limitation in this 
paragraph (c)(1).
    (ii) Maintain combustion zone temperature of the thermal oxidation 
system at or above the 3-hour rolling average operating limit 
established during the performance test when loading liquid product 
into gasoline cargo tanks. Valid operating data must exclude periods 
when there is no liquid product being loaded. If previous contents of 
the cargo tanks are known, you may also exclude periods when liquid 
product is loaded but no gasoline cargo tanks are being loaded provided 
that you excluded these periods in the determination of the combustion 
zone temperature operating limit according to the provisions in Sec.  
60.503a(c)(8)(ii).
    (iii) As an alternative to the combustion zone temperature 
operating limit, you may elect to use the monitoring provisions as 
specified in paragraph (c)(3) of this section.
    (2) If a vapor recovery system is used:
    (i) Maintain the emissions to the atmosphere from the vapor 
collection system at or below 5,500 ppmv of TOC as propane determined 
on a 3-hour rolling average when the vapor recovery system is 
operating;
    (ii) Operate the vapor recovery system during all periods when the 
vapor recovery system is capable of processing gasoline vapors, 
including periods when liquid product is being loaded, during carbon 
bed regeneration, and when preparing the beds for reuse; and
    (iii) Operate 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.
    (3) If a flare is used or if a thermal oxidation system for which 
these provisions are specified as a monitoring alternative is used, 
meet all applicable requirements specified in Sec.  63.670(b) through 
(g) and (i) through (n) of this chapter except as provided in 
paragraphs (c)(3)(i) through (ix) of this section.
    (i) For the purpose of this subpart, ``regulated materials'' refers 
to ``vapors displaced from gasoline cargo tanks during product 
loading''. If you do not know the previous contents of the cargo tank, 
you must assume that cargo tank is a gasoline cargo tank.
    (ii) In Sec.  63.670(c) of this chapter for visible emissions:
    (A) The phrase ``specify the smokeless design capacity of each 
flare and'' does not apply.
    (B) The phrase ``and the flare vent gas flow rate is less than the 
smokeless design capacity of the flare'' does not apply.
    (C) Substitute ``The owner or operator shall monitor for visible 
emissions from the flare as specified in Sec.  60.504a(c)(4).'' for the 
sentence ``The owner or operator shall monitor for visible emissions 
from the flare as specified in paragraph (h) of this section.''
    (iii) The phrase ``and the flare vent gas flow rate is less than 
the smokeless design capacity of the flare'' in Sec.  63.670(d) of this 
chapter for flare tip velocity requirements does not apply.
    (iv) Substitute ``pilot flame or flare flame'' for each occurrence 
of ``pilot flame.''
    (v) Substitute ``gasoline distribution facility'' for each 
occurrence of ``petroleum refinery'' or ``refinery.''
    (vi) As an alternative to the flow rate monitoring alternatives 
provided in Sec.  63.670(i) of this chapter, you may elect to determine 
flare waste gas flow rate by monitoring the cumulative loading rates of 
all liquid products loaded into cargo tanks for which the displaced 
vapors are managed by the affected facility's vapor collection system 
and vapor processing system.
    (vii) If using provision in Sec.  63.670(j)(6) of this chapter for 
flare vent gas composition monitoring, you must comply with those 
provisions as specified in paragraphs (c)(3)(vii)(A) through (G) of 
this section.
    (A) You must submit a separate written application to the 
Administrator for an exemption from monitoring, as described in Sec.  
63.670(j)(6)(i) of this chapter.
    (B) You must determine the minimum ratio of gasoline loaded to 
total liquid product loaded for which the affected source must operate 
at or above at all times when liquid product is loaded into cargo tanks 
for which vapors collected are sent to the flare or, if applicable, 
thermal oxidation system and include that in the explanation of

[[Page 39347]]

conditions expected to produce the flare gas with lowest net heating 
value as required in Sec.  63.670(j)(6)(i)(C) of this chapter. For air 
assisted flares or thermal oxidation systems, you must also establish a 
minimum gasoline loading rate (i.e., volume of gasoline loaded in a 15-
minute period) for which the affected source must operate at or above 
at all times and include that in the explanation of conditions that 
ensure the flare gas net heating value is consistent and representative 
of the lowest net heating value as required in Sec.  
63.670(j)(6)(i)(C).
    (C) As required in Sec.  63.670(j)(6)(i)(D) of this chapter, 
samples must be collected at the conditions identified in Sec.  
63.670(j)(6)(i)(C) of this chapter, which includes the applicable 
conditions specified in paragraph (c)(3)(vii)(B) of this section.
    (D) The first change from winter gasoline to summer gasoline or 
from summer gasoline to winter gasoline, whichever comes first, is 
considered a change in operating conditions under Sec.  
63.670(j)(6)(iii) of this chapter and must be evaluated according to 
the provisions in Sec.  63.670(j)(6)(iii). If separate net heating 
values are determined for summer gasoline loading versus winter 
gasoline loading, you may use the summer net heating value for all 
subsequent summer gasoline loading operations and the winter net 
heating value for all subsequent winter gasoline loading operations 
provided there are no other changes in operations.
    (E) You must monitor the volume of gasoline loaded and the total 
volume of liquid product loaded on a 5-minute block basis and maintain 
the ratio of gasoline loaded to total liquid product loaded at or above 
the value determined in paragraph (c)(3)(vii)(B) of this section and, 
for air assisted flares or thermal oxidation systems, maintain the 
gasoline loading rate at or above the value determined in paragraph 
(c)(3)(vii)(B) on a rolling 15-minute period basis, calculated based on 
liquid product loaded during 3 contiguous 5-minute blocks, considering 
only those periods when liquid product is loaded into gasoline cargo 
tanks for any portion of three contiguous 5-minute block periods.
    (F) For unassisted or perimeter air assisted flares or thermal 
oxidation systems, if the net heating value determined in Sec.  
63.670(j)(6)(i)(F) of this chapter meets or exceeds 270 British thermal 
units per standard cubic feet (Btu/scf), compliance with the ratio of 
gasoline loaded to total liquid product loaded as specified in 
paragraph (c)(3)(vii)(E) of this section demonstrates compliance with 
the flare combustion zone net heating value (NHVcz) 
operating limit in Sec.  63.670(e) of this chapter.
    (G) For perimeter air assisted flares or thermal oxidation systems, 
if the net heating value determined in Sec.  63.670(j)(6)(i)(F) of this 
chapter meets or exceeds the net heating value dilution parameter 
(NHVdil) operating limit of 22 British thermal units per 
square foot (Btu/ft\2\) at the flow rate associated with the minimum 
gasoline loading rate determined in paragraph (c)(3)(vii)(B) of this 
section at any air assist rate used, compliance with the minimum 
gasoline loading rate as specified in paragraph (c)(3)(vii)(E) of this 
section demonstrates compliance with the NHVdil operating 
limit in Sec.  63.670(f) of this chapter.
    (viii) You may elect to establish a minimum supplemental gas 
addition rate and monitor the supplemental gas addition rate, in 
addition to the operating limits in paragraph (c)(3)(vii)(E) of this 
section, to demonstrate compliance with the flare combustion zone 
operating limit in Sec.  63.670(e) of this chapter and, if applicable, 
flare dilution operating limit in Sec.  63.670(f) of this chapter, as 
follows.
    (A) Use the minimum flare vent gas net heating value prior to 
addition of supplemental gas as established in paragraph (c)(3)(vii) of 
this section.
    (B) Determine the maximum flow rate based on the maximum cumulative 
loading rate for a 15-minute block period considering all loading racks 
at the affected facility and considering restrictions on maximum 
loading rates necessary for compliance with the maximum pressure limits 
for the vapor collection and liquid loading equipment specified in 
paragraph (h) of this section.
    (C) Determine the supplemental gas addition rate needed to yield 
NHVcz of 270 Btu/scf using equation in Sec.  63.670(m)(1) of 
this chapter.
    (D) For flares (or thermal oxidation systems) with perimeter assist 
air, determine the supplemental gas addition rate needed to yield 
NHVdil of 22 Btu/ft\2\ using equation in Sec.  63.670(n)(1) 
of this chapter at the flare vent gas net heating value determined in 
paragraph (c)(3)(vii) of this section, the flare gas flow rate 
associated with the minimum gasoline loading rate as determined in 
paragraph (c)(3)(vii)(B) of this section, and the fixed air assist 
rate. If the air assist rate is varied based on total liquid product 
loading rates, you must use the air assist rate used at low flow rates 
and repeat the calculation using the minimum flow rate associated with 
each air assist rate setting and select the maximum supplemental gas 
addition rate across any of the air assist rate settings.
    (E) Maintain the supplemental gas addition rate above the greater 
of the values determined in paragraphs (c)(3)(viii)(C) and, if 
applicable, (c)(3)(viii)(D) of this section on a 15-minute block period 
basis when liquid product is loaded into gasoline cargo tanks for at 
least 15-minutes.
    (ix) As an alternative to determining the flare tip velocity rate 
for each 15-minute block to determine compliance with the flare tip 
velocity operating limit as specified in Sec.  63.670(k)(2) of this 
chapter, you may elect to conduct a one-time flare tip velocity 
operating limit compliance assessment as provided in paragraphs 
(c)(3)(ix)(A) through (D) of this section. If the flare or loading rack 
configurations change (e.g., flare tip modified or additional loading 
racks are added for which vapors are directed to the flare), you must 
repeat this one-time assessment based on the new configuration.
    (A) Determine the unobstructed cross-sectional area of the flare 
tip, in units of square feet, as specified in Sec.  63.670(k)(1) of 
this chapter.
    (B) Determine the maximum flow rate, in units of cubic feet per 
second, based on the maximum cumulative loading rate for a 15-minute 
block period considering all loading racks at the gasoline loading 
racks affected facility and considering restrictions on maximum loading 
rates necessary for compliance with the maximum pressure limits for the 
vapor collection and liquid loading equipment specified in paragraph 
(h) of this section.
    (C) Calculate the maximum flare tip velocity as the maximum flow 
rate from paragraph (c)(3)(ix)(B) of this section divided by the 
unobstructed cross-sectional area of the flare tip from paragraph 
(c)(3)(ix)(A) of this section.
    (D) Demonstrate that the maximum flare tip velocity as calculated 
in paragraph (c)(3)(ix)(C) of this section is less than 60 feet per 
second.
    (d) Each vapor collection system for the gasoline loading rack 
affected facility shall be designed to prevent any total organic 
compounds vapors collected at one loading rack from passing to another 
loading rack.
    (e) Loadings of liquid product into gasoline cargo tanks at a 
gasoline loading rack affected facility shall be limited to vapor-tight 
gasoline cargo tanks according to the methods in Sec.  60.503a(f) using 
the following procedures:
    (1) The owner or operator shall obtain the vapor tightness annual 
certification test documentation described in Sec.  60.505a(a)(3) for 
each gasoline cargo

[[Page 39348]]

tank which is to be loaded at the affected facility. If you do not know 
the previous contents of a cargo tank, you must assume that cargo tank 
is a gasoline cargo tank.
    (2) The owner or operator shall obtain and record the cargo tank 
identification number of each gasoline cargo tank which is to be loaded 
at the affected facility.
    (3) The owner or operator shall cross-check each cargo tank 
identification number obtained in paragraph (e)(2) of this section with 
the file of gasoline cargo tank vapor tightness documentation specified 
in paragraph (e)(1) of this section prior to loading any liquid product 
into the gasoline cargo tank.
    (f) Loading of liquid product into gasoline cargo tanks at a 
gasoline loading rack affected facility shall be conducted using 
submerged filling, as defined in Sec.  60.501a, and only into gasoline 
cargo tanks equipped with vapor collection equipment that is compatible 
with the terminal's vapor collection system. If you do not know the 
previous contents of a cargo tank, you must assume that cargo tank is a 
gasoline cargo tank.
    (g) Loading of liquid product into gasoline cargo tanks at a 
gasoline loading rack affected facility shall only be conducted when 
the terminal's and the cargo tank's vapor collection systems are 
connected. If you do not know the previous contents of a cargo tank, 
you must assume that cargo tank is a gasoline cargo tank.
    (h) The vapor collection and liquid loading equipment for a 
gasoline loading rack affected facility shall be designed and operated 
to prevent gauge pressure in the gasoline cargo tank from exceeding 18 
inches of water (460 millimeters (mm) of water) during product loading. 
This level is not to be exceeded and must be continuously monitored 
according to the procedures specified in Sec.  60.504a(d).
    (i) No pressure-vacuum vent in the gasoline loading rack affected 
facility's vapor collection system shall begin to open at a system 
pressure less than 18 inches of water (460 mm of water) or at a vacuum 
of less than 6.0 inches of water (150 mm of water).
    (j) Each owner or operator of a collection of equipment at a bulk 
gasoline terminal affected facility shall perform leak inspection and 
repair of all equipment in gasoline service, which includes all 
equipment in the vapor collection system, the vapor processing system, 
and each loading rack and loading arm handling gasoline, according to 
the requirements in paragraphs (j)(1) through (8) of this section. The 
owner or operator must keep a list, summary description, or diagram(s) 
showing the location of all equipment in gasoline service at the 
facility.
    (1) Conduct leak detection monitoring of all pumps, valves, and 
connectors in gasoline service using either of the methods specified in 
paragraph (j)(1)(i) or (ii) of this section.
    (i) Use optical gas imaging (OGI) to quarterly monitor all pumps, 
valves, and connectors in gasoline service as specified in Sec.  
60.503a(e)(2).
    (ii) Use Method 21 of appendix A-7 to this part as specified in 
Sec.  60.503a(e)(1) and paragraphs (j)(1)(ii)(A) through (C) of this 
section.
    (A) All pumps must be monitored quarterly, unless the pump meets 
one of the requirements in Sec.  60.482-1a(d) or Sec.  60.482-2a(d) 
through (g). An instrument reading of 10,000 ppm or greater is a leak.
    (B) All valves must be monitored quarterly, unless the valve meets 
one of the requirements in Sec.  60.482-1a(d) or Sec.  60.482-7a(f) 
through (h). An instrument reading of 10,000 ppm or greater is a leak.
    (C) All connectors must be monitored annually, unless the connector 
meets one of the requirements in Sec.  60.482-1a(d) or Sec.  60.482-
11a(e) or (f). An instrument reading of 10,000 ppm or greater is a 
leak.
    (2) During normal duties, record leaks identified by audio, visual, 
or olfactory methods.
    (3) If evidence of a potential leak is found at any time by audio, 
visual, olfactory, or any other detection method for any equipment (as 
defined in Sec.  60.501a), a leak is detected.
    (4) For pressure relief devices, comply with the requirements in 
paragraphs (j)(4)(i) through (ii) of this section.
    (i) Conduct instrument monitoring of each pressure relief device 
quarterly and within 5 calendar days after each pressure release to 
detect leaks by the methods specified in paragraph (j)(1) of this 
section, except as provided in Sec.  60.482-4a(c).
    (ii) If emissions are observed when using OGI, a leak is detected. 
If Method 21 is used, an instrument reading of 10,000 ppm or greater 
indicates a leak is detected.
    (5) For sampling connection systems, comply with the requirements 
in Sec.  60.482-5a.
    (6) For open-ended valves or lines, comply with the requirements in 
Sec.  60.482-6a.
    (7) When a leak is detected for any equipment, comply with the 
requirements of paragraphs (j)(7)(i) through (iii) of this section.
    (i) A weatherproof and readily visible identification, marked with 
the equipment identification number, must be attached to the leaking 
equipment. The identification on equipment may be removed after it has 
been repaired.
    (ii) An initial attempt at repair shall be made as soon as 
practicable, but no later than 5 calendar days after the leak is 
detected. An initial attempt at repair is not required if the leak is 
detected using OGI and the equipment identified as leaking would 
require elevating the repair personnel more than 2 meters above a 
support surface.
    (iii) Repair or replacement of leaking equipment shall be completed 
within 15 calendar days after detection of each leak, except as 
provided in paragraph (j)(8) of this section.
    (A) For leaks identified pursuant to instrument monitoring required 
under paragraph (j)(1) of this section, the leak is repaired when 
instrument re-monitoring of the equipment does not detect a leak.
    (B) For leaks identified pursuant to paragraph (j)(2) of this 
section, the leak is repaired when the leak can no longer be identified 
using audio, visual, or olfactory methods.
    (8) Delay of repair of leaking equipment will be allowed according 
to the provisions in paragraphs (j)(8)(i) though (iv) of this section. 
The owner or operator shall provide in the semiannual report specified 
in Sec.  60.505a(c), the reason(s) why the repair was delayed and the 
date each repair was completed.
    (i) Delay of repair of equipment will be allowed for equipment that 
is isolated from the affected facility and that does not remain in 
gasoline service.
    (ii) Delay of repair for valves and connectors will be allowed if:
    (A) The owner or operator demonstrates that emissions of purged 
material resulting from immediate repair are greater than the fugitive 
emissions likely to result from delay of repair, and
    (B) When repair procedures are effected, the purged material is 
collected and destroyed or recovered in a control device complying with 
Sec.  60.482-10a or the requirements in paragraph (b) or (c) of this 
section, as applicable.
    (iii) Delay of repair will be allowed for a valve, but not later 
than 3 months after the leak was detected, if valve assembly 
replacement is necessary, valve assembly supplies have been depleted, 
and valve assembly supplies had been sufficiently stocked before the 
supplies were depleted.
    (iv) Delay of repair for pumps will be allowed if:

[[Page 39349]]

    (A) Repair requires the use of a dual mechanical seal system that 
includes a barrier fluid system; and
    (B) Repair is completed as soon as practicable, but not later than 
6 months after the leak was detected.
    (k) You must not allow gasoline to be handled at a bulk gasoline 
terminal that contains an affected facility listed under Sec.  
60.500a(a) in a manner that would result in vapor releases to the 
atmosphere for extended periods of time. Measures to be taken include, 
but are not limited to, the following:
    (1) Minimize gasoline spills;
    (2) Clean up spills as expeditiously as practicable;
    (3) Cover all open gasoline containers and all gasoline storage 
tank fill-pipes with a gasketed seal when not in use; and
    (4) Minimize gasoline sent to open waste collection systems that 
collect and transport gasoline to reclamation and recycling devices, 
such as oil/water separators.


Sec.  60.503a  Test methods and procedures.

    (a) General performance test and performance evaluation 
requirements. (1) In conducting the performance tests or evaluations 
required by this subpart (or as requested by the Administrator), the 
owner or operator shall use the test methods and procedures as 
specified in this section, except as provided in Sec.  60.8(b). The 
three-run requirement of Sec.  60.8(f) does not apply to this subpart.
    (2) Immediately before the performance test, conduct leak detection 
monitoring following the methods in paragraph (e)(1) of this section to 
identify leakage of vapor from all equipment, including loading arms, 
in the gasoline loading rack affected facility while gasoline is being 
loaded into a gasoline cargo tank to ensure the terminal's vapor 
collection system equipment is operated with no detectable emissions. 
The owner or operator shall repair all leaks identified with readings 
of 500 ppmv (as methane) or greater above background before conducting 
the performance test and within the timeframe specified in Sec.  
60.502a(j)(7).
    (b) Performance test or performance evaluation timing. (1) For each 
gasoline loading rack affected facility subject to the mass emission 
limits in Sec.  60.502a(b)(1) or (c)(1), conduct the initial 
performance test of the vapor collection and processing systems 
according to the timing specified in Sec.  60.8(a). For each gasoline 
loading rack affected facility subject to the emission limits in Sec.  
60.502a(b)(2) or (c)(2), conduct the initial performance evaluation of 
the continuous emissions monitoring system (CEMS) according to the 
timing specified for performance tests in Sec.  60.8(a).
    (2) For each gasoline loading rack affected facility complying with 
the mass emission limits in Sec.  60.502a(b)(1) or (c)(1), conduct 
subsequent performance test of the vapor collection and processing 
system no later than 60 calendar months after the previous performance 
test.
    (3) For each gasoline loading rack affected facility complying with 
the concentration emission limits in Sec.  60.502a(b)(2) or (c)(2), 
conduct subsequent performance evaluations of CEMS for the vapor 
collection and processing system no later than 12 calendar months after 
the previous performance evaluation.
    (c) Performance test requirements for mass loading emission limit. 
The owner or operator of a gasoline loading rack affected facility 
shall conduct performance tests of the vapor collection and processing 
system subject to the emission limits in Sec.  60.502a(b)(1) or (c)(1), 
as specified in paragraphs (c)(1) through (8) of this section.
    (1) The performance test shall be 6 hours long during which at 
least 80,000 gallons (300,000 liters) of gasoline is loaded. If this is 
not possible, the test may be continued the same day until 80,000 
gallons (300,000 liters) of gasoline is loaded. If 80,000 gallons 
(300,000 liters) cannot be loaded during the first day of testing, the 
test may be resumed the next day with another 6-hour period. During the 
second day of testing, the 80,000-gallon (300,000-liter) criterion need 
not be met. However, as much as possible, testing should be conducted 
during the 6-hour period in which the highest throughput of gasoline 
normally occurs.
    (2) If the vapor processing system is intermittent in operation and 
employs an intermediate vapor holder to accumulate total organic 
compounds vapors collected from gasoline cargo tanks, the performance 
test shall begin at a reference vapor holder level and shall end at the 
same reference point. The test shall include at least two startups and 
shutdowns of the vapor processor. If this does not occur under 
automatically controlled operations, the system shall be manually 
controlled.
    (3) The emission rate (E) of total organic compounds shall be 
computed using the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MY24.015

Equation 1 to paragraph (c)(3)

Where:

E = emission rate of total organic compounds, mg/liter of gasoline 
loaded.
Vesi = volume of air-vapor mixture exhausted at each 
interval ``i'', scm.
Cei = concentration of total organic compounds at each 
interval ``i'', ppm.
L = total volume of gasoline loaded, liters.
n = number of testing intervals.
i = emission testing interval of 5 minutes.
K = density of calibration gas, 1.83 x 10\6\ for propane, mg/scm.

    (4) The performance test shall be conducted in intervals of 5 
minutes. For each interval ``i'', readings from each measurement shall 
be recorded, and the volume exhausted (Vesi) and the 
corresponding average total organic compounds concentration 
(Cei) shall be determined. The sampling system response time 
shall be accounted for when determining the average total organic 
compounds concentration corresponding to the volume exhausted.
    (5) Method 2B of appendix A-1 to this part shall be used to 
determine the volume (Vesi) of air-vapor mixture exhausted 
at each interval.
    (6) Method 25, 25A, or 25B of appendix A-7 to this part shall be 
used for determining the total organic compounds concentration 
(Cei) at each interval. Method 25 must not be used if the 
outlet TOC concentration is less than 50 ppmv. The calibration gas 
shall be propane. If the owner or operator conducts the performance 
test using either Method 25A or Method 25B, the methane content in the 
exhaust vent may be excluded following the procedures in paragraphs 
(c)(6)(i) through (v) of this section. Alternatively, an instrument 
that uses gas chromatography with a flame ionization detector may be 
used according to the procedures in paragraph (c)(6)(vi) of this 
section.
    (i) Measure the methane concentration by Method 18 of appendix A-6 
to this part or Method 320 of appendix A to part 63 of this chapter.

[[Page 39350]]

    (ii) Calibrate the Method 25A or Method 25B analyzer using both 
propane and methane to develop response factors to both compounds.
    (iii) Determine the TOC concentration with the Method 25A or Method 
25B analyzer on an as methane basis.
    (iv) Subtract the methane measured according to paragraph (c)(6)(i) 
of this section from the concentration determined in paragraph 
(c)(6)(iii) of this section.
    (v) Convert the concentration difference determined in paragraph 
(c)(6)(iv) of this section to TOC (minus methane), as propane, by using 
the response factors determined in paragraph (c)(6)(ii) of this 
section. Multiply the concentration difference in paragraph (c)(6)(iv) 
of this section by the ratio of the response factor for propane to the 
response factor for methane.
    (vi) Methane must be separated by the gas chromatograph and 
measured by the flame ionization detector, followed by a back-flush of 
the chromatographic column to directly measure TOC concentration minus 
methane. Use a direct interface and heated sampling line from the 
sampling point to the gas chromatographic injection valve. All sampling 
components leading to the analyzer must be heated to greater than 110 
[deg]C. Calibrate the instrument with propane. Calibration error and 
calibration drift must be demonstrated according to Method 25A, and the 
appropriate procedures in Method 25A must be followed to ensure the 
calibration error and calibration drift are within Method 25A limits. 
The TOC concentration minus methane must be recorded at least once 
every 15 minutes. The performance test report must include the 
calibration results and the results demonstrating proper separation of 
methane from the TOC concentration.
    (7) To determine the volume (L) of gasoline dispensed during the 
performance test period at all loading racks whose vapor emissions are 
controlled by the processing system being tested, terminal records or 
readings from gasoline dispensing meters at each loading rack shall be 
used.
    (8) Monitor the temperature in the combustion zone using the 
continuous parameter monitoring system (CPMS) required in Sec.  
60.504a(a) and determine the operating limit for the combustion device 
using the following procedures:
    (i) Record the temperature or average temperature for each 5-minute 
period during the performance test.
    (ii) Using only the 5-minute periods in which liquid product is 
loaded into gasoline cargo tanks, determine the 1-hour average 
temperature for each hour of the performance test. If you do not know 
the previous contents of the cargo tank, you must assume liquid product 
loading is performed in gasoline cargo tanks such that you use all 5-
minute periods in which liquid product is loaded into gasoline cargo 
tanks when determining the 1-hour average temperature for each hour of 
the performance test.
    (iii) Starting at the end of the third hour of the performance test 
and at the end of each successive hour, calculate the 3-hour rolling 
average temperature using the 1-hour average values in paragraph 
(c)(8)(ii) of this section. For a 6-hour test, this would result in 
four 3-hour averages (averages for hours 1 through 3, 2 through 4, 3 
through 5, and 4 through 6).
    (iv) Set the operating limit at the lowest 3-hour average 
temperature determined in paragraph (c)(8)(iii) of this section. New 
operating limits become effective on the date that the performance test 
report is submitted to the U.S. Environmental Protection Agency (EPA) 
Compliance and Emissions Data Reporting Interface (CEDRI), per the 
requirements of Sec.  60.505a(b).
    (d) Performance evaluation requirements for concentration emission 
limit. The owner or operator shall conduct performance evaluations of 
the CEMS for vapor collection and processing systems subject to the 
emission limits in Sec.  60.502a(b)(2) or (c)(2) as specified in 
paragraph (d)(1) or (2) of this section, as applicable.
    (1) If the CEMS uses a nondispersive infrared analyzer, the CEMS 
must be installed, evaluated, and operated according to the 
requirements of Performance Specification 8 of appendix B to this part. 
Method 25B in appendix A-7 to this part must be used as the reference 
method, and the calibration gas must be propane. The owner or operator 
may request an alternative test method under Sec.  60.8(b) to use a 
CEMS that excludes the methane content in the exhaust vent.
    (2) If the CEMS uses a flame ionization detector, the CEMS must be 
installed, evaluated, and operated according to the requirements of 
Performance Specification 8A of appendix B to this part. As part of the 
performance evaluation, conduct a relative accuracy test audit (RATA) 
following the procedures in Performance Specification 2, section 8.4, 
of appendix B to this part; the relative accuracy must meet the 
criteria of Performance Specification 8, section 13.2, of appendix B to 
this part. Method 25A in appendix A-7 to this part must be used as the 
reference method, and the calibration gas must be propane. The owner or 
operator may exclude the methane content in the exhaust following the 
procedures in paragraphs (d)(2)(i) through (iv) of this section.
    (i) Methane must be separated using a chromatographic column and 
measured by the flame ionization detector, followed by a back-flush of 
the chromatographic column to directly measure TOC concentration minus 
methane.
    (ii) The CEMS must be installed, evaluated, and operated according 
to the requirements of Performance Specification 8A of appendix B to 
this part, except the target compound is TOC minus methane. As part of 
the performance evaluation, conduct a RATA following the procedures in 
Performance Specification 2, section 8.4, of appendix B to this part; 
the relative accuracy must meet the criteria of Performance 
Specification 8, section 13.2, of appendix B to this part.
    (iii) If the concentration of TOC minus methane in the exhaust 
stream is greater than 50 ppmv, Method 25 in appendix A-7 to this part 
must be used as the reference method, and the calibration gas must be 
propane. If the concentration of TOC minus methane in the exhaust 
stream is 50 ppmv or less, Method 25A in appendix A-7 to this part must 
be used as the reference method, and the calibration gas must be 
propane. If Method 25A is the reference method, the procedures in 
paragraph (c)(6) of this section may be used to subtract methane from 
the TOC concentration.
    (iv) The TOC concentration minus methane must be recorded at least 
once every 15 minutes.
    (e) Leak detection monitoring. Conduct the leak detection 
monitoring specified in Sec.  60.502a(j)(1) for the collection of 
equipment at a bulk gasoline terminal affected facility using one of 
the procedures specified in paragraph (e)(1) or (2) of this section. 
Conduct the leak detection monitoring specified in paragraph (a)(2) of 
this section using the procedures specified in paragraph (e)(1) of this 
section, except that the instrument reading that defines a leak is 
specified in paragraph (a)(2) for all equipment, including loading 
arms, in the gasoline loading rack affected facility and the 
calibration gas in paragraph (e)(1)(ii) must be at a concentration of 
500 ppm methane.
    (1) Method 21 in appendix A-7 to this part. The instrument reading 
that defines a leak is 10,000 ppmv (as methane). The instrument shall 
be calibrated before use each day of its use by the procedures 
specified in Method 21 of appendix A-7. The calibration

[[Page 39351]]

gases in paragraphs (e)(1)(i) and (ii) of this section must be used. 
The drift assessment specified in paragraph (e)(1)(iii) of this section 
must be performed at the end of each monitoring day.
    (i) Zero air (less than 10 ppm of hydrocarbon in air); and
    (ii) Methane and air at a concentration of 10,000 ppm methane.
    (iii) At the end of each monitoring day, check the instrument using 
the same calibration gas that was used to calibrate the instrument 
before use. Follow the procedures specified in Method 21 of appendix A-
7 to this part, section 10.1, except do not adjust the meter readout to 
correspond to the calibration gas value. If multiple scales are used, 
record the instrument reading for each scale used. Divide the 
arithmetic difference of the initial and post-test calibration response 
by the corresponding calibration gas value for each scale and multiply 
by 100 to express the calibration drift as a percentage. If a 
calibration drift assessment shows a negative drift of more than 10 
percent, then re-monitor all equipment monitored since the last 
calibration with instrument readings between the leak definition and 
the leak definition multiplied by (100 minus the percent of negative 
drift) divided by 100. If any calibration drift assessment shows a 
positive drift of more than 10 percent from the initial calibration 
value, then, at the owner/operator's discretion, all equipment with 
instrument readings above the leak definition and below the leak 
definition multiplied by (100 plus the percent of positive drift) 
divided by 100 monitored since the last calibration may be re-
monitored.
    (2) OGI according to all the requirements in appendix K to this 
part. A leak is defined as any emissions plume imaged by the camera 
from equipment regulated by this subpart.
    (f) Annual certification test. The annual certification test for 
gasoline cargo tanks shall consist of the following test methods and 
procedures:
    (1) Method 27 of appendix A-8 to this part. Conduct the test using 
a time period (t) for the pressure and vacuum tests of 5 minutes. The 
initial pressure (Pi) for the pressure test shall be 460 mm 
water (H2O) (18 in. H2O), gauge. The initial 
vacuum (Vi) for the vacuum test shall be 150 mm 
H2O (6 in. H2O), gauge. The maximum allowable 
pressure and vacuum changes ([Delta] p, [Delta] v) are as shown in 
table 1 to this paragraph (f)(1).

Table 1 to Paragraph (f)(1)--Allowable Gasoline Cargo Tank Test Pressure
                            or Vacuum Change
------------------------------------------------------------------------
                                                    Annual certification-
                                                      allowable pressure
                                                      or vacuum change
   Gasoline cargo tank or compartment capacity,      ([Delta] p, [Delta]
                 gallons (liters)                    v) in 5 minutes, mm
                                                        H2O (in. H2O)
 
------------------------------------------------------------------------
2,500 or more (9,464 or more).....................           12.7 (0.50)
1,500 to 2,499 (5,678 to 9,463)...................           19.1 (0.75)
1,000 to 1,499 (3,785 to 5,677)...................           25.4 (1.00)
999 or less (3,784 or less).......................           31.8 (1.25)
------------------------------------------------------------------------

    (2) Pressure test of the gasoline cargo tank's internal vapor valve 
as follows:
    (i) After completing the tests under paragraph (f)(1) of this 
section, use the procedures in Method 27 to repressurize the gasoline 
cargo tank to 460 mm H2O (18 in. H2O), gauge. 
Close the gasoline cargo tank's internal vapor valve(s), thereby 
isolating the vapor return line and manifold from the gasoline cargo 
tank.
    (ii) Relieve the pressure in the vapor return line to atmospheric 
pressure, then reseal the line. After 5 minutes, record the gauge 
pressure in the vapor return line and manifold. The maximum allowable 
5-minute pressure increase is 65 mm H2O (2.5 in. 
H2O).
    (3) As an alternative to paragraph (f)(1) of this section, you may 
use the procedure in Sec.  63.425(i) of this chapter.


Sec.  60.504a  Monitoring requirements.

    (a) Monitoring requirements for thermal oxidation systems complying 
with the combustion zone temperature operating limit. Install, operate, 
and maintain a CPMS for measuring the combustion zone temperature as 
specified in paragraphs (a)(1) through (5) of this section.
    (1) Install the temperature CPMS in the combustion (flame) zone or 
in the exhaust gas stream as close as practical to the combustion 
burners in a position that provides a representative temperature of the 
combustion zone of the thermal oxidation system.
    (2) The temperature CPMS must be capable of measuring temperature 
with an accuracy of 1 percent over the normal range of 
temperatures measured.
    (3) The temperature CPMS must be capable of recording the 
temperature at least once every 5 minutes and calculating hourly block 
averages that include only those 5-minute periods in which liquid 
product was loaded into gasoline cargo tanks.
    (4) At least quarterly, inspect all components for integrity and 
all electrical connections for continuity, oxidation, and galvanic 
corrosion, unless the CPMS has a redundant temperature sensor.
    (5) Conduct calibration checks at least annually and conduct 
calibration checks following any period of more than 24 hours 
throughout which the temperature exceeded the manufacturer's specified 
maximum rated temperature or install a new temperature sensor.
    (b) Monitoring requirements for vapor recovery systems. Install, 
calibrate, operate, and maintain a CEMS for measuring the concentration 
of TOC in the atmospheric vent from the vapor recovery system as 
specified in paragraphs (b)(1) and (2) of this section. Locate the 
sampling probe or other interface at a measurement location such that 
you obtain representative measurements of emissions from the vapor 
recovery system.
    (1) The requirements of Performance Specification 8 of appendix B 
to this part, or, if the CEMS uses a flame ionization detector, 
Performance Specification 8A of appendix B to this part, the quality 
assurance requirements in Procedure 1 of appendix F to this part, and 
the procedures under Sec.  60.13 must be followed for installation, 
evaluation, and operation of the CEMS. For CEMS certified using 
Performance Specification 8A of appendix B, conduct the RATA required 
under Procedure 1 according to the requirements in Sec.  60.503a(d). As 
required by Sec.  60.503a(b)(3), conduct annual performance evaluations 
of each TOC CEMS according to the requirements in Sec.  60.503a(d). 
Conduct accuracy determinations quarterly and calibration drift tests 
daily in accordance with Procedure 1 in appendix F.
    (2) The span value of the TOC CEMS must be approximately 2 times 
the applicable emission limit.
    (c) Monitoring requirements for flares and thermal oxidation 
systems for which flare monitoring alternative is provided. Install, 
operate, and maintain CPMS for flares used to comply with the emission 
limitations in Sec.  60.502a(c)(3), including monitors used for 
gasoline and total liquid product loading rates, following the 
requirements specified in Sec.  63.671 of this chapter as specified in 
paragraphs (c)(1) through (3) of this section and conduct visible 
emission observations as specified in paragraph (c)(4) of this section.
    (1) Substitute ``pilot flame or flare flame'' for each occurrence 
of ``pilot flame.''
    (2) You may elect to determine compositional analysis for net 
heating value with a continuous process mass spectrometer without the 
use of a gas

[[Page 39352]]

chromatograph. If you choose to determine compositional analysis for 
net heating value with a continuous process mass spectrometer, then you 
must comply with the requirements specified in paragraphs (c)(2)(i) 
through (vii) of this section.
    (i) You must meet the requirements in Sec.  63.671(e)(2) of this 
chapter. You may augment the minimum list of calibration gas components 
found in Sec.  63.671(e)(2) with compounds found during a pre-survey or 
known to be in the gas through process knowledge.
    (ii) Calibration gas cylinders must be certified to an accuracy of 
2 percent and traceable to National Institute of Standards and 
Technology (NIST) standards.
    (iii) For unknown gas components that have similar analytical mass 
fragments to calibration compounds, you may report the unknowns as an 
increase in the overlapped calibration gas compound. For unknown 
compounds that produce mass fragments that do not overlap calibration 
compounds, you may use the response factor for the nearest molecular 
weight hydrocarbon in the calibration mix to quantify the unknown 
component's net heating value of flare vent gas (NHVvg).
    (iv) You may use the response factor for n-pentane to quantify any 
unknown components detected with a higher molecular weight than n-
pentane.
    (v) You must perform an initial calibration to identify mass 
fragment overlap and response factors for the target compounds.
    (vi) You must meet applicable requirements in Performance 
Specification 9 of appendix B to this part for continuous monitoring 
system acceptance including, but not limited to, performing an initial 
multi-point calibration check at three concentrations following the 
procedure in section 10.1 of Performance Specification 9 and performing 
the periodic calibration requirements listed for gas chromatographs in 
table 13 to part 63, subpart CC, of this chapter, for the process mass 
spectrometer. You may use the alternative sampling line temperature 
allowed under Net Heating Value by Gas Chromatograph in table 13 to 
part 63, subpart CC.
    (vii) The average instrument calibration error (CE) for each 
calibration compound at any calibration concentration must not differ 
by more than 10 percent from the certified cylinder gas value. The CE 
for each component in the calibration blend must be calculated using 
the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MY24.016

Equation 1 to paragraph (c)(2)(vii)

Where:

Cm = Average instrument response (ppm).
Ca = Certified cylinder gas value (ppm).

    (3) If you use a gas chromatograph or mass spectrometer for 
compositional analysis for net heating value, then you may choose to 
use the CE of net heating value (NHV) measured versus the cylinder tag 
value NHV as the measure of agreement for daily calibration and 
quarterly audits in lieu of determining the compound-specific CE. The 
CE for NHV at any calibration level must not differ by more than 10 
percent from the certified cylinder gas value. The CE for NHV must be 
calculated using the following equation:
[GRAPHIC] [TIFF OMITTED] TR08MY24.017

Equation 2 to paragraph (c)(3)

Where:

NHVmeasured = Average instrument response (Btu/scf)
NHVa = Certified cylinder gas value (Btu/scf).

    (4) If visible emissions are observed for more than one continuous 
minute during normal duties, visible emissions observation using Method 
22 of appendix A-7 to this part must be conducted for 2 hours or until 
5-minutes of visible emissions are observed.
    (d) Pressure CPMS requirements. The owner or operator shall 
install, operate, and maintain a CPMS to measure the pressure of the 
vapor collection system to determine compliance with the standard in 
Sec.  60.502a(h) as specified in paragraphs (d)(1) through (4) of this 
section.
    (1) Install a pressure CPMS (liquid manometer, magnehelic gauge, or 
equivalent instrument), capable of measuring up to 500 mm of water 
gauge pressure with 2.5 mm of water precision on the 
terminal's vapor collection system at a pressure tap located as close 
as possible to the connection with the gasoline cargo tank. If 
necessary to obtain representative loading pressures, install pressure 
CPMS for each loading rack.
    (2) Check the calibration of the pressure CPMS at least annually. 
Check the calibration of the pressure CPMS following any period of more 
than 24 hours throughout which the pressure exceeded the manufacturer's 
specified maximum rated pressure or install a new pressure sensor.
    (3) At least quarterly, visually inspect components of the pressure 
CPMS for integrity, oxidation and galvanic corrosion, unless the system 
has a redundant pressure sensor.
    (4) The output of the pressure CPMS must be reviewed each operating 
day to ensure that the pressure readings fluctuate as expected during 
loading of gasoline cargo tanks to verify the pressure taps are not 
plugged. Plugged pressure taps must be unplugged or otherwise repaired 
within 24 hours or prior to the next gasoline cargo tank loading, 
whichever time period is longer.
    (e) Limited alternative requirements for vapor recovery systems. If 
the CEMS used for measuring the concentration of TOC in the atmospheric 
vent from the vapor recovery system as specified in paragraph (b) of 
this section requires maintenance such that it is off-line for more 
than 15 minutes, you may follow the requirements in paragraphs (e)(1) 
and (2) of this section and monitor product loading quantities and 
regeneration cycle parameters as an alternative to the monitoring 
requirement in paragraph (b) for no more than 240 hours in a calendar 
year.
    (1) Determine the quantity of liquid product loaded in gasoline 
cargo tanks for the past 10 adsorption cycles prior to the CEMS going 
off-line and select the smallest of these values as your

[[Page 39353]]

product loading quantity operating limit.
    (2) Determine the vacuum pressure, purge gas quantities, and 
duration of the vacuum/purge cycles used for the past 10 desorption 
cycles prior to the CEMS going off-line. You must operate vapor 
recovery system desorption cycles as specified in paragraphs (e)(2)(i) 
through (iii) of this section.
    (i) The vacuum pressure for each desorption cycle must be at or 
above the average vacuum pressure from the past 10 desorption cycles. 
Note: a higher vacuum means a lower absolute pressure.
    (ii) Purge gas quantity used for each desorption cycle must be at 
or above the average quantity of purge gas used from the past 10 
desorption cycles.
    (iii) Duration of the vacuum/purge cycle for each desorption cycle 
must be at or above the average duration of the vacuum/purge cycle used 
from the past 10 desorption cycles.


Sec.  60.505a  Recordkeeping and reporting.

    (a) Recordkeeping requirements. For each affected facility listed 
under Sec.  60.500a(a), keep records as specified in paragraphs (a)(1) 
through (9) of this section, as applicable, for a minimum of five years 
unless otherwise specified in this section. These recordkeeping 
requirements supersede the requirements in Sec.  60.7(b).
    (1) For each thermal oxidation system used to comply with the 
emission limitations in Sec.  60.502a(b)(1) or (c)(1) by monitoring the 
combustion zone temperature as specified in Sec.  60.502a(b)(1)(ii) or 
(c)(1)(ii), for each pressure CPMS used to comply with the requirements 
in Sec.  60.502a(h), and for each vapor recovery system used to comply 
with the emission limitations in Sec.  60.502a(b)(2) or (c)(2), 
maintain records, as applicable, of:
    (i) The applicable operating or emission limit for the continuous 
monitoring system (CMS). For combustion zone temperature operating 
limits, include the applicable date range the limit applies based on 
when the performance test was conducted.
    (ii) Each 3-hour rolling average combustion zone temperature 
measured by the temperature CPMS, each 5-minute average reading from 
the pressure CPMS, and each 3-hour rolling average TOC concentration 
(as propane) measured by the TOC CEMS.
    (iii) For each deviation of the 3-hour rolling average combustion 
zone temperature operating limit, maximum loading pressure specified in 
Sec.  60.502a(h), or 3-hour rolling average TOC concentration (as 
propane), the start date and time, duration, cause, and the corrective 
action taken.
    (iv) For each period when there was a CMS outage or the CMS was out 
of control, the start date and time, duration, cause, and the 
corrective action taken. For TOC CEMS outages where the limited 
alternative for vapor recovery systems in Sec.  60.504a(e) is used, the 
corrective action taken shall include an indication of the use of the 
limited alternative for vapor recovery systems in Sec.  60.504a(e).
    (v) Each inspection or calibration of the CMS including a unique 
identifier, make, and model number of the CMS, and date of calibration 
check. For TOC CEMS, include the type of CEMS used (i.e., flame 
ionization detector, nondispersive infrared analyzer) and an indication 
of whether methane is excluded from the TOC concentration reported in 
paragraph (a)(1)(ii) of this section.
    (vi) For TOC CEMS outages where the limited alternative for vapor 
recovery systems in Sec.  60.504a(e) is used, also keep records of:
    (A) The quantity of liquid product loaded in gasoline cargo tanks 
for the past 10 adsorption cycles prior to the CEMS outage.
    (B) The vacuum pressure, purge gas quantities, and duration of the 
vacuum/purge cycles used for the past 10 desorption cycles prior to the 
CEMS outage.
    (C) The quantity of liquid product loaded in gasoline cargo tanks 
for each adsorption cycle while using the alternative.
    (D) The vacuum pressure, purge gas quantities, and duration of the 
vacuum/purge cycles for each desorption cycle while using the 
alternative.
    (2) For each flare used to comply with the emission limitations in 
Sec.  60.502a(c)(3) and for each thermal oxidation system using the 
flare monitoring alternative as provided in Sec.  60.502a(c)(1)(iii), 
maintain records of:
    (i) The output of the monitoring device used to detect the presence 
of a pilot flame as required in Sec.  63.670(b) of this chapter for a 
minimum of 2 years. Retain records of each 15-minute block during which 
there was at least one minute that no pilot flame was present when 
gasoline vapors were routed to the flare for a minimum of 5 years. The 
record must identify the start and end time and date of each 15-minute 
block.
    (ii) Visible emissions observations as specified in paragraphs 
(a)(2)(ii)(A) and (B) of this section, as applicable, for a minimum of 
3 years.
    (A) If visible emissions observations are performed using Method 22 
of appendix A-7 to this part, the record must identify the date, the 
start and end time of the visible emissions observation, and the number 
of minutes for which visible emissions were observed during the 
observation. If the owner or operator performs visible emissions 
observations more than one time during a day, include separate records 
for each visible emissions observation performed.
    (B) For each 2-hour period for which visible emissions are observed 
for more than 5 minutes in 2 consecutive hours but visible emissions 
observations according to Method 22 of appendix A-7 to this part were 
not conducted for the full 2-hour period, the record must include the 
date, the start and end time of the visible emissions observation, and 
an estimate of the cumulative number of minutes in the 2-hour period 
for which emissions were visible based on best information available to 
the owner or operator.
    (iii) Each 15-minute block period during which operating values are 
outside of the applicable operating limits specified in Sec.  63.670(d) 
through (f) of this chapter when liquid product is being loaded into 
gasoline cargo tanks for at least 15-minutes identifying the specific 
operating limit that was not met.
    (iv) The 15-minute block average cumulative flows for flare vent 
gas or the thermal oxidation system vent gas and, if applicable, total 
steam, perimeter assist air, and premix assist air specified to be 
monitored under Sec.  63.670(i) of this chapter, along with the date 
and start and end time for the 15-minute block. If multiple monitoring 
locations are used to determine cumulative vent gas flow, total steam, 
perimeter assist air, and premix assist air, retain records of the 15-
minute block average flows for each monitoring location for a minimum 
of 2 years, and retain the 15-minute block average cumulative flows 
that are used in subsequent calculations for a minimum of 5 years. If 
pressure and temperature monitoring is used, retain records of the 15-
minute block average temperature, pressure and molecular weight of the 
flare vent gas, thermal oxidation system vent gas, or assist gas stream 
for each measurement location used to determine the 15-minute block 
average cumulative flows for a minimum of 2 years, and retain the 15-
minute block average cumulative flows that are used in subsequent 
calculations for a minimum of 5 years. If you use the supplemental gas 
flow rate monitoring alternative in Sec.  60.502a(c)(3)(viii), the 
required minimum supplemental gas flow rate (winter and summer, if 
applicable) and the actual monitored supplemental gas flow rate for the 
15-

[[Page 39354]]

minute block. Retain the supplemental gas flow rate records for a 
minimum of 5 years.
    (v) The flare vent gas compositions or thermal oxidation system 
vent gas specified to be monitored under Sec.  63.670(j) of this 
chapter. Retain records of individual component concentrations from 
each compositional analyses for a minimum of 2 years. If an 
NHVvg analyzer is used, retain records of the 15-minute 
block average values for a minimum of 5 years. If you demonstrate your 
gas streams have consistent composition using the provisions in Sec.  
63.670(j)(6) of this chapter as specified in Sec.  60.502a(c)(3)(vii), 
retain records of the required minimum ratio of gasoline loaded to 
total liquid product loaded and the actual ratio on a 5-minute block 
basis. If applicable, you must retain records of the required minimum 
gasoline loading rate as specified in Sec.  60.502a(c)(3)(vii) and the 
actual gasoline loading rate on a 5-minute block basis for a minimum of 
5 years.
    (vi) Each 15-minute block average operating parameter calculated 
following the methods specified in Sec.  63.670(k) through (n) of this 
chapter, as applicable.
    (vii) All periods during which the owner or operator does not 
perform monitoring according to the procedures in Sec.  63.670(g), (i), 
and (j) of this chapter or in Sec.  60.502a(c)(3)(vii) and (viii) as 
applicable. Note the start date, start time, and duration in minutes 
for each period.
    (viii) An indication of whether ``vapors displaced from gasoline 
cargo tanks during product loading'' excludes periods when liquid 
product is loaded but no gasoline cargo tanks are being loaded or if 
liquid product loading is assumed to be loaded into gasoline cargo 
tanks according to the provisions in Sec.  60.502a(c)(3)(i), records of 
all time periods when ``vapors displaced from gasoline cargo tanks 
during product loading'', and records of time periods when there were 
no ``vapors displaced from gasoline cargo tanks during product 
loading''.
    (ix) If you comply with the flare tip velocity operating limit 
using the one-time flare tip velocity operating limit compliance 
assessment as provided in Sec.  60.502a(c)(3)(ix), maintain records of 
the applicable one-time flare tip velocity operating limit compliance 
assessment for as long as you use this compliance method.
    (x) For each parameter monitored using a CMS, retain the records 
specified in paragraphs (a)(2)(x)(A) through (C) of this section, as 
applicable:
    (A) For each deviation, record the start date and time, duration, 
cause, and corrective action taken.
    (B) For each period when there is a CMS outage or the CMS is out of 
control, record the start date and time, duration, cause, and 
corrective action taken.
    (C) Each inspection or calibration of the CMS including a unique 
identifier, make, and model number of the CMS, and date of calibration 
check.
    (3) The gasoline cargo tank vapor tightness documentation required 
under Sec.  60.502a(e)(1) for each gasoline cargo tank loading at the 
affected facility shall be kept on file at the terminal in either a 
hardcopy or electronic form available for inspection. The documentation 
shall include, at a minimum, the following information:
    (i) Test title: Annual Certification Test--EPA Method 27 or Railcar 
Bubble Leak Test Procedure.
    (ii) Cargo tank owner's name and address.
    (iii) Cargo tank identification number.
    (iv) Test location and date.
    (v) Tester name and signature.
    (vi) Witnessing inspector, if any: Name, signature, and 
affiliation.
    (vii) Vapor tightness repair: Nature of repair work and when 
performed in relation to vapor tightness testing.
    (viii) Test results: Tank or compartment capacity, test pressure; 
pressure or vacuum change, mm of water; time period of test; number of 
leaks found with instrument; and leak definition.
    (4) Records of each instance in which liquid product was loaded 
into a gasoline cargo tank for which vapor tightness documentation 
required under Sec.  60.502a(e)(1) was not provided or available in the 
terminal's records. These records shall include, at a minimum:
    (i) Cargo tank owner and address.
    (ii) Cargo tank identification number.
    (iii) Date and time liquid product was loaded into a gasoline cargo 
tank without proper documentation.
    (iv) Date proper documentation was received or statement that 
proper documentation was never received.
    (5) Records of each instance when liquid product was loaded into 
gasoline cargo tanks not using submerged filling, as defined in Sec.  
60.501a, not equipped with vapor collection equipment that is 
compatible with the terminal's vapor collection system, or not properly 
connected to the terminal's vapor collection system. These records 
shall include, at a minimum:
    (i) Date and time of liquid product loading into gasoline cargo 
tank not using submerged filling, improperly equipped, or improperly 
connected.
    (ii) Type of deviation (e.g., not submerged filling, incompatible 
equipment, not properly connected).
    (iii) Cargo tank identification number.
    (6) A record [list, summary description, or diagram(s) showing the 
location] of all equipment in gasoline service at the collection of 
equipment at a bulk gasoline terminal affected facility and at the 
loading rack affected facility. A record of each leak inspection and 
leak identified under Sec. Sec.  60.503a(a)(2) and 60.502a(j) as 
specified in paragraphs (a)(6)(i) through (iv) of this section:
    (i) For each leak inspection, keep the following records:
    (A) An indication if the leak inspection was conducted under Sec.  
60.502a(j) or Sec.  60.503a(a)(2).
    (B) Leak determination method used for the leak inspection.
    (ii) For leak inspections conducted with Method 21 of appendix A-7 
to this part, keep the following additional records:
    (A) Date of inspection.
    (B) Inspector name.
    (C) Monitoring instrument identification.
    (D) Identification of all equipment surveyed and the instrument 
reading for each piece of equipment.
    (E) Date and time of instrument calibration and initials of 
operator performing the calibration.
    (F) Calibration gas cylinder identification, certification date, 
and certified concentration.
    (G) Instrument scale used.
    (H) Results of the daily calibration drift assessment.
    (iii) For leak inspections conducted with OGI, keep the records 
specified in section 12 of appendix K to this part.
    (iv) For each leak detected during a leak inspection or by audio/
visual/olfactory methods during normal duties, record the following 
information:
    (A) The equipment type and identification number.
    (B) The date the leak was detected, the name of the person who 
found the leak, the nature of the leak (i.e., vapor or liquid), and the 
method of detection (i.e., audio/visual/olfactory, Method 21 of 
appendix A-7 to this part, or OGI).
    (C) The dates of each attempt to repair the leak and the repair 
methods applied in each attempt to repair the leak.
    (D) The date of successful repair of the leak, the method of 
monitoring used to confirm the repair, and if Method 21 of appendix A-7 
to this part is used to confirm the repair, the maximum instrument 
reading measured by Method 21 of appendix A-7. If OGI is used to 
confirm the repair, keep video footage of the repair confirmation.

[[Page 39355]]

    (E) For each repair delayed beyond 15 calendar days after discovery 
of the leak, record ``Repair delayed'', the reason for the delay, and 
the expected date of successful repair. The owner or operator (or 
designate) whose decision it was that repair could not be carried out 
in the 15-calendar-day timeframe must sign the record.
    (F) For each leak that is not repairable, the maximum instrument 
reading measured by Method 21 of appendix A-7 to this part at the time 
the leak is determined to be not repairable, a video captured by the 
OGI camera showing that emissions are still visible, or a signed record 
that the leak is still detectable via audio/visual/olfactory methods.
    (7) Records of each performance test or performance evaluation 
conducted on the affected facility and each notification and report 
submitted to the Administrator. For each performance test, include an 
indication of whether liquid product loading is assumed to be loaded 
into gasoline cargo tanks or periods when liquid product is loaded but 
no gasoline cargo tanks are being loaded are excluded in the 
determination of the combustion zone temperature operating limit 
according to the provision in Sec.  60.503a(c)(8)(ii).
    (8) Records of all 5-minute time periods during which liquid 
product is loaded into gasoline cargo tanks or assumed to be loaded 
into gasoline cargo tanks and records of all 5-minute time periods when 
there was no liquid product loaded into gasoline cargo tanks.
    (9) Any records required to be maintained by this subpart that are 
submitted electronically via the EPA's Compliance and Emissions 
Reporting Interface (CEDRI) may be maintained in electronic format. 
This ability to maintain electronic copies does not affect the 
requirement for facilities to make records, data, and reports available 
upon request to a delegated authority or the EPA as part of an on-site 
compliance evaluation.
    (b) Reporting requirements for performance tests and evaluations. 
Within 60 days after the date of completing each performance test and 
each CEMS performance evaluation required by this subpart, you must 
submit the results following the procedures specified in paragraph (e) 
of this section. As required by Sec.  60.8(f)(2)(iv), you must include 
the value for the combustion zone temperature operating parameter limit 
set based on your performance test in the performance test report. Data 
collected using test methods supported by the EPA's Electronic 
Reporting Tool (ERT) and performance evaluations of CEMS measuring RATA 
pollutants that are supported by the EPA's ERT as listed on the EPA's 
ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of the test or performance 
evaluation must be submitted in a file format generated using the EPA's 
ERT. Alternatively, you may submit an electronic file consistent with 
the extensible markup language (XML) schema listed on the EPA's ERT 
website. Data collected using test methods that are not supported by 
the EPA's ERT and performance evaluations of CEMS measuring RATA 
pollutants that are not supported by the EPA's ERT as listed on the 
EPA's ERT website at the time of the test or performance evaluation 
must be included as an attachment in the ERT or an alternate electronic 
file.
    (c) Reporting requirements for semiannual report. You must submit 
to the Administrator semiannual reports with the applicable information 
in paragraphs (c)(1) through (7) of this section by the dates specified 
in paragraph (d) of this section following the procedure specified in 
paragraph (e) of this section. For this subpart, the semiannual reports 
supersede the excess emissions and monitoring systems performance 
report and/or summary report form required under Sec.  60.7. Beginning 
on July 8, 2024, or once the report template for this subpart has been 
available on the CEDRI website (https://www.epa.gov/electronic-reporting-air-emissions/cedri) for one year, whichever date is later, 
submit all subsequent reports using the appropriate electronic report 
template on the CEDRI website for this subpart and following the 
procedure specified in paragraph (e). The date report templates become 
available will be listed on the CEDRI website. Unless the Administrator 
or delegated State agency or other authority has approved a different 
schedule for submission of reports, the report must be submitted by the 
deadline specified in this subpart, regardless of the method in which 
the report is submitted.
    (1) Report the following general facility information:
    (i) Facility name.
    (ii) Facility physical address, including city, county, and State.
    (iii) Latitude and longitude of facility's physical location. 
Coordinates must be in decimal degrees with at least five decimal 
places.
    (iv) The following information for the contact person:
    (A) Name.
    (B) Mailing address.
    (C) Telephone number.
    (D) Email address.
    (v) Date of report and beginning and ending dates of the reporting 
period. You are no longer required to provide the date of report when 
the report is submitted via CEDRI.
    (vi) Statement by a responsible official, with that official's 
name, title, and signature, certifying the truth, accuracy, and 
completeness of the content of the report. If your report is submitted 
via CEDRI, the certifier's electronic signature during the submission 
process replaces the requirement in this paragraph (c)(1)(vi).
    (2) For each thermal oxidation system used to comply with the 
emission limitations in Sec.  60.502a(b)(1) or (c)(1) by monitoring the 
combustion zone temperature as specified in Sec.  60.502a(b)(1)(ii) or 
(c)(1)(ii), for each pressure CPMS used to comply with the requirements 
in Sec.  60.502a(h), and for each vapor recovery system used to comply 
with the emission limitations in Sec.  60.502a(b)(2) or (c)(2) report 
the following information for the CMS:
    (i) For all instances when the temperature CPMS measured 3-hour 
rolling averages below the established operating limit or when the 
vapor collection system pressure exceeded the maximum loading pressure 
specified in Sec.  60.502a(h) when liquid product was being loaded into 
gasoline cargo tanks or when the TOC CEMS measured 3-hour rolling 
average concentrations higher than the applicable emission limitation 
when the vapor recovery system was operating:
    (A) The date and start time of the deviation.
    (B) The duration of the deviation in hours.
    (C) Each 3-hour rolling average combustion zone temperature, 
average pressure, or 3-hour rolling average TOC concentration during 
the deviation. For TOC concentration, indicate whether methane is 
excluded from the TOC concentration.
    (D) A unique identifier for the CMS.
    (E) The make, model number, and date of last calibration check of 
the CMS.
    (F) The cause of the deviation and the corrective action taken.
    (ii) For all instances that the temperature CPMS for measuring the 
combustion zone temperature or pressure CPMS was not operating or was 
out of control when liquid product was loaded into gasoline cargo 
tanks, or the TOC CEMS was not operating or was out of control when the 
vapor recovery system was operating:
    (A) The date and start time of the deviation.

[[Page 39356]]

    (B) The duration of the deviation in hours.
    (C) A unique identifier for the CMS.
    (D) The make, model number, and date of last calibration check of 
the CMS.
    (E) The cause of the deviation and the corrective action taken. For 
TOC CEMS outages where the limited alternative for vapor recovery 
systems in Sec.  60.504a(e) is used, the corrective action taken shall 
include an indication of the use of the limited alternative for vapor 
recovery systems in Sec.  60.504a(e).
    (F) For TOC CEMS outages where the limited alternative for vapor 
recovery systems in Sec.  60.504a(e) is used, report either an 
indication that there were no deviations from the operating limits when 
using the limited alternative or report the number of each of the 
following types of deviations that occurred during the use of the 
limited alternative for vapor recovery systems in Sec.  60.504a(e).
    (1) The number of adsorption cycles when the quantity of liquid 
product loaded in gasoline cargo tanks exceeded the operating limit 
established in Sec.  60.504a(e)(1). Enter 0 if no deviations of this 
type.
    (2) The number of desorption cycles when the vacuum pressure was 
below the average vacuum pressure as specified in Sec.  
60.504a(e)(2)(i). Enter 0 if no deviations of this type.
    (3) The number of desorption cycles when the quantity of purge gas 
used was below the average quantity of purge gas as specified in Sec.  
60.504a(e)(2)(ii). Enter 0 if no deviations of this type.
    (4) The number of desorption cycles when the duration of the 
vacuum/purge cycle was less than the average duration as specified in 
Sec.  60.504a(e)(2)(iii). Enter 0 if no deviations of this type.
    (3) For each flare used to comply with the emission limitations in 
Sec.  60.502a(c)(3) and for each thermal oxidation system using the 
flare monitoring alternative as provided in Sec.  60.502a(c)(1)(iii), 
report:
    (i) The date and start and end times for each of the following 
instances:
    (A) Each 15-minute block during which there was at least one minute 
when gasoline vapors were routed to the flare and no pilot flame was 
present.
    (B) Each period of 2 consecutive hours during which visible 
emissions exceeded a total of 5 minutes. Additionally, report the 
number of minutes for which visible emissions were observed during the 
observation or an estimate of the cumulative number of minutes in the 
2-hour period for which emissions were visible based on best 
information available to the owner or operator.
    (C) Each 15-minute period for which the applicable operating limits 
specified in Sec.  63.670(d) through (f) of this chapter were not met. 
You must identify the specific operating limit that was not met. 
Additionally, report the information in paragraphs (c)(3)(i)(C)(1) 
through (3) of this section, as applicable.
    (1) If you use the loading rate operating limits as determined in 
Sec.  60.502a(c)(3)(vii) alone or in combination with the supplemental 
gas flow rate monitoring alternative in Sec.  60.502a(c)(3)(viii), the 
required minimum ratio and the actual ratio of gasoline loaded to total 
product loaded for the rolling 15-minute period and, if applicable, the 
required minimum quantity and the actual quantity of gasoline loaded, 
in gallons, for the rolling 15-minute period.
    (2) If you use the supplemental gas flow rate monitoring 
alternative in Sec.  60.502a(c)(3)(viii), the required minimum 
supplemental gas flow rate and the actual supplemental gas flow rate 
including units of flow rates for the 15-minute block.
    (3) If you use parameter monitoring systems other than those 
specified in paragraphs (c)(3)(i)(C)(1) and (2) of this section, the 
value of the net heating value operating parameter(s) during the 
deviation determined following the methods in Sec.  63.670(k) through 
(n) of this chapter as applicable.
    (ii) The start date, start time, and duration in minutes for each 
period when ``vapors displaced from gasoline cargo tanks during product 
loading'' were routed to the flare or thermal oxidation system and the 
applicable monitoring was not performed.
    (iii) For each instance reported under paragraphs (c)(3)(i) and 
(ii) of this section that involves CMS, report the following 
information:
    (A) A unique identifier for the CMS.
    (B) The make, model number, and date of last calibration check of 
the CMS.
    (C) The cause of the deviation or downtime and the corrective 
action taken.
    (4) For any instance in which liquid product was loaded into a 
gasoline cargo tank for which vapor tightness documentation required 
under Sec.  60.502a(e)(1) was not provided or available in the 
terminal's records, report:
    (i) Cargo tank owner and address.
    (ii) Cargo tank identification number.
    (iii) Date and time liquid product was loaded into a gasoline cargo 
tank without proper documentation.
    (iv) Date proper documentation was received or statement that 
proper documentation was never received.
    (5) For each instance when liquid product was loaded into gasoline 
cargo tanks not using submerged filling, as defined in Sec.  60.501a, 
not equipped with vapor collection equipment that is compatible with 
the terminal's vapor collection system, or not properly connected to 
the terminal's vapor collection system, report:
    (i) Date and time of liquid product loading into gasoline cargo 
tank not using submerged filling, improperly equipped, or improperly 
connected.
    (ii) Type of deviation (e.g., not submerged filling, incompatible 
equipment, or not properly connected).
    (iii) Cargo tank identification number.
    (6) Report the following information for each leak inspection 
required under Sec. Sec.  60.502a(j)(1) and 60.503a(a)(2) and each leak 
identified under Sec.  60.502a(j)(2).
    (i) For each leak detected during a leak inspection required under 
Sec. Sec.  60.502a(j)(1) and 60.503a(a)(2), report:
    (A) The date of inspection.
    (B) The leak determination method (OGI or Method 21 of appendix A-7 
to this part).
    (C) The total number and type of equipment for which leaks were 
detected.
    (D) The total number and type of equipment for which leaks were 
repaired within 15 calendar days.
    (E) The total number and type of equipment for which no repair 
attempt was made within 5 calendar days of the leaks being identified.
    (F) The total number and type of equipment placed on the delay of 
repair, as specified in Sec.  60.502a(j)(8).
    (ii) For leaks identified under Sec.  60.502a(j)(2), report:
    (A) The total number and type of equipment for which leaks were 
identified.
    (B) The total number and type of equipment for which leaks were 
repaired within 15 calendar days.
    (C) The total number and type of equipment for which no repair 
attempt was made within 5 calendar days of the leaks being identified.
    (D) The total number and type of equipment placed on the delay of 
repair, as specified in Sec.  60.502a(j)(8).
    (iii) The total number of leaks on the delay of repair list at the 
start of the reporting period.
    (iv) The total number of leaks on the delay of repair list at the 
end of the reporting period.
    (v) For each leak that was on the delay of repair list at any time 
during the reporting period, report:
    (A) Unique equipment identification number.

[[Page 39357]]

    (B) Type of equipment.
    (C) Leak determination method (OGI, Method 21 of appendix A-7 to 
this part, or audio, visual, or olfactory).
    (D) The reason(s) why the repair was not feasible within 15 
calendar days.
    (E) If applicable, the date repair was completed.
    (7) If there were no deviations from the emission limitations, 
operating parameters, or work practice standards, then provide a 
statement that there were no deviations from the emission limitations, 
operating limits, or work practice standards during the reporting 
period. If there were no periods during which a CMS (including a CEMS 
or CPMS) was inoperable or out-of-control, then provide a statement 
that there were no periods during which a CMS was inoperable or out-of-
control during the reporting period.
    (d) Timeframe for semiannual report submissions. (1) The first 
semiannual report will cover the date starting with the date the source 
first becomes an affected facility subject to this subpart and ending 
with the last day of the month five months later. For example, if the 
source becomes an affected facility on April 15, the first semiannual 
report would cover the period from April 15 to September 30. The first 
semiannual report must be submitted on or before the last day of the 
month two months after the last date covered by the semiannual report. 
In this example, the first semiannual report would be due November 30.
    (2) Subsequent semiannual reports will cover subsequent 6 calendar 
month periods with each report due on or before the last day of the 
month two months after the last date covered by the semiannual report.
    (e) Requirements for electronically submitting reports. For reports 
required to be submitted following the procedures specified in this 
paragraph (e), you must submit reports to the EPA via CEDRI, which can 
be accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/). The EPA will make all the information submitted through 
CEDRI available to the public without further notice to you. Do not use 
CEDRI to submit information you claim as confidential business 
information (CBI). Although we do not expect persons to assert a claim 
of CBI, if you wish to assert a CBI claim for some of the information 
in the report, you must submit a complete file in the format specified 
in this subpart, including information claimed to be CBI, to the EPA 
following the procedures in paragraphs (e)(1) and (2) of this section. 
Clearly mark the part or all of the information that you claim to be 
CBI. Information not marked as CBI may be authorized for public release 
without prior notice. Information marked as CBI will not be disclosed 
except in accordance with procedures set forth in 40 CFR part 2. All 
CBI claims must be asserted at the time of submission. Anything 
submitted using CEDRI cannot later be claimed CBI. Furthermore, under 
CAA section 114(c), emissions data are not entitled to confidential 
treatment, and the EPA is required to make emissions data available to 
the public. Thus, emissions data will not be protected as CBI and will 
be made publicly available. You must submit the same file submitted to 
the CBI office with the CBI omitted to the EPA via the EPA's CDX as 
described earlier in this paragraph (e).
    (1) The preferred method to receive CBI is for it to be transmitted 
electronically using email attachments, File Transfer Protocol, or 
other online file sharing services. Electronic submissions must be 
transmitted directly to the OAQPS CBI Office at the email address 
[email protected], and as described above, should include clear CBI 
markings. ERT files should be flagged to the attention of the Group 
Leader, Measurement Policy Group; all other files should be flagged to 
the attention of the Gasoline Distribution Sector Lead. If assistance 
is needed with submitting large electronic files that exceed the file 
size limit for email attachments, and if you do not have your own file 
sharing service, please email [email protected] to request a file 
transfer link.
    (2) If you cannot transmit the file electronically, you may send 
CBI information through the postal service to the following address: 
U.S. EPA, Attn: OAQPS Document Control Officer, Mail Drop: C404-02, 109 
T.W. Alexander Drive, P.O. Box 12055, RTP, NC 27711. ERT files should 
be flagged to the attention of the Group Leader, Measurement Policy 
Group, and all other files should also be flagged to the attention of 
the Gasoline Distribution Sector Lead. The mailed CBI material should 
be double wrapped and clearly marked. Any CBI markings should not show 
through the outer envelope.
    (f) Claims of EPA system outage. If you are required to 
electronically submit a report through CEDRI in the EPA's CDX, you may 
assert a claim of EPA system outage for failure to timely comply with 
that reporting requirement. To assert a claim of EPA system outage, you 
must meet the requirements outlined in paragraphs (f)(1) through (7) of 
this section.
    (1) You must have been or will be precluded from accessing CEDRI 
and submitting a required report within the time prescribed due to an 
outage of either the EPA's CEDRI or CDX systems.
    (2) The outage must have occurred within the period of time 
beginning five business days prior to the date that the submission is 
due.
    (3) The outage may be planned or unplanned.
    (4) You must submit notification to the Administrator in writing as 
soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (5) You must provide to the Administrator a written description 
identifying:
    (i) The date(s) and time(s) when CDX or CEDRI was accessed and the 
system was unavailable;
    (ii) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to EPA system outage;
    (iii) A description of measures taken or to be taken to minimize 
the delay in reporting; and
    (iv) The date by which you propose to report, or if you have 
already met the reporting requirement at the time of the notification, 
the date you reported.
    (6) The decision to accept the claim of EPA system outage and allow 
an extension to the reporting deadline is solely within the discretion 
of the Administrator.
    (7) In any circumstance, the report must be submitted 
electronically as soon as possible after the outage is resolved.
    (g) Claims of force majeure. If you are required to electronically 
submit a report through CEDRI in the EPA's CDX, you may assert a claim 
of force majeure for failure to timely comply with that reporting 
requirement. To assert a claim of force majeure, you must meet the 
requirements outlined in paragraphs (g)(1) through (5) of this section.
    (1) You may submit a claim if a force majeure event is about to 
occur, occurs, or has occurred or there are lingering effects from such 
an event within the period of time beginning five business days prior 
to the date the submission is due. For the purposes of this section, a 
force majeure event is defined as an event that will be or has been 
caused by circumstances beyond the control of the affected facility, 
its contractors, or any entity controlled by the affected facility that 
prevents you from complying with the requirement to submit a report 
electronically within the time period prescribed. Examples of such 
events are acts of nature (e.g., hurricanes, earthquakes, or floods), 
acts of war or terrorism, or equipment failure or safety hazard beyond 
the control of the

[[Page 39358]]

affected facility (e.g., large scale power outage).
    (2) You must submit notification to the Administrator in writing as 
soon as possible following the date you first knew, or through due 
diligence should have known, that the event may cause or has caused a 
delay in reporting.
    (3) You must provide to the Administrator:
    (i) A written description of the force majeure event;
    (ii) A rationale for attributing the delay in reporting beyond the 
regulatory deadline to the force majeure event;
    (iii) A description of measures taken or to be taken to minimize 
the delay in reporting; and
    (iv) The date by which you propose to report, or if you have 
already met the reporting requirement at the time of the notification, 
the date you reported.
    (4) The decision to accept the claim of force majeure and allow an 
extension to the reporting deadline is solely within the discretion of 
the Administrator.
    (5) In any circumstance, the reporting must occur as soon as 
possible after the force majeure event occurs.

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

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

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

Subpart R--National Emission Standards for Gasoline Distribution 
Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations)

0
6. Section 63.420 is amended by
0
a. Revising paragraphs (a) introductory text, (a)(1) introductory text, 
(a)(2), (b) introductory text, (b)(1) introductory text, (b)(2), (c) 
introductory text, (c)(2), (d) introductory text, (d)(2), (g), (i), and 
(j); and
0
b. Adding paragraph (k).
    The revisions and addition read as follows:


Sec.  63.420  Applicability.

    (a) Prior to May 8, 2027, the affected source to which the 
provisions of this subpart apply is each bulk gasoline terminal, except 
those bulk gasoline terminals meeting either of the criteria listed in 
paragraph (a)(1) or (2) of this section. No later than May 8, 2027, the 
affected source to which the provisions of this subpart apply is each 
bulk gasoline terminal located at a major source as defined in Sec.  
63.2.
    (1) Bulk gasoline terminals for which the owner or operator has 
documented and recorded to the Administrator's satisfaction that the 
result, ET, of the following equation is less than 1, and 
complies with requirements in paragraphs (c), (d), (e), and (f) of this 
section:
* * * * *
    (2) Bulk gasoline terminals for which the owner or operator has 
documented and recorded to the Administrator's satisfaction that the 
facility is not a major source, or is not located within a contiguous 
area and under common control of a facility that is a major source, as 
defined in Sec.  63.2.
    (b) Prior to May 8, 2027, the affected source to which the 
provisions of this subpart apply is each pipeline breakout station, 
except those pipeline breakout stations meeting either of the criteria 
listed in paragraph (b)(1) or (2) of this section. No later than May 8, 
2027, the affected source to which the provisions of this subpart apply 
is each pipeline breakout station located at a major source as defined 
in Sec.  63.2.
    (1) Pipeline breakout stations for which the owner or operator has 
documented and recorded to the Administrator's satisfaction that the 
result, EP, of the following equation is less than 1, and 
complies with requirements in paragraphs (c), (d), (e), and (f) of this 
section:
* * * * *
    (2) Pipeline breakout stations for which the owner or operator has 
documented and recorded to the Administrator's satisfaction that the 
facility is not a major source, or is not located within a contiguous 
area and under common control of a facility that is a major source, as 
defined in Sec.  63.2.
    (c) Prior to May 8, 2027, a facility for which the results, 
ET or EP, of the calculation in paragraph (a)(1) 
or (b)(1) of this section has been documented and is less than 1.0 but 
greater than or equal to 0.50, is exempt from the requirements of this 
subpart, except that the owner or operator shall:
* * * * *
    (2) Maintain records and provide reports in accordance with the 
provisions of Sec.  63.428(l)(4).
    (d) Prior to May 8, 2027, a facility for which the results, 
ET or EP, of the calculation in paragraph (a)(1) 
or (b)(1) of this section has been documented and is less than 0.50, is 
exempt from the requirements of this subpart, except that the owner or 
operator shall:
* * * * *
    (2) Maintain records and provide reports in accordance with the 
provisions of Sec.  63.428(l)(5).
* * * * *
    (g) Each owner or operator of a bulk gasoline terminal or pipeline 
breakout station subject to the provisions of this subpart that is also 
subject to applicable provisions of part 60, subpart Kb, XX, or XXa, of 
this chapter shall comply only with the provisions in each subpart that 
contain the most stringent control requirements for that facility.
* * * * *
    (i) A bulk gasoline terminal or pipeline breakout station with a 
Standard Industrial Classification code 2911 located within a 
contiguous area and under common control with a refinery complying with 
Sec. Sec.  63.646, 63.648, 63.649, 63.650, and 63.660 is not subject to 
the standards in this subpart, except as specified in Sec.  63.650.
    (j) Notwithstanding any other provision of this subpart, the 
December 14, 1995, compliance date for existing facilities in 
Sec. Sec.  63.424(e) and 63.428(a), (l)(4)(i), and (l)(5)(i) is stayed 
from December 8, 1995, to March 7, 1996.
    (k) Each owner or operator of an affected source bulk gasoline 
terminal or pipeline breakout station must comply with the standards in 
this part at all times. At all times, the owner or operator must 
operate and maintain any affected source, including associated air 
pollution control equipment and monitoring equipment, in a manner 
consistent with safety and good air pollution control practices for 
minimizing emissions. The general duty to minimize emissions does not 
require the owner or operator to make any further efforts to reduce 
emissions if levels required by the applicable standard have been 
achieved. Determination of whether a source is operating in compliance 
with operation and maintenance requirements will be based on 
information available to the Administrator which may include, but is 
not limited to, monitoring results, review of operation and maintenance 
procedures, review of operation and maintenance records, and inspection 
of the source.

0
7. Section 63.421 is amended by:
0
a. Revising the introductory text and the definitions of ``Bulk 
gasoline terminal'' and ``Flare'';
0
b. Adding in alphabetical order a definition for ``Gasoline'';
0
c. Revising the definition of ``Pipeline breakout station'';
0
d. Adding in alphabetical order a definition for ``Submerged filling''; 
and
0
e. Revising the definition for ``Thermal oxidation system''.
    The revisions and additions read as follows:

[[Page 39359]]

Sec.  63.421  Definitions.

    As used in this subpart, all terms not defined herein shall have 
the meaning given them in the Act; in subparts A, K, Ka, Kb, and Xxa of 
part 60 of this chapter; or in subpart A of this part. All terms 
defined in both subpart A of part 60 of this chapter and subpart A of 
this part shall have the meaning given in subpart A of this part. For 
purposes of this subpart, definitions in this section supersede 
definitions in other parts or subparts.
    Bulk gasoline terminal means:
    (1) Prior to May 8, 2027, any gasoline facility which receives 
gasoline by pipeline, ship or barge, and has a gasoline throughput 
greater than 75,700 liters per day. Gasoline throughput shall be the 
maximum calculated design throughput as may be limited by compliance 
with an enforceable condition under Federal, State, or local law and 
discoverable by the Administrator and any other person.
    (2) On or after May 8, 2027, any gasoline facility which receives 
gasoline by pipeline, ship, barge, or cargo tank and subsequently loads 
all or a portion of the gasoline into gasoline cargo tanks for 
transport to bulk gasoline plants or gasoline dispensing facilities and 
has a gasoline throughput greater than 20,000 gallons per day (75,700 
liters per day). Gasoline throughput shall be the maximum calculated 
design throughput for the facility as may be limited by compliance with 
an enforceable condition under Federal, State, or local law and 
discoverable by the Administrator and any other person.
* * * * *
    Flare means a thermal combustion device using an open or shrouded 
flame (without full enclosure) such that the pollutants are not emitted 
through a conveyance suitable to conduct a performance test.
    Gasoline means any petroleum distillate or petroleum distillate/
alcohol blend having a Reid vapor pressure of 4.0 pounds per square 
inch (27.6 kilopascals) or greater, which is used as a fuel for 
internal combustion engines.
* * * * *
    Pipeline breakout station means:
    (1) Prior to May 8, 2027, a facility along a pipeline containing 
storage vessels used to relieve surges or receive and store gasoline 
from the pipeline for reinjection and continued transportation by 
pipeline or to other facilities.
    (2) On or after May 8, 2027, a facility along a pipeline containing 
storage vessels used to relieve surges or receive and store gasoline 
from the pipeline for reinjection and continued transportation by 
pipeline to other facilities. Pipeline breakout stations do not have 
loading racks where gasoline is loaded into cargo tanks. 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.
* * * * *
    Submerged filling means the filling of a gasoline cargo tank 
through a submerged fill pipe whose discharge is no more than the 6 
inches from the bottom of the tank. Bottom filling of gasoline cargo 
tanks is included in this definition.
    Thermal oxidation system means an enclosed combustion device used 
to mix and ignite fuel, air pollutants, and air to provide a flame to 
heat and oxidize hazardous air pollutants. Auxiliary fuel may be used 
to heat air pollutants to combustion temperatures. Thermal oxidation 
systems emit pollutants through a conveyance suitable to conduct a 
performance test.
* * * * *

0
8. Revise Sec.  63.422 to read as follows:


Sec.  63.422  Standards: Loading racks.

    (a) You must meet either the requirements in paragraph (a)(1) or 
(2) of this section, as applicable in paragraph (d) of this section.
    (1) Each owner or operator of loading racks at a bulk gasoline 
terminal subject to the provisions of this subpart shall comply with 
the requirements in Sec.  60.502 of this chapter except for paragraphs 
(b), (c), and (j) of that section. For purposes of this section, the 
term ``affected facility'' used in Sec.  60.502 means the loading racks 
that load gasoline cargo tanks at the bulk gasoline terminals subject 
to the provisions of this subpart.
    (2) Each owner or operator of loading racks at a bulk gasoline 
terminal subject to the provisions of this subpart shall comply with 
the requirements in Sec.  60.502a of this chapter except for paragraphs 
(b) and (j) of that section and shall comply with the provisions in 
paragraphs (b) through (c) of this section. For purposes of this 
section, the term ``gasoline loading rack affected facility'' used in 
Sec.  60.502a means ``the loading racks that load gasoline cargo tanks 
at the bulk gasoline terminals subject to the provisions of this 
subpart.'' For purposes of this subpart, the term ``vapor-tight 
gasoline cargo tanks'' used in Sec.  60.502a(e) of this chapter shall 
have the meaning given in Sec.  63.421. As an alternative to the 
pressure monitoring requirements in Sec.  60.504a(d) of this chapter, 
you may comply with the requirements specified in Sec.  63.427(f).
    (b) You must meet either the emission limits in paragraph (b)(1) or 
(2) of this section, as applicable in paragraph (d) of this section.
    (1) Emissions to the atmosphere from the vapor collection and 
processing systems due to the loading of gasoline cargo tanks shall not 
exceed 10 milligrams of total organic compounds per liter of gasoline 
loaded.
    (2) You must comply with the provisions in Sec.  60.502a(c) of this 
chapter for all loading racks that load gasoline cargo tanks at the 
bulk gasoline terminals subject to the provisions of this subpart, not 
just those that are modified or reconstructed.
    (c) Each owner or operator of a bulk gasoline terminal subject to 
the provisions of this subpart shall discontinue loading any cargo tank 
that fails vapor tightness according to the test requirements in Sec.  
63.425(f), (g), and (h) until vapor tightness documentation for that 
gasoline cargo tank is obtained which documents that:
    (1) The tank truck or railcar gasoline cargo tank has been 
repaired, retested, and subsequently passed either the annual 
certification test described in Sec.  63.425(e) or the railcar bubble 
test described in Sec.  63.425(i); or
    (2) For each gasoline cargo tank failing the test in Sec.  
63.425(f) at the facility, the cargo tank meets the test requirements 
in either Sec.  63.425(g) or (h); or
    (3) For each gasoline cargo tank failing the test in Sec.  
63.425(g) at the facility, the cargo tank meets the test requirements 
in Sec.  63.425(h).
    (d) Each owner or operator shall meet the requirements in this 
section as expeditiously as practicable, but no later than the dates 
provided in paragraphs (d)(1) through (3) of this section.
    (1) For facilities that commenced construction on or before 
February 8, 1994, each owner or operator shall meet the requirements in 
paragraphs (a)(1), (b)(1), and (c) of this section no later than 
December 15, 1997. Beginning no later than May 8, 2027, paragraphs 
(a)(1) and (b)(1) of this section no longer apply and each owner or 
operator shall meet the requirements in paragraphs (a)(2), (b)(2), and 
(c) of this section.
    (2) For facilities that commenced construction after February 8, 
1994, and on or before June 10, 2022, each owner or operator shall meet 
the requirements in paragraphs (a)(1), (b)(1), and (c) of this section 
upon startup. Beginning no later than May 8, 2027, paragraphs (a)(1) 
and (b)(1) of this section no longer apply and each owner or operator 
shall meet

[[Page 39360]]

the requirements in paragraphs (a)(2), (b)(2), and (c) of this section.
    (3) For facilities that commenced construction after June 10, 2022, 
each owner or operator shall meet the requirements in paragraphs 
(a)(2), (b)(2), and (c) of this section upon startup or July 8, 2024, 
whichever is later.
    (e) As an alternative to Sec.  60.502(h) and (i) or Sec.  
60.502a(h) and (i) of this chapter as specified in paragraph (a) of 
this section, the owner or operator may comply with paragraphs (e)(1) 
and (2) of this section.
    (1) The owner or operator shall design and operate the vapor 
processing system, vapor collection system, and liquid loading 
equipment to prevent gauge pressure in the railcar gasoline cargo tank 
from exceeding the applicable test limits in Sec.  63.425(e) and (i) 
during product loading. This level is not to be exceeded when measured 
by the procedures specified in Sec.  60.503(d) of this chapter during 
any performance test or performance evaluation conducted under Sec.  
63.425(b) or (c).
    (2) No pressure-vacuum vent in the bulk' gasoline terminal's vapor 
processing system or vapor collection system may begin to open at a 
system pressure less than the applicable test limits in Sec.  63.425(e) 
or (i).

0
9. Revise Sec.  63.423 to read as follows:


Sec.  63.423  Standards: Storage vessels.

    (a) Each owner or operator of a bulk gasoline terminal or pipeline 
breakout station subject to the provisions of this subpart shall equip 
each gasoline storage vessel according to the requirements in paragraph 
(a)(1) or (2) of this section, as applicable in paragraph (c) of this 
section.
    (1) Equip each gasoline storage vessel with a design capacity 
greater than or equal to 75 m\3\ according to the requirements in Sec.  
60.112b(a)(1) through (4) of this chapter, except for the requirements 
in Sec.  60.112b(a)(1)(iv) through (ix) and (a)(2)(ii) of this chapter.
    (2) Equip each gasoline external floating roof storage vessel with 
a design capacity greater than or equal to 75 m\3\ according to the 
requirements in Sec.  60.112b(a)(2)(ii) of this chapter if such storage 
vessel does not currently meet the requirements in paragraph (a)(1) of 
this section.
    (b) Each owner or operator of a bulk gasoline terminal or pipeline 
breakout station subject to the provisions of this subpart shall equip 
each gasoline storage vessel according to the requirements in 
paragraphs (b)(1) of this section and, if a floating roof is used, 
either paragraph (b)(2) or (3) of this section, as applicable in 
paragraph (c) of this section.
    (1) Equip, maintain, and operate each gasoline storage vessel with 
a design capacity greater than or equal to 75 m\3\ according to the 
requirements in Sec.  60.112b(a)(1) through (4) of this chapter, except 
for the requirements in Sec.  60.112b(a)(1)(iv) through (ix) of this 
chapter. Alternatively, you may elect to equip, maintain, and operate 
each affected gasoline storage vessel with a design capacity greater 
than or equal to 75 m\3\ according to the requirements in subpart WW of 
this part as specified in Sec.  60.110b(e)(5) of this chapter.
    (2) Equip, maintain, and operate each internal floating control 
system to maintain the vapor concentration within the storage vessel 
above the floating roof at or below 25 percent of the lower explosive 
limit (LEL) on a 5-minute rolling average basis without the use of 
purge gas. This standard may require additional controls beyond those 
specified in paragraph (b)(1) of this section. Compliance with this 
paragraph (b)(2) shall be determined using the methods in Sec.  
63.425(j). 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. 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.
    (3) Equip, maintain, and operate each gasoline external floating 
roof storage vessel with a design capacity greater than or equal to 75 
m\3\ with fitting controls as specified in Sec.  60.112b(a)(2)(ii) of 
this chapter.
    (c) Each gasoline storage vessel at bulk gasoline terminals and 
pipeline breakout stations shall be in compliance with the requirements 
of this section as expeditiously as practicable, but no later than the 
dates provided in paragraphs (c)(1) through (3) of this section.
    (1) For facilities that commenced construction on or before 
February 8, 1994, each gasoline storage vessel shall meet the 
requirements in paragraph (a) of this section no later than December 
15, 1997. Beginning no later than May 8, 2027, paragraph (a) of this 
section no longer applies and each gasoline storage vessel shall meet 
the requirements in paragraphs (b)(1) and (2) of this section no later 
than May 8, 2027. If applicable, the fitting controls required in 
paragraph (b)(3) of this section must be installed the next time the 
storage vessel is completely emptied and degassed, or by May 8, 2034, 
whichever occurs first.
    (2) For facilities that commenced construction after February 8, 
1994, and on or before June 10, 2022, each gasoline storage vessel 
shall meet the requirements in paragraph (a) of this section upon 
startup. Beginning no later than May 8, 2027, paragraph (a) of this 
section no longer applies and each gasoline storage vessel shall meet 
the requirements in paragraphs (b)(1) and (2) of this section no later 
than May 8, 2027. If applicable, the fitting controls required in 
paragraph (b)(3) of this section must be installed the next time the 
storage vessel is completely emptied and degassed, or by May 8, 2034, 
whichever occurs first.
    (3) For facilities that commenced construction after June 10, 2022, 
each owner or operator shall meet the requirements in paragraph (b) of 
this section upon startup or July 8, 2024, whichever is later.

0
10. Revise Sec.  63.424 to read as follows:


Sec.  63.424  Standards: Equipment leaks.

    (a) Each owner or operator of a bulk gasoline terminal or pipeline 
breakout station subject to the provisions of this subpart shall 
implement a leak detection and repair program for all equipment in 
gasoline service according to the requirements in paragraph (b) or (c) 
of this section, as applicable in paragraph (e) of this section and 
minimize gasoline vapor losses according to paragraph (d) of this 
section.
    (b) Each owner or operator of a bulk gasoline terminal or pipeline 
breakout station subject to the provisions of this subpart shall 
perform a monthly leak inspection of all equipment in gasoline service. 
For this inspection, detection methods incorporating sight, sound, and 
smell are acceptable. Each piece of equipment shall be inspected during 
the loading of a gasoline cargo tank.
    (1) A logbook shall be used and shall be signed by the owner or 
operator at the completion of each inspection. A section of the log 
shall contain a list, summary description, or diagram(s) showing the 
location of all equipment in gasoline service at the facility.
    (2) Each detection of a liquid or vapor leak shall be recorded in 
the logbook. When a leak is detected, an initial attempt at repair 
shall be made as soon as practicable, but no later than 5 calendar days 
after the leak is detected. Repair or replacement of leaking equipment 
shall be completed within 15 calendar days after detection of each 
leak, except as provided in paragraph (b)(3) of this section.
    (3) Delay of repair of leaking equipment will be allowed upon a 
demonstration to the Administrator that repair within 15 days is not 
feasible. The owner or operator shall provide the reason(s) a delay is 
needed and the date

[[Page 39361]]

by which each repair is expected to be completed.
    (4) As an alternative to compliance with the provisions in 
paragraphs (b)(1) through (3) of this section, owners or operators may 
implement an instrument leak monitoring program that has been 
demonstrated to the Administrator as at least equivalent.
    (c) Comply with the requirements in Sec.  60.502a(j) of this 
chapter except as provided in paragraphs (c)(1) through (3) of this 
section.
    (1) The frequency for optical gas imaging (OGI) monitoring shall be 
semiannually rather than quarterly as specified in Sec.  
60.502a(j)(1)(i).
    (2) The frequency for Method 21 monitoring of pumps and valves 
shall be semiannually rather than quarterly as specified in Sec.  
60.502a(j)(1)(ii)(A) and (B).
    (3) The frequency of monitoring of pressure relief devices shall be 
semiannually and within 5 calendar days after each pressure release 
rather than quarterly and within 5 calendar days after each pressure 
release as specified in Sec.  60.502a(j)(4)(i).
    (d) Owners and operators shall not allow gasoline to be handled in 
a manner that would result in vapor releases to the atmosphere for 
extended periods of time. Measures to be taken include, but are not 
limited to, the following:
    (1) Minimize gasoline spills;
    (2) Clean up spills as expeditiously as practicable;
    (3) Cover all open gasoline containers with a gasketed seal when 
not in use; and
    (4) Minimize gasoline sent to open waste collection systems that 
collect and transport gasoline to reclamation and recycling devices, 
such as oil/water separators.
    (e) Compliance with the provisions of this section shall be 
achieved as expeditiously as practicable, but no later than the dates 
provided in paragraphs (e)(1) through (3) of this section.
    (1) For facilities that commenced construction on or before 
February 8, 1994, meet the requirements in paragraphs (b) and (d) of 
this section no later than December 15, 1997. Beginning no later than 
May 8, 2027, paragraph (b) of this section no longer applies and 
facilities shall meet the requirements in paragraphs (c) and (d) of 
this section no later than May 8, 2027.
    (2) For facilities that commenced construction after February 8, 
1994, and on or before June 10, 2022, meet the requirements in 
paragraphs (b) and (d) of this section upon startup. Beginning no later 
than May 8, 2027, paragraph (b) of this section no longer applies and 
facilities shall meet the requirements in paragraphs (c) and (d) of 
this section no later than May 8, 2027.
    (3) For facilities that commenced construction after June 10, 2022, 
meet the requirements in paragraph (c) and (d) of this section upon 
startup or July 8, 2024, whichever is later.

0
11. Section 63.425 is amended by:
0
a. Revising paragraphs (a) through (d), (e)(1), (f) introductory text, 
and (f)(1);
0
b. Revising equation term ``N'' in the equation in paragraph (g)(3);
0
c. Revising paragraph (h); and
0
d. Adding paragraph (j).
    The revisions and addition read as follows:


Sec.  63.425  Test methods and procedures.

    (a) Performance test and evaluation requirements. Each owner or 
operator subject to the emission standard in Sec.  63.422(b)(1) or 
Sec.  60.112b(a)(3)(ii) of this chapter shall comply with the 
requirements in paragraph (b) of this section. Each owner or operator 
subject to the emission standard in Sec.  63.422(b)(2) shall comply 
with the requirements in paragraph (c) of this section. Performance 
tests shall be conducted under representative conditions when liquid 
product is being loaded into gasoline cargo tanks and shall include 
periods between gasoline cargo tank loading (when one cargo tank is 
disconnected and another cargo tank is moved into position for loading) 
provided that liquid product loading into gasoline cargo tanks is 
conducted for at least a portion of each 5 minute block of the 
performance test. You may not conduct performance tests during periods 
of malfunction. You must record the process information that is 
necessary to document operating conditions during the test and include 
in such record an explanation to support that such conditions represent 
normal operation. Upon request, you shall make available to the 
Administrator such records as may be necessary to determine the 
conditions of performance tests.
    (b) Gasoline loading rack and gasoline storage vessel performance 
test requirements. For gasoline loading racks subject to the 
requirements in Sec.  63.422(b)(1) or gasoline storage vessels subject 
to the requirements in Sec.  60.112b(a)(3)(ii) of this chapter:
    (1) Conduct a performance test on the vapor processing and 
collection systems according to either paragraph (b)(1)(i) or (ii) of 
this section.
    (i) Use the test methods and procedures in Sec.  60.503 of this 
chapter, except a reading of 500 ppm shall be used to determine the 
level of leaks to be repaired under Sec.  60.503(b) of this chapter, or
    (ii) Use alternative test methods and procedures in accordance with 
the alternative test method requirements in Sec.  63.7(f).
    (2) The performance test requirements of Sec.  60.503(c) of this 
chapter do not apply to flares defined in Sec.  63.421 and meeting the 
flare requirements in Sec.  63.11(b). The owner or operator shall 
demonstrate that the flare and associated vapor collection system is in 
compliance with the requirements in Sec.  63.11(b) and Sec.  60.503(a), 
(b), and (d) of this chapter, respectively.
    (3) For each performance test conducted under paragraph (b)(1) of 
this section, the owner or operator shall determine a monitored 
operating parameter value for the vapor processing system using the 
following procedure:
    (i) During the performance test, continuously record the operating 
parameter under Sec.  63.427(a);
    (ii) Determine an operating parameter value based on the parameter 
data monitored during the performance test, supplemented by engineering 
assessments and the manufacturer's recommendations; and
    (iii) Provide for the Administrator's approval the rationale for 
the selected operating parameter value, and monitoring frequency and 
averaging time, including data and calculations used to develop the 
value and a description of why the value, monitoring frequency, and 
averaging time demonstrate continuous compliance with the emission 
standard in Sec.  63.422(b)(1) or Sec.  60.112b(a)(3)(ii) of this 
chapter.
    (4) For performance tests performed after the initial test, the 
owner or operator shall document the reasons for any change in the 
operating parameter value since the previous performance test.
    (c) Gasoline loading rack performance test and evaluation 
requirements. For gasoline loading rack sources subject to the 
requirements in Sec.  63.422(b)(2):
    (1) Conduct performance tests or evaluations on the vapor 
processing and collection systems according to the requirements in 
Sec.  60.503a(a), (c) and (d) of this chapter.
    (2) The first performance test or performance evaluation of the 
continuous emissions monitoring system (CEMS) shall be conducted within 
180 days of the date affected source begins compliance with the 
requirements in Sec.  63.422(b)(2). A previously conducted performance 
test may be used to satisfy this requirement if the conditions in 
paragraphs (c)(2)(i)

[[Page 39362]]

through (v) of this section are met. Prior to conducting this 
performance test or evaluation, you must continue to meet the 
monitoring and operating limits that apply based on the previously 
conducted performance test.
    (i) The performance test was conducted on or after May 8, 2022.
    (ii) No changes have been made to the process or control device 
since the time of the performance test.
    (iii) The operating conditions, test methods, and test requirements 
(e.g., length of test) used for the previous performance test conform 
to the requirements in paragraph (c)(1) of this section.
    (iv) The temperature in the combustion zone was recorded during the 
performance test as specified in Sec.  60.503a(c)(8)(i) of this chapter 
and can be used to establish the operating limit as specified in Sec.  
60.503a(c)(8)(ii) through (iv) of this chapter.
    (v) The performance test demonstrates compliance with the emission 
limit specified in Sec.  63.422(b)(2).
    (3) For loading racks complying with the mass loading emission 
limit in Sec.  60.502a(c)(1) of this chapter, subsequent performance 
tests shall be conducted no later than 60 calendar months after the 
previous performance test.
    (4) For loading racks complying with the concentration emission 
limit in Sec.  60.502a(c)(2) of this chapter, subsequent performance 
evaluations of CEMS for the vapor collection and processing system 
shall be conducted no later than 12 calendar months after the previous 
performance evaluation.
    (d) Gasoline storage vessel requirements. The owner or operator of 
each gasoline storage vessel subject to the provisions of Sec.  63.423 
shall comply with Sec.  60.113b of this chapter and, if applicable, the 
provisions in paragraph (j) of this section. If a closed vent system 
and control device are used, as specified in Sec.  60.112b(a)(3) of 
this chapter, to comply with the requirements in Sec.  63.423, the 
owner or operator shall also comply with the requirements in paragraph 
(d)(1) or (2) of this section, as applicable.
    (1) If the gasoline storage vessel is subject to the provision in 
Sec.  63.423(a) or the provision in Sec.  63.423(b) and a control 
device other than a flare is used for the gasoline storage vessel, the 
owner or operator shall also comply with the requirements in paragraph 
(b) of this section.
    (2) If the gasoline storage vessel is subject to the provision in 
Sec.  63.423(b) and a flare is used as the control device for the 
gasoline storage vessel, you must comply with the requirements in Sec.  
60.502a(c)(3) of this chapter as indicated in paragraphs (d)(2)(i) and 
(ii) of this section rather than the requirements in Sec.  60.18(e) and 
(f) of this chapter as specified in Sec.  60.113b(d) of this chapter.
    (i) At Sec.  60.502a(c)(3)(i) of this chapter, replace ``vapors 
displaced from gasoline cargo tanks during product loading'' with 
``vapors from the gasoline storage vessel.''
    (ii) Section 60.502a(c)(3)(vi) through (ix) of this chapter does 
not apply.
    (e) * * *
    (1) Method 27 of appendix A-8 to part 60 of this chapter. Conduct 
the test using a time period (t) for the pressure and vacuum tests of 5 
minutes. The initial pressure (Pi) for the pressure test 
shall be 460 millimeters (mm) of water (H2O) (18 inches 
(in.) H2O), gauge. The initial vacuum (Vi) for 
the vacuum test shall be 150 mm H2O (6 in. H2O), 
gauge. Each owner or operator shall implement the requirements in 
paragraph (e)(1)(i) or (ii) of this section, as applicable in paragraph 
(e)(1)(iii) of this section.
    (i) The maximum allowable pressure and vacuum changes ([Delta] p, 
[Delta] v) are as shown in the second column of table 1 to this 
paragraph (e)(1).
    (ii) The maximum allowable pressure and vacuum changes ([Delta] p, 
[Delta] v) are as shown in the third column of table 1 to this 
paragraph (e)(1).
    (iii) Compliance with the provisions of this section shall be 
achieved as expeditiously as practicable, but no later than the dates 
provided in paragraphs (e)(1)(iii)(A) and (B) of this section.
    (A) For facilities that commenced construction on or before June 
10, 2022, meet the requirements in paragraph (e)(1)(i) of this section 
prior to May 8, 2027, and meet the requirements in paragraph (e)(1)(ii) 
of this section no later than May 8, 2027.
    (B) For facilities that commenced construction after June 10, 2022, 
meet the requirements in paragraph (e)(1)(ii) of this section upon 
startup or July 8, 2024, whichever is later.

                Table 1 to Paragraph (e)(1)--Allowable Cargo Tank Test Pressure or Vacuum Change
----------------------------------------------------------------------------------------------------------------
                                        Annual certification-    Annual certification-
                                        allowable pressure or    allowable pressure or      Allowable pressure
 Cargo tank or compartment capacity,    vacuum change ([Delta]   vacuum change ([Delta]  change ([Delta] p) in 5
             liters (gal)                 p, [Delta] v) in 5       p, [Delta] v) in 5    minutes at any time, mm
                                         minutes, mm H2O (in.     minutes, mm H2O (in.        H2O (in. H2O)
                                                 H2O)                    H2O)]
----------------------------------------------------------------------------------------------------------------
9,464 or more (2,500 or more)........                 25 (1.0)              12.7 (0.50)                 64 (2.5)
9,463 to 5,678 (2,499 to 1,500)......                 38 (1.5)              19.1 (0.75)                 76 (3.0)
5,677 to 3,785 (1,499 to 1,000)......                 51 (2.0)              25.4 (1.00)                 89 (3.5)
3,784 or less (999 or less)..........                 64 (2.5)              31.8 (1.25)                102 (4.0)
----------------------------------------------------------------------------------------------------------------

* * * * *
    (f) Leak detection test. The leak detection test shall be performed 
using Method 21 of appendix A-7 to part 60 of this chapter. A vapor-
tight gasoline cargo tank shall have no leaks at any time when tested 
according to the procedures in this paragraph (f).
    (1) The instrument reading that defines a leak is 10,000 ppm (as 
propane). Use propane to calibrate the instrument, setting the span at 
the leak definition. The response time to 90 percent of the final 
stable reading shall be less than 8 seconds for the detector with the 
sampling line and probe attached.
* * * * *
    (g) * * *
    (3) * * *
    N = 5-minute continuous performance standard at any time from the 
fourth column of table 1 to paragraph (e)(1) of this section, inches 
H2O.
* * * * *
    (h) Continuous performance pressure decay test. The continuous 
performance pressure decay test shall be performed using Method 27 in 
appendix A to part 60 of this chapter. Conduct only the positive 
pressure test using a time period (t) of 5 minutes. The initial 
pressure (Pi) shall be 460 mm H2O (18 in. 
H2O), gauge. The maximum allowable 5-minute pressure change 
([Delta] p) which shall be met at any time is

[[Page 39363]]

shown in the fourth column of table 1 to paragraph (e)(1) of this 
section.
* * * * *
    (j) LEL monitoring procedures. Compliance with the vapor 
concentration below the LEL level for internal floating roof storage 
vessels at Sec.  63.423(b)(2) shall be determined based on the 
procedures specified in paragraphs (j)(1) through (5) of this section. 
If tubing is necessary to obtain the measurements, the tubing must be 
non-crimping and made of Teflon or other inert material.
    (1) LEL monitoring must be conducted at least once every 12 months 
and at other times upon request by the Administrator. If the 
measurement cannot be performed due to wind speeds exceeding those 
specified in paragraph (j)(3)(iii) of this section, the measurement 
must be performed within 30 days of the previous attempt.
    (2) The calibration of the LEL meter must be checked per 
manufacturer specifications immediately before and after the 
measurements as specified in paragraphs (j)(2)(i) and (ii) of this 
section. If tubing will be used for the measurements, the tubing must 
be attached during calibration so that the calibration gas travels 
through the entire measurement system.
    (i) Conduct the span check using a calibration gas recommended by 
the LEL meter manufacturer. The calibration gas must contain a single 
hydrocarbon at a concentration corresponding to 50 percent of the LEL 
(e.g., 2.50 percent by volume when using methane as the calibration 
gas). The vendor must provide a Certificate of Analysis for the gas, 
and the certified concentration must be within 2 percent 
(e.g., 2.45 percent--2.55 percent by volume when using methane as the 
calibration gas). The LEL span response must be between 49 percent and 
51 percent. If the span check prior to the measurements does not meet 
this requirement, the LEL meter must be recalibrated or replaced. If 
the span check after the measurements does not meet this requirement, 
the LEL meter must be recalibrated or replaced, and the measurements 
must be repeated.
    (ii) Check the instrumental offset response using a certified 
compressed gas cylinder of zero air or an ambient environment that is 
free of organic compounds. The pre-measurement instrumental offset 
response must be 0 percent LEL. If the LEL meter does not meet this 
requirement, the LEL meter must be recalibrated or replaced.
    (3) Conduct the measurements as specified in paragraphs (j)(3)(i) 
through (iv) of this section.
    (i) Measurements of the vapors within the internal floating roof 
storage vessel must be collected no more than 3 feet above the internal 
floating roof.
    (ii) Measurements shall be taken for a minimum of 20 minutes, 
logging the measurements at least once every 15 seconds, or until one 
5-minute average as determined according to paragraph (j)(5)(ii) of 
this section exceeds the level specified in Sec.  63.423(b)(2).
    (iii) 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 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.
    (iv) Measurements should be conducted when the internal floating 
roof is floating with limited product movement (limited filling or 
emptying of the tank).
    (4) To determine the actual vapor concentration within the storage 
vessel, the percent of the LEL ``as the calibration gas'' must be 
corrected according to one of the following procedures. Alternatively, 
if the LEL meter used has correction factors that can be selected from 
the meter's program, you may enable this feature to automatically apply 
one of the correction factors specified in paragraphs (j)(4)(i) and 
(ii) of this section.
    (i) Multiply the measurement by the published gasoline vapor 
correction factor for the specific LEL meter and calibration gas used.
    (ii) If there is no published correction factor for gasoline vapors 
for the specific LEL meter used, multiply the measurement by the 
published correction factor for butane as a surrogate for determining 
the LEL of gasoline vapors. The correction factor must correspond to 
the calibration gas used.
    (5) Use the calculation procedures in paragraphs (j)(5)(i) through 
(iii) of this section to determine compliance with the LEL level.
    (i) For each minute while measurements are being taken, determine 
the one-minute average reading as the arithmetic average of the 
corrected individual measurements (taken at least once every 15 
seconds) during the minute.
    (ii) Starting with the end of the fifth minute of data, calculate a 
five-minute rolling average as the arithmetic average of the previous 
five one-minute readings determined under paragraph (j)(5)(i) of this 
section. Determine a new five-minute average reading for every 
subsequent one-minute reading.
    (iii) Each five-minute rolling average must meet the LEL level 
specified in Sec.  63.423(b)(2).

0
12. Section 63.427 is amended by revising paragraphs (a) introductory 
text, (a)(3), (b), and (c) and adding paragraphs (d), (e), and (f) to 
read as follows:


Sec.  63.427  Continuous monitoring.

    (a) Each owner or operator of a bulk gasoline terminal subject to 
the provisions in Sec.  63.422(b)(1) shall install, calibrate, certify, 
operate, and maintain, according to the manufacturer's specifications, 
a continuous monitoring system (CMS) as specified in paragraph (a)(1), 
(2), (3), or (4) of this section, except as allowed in paragraph (a)(5) 
of this section.
* * * * *
    (3) Where a thermal oxidation system is used, a CPMS capable of 
measuring temperature must be installed in the firebox or in the 
ductwork immediately downstream from the firebox in a position before 
any substantial heat exchange occurs.
* * * * *
    (b) Each owner or operator of a bulk gasoline terminal subject to 
the provisions in Sec.  63.422(b)(1) shall operate the vapor processing 
system in a manner not to exceed the operating parameter value for the 
parameter described in paragraphs (a)(1) and (2) of this section, or to 
go below the operating parameter value for the parameter described in 
paragraph (a)(3) of this section, and established using the procedures 
in Sec.  63.425(b). In cases where an alternative parameter pursuant to 
paragraph (a)(5) of this section is approved, each owner or operator 
shall operate the vapor processing system in a manner not to exceed or 
not to go below, as appropriate, the alternative operating parameter 
value. Operation of the vapor processing system in a manner exceeding 
or going below the operating parameter value, as specified above, shall 
constitute a violation of the emission standard in Sec.  63.422(b)(1).
    (c) Except as provided in paragraph (f) of this section, each owner 
or operator of a bulk gasoline terminal subject to the provisions in 
Sec.  63.422(b)(2) shall install, calibrate, certify, operate, and 
maintain a CMS as specified in Sec.  60.504a(a) through (d) of this 
chapter, as applicable. You may use the limited alternative monitoring 
methods as specified in Sec.  60.504a(e) of this chapter, if 
applicable.
    (d) Each owner or operator of a bulk gasoline terminal subject to 
the

[[Page 39364]]

provisions in Sec.  63.422(b)(2) shall operate the vapor processing 
system in a manner consistent with the minimum and/or maximum operating 
parameter value or procedures described in Sec. Sec.  60.502a(a) and 
(c) and 60.504a(a) and (c) of this chapter. Operation of the vapor 
processing system in a manner that constitutes a period of excess 
emissions or failure to perform procedures required shall constitute a 
deviation of the emission standard in Sec.  63.422(b)(2).
    (e) Each owner or operator of gasoline storage vessels subject to 
the provisions of Sec.  63.423 shall comply with the monitoring 
requirements in Sec.  60.116b of this chapter, except records shall be 
kept for at least 5 years. If a closed vent system and control device 
are used, as specified in Sec.  60.112b(a)(3) of this chapter, to 
comply with the requirements in Sec.  63.423, the owner or operator 
shall also comply with the requirements in paragraph (e)(1) or (2) of 
this section, as applicable.
    (1) If the gasoline storage vessel is subject to the provision in 
Sec.  63.423(a) or if the gasoline storage vessel is subject to the 
provision in Sec.  63.423(b) and a control device other than a flare is 
used for the gasoline storage vessel, the owner or operator shall also 
comply with the requirements in paragraph (a) of this section.
    (2) If the gasoline storage vessel is subject to the provision in 
Sec.  63.423(b) and a flare is used as the control device for the 
affected gasoline storage vessel, you must comply with the monitoring 
requirements in Sec.  60.504a(c) of this chapter.
    (f) As an alternative to the pressure monitoring requirements in 
Sec.  60.504a(d) of this chapter, you may comply with the pressure 
monitoring requirements in Sec.  60.503(d) of this chapter during any 
performance test or performance evaluation conducted under Sec.  
63.425(c) to demonstrate compliance with the provisions in Sec.  
60.502a(h) of this chapter.

0
13. Revising Sec.  63.428 to read as follows:


Sec.  63.428  Recordkeeping and reporting.

    (a) The initial notifications required for existing affected 
sources under Sec.  63.9(b)(2) shall be submitted by 1 year after an 
affected source becomes subject to the provisions of this subpart or by 
December 16, 1996, whichever is later. Affected sources that are major 
sources on December 16, 1996, and plan to be area sources by December 
15, 1997, shall include in this notification a brief, non-binding 
description of and schedule for the action(s) that are planned to 
achieve area source status.
    (b) Each owner or operator of a bulk gasoline terminal subject to 
the provisions of this subpart shall keep records in either hardcopy or 
electronic form of the test results for each gasoline cargo tank 
loading at the facility for at least 5 years as specified in paragraphs 
(b)(1) through (3) of this section. Each owner or operator of a bulk 
gasoline terminal subject to the provisions of this subpart shall keep 
records for at least 5 years as specified in paragraphs (b)(4) and (5) 
of this section.
    (1) Annual certification testing performed under Sec.  63.425(e) 
and railcar bubble leak testing performed under Sec.  63.425(i); and
    (2) Continuous performance testing performed at any time at that 
facility under Sec.  63.425(f), (g), and (h).
    (3) The documentation file shall be kept up-to-date for each 
gasoline cargo tank loading at the facility. The documentation for each 
test shall include, as a minimum, the following information:
    (i) Name of test: Annual Certification Test--Method 27 (Sec.  
63.425(e)(1)); Annual Certification Test--Internal Vapor Valve (Sec.  
63.425(e)(2)); Leak Detection Test (Sec.  63.425(f)); Nitrogen Pressure 
Decay Field Test (Sec.  63.425(g)); Continuous Performance Pressure 
Decay Test (Sec.  63.425(h)); or Railcar Bubble Leak Test Procedure 
(Sec.  63.425(i)).
    (ii) Cargo tank owner's name and address.
    (iii) Cargo tank identification number.
    (iv) Test location and date.
    (v) Tester name and signature.
    (vi) Witnessing inspector, if any: Name, signature, and 
affiliation.
    (vii) Vapor tightness repair: Nature of repair work and when 
performed in relation to vapor tightness testing.
    (viii) Test results: tank or compartment capacity; test pressure; 
pressure or vacuum change, mm of water; time period of test; number of 
leaks found with instrument; and leak definition.
    (4) Records of each instance in which liquid product was loaded 
into a gasoline cargo tank for which vapor tightness documentation 
required under Sec.  60.502(e)(1) or Sec.  60.502a(e)(1) of this 
chapter, as applicable, was not provided or available in the terminal's 
records. These records shall include, at a minimum:
    (i) Cargo tank owner and address.
    (ii) Cargo tank identification number.
    (iii) Date and time liquid product was loaded into a gasoline cargo 
tank without proper documentation.
    (iv) Date proper documentation was received or statement that 
proper documentation was never received.
    (5) Records of each instance when liquid product was loaded into 
gasoline cargo tanks not using submerged filling, as defined in Sec.  
63.421, not equipped with vapor collection equipment that is compatible 
with the terminal's vapor collection system, or not properly connected 
to the terminal's vapor collection system. These records shall include, 
at a minimum:
    (i) Date and time of liquid product loading into gasoline cargo 
tank not using submerged filling, improperly equipped or improperly 
connected.
    (ii) Type of deviation (e.g., not submerged filling, incompatible 
equipment, not properly connected).
    (iii) Cargo tank identification number.
    (c) Each owner or operator of a bulk gasoline terminal subject to 
the provisions in Sec.  63.422(b)(1) shall:
    (1) Keep an up-to-date, readily accessible record of the continuous 
monitoring data required under Sec.  63.427(a). This record shall 
indicate the time intervals during which loadings of gasoline cargo 
tanks have occurred or, alternatively, shall record the operating 
parameter data only during such loadings. The date and time of day 
shall also be indicated at reasonable intervals on this record.
    (2) Record and report simultaneously with the notification of 
compliance status required under Sec.  63.9(h):
    (i) All data and calculations, engineering assessments, and 
manufacturer's recommendations used in determining the operating 
parameter value under Sec.  63.425(b); and
    (ii) The following information when using a flare under provisions 
of Sec.  63.11(b) to comply with Sec.  63.422(b):
    (A) Flare design (i.e., steam-assisted, air-assisted, or non-
assisted); and
    (B) All visible emissions readings, heat content determinations, 
flow rate measurements, and exit velocity determinations made during 
the compliance determination required under Sec.  63.425(b).
    (3) If an owner or operator requests approval to use a vapor 
processing system or monitor an operating parameter other than those 
specified in Sec.  63.427(a), the owner or operator shall submit a 
description of planned reporting and recordkeeping procedures. The 
Administrator will specify appropriate reporting and recordkeeping 
requirements as part of the review of the permit application.
    (4) Keep written procedures required under Sec.  63.8(d)(2) on 
record for the life of the affected source or until the affected source 
is no longer subject to the provisions of this part, to be made 
available for inspection, upon request, by the Administrator. If the 
performance evaluation plan is revised, you shall keep previous (i.e., 
superseded) versions

[[Page 39365]]

of the performance evaluation plan on record to be made available for 
inspection, upon request, by the Administrator, for a period of 5 years 
after each revision to the plan. The program of corrective action shall 
be included in the plan as required under Sec.  63.8(d)(2).
    (d) Each owner or operator of a bulk gasoline terminal subject to 
the provisions in Sec.  63.422(b)(2) shall keep records as specified in 
paragraphs (d)(1) through (4) of this section, as applicable, for a 
minimum of five years unless otherwise specified in this section:
    (1) For each thermal oxidation system used to comply with the 
emission limitations in Sec.  63.422(b)(2) by monitoring the combustion 
zone temperature as specified in Sec.  60.502a(c)(1)(ii) of this 
chapter, for each pressure CPMS used to comply with the requirements in 
Sec.  60.502a(h) of this chapter, and for each vapor recovery system 
used to comply with the emission limitations in Sec.  63.422(b)(2), 
maintain records, as applicable, of:
    (i) The applicable operating or emission limit for the CMS. For 
combustion zone temperature operating limits, include the applicable 
date range the limit applies based on when the performance test was 
conducted.
    (ii) Each 3-hour rolling average combustion zone temperature 
measured by the temperature CPMS, each 5-minute average reading from 
the pressure CPMS, and each 3-hour rolling average total organic 
compounds (TOC) concentration (as propane) measured by the TOC CEMS.
    (iii) For each deviation of the 3-hour rolling average combustion 
zone temperature operating limit, maximum loading pressure specified in 
Sec.  60.502a(h) of this chapter, or 3-hour rolling average TOC 
concentration (as propane), the start date and time, duration, cause, 
and the corrective action taken.
    (iv) For each period when there was a CMS outage or the CMS was out 
of control, the start date and time, duration, cause, and the 
corrective action taken. For TOC CEMS outages where the limited 
alternative for vapor recovery systems in Sec.  60.504a(e) of this 
chapter is used, the corrective action taken shall include an 
indication of the use of the limited alternative for vapor recovery 
systems in Sec.  60.504a(e).
    (v) Each inspection or calibration of the CMS including a unique 
identifier, make, and model number of the CMS, and date of calibration 
check. For TOC CEMS, include the type of CEMS used (i.e., flame 
ionization detector, nondispersive infrared analyzer) and an indication 
of whether methane is excluded from the TOC concentration reported in 
paragraph (d)(1)(ii) of this section.
    (vi) TOC CEMS outages where the limited alternative for vapor 
recovery systems in Sec.  60.504a(e) of this chapter is used, also keep 
records of:
    (A) The quantity of liquid product loaded in gasoline cargo tanks 
for the past 10 adsorption cycles prior to the CEMS outage.
    (B) The vacuum pressure, purge gas quantities, and duration of the 
vacuum/purge cycles used for the past 10 desorption cycles prior to the 
CEMS outage.
    (C) The quantity of liquid product loaded in gasoline cargo tanks 
for each adsorption cycle while using the alternative.
    (D) The vacuum pressure, purge gas quantities, and duration of the 
vacuum/purge cycles for each desorption cycle while using the 
alternative.
    (2) For each flare used to comply with the emission limitations in 
Sec.  63.422(b)(2) and for each thermal oxidation system using the 
flare monitoring alternative as provided in Sec.  60.502a(c)(1)(iii) of 
this chapter, maintain records of:
    (i) The output of the monitoring device used to detect the presence 
of a pilot flame as required in Sec.  63.670(b) for a minimum of 2 
years. Retain records of each 15-minute block during which there was at 
least one minute that no pilot flame is present when gasoline vapors 
were routed to the flare for a minimum of 5 years. The record must 
identify the start and end time and date of each 15-minute block.
    (ii) Visible emissions observations as specified in paragraphs 
(d)(2)(ii)(A) and (B) of this section, as applicable, for a minimum of 
3 years.
    (A) If visible emissions observations are performed using Method 22 
of appendix A-7 to part 60 of this chapter, the record must identify 
the date, the start and end time of the visible emissions observation, 
and the number of minutes for which visible emissions were observed 
during the observation. If the owner or operator performs visible 
emissions observations more than one time during a day, include 
separate records for each visible emissions observation performed.
    (B) For each 2-hour period for which visible emissions are observed 
for more than 5 minutes in 2 consecutive hours but visible emissions 
observations according to Method 22 of appendix A-7 to part 60 of this 
chapter were not conducted for the full 2-hour period, the record must 
include the date, the start and end time of the visible emissions 
observation, and an estimate of the cumulative number of minutes in the 
2-hour period for which emissions were visible based on best 
information available to the owner or operator.
    (iii) Each 15-minute block period during which operating values are 
outside of the applicable operating limits specified in Sec.  63.670(d) 
through (f) when liquid product is being loaded into gasoline cargo 
tanks for at least 15-minutes identifying the specific operating limit 
that was not met.
    (iv) The 15-minute block average cumulative flows for the thermal 
oxidation system vent gas or flare vent gas and, if applicable, total 
steam, perimeter assist air, and premix assist air specified to be 
monitored under Sec.  63.670(i), along with the date and start and end 
time for the 15-minute block. If multiple monitoring locations are used 
to determine cumulative vent gas flow, total steam, perimeter assist 
air, and premix assist air, retain records of the 15-minute block 
average flows for each monitoring location for a minimum of 2 years, 
and retain the 15-minute block average cumulative flows that are used 
in subsequent calculations for a minimum of 5 years. If pressure and 
temperature monitoring is used, retain records of the 15-minute block 
average temperature, pressure and molecular weight of the thermal 
oxidation system vent gas, flare vent gas, or assist gas stream for 
each measurement location used to determine the 15-minute block average 
cumulative flows for a minimum of 2 years, and retain the 15-minute 
block average cumulative flows that are used in subsequent calculations 
for a minimum of 5 years. If you use the supplemental gas flow rate 
monitoring alternative in Sec.  60.502a(c)(3)(viii) of this chapter, 
the required supplemental gas flow rate (winter and summer, if 
applicable) and the actual monitored supplemental gas flow rate for the 
15-minute block. Retain the supplemental gas flow rate records for a 
minimum of 5 years.
    (v) The thermal oxidation system vent gas or flare vent gas 
compositions specified to be monitored under Sec.  63.670(j). Retain 
records of individual component concentrations from each compositional 
analyses for a minimum of 2 years. If NHVvg analyzer is 
used, retain records of the 15-minute block average values for a 
minimum of 5 years. If you demonstrate your gas streams have consistent 
composition using the provisions in Sec.  63.670(j)(6) as specified in 
Sec.  60.502a(c)(3)(vii) of this chapter, retain records of the 
required minimum ratio of gasoline loaded to total liquid product 
loaded and the actual ratio on a 15-minute block basis.

[[Page 39366]]

If applicable, you must retain records of the required minimum gasoline 
loading rate as specified in Sec.  60.502a(c)(3)(vii) and the actual 
gasoline loading rate on a 15-minute block basis for a minimum of 5 
years.
    (vi) Each 15-minute block average operating parameter calculated 
following the methods specified in Sec.  63.670(k) through (n), as 
applicable.
    (vii) All periods during which the owner or operator does not 
perform monitoring according to the procedures in Sec.  63.670(g), (i), 
and (j) or in Sec.  60.502a(c)(3)(vii) and (viii) of this chapter as 
applicable. Note the start date, start time, and duration in minutes 
for each period.
    (viii) An indication of whether ``vapors displaced from gasoline 
cargo tanks during product loading'' excludes periods when liquid 
product is loaded but no gasoline cargo tanks are being loaded or if 
liquid product loading is assumed to be loaded into gasoline cargo 
tanks according to the provisions in Sec.  60.502a(c)(3)(i) of this 
chapter, records of all time periods when ``vapors displaced from 
gasoline cargo tanks during product loading'', and records of time 
periods when there were no ``vapors displaced from gasoline cargo tanks 
during product loading''.
    (ix) If you comply with the flare tip velocity operating limit 
using the one-time flare tip velocity operating limit compliance 
assessment as provided in Sec.  60.502a(c)(3)(ix) of this chapter, 
maintain records of the applicable one-time flare tip velocity 
operating limit compliance assessment for as long as you use this 
compliance method.
    (x) For each parameter monitored using a CMS, retain the records 
specified in paragraphs (d)(2)(x)(A) through (C) of this section, as 
applicable:
    (A) For each deviation, record the start date and time, duration, 
cause, and corrective action taken.
    (B) For each period when there is a CMS outage or the CMS is out of 
control, record the start date and time, duration, cause, and 
corrective action taken.
    (C) Each inspection or calibration of the CMS including a unique 
identifier, make, and model number of the CMS, and date of calibration 
check.
    (3) Records of all 5-minute time periods during which liquid 
product is loaded into gasoline cargo tanks or assumed to be loaded 
into gasoline cargo tanks and records of all 5-minute time periods when 
there was no liquid product loaded into gasoline cargo tanks.
    (4) Keep written procedures required under Sec.  63.8(d)(2) on 
record for the life of the affected source or until the affected source 
is no longer subject to the provisions of this part, to be made 
available for inspection, upon request, by the Administrator. If the 
performance evaluation plan is revised, you shall keep previous (i.e., 
superseded) versions of the performance evaluation plan on record to be 
made available for inspection, upon request, by the Administrator, for 
a period of 5 years after each revision to the plan. The program of 
corrective action shall be included in the plan as required under Sec.  
63.8(d)(2).
    (e) Each owner or operator of storage vessels subject to the 
provisions of this subpart shall keep records as specified in Sec.  
60.115b of this chapter, except records shall be kept for at least 5 
years. Additionally, for each storage vessel complying with the 
provisions in Sec.  63.423(b)(2), keep records of each LEL monitoring 
event as specified in paragraphs (e)(1) through (9) of this section.
    (1) Date and time of the LEL monitoring, and the storage vessel 
being monitored.
    (2) A description of the monitoring event (e.g., monitoring 
conducted concurrent with visual inspection required under Sec.  
60.113b(a)(2) of this chapter or Sec.  63.1063(d)(2); monitoring that 
occurred on a date other than the visual inspection required under 
Sec.  60.113b(a)(2) or Sec.  63.1063(d)(2); re-monitoring due to high 
winds; re-monitoring after repair attempt).
    (3) Wind speed at the top of the storage vessel on the date of LEL 
monitoring.
    (4) The LEL meter manufacturer and model number used, as well as an 
indication of whether tubing was used during the LEL monitoring, and if 
so, the type and length of tubing used.
    (5) Calibration checks conducted before and after making the 
measurements, including both the span check and instrumental offset. 
This includes the hydrocarbon used as the calibration gas, the 
Certificate of Analysis for the calibration gas(es), the results of the 
calibration check, and any corrective action for calibration checks 
that do not meet the required response.
    (6) Location of the measurements and the location of the floating 
roof.
    (7) Each measurement (taken at least once every 15 seconds). The 
records should indicate whether the recorded values were automatically 
corrected using the meter's programming. If the values were not 
automatically corrected, record both the raw (as the calibration gas) 
and corrected measurements, as well as the correction factor used.
    (8) Each 5-minute rolling average reading.
    (9) If the vapor concentration of the storage vessel was above 25 
percent of the LEL on a 5-minue rolling average basis, a description of 
whether the floating roof was repaired, replaced, or taken out of 
gasoline service.
    (f) Each owner or operator complying with the provisions of Sec.  
63.424 shall keep records of the information in paragraphs (f)(1) and 
(2) of this section.
    (1) Each owner or operator complying with the provisions of Sec.  
63.424(b) shall record the following information in the logbook for 
each leak that is detected:
    (i) The equipment type and identification number;
    (ii) The nature of the leak (i.e., vapor or liquid) and the method 
of detection (i.e., sight, sound, or smell);
    (iii) The date the leak was detected and the date of each attempt 
to repair the leak;
    (iv) Repair methods applied in each attempt to repair the leak;
    (v) ``Repair delayed'' and the reason for the delay if the leak is 
not repaired within 15 calendar days after discovery of the leak;
    (vi) The expected date of successful repair of the leak if the leak 
is not repaired within 15 days; and
    (vii) The date of successful repair of the leak.
    (2) Each owner or operator complying with the provisions of Sec.  
63.424(c) or Sec.  60.503a(a)(2) of this chapter shall keep records of 
the following information:
    (i) Types, identification numbers, and locations of all equipment 
in gasoline service.
    (ii) For each leak inspection conducted under Sec.  63.424(c) or 
Sec.  60.503a(a)(2) of this chapter, keep the following records:
    (A) An indication if the leak inspection was conducted under Sec.  
63.424(c) or Sec.  60.503a(a)(2) of this chapter.
    (B) Leak determination method used for the leak inspection.
    (iii) For leak inspections conducted with Method 21 of appendix A-7 
to part 60 of this chapter, keep the following additional records:
    (A) Date of inspection.
    (B) Inspector name.
    (C) Monitoring instrument identification.
    (D) Identification of all equipment surveyed and the instrument 
reading for each piece of equipment.
    (E) Date and time of instrument calibration and initials of 
operator performing the calibration.
    (F) Calibration gas cylinder identification, certification date, 
and certified concentration.

[[Page 39367]]

    (G) Instrument scale used.
    (H) Results of the daily calibration drift assessment.
    (iv) For leak inspections conducted with OGI, keep the records 
specified in section 12 of appendix K to part 60 of this chapter.
    (v) For each leak that is detected during a leak inspection or by 
audio/visual/olfactory methods during normal duties, record the 
following information:
    (A) The equipment type and identification number.
    (B) The date the leak was detected, the name of the person who 
found the leak, nature of the leak (i.e., vapor or liquid) and the 
method of detection (i.e., audio/visual/olfactory, Method 21 of 
appendix A-7 to part 60 of this chapter, or OGI).
    (C) The date of each attempt to repair the leak and the repair 
methods applied in each attempt to repair the leak.
    (D) The date of successful repair of the leak, the method of 
monitoring used to confirm the repair, and if Method 21 of appendix A-7 
to part 60 of this chapter is used to confirm the repair, the maximum 
instrument reading measured by Method 21 of appendix A-7 to part 60. If 
OGI is used to confirm the repair, keep video footage of the repair 
confirmation.
    (E) For each repair delayed beyond 15 calendar days after discovery 
of the leak, record ``Repair delayed'', the reason for the delay, and 
the expected date of successful repair. The owner or operator (or 
designate) whose decision it was that repair could not be carried out 
in the 15-calendar day timeframe must sign the record.
    (F) For each leak that is not repairable, the maximum instrument 
reading measured by Method 21 of appendix A-7 to part 60 of this 
chapter at the time the leak is determined to be not repairable, a 
video captured by the OGI camera showing that emissions are still 
visible, or a signed record that the leak is still detectable via 
audio/visual/olfactory methods.
    (g) Each owner or operator of a bulk gasoline terminal or pipeline 
breakout station subject to the provisions of this subpart shall keep 
the following records for each deviation of an emissions limitation 
(including operating limit), work practice standard, or operation and 
maintenance requirement in this subpart.
    (1) Date, start time, and duration of each deviation.
    (2) List of the affected sources or equipment for each deviation, 
an estimate of the quantity of each regulated pollutant emitted over 
any emission limit and a description of the method used to estimate the 
emissions.
    (3) Actions taken to minimize emissions.
    (h) Any records required to be maintained by this subpart that are 
submitted electronically via the U.S. Environmental Protection Agency 
(EPA) Compliance and Emissions Data Reporting Interface (CEDRI) may be 
maintained in electronic format. This ability to maintain electronic 
copies does not affect the requirement for facilities to make records, 
data, and reports available upon request to a delegated authority or 
the EPA as part of an on-site compliance evaluation.
    (i) Records of each performance test or performance evaluation 
conducted and each notification and report submitted to the 
Administrator for at least 5 years. For each performance test, include 
an indication of whether liquid product loading is assumed to be loaded 
into gasoline cargo tanks or periods when liquid product is loaded but 
no gasoline cargo tanks are being loaded are excluded in the 
determination of the combustion zone temperature operating limit 
according to the provision in Sec.  60.503a(c)(8)(ii) of this chapter. 
If complying with the alternative in Sec.  63.427(f), for each 
performance test or performance evaluation conducted, include the 
pressure every 5 minutes while a gasoline cargo tank is being loaded 
and the highest instantaneous pressure that occurs during each loading.
    (j) Prior to November 4, 2024, each owner or operator of an 
affected source under this subpart shall submit performance test 
reports to the Administrator according to the requirements in Sec.  
63.13. Beginning on November 4, 2024, within 60 days after the date of 
completing each performance test and each CEMS performance evaluation 
required by this subpart, you must submit the results of the 
performance test following the procedure specified in Sec.  63.9(k). As 
required by Sec.  63.7(g)(2)(iv), you must include the value for the 
combustion zone temperature operating parameter limit set based on your 
performance test in the performance test report. If the monitoring 
alternative in Sec.  63.427(f) is used, indicate that this monitoring 
alternative is being used, identify each loading rack that loads 
gasoline cargo tanks at the bulk gasoline terminal subject to the 
provisions of this subpart, and report the highest instantaneous 
pressure monitored during the performance test or performance 
evaluation for each identified loading rack. Data collected using test 
methods supported by the EPA's Electronic Reporting Tool (ERT) and 
performance evaluations of CEMS measuring RATA pollutants that are 
supported by the EPA's ERT as listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of the test or performance evaluation must be 
submitted in a file format generated using the EPA's ERT. 
Alternatively, you may submit an electronic file consistent with the 
extensible markup language (XML) schema listed on the EPA's ERT 
website. Data collected using test methods that are not supported by 
the EPA's ERT and performance evaluations of CEMS measuring RATA 
pollutants that are not supported by the EPA's ERT as listed on the 
EPA's ERT website at the time of the test must be included as an 
attachment in the ERT or alternate electronic file.
    (k) The owner or operator must submit all Notification of 
Compliance Status reports in PDF format to the EPA following the 
procedure specified in Sec.  63.9(k), except any medium submitted 
through mail must be sent to the attention of the Gasoline Distribution 
Sector Lead.
    (l) Prior to May 8, 2027, each owner or operator of a source 
subject to the requirements of this subpart shall submit reports as 
specified in paragraphs (l)(1) through (5) of this section, as 
applicable.
    (1) Each owner or operator subject to the provisions of Sec.  
63.424 shall report to the Administrator a description of the types, 
identification numbers, and locations of all equipment in gasoline 
service. For facilities electing to implement an instrument program 
under Sec.  63.424(b)(4), the report shall contain a full description 
of the program.
    (i) In the case of an existing source or a new source that has an 
initial startup date before December 14, 1994, the report shall be 
submitted with the notification of compliance status required under 
Sec.  63.9(h), unless an extension of compliance is granted under Sec.  
63.6(i). If an extension of compliance is granted, the report shall be 
submitted on a date scheduled by the Administrator.
    (ii) In the case of new sources that did not have an initial 
startup date before December 14, 1994, the report shall be submitted 
with the application for approval of construction, as described in 
Sec.  63.5(d).
    (2) Each owner or operator of a bulk gasoline terminal or pipeline 
breakout station subject to the provisions of this subpart shall 
include in a semiannual

[[Page 39368]]

report to the Administrator the following information, as applicable:
    (i) Each loading of a gasoline cargo tank for which vapor tightness 
documentation had not been previously obtained by the facility;
    (ii) Periodic reports as specified in Sec.  60.115b of this 
chapter; and
    (iii) The number of equipment leaks not repaired within 5 days 
after detection.
    (3) Each owner or operator of a bulk gasoline terminal or pipeline 
breakout station subject to the provisions of this subpart shall submit 
an excess emissions report to the Administrator in accordance with 
Sec.  63.10(e)(3), whether or not a CMS is installed at the facility. 
The following occurrences are excess emissions events under this 
subpart, and the following information shall be included in the excess 
emissions report, as applicable:
    (i) Each exceedance or failure to maintain, as appropriate, the 
monitored operating parameter value determined under Sec.  
63.425(b)(3). The report shall include the monitoring data for the days 
on which exceedances or failures to maintain have occurred, and a 
description and timing of the steps taken to repair or perform 
maintenance on the vapor collection and processing systems or the CMS.
    (ii) Each instance of a nonvapor-tight gasoline cargo tank loading 
at the facility in which the owner or operator failed to take steps to 
assure that such cargo tank would not be reloaded at the facility 
before vapor tightness documentation for that cargo tank was obtained.
    (iii) Each reloading of a nonvapor-tight gasoline cargo tank at the 
facility before vapor tightness documentation for that cargo tank is 
obtained by the facility in accordance with Sec.  63.422(c).
    (iv) For each occurrence of an equipment leak for which no repair 
attempt was made within 5 days or for which repair was not completed 
within 15 days after detection:
    (A) The date on which the leak was detected;
    (B) The date of each attempt to repair the leak;
    (C) The reasons for the delay of repair; and
    (D) The date of successful repair.
    (4) Each owner or operator of a facility meeting the criteria in 
Sec.  63.420(c) shall perform the requirements of this paragraph 
(l)(4), all of which will be available for public inspection:
    (i) Document and report to the Administrator not later than 
December 16, 1996, for existing facilities, within 30 days for existing 
facilities subject to Sec.  63.420(c) after December 16, 1996, or at 
startup for new facilities the methods, procedures, and assumptions 
supporting the calculations for determining criteria in Sec.  
63.420(c);
    (ii) Maintain records to document that the facility parameters 
established under Sec.  63.420(c) have not been exceeded; and
    (iii) Report annually to the Administrator that the facility 
parameters established under Sec.  63.420(c) have not been exceeded.
    (iv) At any time following the notification required under 
paragraph (l)(4)(i) of this section and approval by the Administrator 
of the facility parameters, and prior to any of the parameters being 
exceeded, the owner or operator may submit a report to request 
modification of any facility parameter to the Administrator for 
approval. Each such request shall document any expected HAP emission 
change resulting from the change in parameter.
    (5) Each owner or operator of a facility meeting the criteria in 
Sec.  63.420(d) shall perform the requirements of this paragraph 
(l)(5), all of which will be available for public inspection:
    (i) Document and report to the Administrator not later than 
December 16, 1996, for existing facilities, within 30 days for existing 
facilities subject to Sec.  63.420(d) after December 16, 1996, or at 
startup for new facilities the use of the emission screening equations 
in Sec.  63.420(a)(1) or (b)(1) and the calculated value of 
ET or EP;
    (ii) Maintain a record of the calculations in Sec.  63.420 (a)(1) 
or (b)(1), including methods, procedures, and assumptions supporting 
the calculations for determining criteria in Sec.  63.420(d); and
    (iii) At any time following the notification required under 
paragraph (l)(5)(i) of this section, and prior to any of the parameters 
being exceeded, the owner or operator may notify the Administrator of 
modifications to the facility parameters. Each such notification shall 
document any expected HAP emission change resulting from the change in 
parameter.
    (m) On or after May 8, 2027, you must submit to the Administrator 
semiannual reports with the applicable information in paragraphs (m)(1) 
through (8) of this section following the procedure specified in 
paragraph (n) of this section.
    (1) Report the following general facility information:
    (i) Facility name.
    (ii) Facility physical address, including city, county, and State.
    (iii) Latitude and longitude of facility's physical location. 
Coordinates must be in decimal degrees with at least five decimal 
places.
    (iv) The following information for the contact person:
    (A) Name.
    (B) Mailing address.
    (C) Telephone number.
    (D) Email address.
    (v) The type of facility (bulk gasoline terminal or pipeline 
breakout station).
    (vi) Date of report and beginning and ending dates of the reporting 
period. You are no longer required to provide the date of report when 
the report is submitted via CEDRI.
    (vii) Statement by a responsible official, with that official's 
name, title, and signature, certifying the truth, accuracy, and 
completeness of the content of the report. If your report is submitted 
via CEDRI, the certifier's electronic signature during the submission 
process replaces the requirement in this paragraph (m)(1)(vii).
    (2) For each thermal oxidation system used to comply with the 
emission limit in Sec.  60.502a(c)(1) of this chapter by monitoring the 
combustion zone temperature as specified in Sec.  60.502a(c)(1)(ii), 
for each pressure CPMS used to comply with the requirements in Sec.  
60.502a(h), and for each vapor recovery system used to comply with the 
emission limitations in Sec.  60.502a(c)(2), report the following 
information for the CMS:
    (i) For all instances when the temperature CPMS measured 3-hour 
rolling averages below the established operating limit or when the 
vapor collection system pressure exceeded the maximum loading pressure 
specified in Sec.  60.502a(h) of this chapter when liquid product was 
being loaded into gasoline cargo tanks or when the TOC CEMS measured 3-
hour rolling average concentrations higher than the applicable emission 
limitation when the vapor recovery system was operating:
    (A) The date and start time of the deviation.
    (B) The duration of the deviation in hours.
    (C) Each 3-hour rolling average combustion zone temperature, 
average pressure, or 3-hour rolling average TOC concentration during 
the deviation. For TOC concentration, indicate whether methane is 
excluded from the TOC concentration.
    (D) A unique identifier for the CMS.
    (E) The make, model number, and date of last calibration check of 
the CMS.
    (F) The cause of the deviation and the corrective action taken.
    (ii) For all instances that the temperature CPMS for measuring the

[[Page 39369]]

combustion zone temperature or pressure CPMS was not operating or out 
of control when liquid product was loaded into gasoline cargo tanks, or 
the TOC CEMS was not operating or was out of control when the vapor 
recovery system was operating:
    (A) The date and start time of the deviation.
    (B) The duration of the deviation in hours.
    (C) A unique identifier for the CMS.
    (D) The make, model number, and date of last calibration check of 
the CMS.
    (E) The cause of the deviation and the corrective action taken. For 
TOC CEMS outages where the limited alternative for vapor recovery 
systems in Sec.  60.504a(e) of this chapter is used, the corrective 
action taken shall include an indication of the use of the limited 
alternative for vapor recovery systems in Sec.  60.504a(e).
    (F) For TOC CEMS outages where the limited alternative for vapor 
recovery systems in Sec.  60.504a(e) of this chapter is used, report 
either an indication that there were no deviations from the operating 
limits when using the limited alternative or report the number of each 
of the following types of deviations that occurred during the use of 
the limited alternative for vapor recovery systems in Sec.  60.504a(e).
    (1) The number of adsorption cycles when the quantity of liquid 
product loaded in gasoline cargo tanks exceeded the operating limit 
established in Sec.  60.504a(e)(1) of this chapter. Enter 0 if no 
deviations of this type.
    (2) The number of desorption cycles when the vacuum pressure was 
below the average vacuum pressure as specified in Sec.  
60.504a(e)(2)(i) of this chapter. Enter 0 if no deviations of this 
type.
    (3) The number of desorption cycles when the quantity of purge gas 
used was below the average quantity of purge gas as specified in Sec.  
60.504a(e)(2)(ii) of this chapter. Enter 0 if no deviations of this 
type.
    (4) The number of desorption cycles when the duration of the 
vacuum/purge cycle was less than the average duration as specified in 
Sec.  60.504a(e)(2)(iii) of this chapter. Enter 0 if no deviations of 
this type.
    (3) For each flare used to comply with the emission limitations in 
Sec.  60.502a(c)(3) of this chapter and for each thermal oxidation 
system using the flare monitoring alternative as provided in Sec.  
60.502a(c)(1)(iii), report:
    (i) The date and start and end times for each of the following 
instances:
    (A) Each 15-minute block during which there was at least one minute 
when gasoline vapors were routed to the flare and no pilot flame was 
present.
    (B) Each period of 2 consecutive hours during which visible 
emissions exceeded a total of 5 minutes. Additionally, report the 
number of minutes for which visible emissions were observed during the 
observation or an estimate of the cumulative number of minutes in the 
2-hour period for which emissions were visible based on best 
information available to the owner or operator.
    (C) Each 15-minute period for which the applicable operating limits 
specified in Sec.  63.670(d) through (f) were not met. You must 
identify the specific operating limit that was not met. Additionally, 
report the information in paragraphs (m)(3)(i)(C)(1) through (3) of 
this section, as applicable.
    (1) If you use the loading rate operating limits as determined in 
Sec.  60.502a(c)(3)(vii) of this chapter alone or in combination with 
the supplemental gas flow rate monitoring alternative in Sec.  
60.502a(c)(3)(viii) of this chapter, the required minimum ratio and the 
actual ratio of gasoline loaded to total product loaded for the rolling 
15-minute period and, if applicable, the required minimum quantity and 
the actual quantity of gasoline loaded, in gallons, for the rolling 15-
minute period.
    (2) If you use the supplemental gas flow rate monitoring 
alternative in Sec.  60.502a(c)(3)(viii) of this chapter, the required 
minimum supplemental gas flow rate and the actual supplemental gas flow 
rate including units of flow rates for the 15-minute block.
    (3) If you use parameter monitoring systems other than those 
specified in paragraphs (m)(3)(i)(C)(1) and (2) of this section, the 
value of the net heating value operating parameter(s) during the 
deviation determined following the methods in Sec.  63.670(k) through 
(n) as applicable.
    (ii) The start date, start time, and duration in minutes for each 
period when ``vapors displaced from gasoline cargo tanks during product 
loading'' were routed to the flare or thermal oxidation system and the 
applicable monitoring was not performed.
    (iii) For each instance reported under paragraphs (m)(3)(i) and 
(ii) of this section that involves CMS, report the following 
information:
    (A) A unique identifier for the CMS.
    (B) The make, model number, and date of last calibration check of 
the CMS.
    (C) The cause of the deviation or downtime and the corrective 
action taken.
    (4) For any instance in which liquid product was loaded into a 
gasoline cargo tank for which vapor tightness documentation required 
under Sec.  60.502a(e)(1) of this chapter was not provided or available 
in the terminal's records, report:
    (i) Cargo tank owner and address.
    (ii) Cargo tank identification number.
    (iii) Date and time liquid product was loaded into a gasoline cargo 
tank without proper documentation.
    (iv) Date proper documentation was received or statement that 
proper documentation was never received.
    (5) For each instance when liquid product was loaded into gasoline 
cargo tanks not using submerged filling, as defined in Sec.  63.421, 
not equipped with vapor collection equipment that is compatible with 
the terminal's vapor collection system, or not properly connected to 
the terminal's vapor collection system, report:
    (i) Date and time of liquid product loading into gasoline cargo 
tank not using submerged filling, improperly equipped, or improperly 
connected.
    (ii) The type of deviation (e.g., not submerged filling, 
incompatible equipment, not properly connected).
    (iii) Cargo tank identification number.
    (6) Report the following information for each leak inspection 
required and each leak identified under Sec.  63.424(c) and Sec.  
60.503a(a)(2) of this chapter.
    (i) For each leak detected during a leak inspection required under 
Sec.  63.424(c) and Sec.  60.503a(a)(2) of this chapter, report:
    (A) The date of inspection.
    (B) The leak determination method (OGI or Method 21).
    (C) The total number and type of equipment for which leaks were 
detected.
    (D) The total number and type of equipment for which leaks were 
repaired within 15 calendar days.
    (E) The total number and type of equipment for which no repair 
attempt was made within 5 calendar days of the leaks being identified.
    (F) The total number and types of equipment that were placed on the 
delay of repair, as specified in Sec.  60.502a(j)(8) of this chapter.
    (ii) For leaks identified under Sec.  63.424(c) by audio/visual/
olfactory methods during normal duties report:
    (A) The total number and type of equipment for which leaks were 
identified.
    (B) The total number and type of equipment for which leaks were 
repaired within 15 calendar days.
    (C) The total number and type of equipment for which no repair 
attempt was made within 5 calendar days of the leaks being identified.

[[Page 39370]]

    (D) The total number and type of equipment placed on the delay of 
repair, as specified in Sec.  60.502a(j)(8) of this chapter.
    (iii) The total number of leaks on the delay of repair list at the 
start of the reporting period.
    (iv) The total number of leaks on the delay of repair list at the 
end of the reporting period.
    (v) For each leak that was on the delay of repair list at any time 
during the reporting period, report:
    (A) Unique equipment identification number.
    (B) Type of equipment.
    (C) Leak determination method (OGI, Method 21, or audio/visual/
olfactory).
    (D) The reason(s) why the repair was not feasible within 15 
calendar days.
    (E) If applicable, the date repair was completed.
    (7) For each gasoline storage vessel subject to requirements in 
Sec.  63.423, report:
    (i) The information specified in Sec.  60.115b(a) or (b) of this 
chapter or deviations in measured parameter values from the plan 
specified in Sec.  60.115b(c) of this chapter, depending upon the 
control equipment installed, or, if applicable, the information 
specified in Sec.  63.1066(b).
    (ii) If you are complying with Sec.  63.423(b)(2), for each 
deviation in LEL monitoring, report:
    (A) Date and start and end times of the LEL monitoring, and the 
storage vessel being monitored.
    (B) Description of the monitoring event, e.g., monitoring conducted 
concurrent with visual inspection required under Sec.  60.113b(a)(2) of 
this chapter or Sec.  63.1063(d)(2); monitoring that occurred on a date 
other than the visual inspection required under Sec.  60.113b(a)(2) or 
Sec.  63.1063(d)(2); re-monitoring due to high winds; re-monitoring 
after repair attempt.
    (C) Wind speed in miles per hour at the top of the storage vessel 
on the date of LEL monitoring.
    (D) The highest 5-minute rolling average reading during the 
monitoring event.
    (E) Whether the floating roof was repaired, replaced, or taken out 
of gasoline service. If the floating roof was repaired or replaced, 
also report the information in paragraphs (m)(7)(ii)(A) through (D) of 
this section for each re-monitoring conducted to confirm the repair.
    (8) If there were no deviations from the emission limitations, 
operating parameters, or work practice standards, then provide a 
statement that there were no deviations from the emission limitations, 
operating parameters, or work practice standards during the reporting 
period. If there were no periods during which a continuous monitoring 
system (including a CEMS or CPMS) was inoperable or out-of-control, 
then provide a statement that there were no periods during which a 
continuous monitoring system was inoperable or out-of-control during 
the reporting period.
    (n) Each owner or operator of an affected source under this subpart 
shall submit semiannual compliance reports with the information 
specified in paragraph (l) or (m) of this section to the Administrator 
according to the requirements in Sec.  63.13. Beginning on May 8, 2027, 
or once the report template for this subpart has been available on the 
CEDRI website (https://www.epa.gov/electronic-reporting-air-emissions/cedri) for one year, whichever date is later, you must submit all 
subsequent semiannual compliance reports using the appropriate 
electronic report template on the CEDRI website for this subpart and 
following the procedure specified in Sec.  63.9(k), except any medium 
submitted through mail must be sent to the attention of the Gasoline 
Distribution Sector Lead. The date report templates become available 
will be listed on the CEDRI website. Unless the Administrator or 
delegated State agency or other authority has approved a different 
schedule for submission of reports, the report must be submitted by the 
deadline specified in this subpart, regardless of the method in which 
the report is submitted.

0
14. Section 63.429 is amended by revising paragraph (c) introductory 
text and adding paragraph (c)(5) to read as follows:


Sec.  63.429  Implementation and enforcement.

* * * * *
    (c) The authorities that cannot be delegated to State, local, or 
Tribal agencies are as specified in paragraphs (c)(1) through (5) of 
this section.
* * * * *
    (5) Approval of an alternative to any electronic reporting to the 
EPA required by this subpart.

0
15. Table 1 to subpart R of part 63 is revised to read as follows:

  Table 1 to Subpart R of Part 63--General Provisions Applicability to
                              This Subpart
------------------------------------------------------------------------
                                 Applies to this
           Reference                 subpart              Comment
------------------------------------------------------------------------
63.1(a)(1)....................  Yes.
63.1(a)(2)....................  Yes.
63.1(a)(3)....................  Yes.
63.1(a)(4)....................  Yes.
63.1(a)(5)....................  No...............  Section reserved.
63.1(a)(6)....................  Yes.
63.1(a)(7) through (9)........  No...............  Sections reserved.
63.1(a)(10)...................  Yes.
63.1(a)(11)...................  Yes.
63.1(a)(12)...................  Yes.
63.1(b)(1)....................  No...............  This subpart
                                                    specifies
                                                    applicability in
                                                    Sec.   63.420.
63.1(b)(2)....................  Yes.
63.1(b)(3)....................  Yes..............  Except this subpart
                                                    specifies additional
                                                    reporting and
                                                    recordkeeping for
                                                    some large area
                                                    sources in Sec.
                                                    63.428. These
                                                    additional
                                                    requirements only
                                                    apply prior to the
                                                    date the
                                                    applicability
                                                    equations are no
                                                    longer applicable.
63.1(c)(1)....................  Yes.
63.1(c)(2)....................  Yes..............  Some small sources
                                                    are not subject to
                                                    this subpart.
63.1(c)(3)....................  No...............  Section reserved.
63.1(c)(4)....................  No...............  Section reserved.
63.1(c)(5)....................  Yes.
63.1(c)(6)....................  Yes.
63.1(d).......................  No...............  Section reserved.
63.1(e).......................  Yes.

[[Page 39371]]

 
63.2..........................  Yes..............  Additional
                                                    definitions in Sec.
                                                     63.421.
63.3(a)-(c)...................  Yes.
63.4(a)(1) and (2)............  Yes.
63.4(a)(3) through (5)........  No...............  Sections reserved.
63.4(b).......................  Yes.
63.4(c).......................  Yes.
63.5(a)(1)....................  Yes.
63.5(a)(2)....................  Yes.
63.5(b)(1)....................  Yes.
63.5(b)(2)....................  No...............  Section reserved.
63.5(b)(3)....................  Yes.
63.5(b)(4)....................  Yes.
63.5(b)(5)....................  No...............  Section reserved.
63.5(b)(6)....................  Yes.
63.5(c).......................  No...............  Section reserved.
63.5(d)(1)....................  Yes.
63.5(d)(2)....................  Yes.
63.5(d)(3)....................  Yes.
63.5(d)(4)....................  Yes.
63.5(e).......................  Yes.
63.5(f)(1)....................  Yes.
63.5(f)(2)....................  Yes.
63.6(a).......................  Yes.
63.6(b)(1)....................  Yes.
63.6(b)(2)....................  Yes.
63.6(b)(3)....................  Yes.
63.6(b)(4)....................  Yes.
63.6(b)(5)....................  Yes.
63.6(b)(6)....................  No...............  Section reserved.
63.6(b)(7)....................  Yes.
63.6(c)(1)....................  No...............  This subpart
                                                    specifies the
                                                    compliance date.
63.6(c)(2)....................  Yes.
63.6(c)(3) and (4)............  No...............  Sections reserved.
63.6(c)(5)....................  Yes.
63.6(d).......................  No...............  Section reserved.
63.6(e).......................  No...............  See Sec.   62.420(k)
                                                    for general duty
                                                    requirement.
63.6(f)(1)....................  No...............
63.6(f)(2)....................  Yes.
63.6(f)(3)....................  Yes.
63.6(g).......................  Yes.
63.6(h).......................  No...............  This subpart does not
                                                    require COMS; this
                                                    subpart specifies
                                                    requirements for
                                                    visible emissions
                                                    observations for
                                                    flares.
63.6(i)(1) through (14).......  Yes.
63.6(i)(15)...................  No...............  Section reserved.
63.6(i)(16)...................  Yes.
63.6(j).......................  Yes.
63.7(a)(1)....................  Yes.
63.7(a)(2)....................  Yes.
63.7(a)(3)....................  Yes.
63.7(a)(4)....................  Yes.
63.7(b).......................  Yes.
63.7(c).......................  Yes.
63.7(d).......................  Yes.
63.7(e)(1)....................  No...............  This subpart
                                                    specifies
                                                    performance test
                                                    conditions.
63.7(e)(2)....................  Yes.
63.7(e)(3)....................  Yes.
63.7(e)(4)....................  Yes.
63.7(f).......................  Yes.
63.7(g).......................  Yes..............  Except this subpart
                                                    specifies how and
                                                    when the performance
                                                    test and performance
                                                    evaluation results
                                                    are reported.
63.7(h).......................  Yes.
63.8(a)(1)....................  Yes.
63.8(a)(2)....................  Yes.
63.8(a)(3)....................  No...............  Section reserved.
63.8(a)(4)....................  Yes.
63.8(b)(1)....................  Yes.
63.8(b)(2)....................  Yes.
63.8(b)(3)....................  Yes.
63.8(c)(1) introductory text..  Yes.
63.8(c)(1)(i).................  No...............
63.8(c)(1)(ii)................  Yes.
63.8(c)(1)(iii)...............  No...............

[[Page 39372]]

 
63.8(c)(2)....................  Yes.
63.8(c)(3)....................  Yes.
63.8(c)(4)....................  Yes.
63.8(c)(5)....................  No...............  This subpart does not
                                                    require COMS.
63.8(c)(6) through (8)........  Yes.
63.8(d)(1) and (2)............  Yes.
63.8(d)(3)....................  No...............  This subpart
                                                    specifies CMS
                                                    records
                                                    requirements.
63.8(e).......................  Yes..............  Except this subpart
                                                    specifies how and
                                                    when the performance
                                                    evaluation results
                                                    are reported.
63.8(f)(1) through (5)........  Yes.
63.8(f)(6)....................  Yes.
63.8(g).......................  Yes.
63.9(a).......................  Yes.
63.9(b)(1)....................  Yes.
63.9(b)(2)....................  Yes..............  Except this subpart
                                                    allows additional
                                                    time for existing
                                                    sources to submit
                                                    initial
                                                    notification.
                                                    Section 63.428(a)
                                                    specifies submittal
                                                    by 1 year after
                                                    being subject to the
                                                    rule or December 16,
                                                    1996, whichever is
                                                    later.
63.9(b)(3)....................  No...............  Section reserved.
63.9(b)(4)....................  Yes.
63.9(b)(5)....................  Yes.
63.9(c).......................  Yes.
63.9(d).......................  Yes.
63.9(e).......................  Yes.
63.9(f).......................  No...............
63.9(g).......................  Yes.
63.9(h)(1) through (3)........  Yes..............  Except this subpart
                                                    specifies how to
                                                    submit the
                                                    Notification of
                                                    Compliance Status.
63.9(h)(4)....................  No...............  Section reserved.
63.9(h)(5) and (6)............  Yes.
63.9(i).......................  Yes.
63.9(j).......................  Yes.
63.9(k).......................  Yes.
63.10(a)......................  Yes.
63.10(b)(1)...................  Yes.
63.10(b)(2)(i), (ii), (iv),     No...............  This subpart
 and (v).                                           specifies
                                                    recordkeeping
                                                    requirements for
                                                    deviations.
63.10(b)(2)(iii) and (vi)       Yes.
 through (xiv).
63.10(b)(3)...................  Yes.
63.10(c)(1)...................  Yes.
63.10(c)(2) through (4).......  No...............  Sections reserved.
63.10(c)(5) through (8).......  Yes.
63.10(c)(9)...................  No...............  Section reserved.
63.10(c)(10) through (14).....  Yes.
63.10(c)(15)..................  No...............
63.10(d)(1)...................  Yes..............
63.10(d)(2)...................  No...............  This subpart
                                                    specifies how and
                                                    when the performance
                                                    test results are
                                                    reported.
63.10(d)(3)...................  No...............  This subpart
                                                    specifies reporting
                                                    requirements for
                                                    visible emissions
                                                    observations for
                                                    flares.
63.10(d)(4)...................  Yes.
63.10(d)(5)...................  No...............
63.10(e)(1)...................  Yes.
63.10(e)(2) through (4).......  No...............  This subpart
                                                    specifies reporting
                                                    requirements for CMS
                                                    and continuous
                                                    opacity monitoring
                                                    systems.
63.10(f)......................  Yes.
63.11(a) and (b)..............  Yes..............  Except these
                                                    provisions no longer
                                                    apply upon
                                                    compliance with the
                                                    provisions in Sec.
                                                    Sec.   63.422(b)(2)
                                                    and 63.425(d)(2) for
                                                    flares to meet the
                                                    requirements
                                                    specified in Sec.
                                                    Sec.   60.502a(c)(3)
                                                    and 60.504a(c) of
                                                    this chapter.
63.11(c), (d), and (e)........  Yes..............  Except these
                                                    provisions do not
                                                    apply to monitoring
                                                    required under Sec.
                                                     63.425(b)(1) or
                                                    (c)(1) and these
                                                    provisions no longer
                                                    apply upon
                                                    compliance with the
                                                    provisions in Sec.
                                                    63.424(c).
63.12.........................  Yes.
63.13.........................  Yes.
63.14.........................  Yes.
63.15.........................  Yes.
63.16.........................  Yes.
------------------------------------------------------------------------


[[Page 39373]]

Subpart BBBBBB--National Emission Standards for Hazardous Air 
Pollutants for Source Category: Gasoline Distribution Bulk 
Terminals, Bulk Plants, and Pipeline Facilities

0
16. Section 63.11081 is amended by revising paragraphs (c) and (f) to 
read as follows:


Sec.  63.11081  Am I subject to the requirements in this subpart?

* * * * *
    (c) Gasoline storage tanks that are located at affected sources 
identified in paragraphs (a)(1) through (4) of this section, and that 
are used only for dispensing gasoline in a manner consistent with tanks 
located at a gasoline dispensing facility as defined in Sec.  63.11132, 
are not subject to any of the requirements in this subpart. These tanks 
must comply with subpart CCCCCC of this part.
* * * * *
    (f) If your affected source's throughput ever exceeds an applicable 
throughput threshold in the definition of ``bulk gasoline terminal'' or 
in item 1 in table 2 to this subpart, the affected source will remain 
subject to the requirements for sources above the threshold, even if 
the affected source throughput later falls below the applicable 
throughput threshold. If your bulk gasoline plant's annual average 
gasoline throughput ever reaches or exceeds 4,000 gallons per day, the 
bulk gasoline plant will remain subject to the vapor balancing 
requirements, even if the affected source annual average gasoline 
throughput later falls below 4,000 gallons per day.
* * * * *

0
17. Section 63.11082 is amended by revising paragraph (a) to read as 
follows:


Sec.  63.11082  What parts of my affected source does this subpart 
cover?

    (a) The emission sources to which this subpart applies are gasoline 
storage tanks, gasoline loading racks, vapor collection-equipped 
gasoline cargo tanks, and equipment components in vapor or liquid 
gasoline service that meet the criteria specified in tables 1 through 4 
to this subpart.
* * * * *

0
18. Revise Sec.  63.11083 to read as follows:


Sec.  63.11083  When do I have to comply with this subpart?

    (a) Except as specified in paragraphs (d) and (e) of this section, 
if you have a new or reconstructed affected source, you must comply 
with this subpart according to paragraphs (a)(1) and (2) of this 
section.
    (1) If you start up your affected source before January 10, 2008, 
you must comply with the standards in this subpart no later than 
January 10, 2008.
    (2) If you start up your affected source after January 10, 2008, 
you must comply with the standards in this subpart upon startup of your 
affected source.
    (b) Except as specified in paragraphs (d) and (e) of this section, 
if you have an existing affected source, you must comply with the 
standards in this subpart no later than January 10, 2011.
    (c) If you have an existing affected source that becomes subject to 
the control requirements in this subpart because of an increase in the 
daily throughput, as specified in Sec.  63.11086(a) or in option 1 of 
table 2 to this subpart, you must comply with the standards in this 
subpart no later than 3 years after the affected source becomes subject 
to the control requirements in this subpart.
    (d) All affected sources that commenced construction or 
reconstruction on or before June 10, 2022, must comply with the 
requirements in paragraphs (d)(1) through (5) of this section upon 
startup or on May 8, 2027, whichever is later. All affected sources 
that commenced construction or reconstruction after June 10, 2022, must 
comply with the requirements in paragraphs (d)(1) through (5) of this 
section upon startup, or on July 8, 2024, whichever is later.
    (1) For bulk gasoline plants, the requirements specified in Sec.  
63.11086(a)(4) through (6).
    (2) For storage vessels at bulk gasoline terminals, pipeline 
breakout stations, or pipeline pumping stations, the requirements 
specified in items 1(b), 2(c), and 2(f) in table 1 to this subpart and 
Sec. Sec.  63.11087(g) and 63.11092(f)(1)(ii).
    (3) For loading racks at bulk gasoline terminals, the requirements 
specified in items 1(c), 1(f), and 2(c) in table 2 to this subpart.
    (4) For equipment leak inspections at bulk gasoline terminals, bulk 
gasoline plants, pipeline breakout stations, or pipeline pumping 
stations, the requirements in Sec.  63.11089(c).
    (5) For gasoline cargo tanks, the requirements specified in Sec.  
63.11092(g)(1)(ii).
    (e) All affected sources that commenced construction or 
reconstruction on or before June 10, 2022, must comply with the 
requirements specified in items 2(d) and 2(e) in table 1 to this 
subpart upon startup or the next time the storage vessel is completely 
emptied and degassed, or by May 8, 2034, whichever occurs first. All 
affected sources that commenced construction or reconstruction after 
June 10, 2022, must comply with the requirements specified in items 
2(d) and 2(e) in table 1 to this subpart upon startup, or on July 8, 
2024, whichever is later.

0
19. Revise Sec.  63.11085 to read as follows:


Sec.  63.11085  What are my general duties to minimize emissions?

    Each owner or operator of an affected source under this subpart 
must comply with the requirements of paragraphs (a) through (c) of this 
section.
    (a) You must, at all times, operate and maintain any affected 
source, including associated air pollution control equipment and 
monitoring equipment, in a manner consistent with safety and good air 
pollution control practices for minimizing emissions. The general duty 
to minimize emissions does not require the owner or operator to make 
any further efforts to reduce emissions if levels required by the 
applicable standard have been achieved. Determination of whether such 
operation and maintenance procedures are being used will be based on 
information available to the Administrator, which may include, but is 
not limited to, monitoring results, review of operation and maintenance 
procedures, review of operation and maintenance records, and inspection 
of the source.
    (b) You must not allow gasoline to be handled in a manner that 
would result in vapor releases to the atmosphere for extended periods 
of time. Measures to be taken include, but are not limited to, the 
following:
    (1) Minimize gasoline spills;
    (2) Clean up spills as expeditiously as practicable;
    (3) Cover all open gasoline containers and all gasoline storage 
tank fill-pipes with a gasketed seal when not in use; and
    (4) Minimize gasoline sent to open waste collection systems that 
collect and transport gasoline to reclamation and recycling devices, 
such as oil/water separators.
    (c) You must keep applicable records and submit reports as 
specified in Sec. Sec.  63.11094(g) and 63.11095(d) or Sec.  
63.11095(e).

0
20. Section 63.11086 is amended by:
0
a. Revising the introductory text and paragraph (a) introductory text;
0
b. Adding paragraphs (a)(4) through (6);
0
c. Revising paragraphs (b) and (c);
0
d. Removing and reserving paragraph (d); and
0
e. Revising paragraphs (e) and (i).
    The revisions and additions read as follows:

[[Page 39374]]

Sec.  63.11086  What requirements must I meet if my facility is a bulk 
gasoline plant?

    Each owner or operator of an affected bulk gasoline plant, as 
defined in Sec.  63.11100, must comply with the requirements of 
paragraphs (a) through (j) of this section.
    (a) Except as specified in paragraph (b) of this section, you must 
only load gasoline into storage tanks and cargo tanks at your facility 
by utilizing submerged filling, as defined in Sec.  63.11100, and as 
specified in paragraph (a)(1), (2), or (3) of this section. The 
applicable distances in paragraphs (a)(1) and (2) of this section shall 
be measured from the point in the opening of the submerged fill pipe 
that is the greatest distance from the bottom of the storage tank. 
Additionally, for bulk gasoline plants with an annual average gasoline 
throughput of 4,000 gallons per day or more (calculated by summing the 
current day's throughput, plus the throughput for the previous 364 
days, and then dividing that sum by 365), you must only load gasoline 
utilizing vapor balancing as specified in paragraphs (a)(4) through (6) 
of this section.
* * * * *
    (4) Beginning no later than the dates specified in Sec.  63.11083, 
each bulk gasoline plant with an annual average gasoline throughput of 
4,000 gallons per day or more shall be equipped with a vapor balance 
system between fixed roof gasoline storage tank(s) other than storage 
tank(s) vented through a closed vent system to a control device and 
incoming gasoline cargo tank(s) designed to capture and transfer vapors 
displaced during filling of fixed roof gasoline storage tank(s) other 
than storage tank(s) vented through a closed vent system to a control 
device. These lines shall be equipped with fittings that are vapor 
tight and that automatically and immediately close upon disconnection.
    (5) Beginning no later than the dates specified in Sec.  63.11083, 
each bulk gasoline plant with an annual average gasoline throughput of 
4,000 gallons per day or more shall be equipped with a vapor balance 
system between fixed roof gasoline storage tank(s) other than storage 
tank(s) vented through a closed vent system to a control device and 
outgoing gasoline cargo tank(s) designed to capture and transfer vapors 
displaced during the loading of gasoline cargo tank(s). The vapor 
balance system shall be designed to prevent any vapors collected at one 
loading rack from passing to another loading rack.
    (6) Beginning no later than the dates specified in Sec.  63.11083, 
each owner or operator of a bulk gasoline plant subject to this subpart 
shall act to ensure that the following procedures are followed during 
all loading, unloading, and storage operations:
    (i) The vapor balance system shall be connected between the cargo 
tank and storage tank during all gasoline transfer operations between a 
cargo tank and a fixed roof gasoline storage tank other than a storage 
tank vented through a closed vent system to a control device;
    (ii) All storage tank openings, including inspection hatches and 
gauging and sampling devices shall be vapor tight when not in use;
    (iii) No pressure relief device on a gasoline storage tank shall 
begin to open at a tank pressure less than 18 inches of water to 
minimize breathing losses;
    (iv) The gasoline cargo tank compartment hatch covers shall not be 
opened during the gasoline transfer;
    (v) All vapor balance systems shall be designed and operated at all 
times to prevent gauge pressure in the gasoline cargo tank from 
exceeding 18 inches of water and vacuum from exceeding 6 inches of 
water during product transfers;
    (vi) No pressure vacuum relief valve in the bulk gasoline plant 
vapor balance system shall begin to open at a system pressure of less 
than 18 inches of water or at a vacuum of less than 6 inches of water; 
and
    (vii) No gasoline shall be transferred into a cargo tank that does 
not have a current annual certification for vapor-tightness pursuant to 
the requirements in Sec.  60.502a(e) of this chapter.
    (b) Gasoline storage tanks with a capacity of less than 250 gallons 
are not required to comply with the control requirements in paragraph 
(a) of this section but must comply only with the requirements in Sec.  
63.11085(b).
    (c) You must perform a leak inspection of all equipment in gasoline 
service and repair leaking equipment according to the requirements 
specified in Sec.  63.11089.
* * * * *
    (e) You must submit an Initial Notification that you are subject to 
this subpart by May 9, 2008, or no later than 120 days after the source 
becomes subject to this subpart, whichever is later unless you meet the 
requirements in paragraph (g) of this section. The Initial Notification 
must contain the information specified in paragraphs (e)(1) through (4) 
of this section. The notification must be submitted to the applicable 
U.S. Environmental Protection Agency (EPA) Regional Office and the 
delegated State authority, as specified in Sec.  63.13.
    (1) The name and address of the owner and the operator.
    (2) The address (i.e., physical location) of the bulk gasoline 
plant.
    (3) A statement that the notification is being submitted in 
response to this subpart and identifying the requirements in paragraphs 
(a), (b), and (c) of this section that apply to you.
    (4) A brief description of the bulk gasoline plant, including the 
number of storage tanks in gasoline service, the capacity of each 
storage tank in gasoline service, and the average monthly gasoline 
throughput at the affected source.
* * * * *
    (i) You must keep applicable records and submit reports as 
specified in Sec. Sec.  63.11094 and 63.11095.

0
21. Section 63.11087 is amended by revising paragraph (c) and adding 
paragraph (g) to read as follows:


Sec.  63.11087  What requirements must I meet for gasoline storage 
tanks if my facility is a bulk gasoline terminal, pipeline breakout 
station, or pipeline pumping station?

* * * * *
    (c) You must comply with the applicable testing and monitoring 
requirements specified in Sec.  63.11092(f).
* * * * *
    (g) No later than the dates specified in Sec.  63.11083, if your 
gasoline storage tank is subject to, and complies with, the control 
requirements of Sec.  60.112b(a)(2), (3), or (4) of this chapter, your 
storage tank will be deemed in compliance with this section. If your 
gasoline storage tank is subject to the control requirements of Sec.  
60.112b(a)(1) of this chapter, you must conduct lower explosive limit 
(LEL) monitoring as specified in Sec.  63.11092(f)(1)(ii) to 
demonstrate compliance with this section. You must report this 
determination in the Notification of Compliance Status report under 
Sec.  63.11093(b). The requirements in paragraph (f) of this section do 
not apply when demonstrating compliance with this paragraph (g).

0
22. Section 63.11088 is amended by revising the section heading and 
paragraph (d) to read as follows:


Sec.  63.11088  What requirements must I meet for gasoline loading 
racks if my facility is a bulk gasoline terminal?

* * * * *
    (d) You must comply with the applicable testing and monitoring 
requirements specified in Sec.  63.11092. As an alternative to the 
pressure monitoring requirements specified in Sec.  60.504a(d) of this 
chapter, you may

[[Page 39375]]

comply with the requirements specified in Sec.  63.11092(h).
* * * * *

0
23. Revise Sec.  63.11089 to read as follows:


Sec.  63.11089  What requirements must I meet for equipment leak 
inspections if my facility is a bulk gasoline terminal, bulk gasoline 
plant, pipeline breakout station, or pipeline pumping station?

    (a) Each owner or operator of a bulk gasoline terminal, bulk 
gasoline plant, pipeline breakout station, or pipeline pumping station 
subject to the provisions of this subpart shall implement a leak 
detection and repair program for all equipment in gasoline service 
according to the requirements in paragraph (b) or (c) of this section, 
as applicable based on the compliance dates specified in Sec.  
63.11083.
    (b) Perform a monthly leak inspection of all equipment in gasoline 
service, as defined in Sec.  63.11100. For this inspection, detection 
methods incorporating sight, sound, and smell are acceptable.
    (1) A logbook shall be used and shall be signed by the owner or 
operator at the completion of each inspection. A section of the logbook 
shall contain a list, summary description, or diagram(s) showing the 
location of all equipment in gasoline service at the facility.
    (2) Each detection of a liquid or vapor leak shall be recorded in 
the logbook. When a leak is detected, an initial attempt at repair 
shall be made as soon as practicable, but no later than 5 calendar days 
after the leak is detected. Repair or replacement of leaking equipment 
shall be completed within 15 calendar days after detection of each 
leak, except as provided in paragraph (b)(3) of this section.
    (3) Delay of repair of leaking equipment will be allowed if the 
repair is not feasible within 15 days. The owner or operator shall 
provide in the semiannual report specified in Sec.  63.11095(c), the 
reason(s) why the repair was not feasible and the date each repair was 
completed.
    (c) No later than the dates specified in Sec.  63.11083, comply 
with the requirements in Sec.  60.502a(j) of this chapter except as 
provided in paragraphs (c)(1) through (4) of this section. The 
requirements in paragraph (b) of this section do not apply when 
demonstrating compliance with this paragraph (c).
    (1) The frequency for optical gas imaging (OGI) monitoring shall be 
annually rather than quarterly as specified in Sec.  60.502a(j)(1)(i) 
of this chapter.
    (2) The frequency for Method 21 monitoring of pumps and valves 
shall be annually rather than quarterly as specified in Sec.  
60.502a(j)(1)(ii)(A) and (B) of this chapter.
    (3) The frequency of monitoring of pressure relief devices shall be 
annually and within 5 calendar days after each pressure release rather 
than quarterly and within 5 calendar days after each pressure release 
as specified in Sec.  60.502a(j)(4)(i) of this chapter.
    (4) Any pressure relief device that is located at a bulk gasoline 
plant or pipeline pumping station that is monitored only by non-plant 
personnel may be monitored after a pressure release the next time the 
monitoring personnel are onsite, but in no case more than 30 calendar 
days after a pressure release.
    (d) You must comply with the requirements of this subpart by the 
applicable dates specified in Sec.  63.11083.
    (e) You must submit the applicable notifications as required under 
Sec.  63.11093.
    (f) You must keep records and submit reports as specified in 
Sec. Sec.  63.11094 and 63.11095.

0
24. Section 63.11092 is amended by:
0
a. Revising paragraphs (a)(1) introductory text and (b)(1)(i)(B)(1) 
introductory text;
0
b. Removing and reserving paragraph (b)(1)(i)(B)(2)(iv);
0
c. Revising paragraphs (b)(1)(i)(B)(2)(v) and (b)(1)(iii) introductory 
text;
0
d. Removing and reserving paragraph (b)(1)(iii)(B)(2)(iv);
0
e. Revising paragraphs (b)(1)(iii)(B)(2)(v) and (d) through (g); and
0
f. Adding paragraphs (h) and (i).
    The revisions and additions read as follows:


Sec.  63.11092  What testing and monitoring requirements must I meet?

    (a) * * *
    (1) Conduct a performance test on the vapor processing and 
collection systems according to either paragraph (a)(1)(i) or (ii) of 
this section, except as provided in paragraphs (a)(2) through (4) of 
this section.
* * * * *
    (b) * * *
    (1) * * *
    (i) * * *
    (B) * * *
    (1) Carbon adsorption devices shall be monitored as specified in 
paragraphs (b)(1)(i)(B)(1)(i), (ii), and (iii) of this section.
* * * * *
    (2) * * *
    (v) The owner or operator shall document the maximum vacuum level 
observed on each carbon bed from each daily inspection and the maximum 
VOC concentration observed from each carbon bed on each monthly 
inspection, as defined in the monitoring and inspection plan, and any 
activation of the automated alarm or shutdown system with a written 
entry into a logbook or other permanent form of record. Such record 
shall also include a description of the corrective action taken and 
whether such corrective actions were taken in a timely manner, as 
defined in the monitoring and inspection plan, as well as an estimate 
of the amount of gasoline loaded.
* * * * *
    (iii) Where a thermal oxidation system is used, the owner or 
operator shall monitor the operation of the system as specified in 
paragraph (b)(1)(iii)(A) or (B) of this section.
* * * * *
    (B) * * *
    (2) * * *
    (v) The owner or operator shall document any activation of the 
automated alarm or shutdown system with a written entry into a logbook 
or other permanent form of record. Such record shall also include a 
description of the corrective action taken and whether such corrective 
actions were taken in a timely manner, as defined in the monitoring and 
inspection plan, as well as an estimate of the amount of gasoline 
loaded.
* * * * *
    (d) Each owner or operator of a bulk gasoline terminal subject to 
the provisions of this subpart shall comply with the requirements in 
paragraphs (d)(1) through (3) of this section.
    (1) Operate the vapor processing system in a manner not to exceed 
or not to go below, as appropriate, the operating parameter value for 
the parameters described in paragraph (b)(1) of this section.
    (2) In cases where an alternative parameter pursuant to paragraph 
(b)(1)(iv) or (b)(5)(i) of this section is approved, each owner or 
operator shall operate the vapor processing system in a manner not to 
exceed or not to go below, as appropriate, the alternative operating 
parameter value.
    (3) Operation of the vapor processing system in a manner exceeding 
or going below the operating parameter value, as appropriate, shall 
constitute a violation of the emission standard in Sec.  63.11088(a).
    (e) Each owner or operator of a bulk gasoline terminal subject to 
the emission standard in item 1(c) of table 2 to this subpart for 
loading racks must comply with the requirements in

[[Page 39376]]

paragraphs (e)(1) through (4) of this section, as applicable.
    (1) For each bulk gasoline terminal complying with the emission 
limitations in item 1 of table 3 to this subpart (thermal oxidation 
system), conduct a performance test no later than 180 days after 
becoming subject to the applicable emission limitation in table 3 and 
conduct subsequent performance tests at least once every 60 calendar 
months following the methods specified in Sec.  60.503a(a) and (c) of 
this chapter. Prior to conducting this performance test, you must 
continue to meet the monitoring and operating limits that apply based 
on the previously conducted performance test. A previously conducted 
performance test may be used to satisfy this requirement if the 
conditions in paragraphs (e)(1)(i) through (v) of this section are met.
    (i) The performance test was conducted on or after May 8, 2022.
    (ii) No changes have been made to the process or control device 
since the time of the performance test.
    (iii) The operating conditions, test methods, and test requirements 
(e.g., length of test) used for the previous performance test conform 
to the requirements in paragraph (e)(1) of this section.
    (iv) The temperature in the combustion zone was recorded during the 
performance test as specified in Sec.  60.503a(c)(8)(i) of this chapter 
and can be used to establish the operating limit as specified in Sec.  
60.503a(c)(8)(ii) through (iv) of this chapter.
    (v) The performance test demonstrates compliance with the emission 
limit specified in item 1(a) in table 3 to this subpart.
    (2) For each bulk gasoline terminal complying with the emission 
limitations in item 1 of table 3 to this subpart (thermal oxidation 
system), comply with either the provisions in paragraph (e)(2)(i) or 
(ii) of this section.
    (i) Install, operate, and maintain a CPMS to measure the combustion 
zone temperature according to Sec.  60.504a(a) of this chapter and 
maintain the 3-hour rolling average combustion zone temperature when 
gasoline cargo tanks are being loaded at or above the operating limit 
set during the most recent performance test following the procedures 
specified in Sec.  60.503a(c)(8) of this chapter. Valid operating data 
must exclude periods when there is no liquid product being loaded. If 
previous contents of the cargo tanks are known, you may also exclude 
periods when liquid product is loaded but no gasoline cargo tanks are 
being loaded provided that you excluded these periods in the 
determination of the combustion zone temperature operating limit 
according to the provisions in Sec.  60.503a(c)(8)(ii) of this chapter.
    (ii) Operate each thermal oxidation system in compliance with the 
requirements for a flare in Sec.  60.502a(c)(3) of this chapter and the 
monitoring requirements in Sec.  60.504a(c) of this chapter.
    (3) For each bulk gasoline terminal complying with the emission 
limitations in item 2 of table 3 to this subpart (flare), install, 
operate, and maintain flare continuous parameter monitoring systems as 
specified in in Sec.  60.504a(c) of this chapter.
    (4) For each bulk gasoline terminal complying with the emission 
limitation in item 3 of table 3 to this subpart (carbon adsorption 
system, refrigerated condenser, or other vapor recovery system), 
install, operate, and maintain a continuous emission monitoring system 
(CEMS) to measure the total organic compounds (TOC) concentration 
according to Sec.  60.504a(b) of this chapter and conduct performance 
evaluations as specified in Sec.  60.503a(a) and (d) of this chapter. 
For periods of CEMS outages, you may use the limited alternative 
monitoring methods as specified in Sec.  60.504a(e) of this chapter.
    (f) Each owner or operator subject to the emission standard in 
Sec.  63.11087 for gasoline storage tanks shall comply with the 
requirements in paragraphs (f)(1) through (3) of this section.
    (1) If your gasoline storage tank is equipped with an internal 
floating roof,
    (i) You must perform inspections of the floating roof system 
according to the requirements of Sec.  60.113b(a) of this chapter if 
you are complying with option 2(b) in table 1 to this subpart, or 
according to the requirements of Sec.  63.1063(c)(1) if you are 
complying with option 2(e) in table 1 to this subpart.
    (ii) No later than the dates specified in Sec.  63.11083, you must 
conduct LEL monitoring according to the provisions in Sec.  63.425(j). 
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. Any repairs must be confirmed effective through re-
monitoring of the LEL and meeting the levels in options 2(c) and 2(f) 
in table 1 to this subpart within the timeframes specified in Sec.  
60.113b(a)(2) or Sec.  63.1063(e), as applicable.
    (2) If your gasoline storage tank is equipped with an external 
floating roof, you must perform inspections of the floating roof system 
according to the requirements of Sec.  60.113b(b) of this chapter if 
you are complying with option 2(d) in table 1 to this subpart, or 
according to the requirements of Sec.  63.1063(c)(2) if you are 
complying with option 2(e) in table 1 to this subpart.
    (3) If your gasoline storage tank is equipped with a closed vent 
system and control device, you must conduct a performance test and 
determine a monitored operating parameter value in accordance with the 
requirements in paragraphs (a) through (d) of this section, except that 
the applicable level of control specified in paragraph (a)(2) of this 
section shall be a 95-percent reduction in inlet TOC levels rather than 
80 mg/l of gasoline loaded.
    (g) The annual certification test for gasoline cargo tanks shall 
consist of the test methods specified in paragraph (g)(1) or (2) of 
this section. Affected facilities that are subject to subpart XX to 
part 60 of this chapter may elect, after notification to the subpart XX 
delegated authority, to comply with paragraphs (g)(1) and (2) of this 
section.
    (1) EPA Method 27 of appendix A-8 to part 60 of this chapter. 
Conduct the test using a time period (t) for the pressure and vacuum 
tests of 5 minutes. The initial pressure (Pi) for the 
pressure test shall be 460 millimeters (mm) of water (18 inches of 
water), gauge. The initial vacuum (Vi) for the vacuum test 
shall be 150 mm of water (6 inches of water), gauge.
    (i) The maximum allowable pressure and vacuum changes ([Delta] p, 
[Delta] v) for all affected gasoline cargo tanks is 3 inches of water, 
or less, in 5 minutes.
    (ii) No later than the dates specified in Sec.  63.11083, the 
maximum allowable pressure and vacuum changes ([Delta] p, [Delta] v) 
for all affected gasoline cargo tanks is provided in column 3 of table 
2 in Sec.  63.425(e). The requirements in paragraph (g)(1)(i) of this 
section do not apply when demonstrating compliance with this paragraph 
(g)(1)(ii).
    (2) Railcar bubble leak test procedures. As an alternative to the 
annual certification test required under paragraph (g)(1) of this 
section for certification leakage testing of gasoline cargo tanks, the 
owner or operator may comply with paragraphs (g)(2)(i) and (ii) of this 
section for railcar cargo tanks, provided the railcar cargo tank meets 
the requirement in paragraph (g)(2)(iii) of this section.
    (i) Comply with the requirements of 49 CFR 173.31(d), 179.7, 
180.509, and 180.511 for the periodic testing of railcar cargo tanks.
    (ii) The leakage pressure test procedure required under 49 CFR 
180.509(j) and used to show no indication of leakage under 49 CFR 
180.511(f) shall be a bubble leak test procedure meeting the 
requirements in

[[Page 39377]]

49 CFR 179.7, 180.505, and 180.509. Use of ASTM E515-95 (Reapproved 
2000) or BS EN 1593:1999 (incorporated by reference, see Sec.  63.14) 
complies with those requirements.
    (iii) The alternative requirements in this paragraph (g)(2) may not 
be used for any railcar cargo tank that collects gasoline vapors from a 
vapor balance system and the system complies with a Federal, State, 
local, or Tribal rule or permit. A vapor balance system is a piping and 
collection system designed to collect gasoline vapors displaced from a 
storage vessel, barge, or other container being loaded, and routes the 
displaced gasoline vapors into the railcar cargo tank from which liquid 
gasoline is being unloaded.
    (h) As an alternative to the pressure monitoring requirements in 
Sec.  60.504a(d) of this chapter, you may comply with the pressure 
monitoring requirements in Sec.  60.503(d) of this chapter during any 
performance test or performance evaluation conducted under Sec.  
63.11092(e) to demonstrate compliance with the provisions in Sec.  
60.502a(h) of this chapter.
    (i) Performance tests conducted for this subpart shall be conducted 
under such conditions as the Administrator specifies to the owner or 
operator, based on representative performance (i.e., performance based 
on normal operating conditions) of the affected source. Performance 
tests shall be conducted under representative conditions when liquid 
product is being loaded into gasoline cargo tanks and shall include 
periods between gasoline cargo tank loading (when one cargo tank is 
disconnected and another cargo tank is moved into position for loading) 
provided that liquid product loading into gasoline cargo tanks is 
conducted for at least a portion of each 5 minute block of the 
performance test. You may not conduct performance tests during periods 
of malfunction. You must record the process information that is 
necessary to document operating conditions during the test and include 
in such record an explanation to support that such conditions represent 
normal operation. Upon request, the owner or operator shall make 
available to the Administrator such records as may be necessary to 
determine the conditions of performance tests.


0
25. Section 63.11093 is amended by revising paragraph (c) and adding 
paragraph (e) to read as follows:


Sec.  63.11093  What notifications must I submit and when?

* * * * *
    (c) Each owner or operator of an affected bulk gasoline terminal 
under this subpart must submit a Notification of Performance Test or 
Performance Evaluation, as specified in subpart A to this part, prior 
to initiating testing required by this subpart.
* * * * *
    (e) The owner or operator must submit all Notification of 
Compliance Status reports in PDF format to the EPA following the 
procedure specified in Sec.  63.9(k), except any medium submitted 
through mail must be sent to the attention of the Gasoline Distribution 
Sector Lead.


0
26. Revise Sec.  63.11094 to read as follows:


Sec.  63.11094  What are my recordkeeping requirements?

    (a) Each owner or operator of a bulk gasoline terminal or pipeline 
breakout station whose storage vessels are subject to the provisions of 
this subpart shall keep records as specified in paragraphs (a)(1) and 
(2) of this section.
    (1) If you are complying with options 2(a), 2(b), or 2(d) in table 
1 to this subpart, keep records as specified in Sec.  60.115b of this 
chapter except records shall be kept for at least 5 years. If you are 
complying with the requirements of option 2(e) in table 1 to this 
subpart, you shall keep records as specified in Sec.  63.1065.
    (2) If you are complying with options 2(c) or 2(f) in table 1 to 
this subpart, keep records of each LEL monitoring event as specified in 
paragraphs (a)(2)(i) through (ix) of this section for at least 5 years.
    (i) Date and time of the LEL monitoring, and the storage vessel 
being monitored.
    (ii) A description of the monitoring event (e.g., monitoring 
conducted concurrent with visual inspection required under Sec.  
60.113b(a)(2) of this chapter or Sec.  63.1063(d)(2); monitoring that 
occurred on a date other than the visual inspection required under 
Sec.  60.113b(a)(2) or Sec.  63.1063(d)(2); re-monitoring due to high 
winds; re-monitoring after repair attempt).
    (iii) Wind speed at the top of the storage vessel on the date of 
LEL monitoring.
    (iv) The LEL meter manufacturer and model number used, as well as 
an indication of whether tubing was used during the LEL monitoring, and 
if so, the type and length of tubing used.
    (v) Calibration checks conducted before and after making the 
measurements, including both the span check and instrumental offset. 
This includes the hydrocarbon used as the calibration gas, the 
Certificate of Analysis for the calibration gas(es), the results of the 
calibration check, and any corrective action for calibration checks 
that do not meet the required response.
    (vi) Location of the measurements and the location of the floating 
roof.
    (vii) Each measurement (taken at least once every 15 seconds). The 
records should indicate whether the recorded values were automatically 
corrected using the meter's programming. If the values were not 
automatically corrected, record both the raw (as the calibration gas) 
and corrected measurements, as well as the correction factor used.
    (viii) Each 5-minute rolling average reading.
    (ix) If the vapor concentration of the storage vessel was above 25 
percent of the LEL on a 5-minue rolling average basis, a description of 
whether the floating roof was repaired, replaced, or taken out of 
gasoline service.
    (b) Each owner or operator of a bulk gasoline terminal subject to 
the provisions in items 1(e), 1(f), or 2(c) in table 2 to this subpart 
or bulk gasoline plant subject to the requirements in Sec.  
63.11086(a)(6) shall keep records in either a hardcopy or electronic 
form of the test results for each gasoline cargo tank loading at the 
facility as specified in paragraphs (b)(1) through (3) of this section 
for at least 5 years.
    (1) Annual certification testing performed under Sec.  
63.11092(g)(1) and periodic railcar bubble leak testing performed under 
Sec.  63.11092(g)(2).
    (2) The documentation file shall be kept up to date for each 
gasoline cargo tank loading at the facility. The documentation for each 
test shall include, as a minimum, the following information:
    (i) Name of test: Annual Certification Test--Method 27 or Periodic 
Railcar Bubble Leak Test Procedure.
    (ii) Cargo tank owner's name and address.
    (iii) Cargo tank identification number.
    (iv) Test location and date.
    (v) Tester name and signature.
    (vi) Witnessing inspector, if any: Name, signature, and 
affiliation.
    (vii) Vapor tightness repair: Nature of repair work and when 
performed in relation to vapor tightness testing.
    (viii) Test results: Tank or compartment capacity; test pressure; 
pressure or vacuum change, mm of water; time period of test; number of 
leaks found with instrument; and leak definition.
    (3) If you are complying with the alternative requirements in Sec.  
63.11088(b), you must keep records documenting that you have verified 
the vapor tightness testing according to the requirements of the 
Administrator.
    (c) Each owner or operator subject to the equipment leak provisions 
of

[[Page 39378]]

Sec.  63.11089 shall prepare and maintain a record describing the 
types, identification numbers, and locations of all equipment in 
gasoline service. For facilities electing to implement an instrument 
program under Sec.  63.11089(b), the record shall contain a full 
description of the program.
    (d) Each owner or operator of an affected source subject to 
equipment leak inspections under Sec.  63.11089(b) shall record in the 
logbook for each leak that is detected the information specified in 
paragraphs (d)(1) through (7) of this section.
    (1) The equipment type and identification number.
    (2) The nature of the leak (i.e., vapor or liquid) and the method 
of detection (i.e., sight, sound, or smell).
    (3) The date the leak was detected and the date of each attempt to 
repair the leak.
    (4) Repair methods applied in each attempt to repair the leak.
    (5) ``Repair delayed'' and the reason for the delay if the leak is 
not repaired within 15 calendar days after discovery of the leak.
    (6) The expected date of successful repair of the leak if the leak 
is not repaired within 15 days.
    (7) The date of successful repair of the leak.
    (e) Each owner or operator of an affected source subject to Sec.  
63.11089(c) or Sec.  60.503a(a)(2) of this chapter shall maintain 
records of each leak inspection and leak identified under Sec.  
63.11089(c) or Sec.  60.503a(a)(2) as specified in paragraphs (e)(1) 
through (5) of this section for at least 5 years.
    (1) An indication if the leak inspection was conducted under Sec.  
63.11089(c) or Sec.  60.503a(a)(2) of this chapter.
    (2) Leak determination method used for the leak inspection.
    (3) For leak inspections conducted with Method 21 of appendix A-7 
to part 60 of this chapter, keep the following additional records:
    (i) Date of inspection.
    (ii) Inspector name.
    (iii) Monitoring instrument identification.
    (iv) Identification of all equipment surveyed and the instrument 
reading for each piece of equipment.
    (v) Date and time of instrument calibration and initials of 
operator performing the calibration.
    (vi) Calibration gas cylinder identification, certification date, 
and certified concentration.
    (vii) Instrument scale used.
    (viii) Results of the daily calibration drift assessment.
    (4) For leak inspections conducted with OGI, keep the records 
specified in section 12 of appendix K to part 60 of this chapter.
    (5) For each leak detected during a leak inspection or by audio/
visual/olfactory methods during normal duties, record the following 
information:
    (i) The equipment type and identification number.
    (ii) The date the leak was detected, the name of the person who 
found the leak, the nature of the leak (i.e., vapor or liquid), and the 
method of detection (i.e., audio/visual/olfactory, Method 21, or OGI).
    (iii) The date of each attempt to repair the leak and the repair 
methods applied in each attempt to repair the leak.
    (iv) The date of successful repair of the leak, the method of 
monitoring used to confirm the repair, and if Method 21 of appendix A-7 
to part 60 of this chapter is used to confirm the repair, the maximum 
instrument reading measured by Method 21 of appendix A-7. If OGI is 
used to confirm the repair, keep video footage of the repair 
confirmation.
    (v) For each repair delayed beyond 15 calendar days after discovery 
of the leak, record ``Repair delayed'', the reason for the delay, and 
the expected date of successful repair. The owner or operator (or 
designate) whose decision it was that repair could not be carried out 
in the 15- calendar day timeframe must sign the record.
    (vi) For each leak that is not repairable, the maximum instrument 
reading measured by Method 21 of appendix A-7 to part 60 of this 
chapter at the time the leak is determined to be not repairable, a 
video captured by the OGI camera showing that emissions are still 
visible, or a signed record that the leak is still detectable via 
audio/visual/olfactory methods.
    (f) Each owner or operator of a bulk gasoline terminal subject to 
the loading rack provisions of item 1(c) of table 2 to this subpart or 
storage vessel provisions in Sec.  63.11092(f) shall:
    (1) Keep an up-to-date, readily accessible record of the continuous 
monitoring data required under Sec.  63.11092(b) or (f). This record 
shall indicate the time intervals during which loadings of gasoline 
cargo tanks have occurred or, alternatively, shall record the operating 
parameter data only during such loadings. The date and time of day 
shall also be indicated at reasonable intervals on this record.
    (2) Record and report simultaneously with the Notification of 
Compliance Status required under Sec.  63.11093(b):
    (i) All data and calculations, engineering assessments, and 
manufacturer's recommendations used in determining the operating 
parameter value under Sec.  63.11092(b) or (f); and
    (ii) The following information when using a flare under provisions 
of Sec.  63.11(b) to comply with Sec.  63.11087(a):
    (A) Flare design (i.e., steam-assisted, air-assisted, or non-
assisted); and
    (B) All visible emissions (VE) readings, heat content 
determinations, flow rate measurements, and exit velocity 
determinations made during the compliance determination required under 
Sec.  63.11092(e)(3).
    (3) Keep an up-to-date, readily accessible copy of the monitoring 
and inspection plan required under Sec.  63.11092(b)(1)(i)(B)(2) or 
(b)(1)(iii)(B)(2).
    (4) Keep an up-to-date, readily accessible record as specified in 
Sec.  63.11092(b)(1)(i)(B)(2)(v) or (b)(1)(iii)(B)(2)(v).
    (5) If an owner or operator requests approval to use a vapor 
processing system or monitor an operating parameter other than those 
specified in Sec.  63.11092(b), the owner or operator shall submit a 
description of planned reporting and recordkeeping procedures.
    (g) Each owner or operator of a bulk gasoline terminal subject to 
the loading rack provisions of item 1(c) of table 2 to this subpart 
shall keep records specified in paragraphs (g)(1) through (3) of this 
section, as applicable, for at least 5 years unless otherwise 
specified.
    (1) For each thermal oxidation system used to comply with the 
provisions in Sec.  63.11092(e)(2)(i) by monitoring the combustion zone 
temperature, for each pressure CPMS used to comply with the 
requirements in Sec.  60.502a(h) of this chapter, and for each vapor 
recovery system used to comply with the provisions in item 3 of table 3 
to this subpart, maintain records, as applicable, of:
    (i) The applicable operating or emission limit for the CMS. For 
combustion zone temperature operating limits, include the applicable 
date range the limit applies based on when the performance test was 
conducted.
    (ii) Each 3-hour rolling average combustion zone temperature 
measured by the temperature CPMS, each 5-minute average reading from 
the pressure CPMS, and each 3-hour rolling average TOC concentration 
(as propane) measured by the TOC CEMS.
    (iii) For each deviation of the 3-hour rolling average combustion 
zone temperature operating limit, maximum loading pressure specified in 
Sec.  60.502a(h) of this chapter, or 3-hour rolling average TOC 
concentration (as propane), the start date and time,

[[Page 39379]]

duration, cause, and the corrective action taken.
    (iv) For each period when there was a CMS outage or the CMS was out 
of control, the start date and time, duration, cause, and the 
corrective action taken. For TOC CEMS outages where the limited 
alternative for vapor recovery systems in Sec.  60.504a(e) of this 
chapter is used, the corrective action taken shall include an 
indication of the use of the limited alternative for vapor recovery 
systems in Sec.  60.504a(e).
    (v) Each inspection or calibration of the CMS including a unique 
identifier, make, and model number of the CMS, and date of calibration 
check. For TOC CEMS, include the type of CEMS used (i.e., flame 
ionization detector, nondispersive infrared analyzer) and an indication 
of whether methane is excluded from the TOC concentration reported in 
paragraph (g)(1)(ii) of this section.
    (vi) TOC CEMS outages where the limited alternative for vapor 
recovery systems in Sec.  60.504a(e) of this chapter is used, also keep 
records of:
    (A) The quantity of liquid product loaded in gasoline cargo tanks 
for the past 10 adsorption cycles prior to the CEMS outage.
    (B) The vacuum pressure, purge gas quantities, and duration of the 
vacuum/purge cycles used for the past 10 desorption cycles prior to the 
CEMS outage.
    (C) The quantity of liquid product loaded in gasoline cargo tanks 
for each adsorption cycle while using the alternative.
    (D) The vacuum pressure, purge gas quantities, and duration of the 
vacuum/purge cycles for each desorption cycle while using the 
alternative.
    (2) For each thermal oxidation system used to comply with the 
provision in Sec.  63.11092(e)(2)(ii) and for each flare used to comply 
with the provision in item 2 of table 3 to this subpart, maintain 
records of:
    (i) The output of the monitoring device used to detect the presence 
of a pilot flame as required in Sec.  63.670(b) for a minimum of 2 
years. Retain records of each 15-minute block during which there was at 
least one minute that no pilot flame is present when gasoline vapors 
were routed to the flare for a minimum of 5 years. The record must 
identify the start and end time and date of each 15-minute block.
    (ii) Visible emissions observations as specified in paragraphs 
(g)(2)(ii)(A) and (B) of this section, as applicable, for a minimum of 
3 years.
    (A) If visible emissions observations are performed using Method 22 
of appendix A-7 to part 60 of this chapter, the record must identify 
the date, the start and end time of the visible emissions observation, 
and the number of minutes for which visible emissions were observed 
during the observation. If the owner or operator performs visible 
emissions observations more than one time during a day, include 
separate records for each visible emissions observation performed.
    (B) For each 2-hour period for which visible emissions are observed 
for more than 5 minutes in 2 consecutive hours but visible emissions 
observations according to Method 22 of appendix A-7 to part 60 of this 
chapter were not conducted for the full 2-hour period, the record must 
include the date, the start and end time of the visible emissions 
observation, and an estimate of the cumulative number of minutes in the 
2-hour period for which emissions were visible based on best 
information available to the owner or operator.
    (iii) Each 15-minute block period during which operating values are 
outside of the applicable operating limits specified in Sec.  63.670(d) 
through (f) when liquid product is being loaded into gasoline cargo 
tanks for at least 15-minutes identifying the specific operating limit 
that was not met.
    (iv) The 15-minute block average cumulative flows for the thermal 
oxidation system vent gas or flare vent gas and, if applicable, total 
steam, perimeter assist air, and premix assist air specified to be 
monitored under Sec.  63.670(i), along with the date and start and end 
time for the 15-minute block. If multiple monitoring locations are used 
to determine cumulative vent gas flow, total steam, perimeter assist 
air, and premix assist air, retain records of the 15-minute block 
average flows for each monitoring location for a minimum of 2 years, 
and retain the 15-minute block average cumulative flows that are used 
in subsequent calculations for a minimum of 5 years. If pressure and 
temperature monitoring is used, retain records of the 15-minute block 
average temperature, pressure and molecular weight of the thermal 
oxidation system vent gas, flare vent gas, or assist gas stream for 
each measurement location used to determine the 15-minute block average 
cumulative flows for a minimum of 2 years, and retain the 15-minute 
block average cumulative flows that are used in subsequent calculations 
for a minimum of 5 years. If you use the supplemental gas flow rate 
monitoring alternative in Sec.  60.502a(c)(3)(viii) of this chapter, 
the required supplemental gas flow rate (winter and summer, if 
applicable) and the actual monitored supplemental gas flow rate for the 
15-minute block. Retain the supplemental gas flow rate records for a 
minimum of 5 years.
    (v) The thermal oxidation system vent gas or flare vent gas 
compositions specified to be monitored under Sec.  63.670(j). Retain 
records of individual component concentrations from each compositional 
analyses for a minimum of 2 years. If NHVvg analyzer is 
used, retain records of the 15-minute block average values for a 
minimum of 5 years. If you demonstrate your gas streams have consistent 
composition using the provisions in Sec.  63.670(j)(6) as specified in 
Sec.  60.502a(c)(3)(vii) of this chapter, retain records of the 
required minimum ratio of gasoline loaded to total liquid product 
loaded and the actual ratio on a 15-minute block basis. If applicable, 
you must retain records of the required minimum gasoline loading rate 
as specified in Sec.  60.502a(c)(3)(vii) and the actual gasoline 
loading rate on a 15-minute block basis for a minimum of 5 years.
    (vi) Each 15-minute block average operating parameter calculated 
following the methods specified in Sec.  63.670(k) through (n), as 
applicable.
    (vii) All periods during which the owner or operator does not 
perform monitoring according to the procedures in Sec.  63.670(g), (i), 
and (j) or in Sec.  60.502a(c)(3)(vii) and (viii) of this chapter as 
applicable. Note the start date, start time, and duration in minutes 
for each period.
    (viii) An indication of whether ``vapors displaced from gasoline 
cargo tanks during product loading'' excludes periods when liquid 
product is loaded but no gasoline cargo tanks are being loaded or if 
liquid product loading is assumed to be loaded into gasoline cargo 
tanks according to the provisions in Sec.  60.502a(c)(3)(i) of this 
chapter, records of all time periods when ``vapors displaced from 
gasoline cargo tanks during product loading'', and records of time 
periods when there were no ``vapors displaced from gasoline cargo tanks 
during product loading''.
    (ix) If you comply with the flare tip velocity operating limit 
using the one-time flare tip velocity operating limit compliance 
assessment as provided in Sec.  60.502a(c)(3)(ix) of this chapter, 
maintain records of the applicable one-time flare tip velocity 
operating limit compliance assessment for as long as you use this 
compliance method.
    (x) For each parameter monitored using a CMS, retain the records 
specified in paragraphs (g)(2)(x)(A) through (C) of this section, as 
applicable:
    (A) For each deviation, record the start date and time, duration, 
cause, and corrective action taken.

[[Page 39380]]

    (B) For each period when there is a CMS outage or the CMS is out of 
control, record the start date and time, duration, cause, and 
corrective action taken.
    (C) Each inspection or calibration of the CMS including a unique 
identifier, make, and model number of the CMS, and date of calibration 
check.
    (3) Records of all 5-minute time periods during which liquid 
product is loaded into gasoline cargo tanks or assumed to be loaded 
into gasoline cargo tanks and records of all 5-minute time periods when 
there was no liquid product loaded into gasoline cargo tanks.
    (h) Each owner or operator of a bulk gasoline terminal subject to 
the provisions in items 1(e), 1(f), or 2(c) in table 2 to this subpart 
or bulk gasoline plant subject to the requirements in Sec.  
63.11086(a)(6) shall maintain records of each instance in which liquid 
product was loaded into a gasoline cargo tank for which vapor tightness 
documentation required under Sec.  60.502(e)(1) or Sec.  60.502a(e)(1) 
of this chapter, as applicable, was not provided or available in the 
terminal's or plant's records for at least 5 years. These records shall 
include, at a minimum:
    (1) Cargo tank owner and address.
    (2) Cargo tank identification number.
    (3) Date and time liquid product was loaded into a gasoline cargo 
tank without proper documentation.
    (4) Date proper documentation was received or statement that proper 
documentation was never received.
    (i) Each owner or operator of a bulk gasoline terminal or bulk 
gasoline plant subject to the provisions of this subpart shall maintain 
records for at least 5 years of each instance when liquid product was 
loaded into gasoline cargo tanks not using submerged filling, or, if 
applicable, not equipped with vapor collection or balancing equipment 
that is compatible with the terminal's vapor collection system or 
plant's vapor balancing system. These records shall include, at a 
minimum:
    (1) Date and time of liquid product loading into gasoline cargo 
tank not using submerged filling, improperly equipped, or improperly 
connected.
    (2) Type of deviation (e.g., not submerged filling, incompatible 
equipment, not properly connected).
    (3) Cargo tank identification number.
    (j) Each owner or operator of a bulk gasoline plant subject to the 
requirements in Sec.  63.11086(a)(6) shall maintain records for at 
least 5 years of instances when gasoline was loaded between gasoline 
cargo tanks and storage tanks and the plant's vapor balancing system 
was not properly connected between the gasoline cargo tank and storage 
tank. These records shall include, at a minimum:
    (1) Date and time of gasoline loading between a gasoline cargo tank 
and a storage tank that was not properly connected.
    (2) Cargo tank identification number and storage tank 
identification number.
    (k) Each owner or operator of an affected source under this subpart 
shall keep the following records for each deviation of an emissions 
limitation (including operating limit), work practice standard, or 
operation and maintenance requirement in this subpart.
    (1) Date, start time, and duration of each deviation.
    (2) List of the affected sources or equipment for each deviation, 
an estimate of the quantity of each regulated pollutant emitted over 
any emission limit and a description of the method used to estimate the 
emissions.
    (3) Actions taken to minimize emissions in accordance with Sec.  
63.11085(a).
    (l) Each owner or operator of a bulk gasoline terminal or bulk 
gasoline plant subject to the provisions of this subpart shall maintain 
records of the average gasoline throughput (in gallons per day) for at 
least 5 years.
    (m) Keep written procedures required under Sec.  63.8(d)(2) on 
record for the life of the affected source or until the affected source 
is no longer subject to the provisions of this part, to be made 
available for inspection, upon request, by the Administrator. If the 
performance evaluation plan is revised, you shall keep previous (i.e., 
superseded) versions of the performance evaluation plan on record to be 
made available for inspection, upon request, by the Administrator, for 
a period of 5 years after each revision to the plan. The program of 
corrective action shall be included in the plan as required under Sec.  
63.8(d)(2).
    (n) Keep records of each performance test or performance evaluation 
conducted and each notification and report submitted to the 
Administrator for at least 5 years. For each performance test, include 
an indication of whether liquid product loading is assumed to be loaded 
into a gasoline cargo tank or periods when liquid product is loaded but 
no gasoline cargo tanks are being loaded are excluded in the 
determination of the combustion zone temperature operating limit 
according to the provision in Sec.  60.503a(c)(8)(ii) of this chapter. 
If complying with the alternative in Sec.  63.11092(h), for each 
performance test or performance evaluation conducted, include the 
pressure every 5 minutes while a gasoline cargo tank is being loaded 
and the highest instantaneous pressure that occurs during each loading.
    (o) Any records required to be maintained by this subpart that are 
submitted electronically via the EPA's Compliance and Emissions 
Reporting Interface (CEDRI) may be maintained in electronic format. 
This ability to maintain electronic copies does not affect the 
requirement for facilities to make records, data, and reports available 
upon request to a delegated authority or the EPA as part of an on-site 
compliance evaluation.


0
27. Revise Sec.  63.11095 to read as follows:


Sec.  63.11095  What are my reporting requirements?

    (a) Reporting requirements for performance tests. Prior to November 
4, 2024, each owner or operator of an affected source under this 
subpart shall submit performance test reports to the Administrator 
according to the requirements in Sec.  63.13. Beginning on November 4, 
2024, within 60 days after the date of completing each performance test 
required by this subpart, you must submit the results of the 
performance test following the procedures specified in Sec.  63.9(k). 
As required by Sec.  63.7(g)(2)(iv), you must include the value for the 
combustion zone temperature operating parameter limit set based on your 
performance test in the performance test report. If the monitoring 
alternative in Sec.  63.11092(h) is used, indicate that this monitoring 
alternative is being used, identify each loading rack that loads 
gasoline cargo tanks at the bulk gasoline terminal subject to the 
provisions of this subpart, and report the highest instantaneous 
pressure monitored during the performance test or performance 
evaluation for each identified loading rack. Data collected using test 
methods supported by the EPA's Electronic Reporting Tool (ERT) as 
listed on the EPA's ERT website (https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) at the time of 
the test must be submitted in a file format generated using the EPA's 
ERT. Alternatively, you may submit an electronic file consistent with 
the extensible markup language (XML) schema listed on the EPA's ERT 
website. Data collected using test methods that are not supported by 
the EPA's ERT as listed on the EPA's ERT website at the time of the 
test must be included as an attachment in the ERT or an alternate 
electronic file.

[[Page 39381]]

    (b) Reporting requirements for performance evaluations. Prior to 
November 4, 2024, each owner or operator of an affected source under 
this subpart shall submit performance evaluations to the Administrator 
according to the requirements in Sec.  63.13. Beginning on November 4, 
2024, within 60 days after the date of completing each CEMS performance 
evaluation, you must submit the results of the performance evaluation 
following the procedures specified in Sec.  63.9(k). If the monitoring 
alternative in Sec.  63.11092(h) is used, indicate that this monitoring 
alternative is being used, identify each loading rack that loads 
gasoline cargo tanks at the bulk gasoline terminal subject to the 
provisions of this subpart, and report the highest instantaneous 
pressure monitored during the performance test or performance 
evaluation for each identified loading rack. The results of performance 
evaluations of CEMS measuring relative accuracy test audit (RATA) 
pollutants that are supported by the EPA's ERT as listed on the EPA's 
ERT website at the time of the evaluation must be submitted in a file 
format generated using the EPA's ERT. Alternatively, you may submit an 
electronic file consistent with the XML schema listed on the EPA's ERT 
website. The results of performance evaluations of CEMS measuring RATA 
pollutants that are not supported by the EPA's ERT as listed on the 
EPA's ERT website at the time of the evaluation must be included as an 
attachment in the ERT or an alternate electronic file.
    (c) Reporting requirements prior to May 8, 2027. Prior to May 8, 
2027, each owner or operator of a source subject to the requirements of 
this subpart shall submit reports as specified in paragraphs (c)(1) 
through (3) of this section, as applicable.
    (1) Each owner or operator of a bulk terminal or a pipeline 
breakout station subject to the control requirements of this subpart 
shall include in a semiannual compliance report to the Administrator 
the following information, as applicable:
    (i) For storage vessels, if you are complying with options 2(a), 
2(b), or 2(d) in table 1 to this subpart, the information specified in 
Sec.  60.115b(a), (b), or (c) of this chapter, depending upon the 
control equipment installed, or, if you are complying with option 2(e) 
in table 1 to this subpart, the information specified in Sec.  63.1066.
    (ii) For loading racks, each loading of a gasoline cargo tank for 
which vapor tightness documentation had not been previously obtained by 
the facility.
    (iii) For equipment leak inspections, the number of equipment leaks 
not repaired within 15 days after detection.
    (iv) For storage vessels complying with Sec.  63.11087(b) after 
January 10, 2011, the storage vessel's Notice of Compliance Status 
information can be included in the next semi-annual compliance report 
in lieu of filing a separate Notification of Compliance Status report 
under Sec.  63.11093.
    (2) Each owner or operator of an affected source subject to the 
control requirements of this subpart shall submit an excess emissions 
report to the Administrator at the time the semiannual compliance 
report is submitted. Excess emissions events under this subpart, and 
the information to be included in the excess emissions report, are 
specified in paragraphs (c)(2)(i) through (v) of this section.
    (i) Each instance of a non-vapor-tight gasoline cargo tank loading 
at the facility in which the owner or operator failed to take steps to 
assure that such cargo tank would not be reloaded at the facility 
before vapor tightness documentation for that cargo tank was obtained.
    (ii) Each reloading of a non-vapor-tight gasoline cargo tank at the 
facility before vapor tightness documentation for that cargo tank is 
obtained by the facility in accordance with Sec.  63.11094(b).
    (iii) Each exceedance or failure to maintain, as appropriate, the 
monitored operating parameter value determined under Sec.  63.11092(b). 
The report shall include the monitoring data for the days on which 
exceedances or failures to maintain have occurred, and a description 
and timing of the steps taken to repair or perform maintenance on the 
vapor collection and processing systems or the CMS.
    (iv) [Reserved]
    (v) For each occurrence of an equipment leak for which no repair 
attempt was made within 5 days or for which repair was not completed 
within 15 days after detection:
    (A) The date on which the leak was detected;
    (B) The date of each attempt to repair the leak;
    (C) The reasons for the delay of repair; and
    (D) The date of successful repair.
    (3) Each owner or operator of a bulk gasoline plant or a pipeline 
pumping station shall submit a semiannual excess emissions report, 
including the information specified in paragraphs (c)(1)(iii) and 
(c)(2)(v) of this section, only for a 6-month period during which an 
excess emission event has occurred. If no excess emission events have 
occurred during the previous 6-month period, no report is required.
    (d) Reporting requirements for semiannual reports on or after May 
8, 2027. On or after May 8, 2027, you must submit to the Administrator 
semiannual reports with the applicable information in paragraphs (d)(1) 
through (9) of this section following the procedure specified in 
paragraph (e) of this section.
    (1) Report the following general facility information:
    (i) Facility name.
    (ii) Facility physical address, including city, county, and State.
    (iii) Latitude and longitude of facility's physical location. 
Coordinates must be in decimal degrees with at least five decimal 
places.
    (iv) The following information for the contact person:
    (A) Name.
    (B) Mailing address.
    (C) Telephone number.
    (D) Email address.
    (v) The type of facility (bulk gasoline plant with an annual 
average gasoline throughput less than 4,000 gallons per day; bulk 
gasoline plant with an annual average gasoline throughput of 4,000 
gallons per day or more; bulk gasoline terminal with a gasoline 
throughput (total of all racks) less than 250,000 gallons per day; bulk 
gasoline terminal with a gasoline throughput (total of all racks) of 
250,000 gallons per day or more; pipeline breakout station; or pipeline 
pumping station).
    (vi) Date of report and beginning and ending dates of the reporting 
period. You are no longer required to provide the date of report when 
the report is submitted via CEDRI.
    (vii) Statement by a responsible official, with that official's 
name, title, and signature, certifying the truth, accuracy, and 
completeness of the content of the report. If your report is submitted 
via CEDRI, the certifier's electronic signature during the submission 
process replaces the requirement in this paragraph (d)(1)(vii).
    (2) For each thermal oxidation system used to comply with the 
provision in Sec.  63.11092(e)(2)(i) by monitoring the combustion zone 
temperature, for each pressure CPMS used to comply with the 
requirements in Sec.  60.502a(h) of this chapter, and for each vapor 
recovery system used to comply with the provisions in item 3 of table 3 
to this subpart, report the following information for the CMS:
    (i) For all instances when the temperature CPMS measured 3-hour 
rolling averages below the established operating limit or when the 
vapor collection system pressure exceeded the

[[Page 39382]]

maximum loading pressure specified in Sec.  60.502a(h) when liquid 
product was being loaded into gasoline cargo tanks or when the TOC CEMS 
measured 3-hour rolling average concentrations higher than the 
applicable emission limitation when the vapor recovery system was 
operating:
    (A) The date and start time of the deviation.
    (B) The duration of the deviation in hours.
    (C) Each 3-hour rolling average combustion zone temperature, 
average pressure, or 3-hour rolling average TOC concentration during 
the deviation. For TOC concentration, indicate whether methane is 
excluded from the TOC concentration.
    (D) A unique identifier for the CMS.
    (E) The make, model number, and date of last calibration check of 
the CMS.
    (F) The cause of the deviation and the corrective action taken.
    (ii) For all instances that the temperature CPMS for measuring the 
combustion zone temperature or pressure CPMS was not operating or out 
of control when liquid product was loaded into gasoline cargo tanks, or 
the TOC CEMS was not operating or was out of control when the vapor 
recovery system was operating:
    (A) The date and start time of the deviation.
    (B) The duration of the deviation in hours.
    (C) A unique identifier for the CMS.
    (D) The make, model number, and date of last calibration check of 
the CMS.
    (E) The cause of the deviation and the corrective action taken. For 
TOC CEMS outages where the limited alternative for vapor recovery 
systems in Sec.  60.504a(e) of this chapter is used, the corrective 
action taken shall include an indication of the use of the limited 
alternative for vapor recovery systems in Sec.  60.504a(e) of this 
chapter.
    (F) For TOC CEMS outages where the limited alternative for vapor 
recovery systems in Sec.  60.504a(e) of this chapter is used, report 
either an indication that there were no deviations from the operating 
limits when using the limited alternative or report the number of each 
of the following types of deviations that occurred during the use of 
the limited alternative for vapor recovery systems in Sec.  60.504a(e) 
of this chapter.
    (1) The number of adsorption cycles when the quantity of liquid 
product loaded in gasoline cargo tanks exceeded the operating limit 
established in Sec.  60.504a(e)(1) of this chapter. Enter 0 if no 
deviations of this type.
    (2) The number of desorption cycles when the vacuum pressure was 
below the average vacuum pressure as specified in Sec.  
60.504a(e)(2)(i) of this chapter. Enter 0 if no deviations of this 
type.
    (3) The number of desorption cycles when the quantity of purge gas 
used was below the average quantity of purge gas as specified in Sec.  
60.504a(e)(2)(ii) of this chapter. Enter 0 if no deviations of this 
type.
    (4) The number of desorption cycles when the duration of the 
vacuum/purge cycle was less than the average duration as specified in 
Sec.  60.504a(e)(2)(iii) of this chapter. Enter 0 if no deviations of 
this type.
    (3) For each thermal oxidation system used to comply with the 
provision in Sec.  63.11092(e)(2)(ii) and each flare used to comply 
with the provision in item 2 of table 3 to this subpart, report:
    (i) The date and start and end times for each of the following 
instances:
    (A) Each 15-minute block during which there was at least one minute 
when gasoline vapors were routed to the flare and no pilot flame was 
present.
    (B) Each period of 2 consecutive hours during which visible 
emissions exceeded a total of 5 minutes. Additionally, report the 
number of minutes for which visible emissions were observed during the 
observation or an estimate of the cumulative number of minutes in the 
2-hour period for which emissions were visible based on best 
information available to the owner or operator.
    (C) Each 15-minute period for which the applicable operating limits 
specified in Sec.  63.670(d) through (f) were not met. You must 
identify the specific operating limit that was not met. Additionally, 
report the information in paragraphs (d)(3)(i)(C)(1) through (3) of 
this section, as applicable.
    (1) If you use the loading rate operating limits as determined in 
Sec.  60.502a(c)(3)(vii) of this chapter alone or in combination with 
the supplemental gas flow rate monitoring alternative in Sec.  
60.502a(c)(3)(viii) of this chapter, the required minimum ratio and the 
actual ratio of gasoline loaded to total product loaded for the rolling 
15-minute period and, if applicable, the required minimum quantity and 
the actual quantity of gasoline loaded, in gallons, for the rolling 15-
minute period.
    (2) If you use the supplemental gas flow rate monitoring 
alternative in Sec.  60.502a(c)(3)(viii) of this chapter, the required 
minimum supplemental gas flow rate and the actual supplemental gas flow 
rate including units of flow rates for the 15-minute block.
    (3) If you use parameter monitoring systems other than those 
specified in paragraphs (d)(3)(i)(C)(1) and (2) of this section, the 
value of the net heating value operating parameter(s) during the 
deviation determined following the methods in Sec.  63.670(k) through 
(n) as applicable.
    (ii) The start date, start time, and duration in minutes for each 
period when ``vapors displaced from gasoline cargo tanks during product 
loading'' were routed to the flare or thermal oxidation system and the 
applicable monitoring was not performed.
    (iii) For each instance reported under paragraphs (d)(3)(i) and 
(ii) of this section that involves CMS, report the following 
information:
    (A) A unique identifier for the CMS.
    (B) The make, model number, and date of last calibration check of 
the CMS.
    (C) The cause of the deviation or downtime and the corrective 
action taken.
    (4) For any instance in which liquid product was loaded into a 
gasoline cargo tank for which vapor tightness documentation required 
under Sec.  63.11094(b) was not provided or available in the terminal's 
records, report:
    (i) Cargo tank owner and address.
    (ii) Cargo tank identification number.
    (iii) Date and time liquid product was loaded into a gasoline cargo 
tank without proper documentation.
    (iv) Date proper documentation was received or statement that 
proper documentation was never received.
    (5) For each instance when liquid product was loaded into gasoline 
cargo tanks not using submerged filling, as defined in Sec.  63.11100, 
not equipped with vapor collection or balancing equipment that is 
compatible with the terminal's vapor collection system or plant's vapor 
balancing system, or not properly connected to the terminal's vapor 
collection system or plant's vapor balancing system, report:
    (i) Date and time of liquid product loading into gasoline cargo 
tank not using submerged filling, improperly equipped, or improperly 
connected.
    (ii) The type of deviation (e.g., not submerged filling, 
incompatible equipment, not properly connected).
    (iii) Cargo tank identification number.
    (6) For each instance when gasoline was loaded between gasoline 
cargo tanks and storage tanks and the plant's vapor balancing system 
was not properly connected between the gasoline cargo tank and storage 
tank, report:
    (i) Date and time of gasoline loading between a gasoline cargo tank 
and a

[[Page 39383]]

storage tank that was not properly connected.
    (ii) Cargo tank identification number and storage tank 
identification number.
    (7) Report the following information for each leak inspection and 
each leak identified under Sec.  63.11089(c) and Sec.  60.503a(a)(2) of 
this chapter.
    (i) For each leak detected during a leak inspection required under 
Sec.  63.11089(c) and Sec.  60.503a(a)(2) of this chapter, report:
    (A) The date of inspection.
    (B) The leak determination method (OGI or Method 21).
    (C) The total number and type of equipment for which leaks were 
detected.
    (D) The total number and type of equipment for which leaks were 
repaired within 15 calendar days.
    (E) The total number and type of equipment for which no repair 
attempt was made within 5 calendar days of the leaks being identified.
    (F) The total number and types of equipment placed on the delay of 
repair, as specified in Sec.  60.502a(j)(8) of this chapter.
    (ii) For leaks identified under Sec.  63.11089(c) by audio/visual/
olfactory methods during normal duties report:
    (A) The total number and type of equipment for which leaks were 
identified.
    (B) The total number and type of equipment for which leaks were 
repaired within 15 calendar days.
    (C) The total number and type of equipment for which no repair 
attempt was made within 5 calendar days of the leaks being identified.
    (D) The total number and type of equipment placed on the delay of 
repair, as specified in Sec.  60.502a(j)(8) of this chapter.
    (iii) The total number of leaks on the delay of repair list at the 
start of the reporting period.
    (iv) The total number of leaks on the delay of repair list at the 
end of the reporting period.
    (v) For each leak that was on the delay of repair list at any time 
during the reporting period, report:
    (A) Unique equipment identification number.
    (B) Type of equipment.
    (C) Leak determination method (OGI, Method 21, or audio/visual/
olfactory).
    (D) The reason(s) why the repair was not feasible within 15 
calendar days.
    (E) If applicable, the date repair was completed.
    (8) For each gasoline storage tank subject to requirements in item 
2 of table 1 to this subpart, report:
    (i) If you are complying with options 2(a), 2(b), or 2(d) in table 
1 to this subpart, the information specified in Sec.  60.115b(a) or (b) 
of this chapter or deviations in measured parameter values from the 
plan specified in Sec.  60.115b(c) of this chapter, depending upon the 
control equipment installed, or, if you are complying with option 2(e) 
in table 1 to this subpart, the information specified in Sec.  
63.1066(b).
    (ii) If you are complying with options 2(c) or 2(e) in table 1 to 
this subpart, for each deviation in LEL monitoring, report:
    (A) Date and start and end times of the LEL monitoring, and the 
tank being monitored.
    (B) Description of the monitoring event, e.g., monitoring conducted 
concurrent with visual inspection required under Sec.  60.113b(a)(2) of 
this chapter or Sec.  63.1063(d)(2); monitoring that occurred on a date 
other than the visual inspection required under Sec.  60.113b(a)(2) or 
Sec.  63.1063(d)(2) of this chapter; re-monitoring due to high winds; 
re-monitoring after repair attempt.
    (C) Wind speed in miles per hour at the top of the tank on the date 
of LEL monitoring.
    (D) The highest 5-minute rolling average reading during the 
monitoring event.
    (E) Whether the floating roof was repaired, replaced, or taken out 
of gasoline service. If the floating roof was repaired or replaced, 
also report the information in paragraphs (d)(8)(ii)(A) through (D) of 
this section for each re-monitoring conducted to confirm the repair.
    (9) If there were no deviations from the emission limitations, 
operating parameters, or work practice standards, then provide a 
statement that there were no deviations from the emission limitations, 
operating parameters, or work practice standards during the reporting 
period. If there were no periods during which a continuous monitoring 
system (including a CEMS or CPMS) was inoperable or out-of-control, 
then provide a statement that there were no periods during which a 
continuous monitoring system was inoperable or out-of-control during 
the reporting period.
    (e) Requirements for semiannual report submissions. Each owner or 
operator of an affected source under this subpart shall submit 
semiannual compliance reports with the information specified in 
paragraph (c) or (d) of this section to the Administrator according to 
the requirements in Sec.  63.13. Beginning on May 8, 2027, or once the 
report template for this subpart has been available on the CEDRI 
website (https://www.epa.gov/electronic-reporting-air-emissions/cedri) 
for one year, whichever date is later, you must submit all subsequent 
semiannual compliance reports using the appropriate electronic report 
template on the CEDRI website for this subpart and following the 
procedure specified in Sec.  63.9(k), except any medium submitted 
through mail must be sent to the attention of the Gasoline Distribution 
Sector Lead. The date report templates become available will be listed 
on the CEDRI website. Unless the Administrator or delegated State 
agency or other authority has approved a different schedule for 
submission of reports, the report must be submitted by the deadline 
specified in this subpart, regardless of the method in which the report 
is submitted.


0
28. Revise Sec.  63.11098 to read as follows:


Sec.  63.11098  What parts of the General Provisions apply to me?

    Table 4 to this subpart shows which parts of the General Provisions 
apply to you.


0
29. Section 63.11099 is amended by revising paragraphs (c) introductory 
text and (c)(5) to read as follows:


Sec.  63.11099  Who implements and enforces this subpart?

* * * * *
    (c) The authorities that cannot be delegated to State, local, or 
Tribal agencies are as specified in paragraphs (c)(1) through (5) of 
this section.
* * * * *
    (5) Approval of an alternative to any electronic reporting to the 
EPA required by this subpart.


0
30. Section 63.11100 is amended by:
0
a. Revising the introductory text and the definitions of ``Bulk 
gasoline terminal'', ``Flare'', ``Gasoline'', ``Operating parameter 
value'', ``Pipeline breakout station'', and ``Pipeline pumping 
station;'' and
0
b. Adding in alphabetical order a definition for ``Thermal oxidation 
system''.
    The revisions and addition read as follows:


Sec.  63.11100  What definitions apply to this subpart?

    As used in this subpart, all terms not defined herein shall have 
the meaning given them in the Clean Air Act (CAA), in subparts A, K, 
Ka, Kb, and XXa of part 60 of this chapter, or in subparts A, R, and WW 
of this part. All terms defined in both subpart A of part 60 of this 
chapter and subparts A, R, and WW of this part shall have the meaning 
given in subparts A, R, and WW of this part. For purposes of this 
subpart, definitions

[[Page 39384]]

in this section supersede definitions in other parts or subparts.
* * * * *
    Bulk gasoline terminal means:
    (1) Prior to May 8, 2027, any gasoline storage and distribution 
facility that receives gasoline by pipeline, ship or barge, or cargo 
tank and has a gasoline throughput of 20,000 gallons per day or 
greater. Gasoline throughput shall be the maximum calculated design 
throughput as may be limited by compliance with an enforceable 
condition under Federal, State, or local law and discoverable by the 
Administrator and any other person.
    (2) On or after May 8, 2027, any gasoline facility which receives 
gasoline by pipeline, ship, barge, or cargo tank and subsequently loads 
all or a portion of the gasoline into gasoline cargo tanks for 
transport to bulk gasoline plants or gasoline dispensing facilities and 
has a gasoline throughput of 20,000 gallons per day (75,700 liters per 
day) or greater. Gasoline throughput shall be the maximum calculated 
design throughput for the facility as may be limited by compliance with 
an enforceable condition under Federal, State, or local law and 
discoverable by the Administrator and any other person.
* * * * *
    Flare means a thermal combustion device using an open or shrouded 
flame (without full enclosure) such that the pollutants are not emitted 
through a conveyance suitable to conduct a performance test.
    Gasoline means any petroleum distillate or petroleum distillate/
alcohol blend having a Reid vapor pressure of 4.0 pounds per square 
inch (27.6 kilopascals) or greater, which is used as a fuel for 
internal combustion engines.
* * * * *
    Operating parameter value means a value for an operating or 
emission parameter of the vapor processing system (e.g., temperature) 
which, if maintained continuously by itself or in combination with one 
or more other operating parameter values, determines that an owner or 
operator has complied with the applicable emission standard. The 
operating parameter value is determined using the procedures specified 
in Sec.  63.11092(b) and (e).
    Pipeline breakout station means:
    (1) Prior to May 8, 2027, a facility along a pipeline containing 
storage vessels used to relieve surges or receive and store gasoline 
from the pipeline for reinjection and continued transportation by 
pipeline or to other facilities.
    (2) On or after May 8, 2027, a facility along a pipeline containing 
storage vessels used to relieve surges or receive and store gasoline 
from the pipeline for reinjection and continued transportation by 
pipeline to other facilities. Pipeline breakout stations do not have 
loading racks where gasoline is loaded into cargo tanks. 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.
    Pipeline pumping station means a facility along a pipeline 
containing pumps to maintain the desired pressure and flow of product 
through the pipeline, and not containing gasoline loading racks or 
gasoline storage tanks other than surge control tanks.
* * * * *
    Thermal oxidation system means an enclosed combustion device used 
to mix and ignite fuel, air pollutants, and air to provide a flame to 
heat and oxidize hazardous air pollutants. Auxiliary fuel may be used 
to heat air pollutants to combustion temperatures. Thermal oxidation 
systems emit pollutants through a conveyance suitable to conduct a 
performance test.
* * * * *

0
31. Table 1 to subpart BBBBBB of part 63 is revised to read as follows:

 Table 1 to Subpart BBBBBB of Part 63--Applicability Criteria, Emission
           Limits, and Management Practices for Storage Tanks
------------------------------------------------------------------------
  If you own or operate . . .              Then you must . . .
------------------------------------------------------------------------
1. A gasoline storage tank      (a) Equip each gasoline storage tank
 meeting either of the           with a fixed roof that is mounted to
 following conditions:.          the storage tank in a stationary
(i) a capacity of less than 75   manner, and maintain all openings in a
 cubic meters (m\3\); or.        closed position at all times when not
(ii) a capacity of less than     in use; and
 151 m\3\ and a gasoline        (b) No later than the dates specified in
 throughput of 480 gallons per   Sec.   63.11083, all pressure relief
 day or less. Gallons per day    devices on each gasoline storage tank
 is calculated by summing the    must be set to no less than 18 inches
 current day's throughput,       of water at all times to minimize
 plus the throughput for the     breathing losses.
 previous 364 days, and then
 dividing that sum by 365.

[[Page 39385]]

 
2. A gasoline storage tank      Do the following:
 with a capacity of greater     (a) Reduce emissions of total organic
 than or equal to 75 m\3\ and    HAP or TOC by 95 weight-percent with a
 not meeting any of the          closed vent system and control device,
 criteria specified in item 1    as specified in Sec.   60.112b(a)(3) of
 of this table.                  this chapter; or
                                (b) Equip each internal floating roof
                                 gasoline storage tank according to the
                                 requirements in Sec.   60.112b(a)(1) of
                                 this chapter, except for the secondary
                                 seal requirements under Sec.
                                 60.112b(a)(1)(ii)(B) and the
                                 requirements in Sec.
                                 60.112b(a)(1)(iv) through (ix) of this
                                 chapter; and
                                (c) No later than the dates specified in
                                 Sec.   63.11083, equip, maintain, and
                                 operate each internal floating roof
                                 control system to maintain the vapor
                                 concentration within the storage tank
                                 above the floating roof at or below 25
                                 percent of the LEL on a 5-minute
                                 rolling average basis without the use
                                 of purge gas, which may require
                                 additional controls beyond those
                                 specified in item 2(b) of this table;
                                 and
                                (d) Equip each external floating roof
                                 gasoline storage tank according to the
                                 requirements in Sec.   60.112b(a)(2) of
                                 this chapter, except that the
                                 requirements of Sec.
                                 60.112b(a)(2)(ii) of this chapter shall
                                 only be required if such storage tank
                                 does not currently meet the
                                 requirements of Sec.   60.112b(a)(2)(i)
                                 of this chapter; by the dates specified
                                 in Sec.   63.11083, all external
                                 floating roofs must meet the
                                 requirements of Sec.
                                 60.112b(a)(2)(ii) of this chapter; or
                                (e) Equip and operate each internal and
                                 external floating roof gasoline storage
                                 tank according to the applicable
                                 requirements in Sec.   63.1063(a)(1)
                                 and (b), except for the secondary seal
                                 requirements under Sec.
                                 63.1063(a)(1)(i)(C) and (D), and equip
                                 each external floating roof gasoline
                                 storage tank according to the
                                 requirements of Sec.   63.1063(a)(2) by
                                 the dates specified in Sec.
                                 63.11087(b) if such storage tank does
                                 not currently meet the requirements of
                                 Sec.   63.1063(a)(1); by the dates
                                 specified in Sec.   63.11083, all
                                 external floating roofs must meet the
                                 requirements of Sec.   63.1063(a)(2);
                                 and
                                (f) No later than the dates specified in
                                 Sec.   63.11083, equip, maintain, and
                                 operate each internal floating roof
                                 control system to maintain the vapor
                                 concentration within the storage tank
                                 above the floating roof at or below 25
                                 percent of the LEL on a 5-minute
                                 rolling average basis without the use
                                 of purge gas, which may require
                                 additional controls beyond those
                                 specified in item 2(e) of this table.
3. A surge control tank.......  Equip each tank with a fixed roof that
                                 is mounted to the tank in a stationary
                                 manner and with a pressure/vacuum vent
                                 with a positive cracking pressure of no
                                 less than 0.50 inches of water.
                                 Maintain all openings in a closed
                                 position at all times when not in use.
------------------------------------------------------------------------


0
32. Table 2 to subpart BBBBBB of part 63 is revised to read as follows:

 Table 2 to Subpart BBBBBB of Part 63--Applicability Criteria, Emission
           Limits, and Management Practices for Loading Racks
------------------------------------------------------------------------
  If you own or operate . . .              Then you must . . .
------------------------------------------------------------------------
1. A bulk gasoline terminal     (a) Equip your loading rack(s) with a
 loading rack(s) with a          vapor collection system designed and
 gasoline throughput (total of   operated to collect the TOC vapors
 all racks) of 250,000 gallons   displaced from cargo tanks during
 per day, or greater (``large    product loading; and
 bulk gasoline terminal'').     (b) Reduce emissions of TOC to less than
 Gallons per day is calculated   or equal to 80 mg/l of gasoline loaded
 by summing the current day's    into gasoline cargo tanks at the
 throughput, plus the            loading rack; and
 throughput for the previous    (c) No later than the dates specified in
 364 days, and then dividing     Sec.   63.11083, reduce emissions of
 that sum by 365.                TOC to the applicable limits in table 3
                                 to this subpart. The requirements in
                                 item 1(b) do not apply when
                                 demonstrating compliance with this
                                 item; and
                                (d) Design and operate the vapor
                                 collection system to prevent any TOC
                                 vapors collected at one loading rack or
                                 lane from passing through another
                                 loading rack or lane to the atmosphere;
                                 and
                                (e) Limit the loading of gasoline into
                                 gasoline cargo tanks that are vapor
                                 tight using the procedures specified in
                                 Sec.   60.502(e) through (j) of this
                                 chapter. For the purposes of this
                                 section, the term ``tank truck'' as
                                 used in Sec.   60.502(e) through (j)
                                 means ``gasoline cargo tank'' as
                                 defined in Sec.   63.11100; and
                                (f) No later than the dates specified in
                                 Sec.   63.11083, limit the loading of
                                 liquid product into gasoline cargo
                                 tanks using the procedures specified in
                                 Sec.   60.502a(e) through (i) of this
                                 chapter and in Sec.   63.11092(g) and
                                 (h). The requirements in item 1(e) do
                                 not apply when demonstrating compliance
                                 with this item.

[[Page 39386]]

 
2. A bulk gasoline terminal     (a) Use submerged filling with a
 loading rack(s) with a          submerged fill pipe that is no more
 gasoline throughput (total of   than 6 inches from the bottom of the
 all racks) of less than         cargo tank; and
 250,000 gallons per day.       (b) Make records available within 24
 Gallons per day is calculated   hours of a request by the Administrator
 by summing the current day's    to document your gasoline throughput.
 throughput, plus the           (c) No later than the dates specified in
 throughput for the previous     Sec.   63.11083, limit the loading of
 364 days, and then dividing     gasoline into gasoline cargo tanks that
 that sum by 365.                are vapor tight using the procedures
                                 specified in Sec.   60.502a(e) of this
                                 chapter and in Sec.   63.11092(g).
------------------------------------------------------------------------



0
33. Table 3 to subpart BBBBBB of part 63 is revised to read as follows:

     Table 3 to Subpart BBBBBB of Part 63--Emission Limitations and
 Requirements for Large Bulk Gasoline Terminals Based on Control System
                                  Used
------------------------------------------------------------------------
     If you operate . . .                  Then you must . . .
------------------------------------------------------------------------
1. A thermal oxidation system.  (a) Reduce emissions of TOC to less than
                                 or equal to 35 mg/l of liquid product
                                 loaded into gasoline cargo tanks at the
                                 loading rack; and
                                (b) Continuously meet the applicable
                                 operating limit as specified in Sec.
                                 63.11092(e)(2).
2. A flare....................  Operate the flare following the
                                 applicable requirements specified in
                                 Sec.   60.502a(c)(3) of this chapter.
3. A carbon adsorption system,  (a) Reduce emissions of TOC to less than
 refrigerated condenser, or      or equal to 19,200 parts per million by
 other vapor recovery system..   volume as propane determined on a 3-
                                 hour rolling average considering all
                                 periods when the vapor recovery system
                                 is capable of processing gasoline
                                 vapors, including periods when liquid
                                 product is being loaded, during carbon
                                 bed regeneration, and when preparing
                                 the beds for reuse.
                                (b) Operate 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.   63.4,
                                 the use of diluents to achieve
                                 compliance with a relevant standard
                                 based on the concentration of a
                                 pollutant in the effluent discharged to
                                 the atmosphere is prohibited.
------------------------------------------------------------------------


0
34. Table 4 to subpart BBBBBB of part 63 is added to read as follows:

                    Table 4 to Subpart BBBBBB of Part 63--Applicability of General Provisions
----------------------------------------------------------------------------------------------------------------
                                                                                              Applies to this
              Citation                       Subject              Brief description               subpart
----------------------------------------------------------------------------------------------------------------
Sec.   63.1........................  Applicability.........  Initial applicability        Yes, specific
                                                              determination;               requirements given in
                                                              applicability after          Sec.   63.11081.
                                                              standard established;
                                                              permit requirements;
                                                              extensions, notifications.
Sec.   63.1(c)(2)..................  Title V permit........  Requirements for obtaining   Yes, Sec.
                                                              a title V permit from the    63.11081(b) exempts
                                                              applicable permitting        identified area
                                                              authority.                   sources from the
                                                                                           obligation to obtain
                                                                                           title V operating
                                                                                           permits.
Sec.   63.2........................  Definitions...........  Definitions for standards    Yes, additional
                                                              in this part.                definitions in Sec.
                                                                                           63.11100.
Sec.   63.3........................  Units and               Units and abbreviations for  Yes.
                                      Abbreviations.          standards under this part.
Sec.   63.4........................  Prohibited Activities   Prohibited activities;       Yes.
                                      and Circumvention.      circumvention,
                                                              severability.
Sec.   63.5........................  Construction/           Applicability;               Yes.
                                      Reconstruction.         applications; approvals.
Sec.   63.6(a).....................  Compliance with         General Provisions apply     Yes.
                                      Standards/Operation &   unless compliance
                                      Maintenance             extension; General
                                      Applicability.          Provisions apply to area
                                                              sources that become major.
Sec.   63.6(b)(1) through (4)......  Compliance Dates for    Dates standards apply for    Yes.
                                      New and Reconstructed   new and reconstructed
                                      Sources.                sources.
Sec.   63.6(b)(5)..................  Notification..........  Must notify if commenced     Yes.
                                                              construction or
                                                              reconstruction after
                                                              proposal.
Sec.   63.6(b)(6)..................  [Reserved].

[[Page 39387]]

 
Sec.   63.6(b)(7)..................  Compliance Dates for    Area sources that become     No.
                                      New and Reconstructed   major must comply with
                                      Area Sources that       major source standards
                                      Become Major.           immediately upon becoming
                                                              major, regardless of
                                                              whether required to comply
                                                              when they were an area
                                                              source.
Sec.   63.6(c)(1) and (2)..........  Compliance Dates for    Comply according to date in  No, Sec.   63.11083
                                      Existing Sources.       this subpart.                specifies the
                                                                                           compliance dates.
Sec.   63.6(c)(3) and (4)..........  [Reserved].
Sec.   63.6(c)(5)..................  Compliance Dates for    Area sources that become     No.
                                      Existing Area Sources   major must comply with
                                      that Become Major.      major source standards by
                                                              date indicated in this
                                                              subpart or by equivalent
                                                              time period (e.g., 3
                                                              years).
Sec.   63.6(d).....................  [Reserved].
Sec.   63.6(e)(1)(i)...............  General duty to         Operate to minimize          No. See Sec.
                                      minimize emissions.     emissions at all times;      63.11085 for general
                                                              information Administrator    duty requirement.
                                                              will use to determine if
                                                              operation and maintenance
                                                              requirements were met.
Sec.   63.6(e)(1)(ii)..............  Requirement to correct  Owner or operator must       No.
                                      malfunctions as soon    correct malfunctions as
                                      as possible.            soon as possible.
Sec.   63.6(e)(2)..................  [Reserved].
Sec.   63.6(e)(3)..................  Startup, Shutdown, and  Requirement for SSM plan;    No.
                                      Malfunction (SSM)       content of SSM plan;
                                      plan.                   actions during SSM.
Sec.   63.6(f)(1)..................  Compliance Except       You must comply with         No.
                                      During SSM.             emission standards at all
                                                              times except during SSM.
Sec.   63.6(f)(2) and (3)..........  Methods for             Compliance based on          Yes.
                                      Determining             performance test,
                                      Compliance.             operation and maintenance
                                                              plans, records, inspection.
Sec.   63.6(g)(1) through (3)......  Alternative Standard..  Procedures for getting an    Yes.
                                                              alternative standard.
Sec.   63.6(h)(1)..................  Compliance with         You must comply with         No.
                                      Opacity/VE Standards.   opacity/VE standards at
                                                              all times except during
                                                              SSM.
Sec.   63.6(h)(2)(i)...............  Determining Compliance  If standard does not state   No.
                                      with Opacity/VE         test method, use EPA
                                      Standards.              Method 9 for opacity in
                                                              appendix A to part 60 of
                                                              this chapter and EPA
                                                              Method 22 for VE in
                                                              appendix A to part 60 of
                                                              this chapter.
Sec.   63.6(h)(2)(ii)..............  [Reserved].
Sec.   63.6(h)(2)(iii).............  Using Previous Tests    Criteria for when previous   No.
                                      to Demonstrate          opacity/VE testing can be
                                      Compliance with         used to show compliance
                                      Opacity/VE Standards.   with this subpart.
Sec.   63.6(h)(3)..................  [Reserved].
Sec.   63.6(h)(4)..................  Notification of         Must notify Administrator    No.
                                      Opacity/VE              of anticipated date of
                                      Observation Date.       observation.
Sec.   63.6(h)(5)(i) and (iii)       Conducting Opacity/VE   Dates and schedule for       No.
 through (v).                         Observations.           conducting opacity/VE
                                                              observations.
Sec.   63.6(h)(5)(ii)..............  Opacity Test Duration   Must have at least 3 hours   No.
                                      and Averaging Times.    of observation with 30 6-
                                                              minute averages.
Sec.   63.6(h)(6)..................  Records of Conditions   Must keep records available  No.
                                      During Opacity/VE       and allow Administrator to
                                      Observations.           inspect.
Sec.   63.6(h)(7)(i)...............  Report Continuous       Must submit COMS data with   No.
                                      Opacity Monitoring      other performance test
                                      System (COMS)           data.
                                      Monitoring Data from
                                      Performance Test.
Sec.   63.6(h)(7)(ii)..............  Using COMS Instead of   Can submit COMS data         No.
                                      EPA Method 9.           instead of EPA Method 9
                                                              results even if this
                                                              subpart requires EPA
                                                              Method 9 in appendix A of
                                                              part 60 of this chapter,
                                                              but must notify
                                                              Administrator before
                                                              performance test.
Sec.   63.6(h)(7)(iii).............  Averaging Time for      To determine compliance,     No.
                                      COMS During             must reduce COMS data to 6-
                                      Performance Test.       minute averages.
Sec.   63.6(h)(7)(iv)..............  COMS Requirements.....  Owner/operator must          No.
                                                              demonstrate that COMS
                                                              performance evaluations
                                                              are conducted according to
                                                              Sec.   63.8(e); COMS are
                                                              properly maintained and
                                                              operated according to Sec.
                                                                63.8(c) and data quality
                                                              as Sec.   63.8(d).
Sec.   63.6(h)(7)(v)...............  Determining Compliance  COMS is probable but not     No.
                                      with Opacity/VE         conclusive evidence of
                                      Standards.              compliance with opacity
                                                              standard, even if EPA
                                                              Method 9 (in appendix A to
                                                              part 60 of this chapter)
                                                              observation shows
                                                              otherwise. Requirements
                                                              for COMS to be probable
                                                              evidence-proper
                                                              maintenance, meeting
                                                              Performance Specification
                                                              1 in appendix B to part 60
                                                              of this chapter, and data
                                                              have not been altered.

[[Page 39388]]

 
Sec.   63.6(h)(8)..................  Determining Compliance  Administrator will use all   No.
                                      with Opacity/VE         COMS, EPA Method 9 (in
                                      Standards.              appendix A to part 60 of
                                                              this chapter), and EPA
                                                              Method 22 (in appendix A
                                                              to part 60 of this
                                                              chapter) results, as well
                                                              as information about
                                                              operation and maintenance
                                                              to determine compliance.
Sec.   63.6(h)(9)..................  Adjusted Opacity        Procedures for               No.
                                      Standard.               Administrator to adjust an
                                                              opacity standard.
Sec.   63.6(i)(1) through (14).....  Compliance Extension..  Procedures and criteria for  Yes.
                                                              Administrator to grant
                                                              compliance extension.
Sec.   63.6(j).....................  Presidential            President may exempt any     Yes.
                                      Compliance Exemption.   source from requirement to
                                                              comply with this subpart.
Sec.   63.7(a)(2)..................  Performance Test Dates  Dates for conducting         Yes.
                                                              initial performance
                                                              testing; must conduct 180
                                                              days after compliance date.
Sec.   63.7(a)(3)..................  Section 114 Authority.  Administrator may require a  Yes.
                                                              performance test under CAA
                                                              section 114 at any time.
Sec.   63.7(a)(4)..................  Force Majeure.........  Provisions for delayed       Yes.
                                                              performance tests due to
                                                              force majeure.
Sec.   63.7(b)(1)..................  Notification of         Must notify Administrator    Yes.
                                      Performance Test.       60 days before the test.
Sec.   63.7(b)(2)..................  Notification of Re-     If have to reschedule        Yes.
                                      scheduling.             performance test, must
                                                              notify Administrator of
                                                              rescheduled date as soon
                                                              as practicable and without
                                                              delay.
Sec.   63.7(c).....................  Quality Assurance (QA)/ Requirement to submit site-  Yes.
                                      Test Plan.              specific test plan 60 days
                                                              before the test or on date
                                                              Administrator agrees with;
                                                              test plan approval
                                                              procedures; performance
                                                              audit requirements;
                                                              internal and external QA
                                                              procedures for testing.
Sec.   63.7(d).....................  Testing Facilities....  Requirements for testing     Yes.
                                                              facilities.
Sec.   63.7(e)(1)..................  Conditions for          Performance test must be     No, Sec.   63.11092(i)
                                      Conducting              conducted under              specifies conditions
                                      Performance Tests.      representative conditions.   for conducting
                                                                                           performance tests.
Sec.   63.7(e)(2)..................  Conditions for          Must conduct according to    Yes.
                                      Conducting              this subpart and EPA test
                                      Performance Tests.      methods unless
                                                              Administrator approves
                                                              alternative.
Sec.   63.7(e)(3)..................  Test Run Duration.....  Must have three test runs    Yes, except for
                                                              of at least 1 hour each;     testing conducted
                                                              compliance is based on       under Sec.
                                                              arithmetic mean of three     63.11092(a) and (e).
                                                              runs; conditions when data
                                                              from an additional test
                                                              run can be used.
Sec.   63.7(f).....................  Alternative Test        Procedures by which          Yes.
                                      Method.                 Administrator can grant
                                                              approval to use an
                                                              intermediate or major
                                                              change, or alternative to
                                                              a test method.
Sec.   63.7(g).....................  Performance Test Data   Must include raw data in     Yes, except this
                                      Analysis.               performance test report;     subpart specifies how
                                                              must submit performance      and when the
                                                              test data 60 days after      performance test and
                                                              end of test with the         performance
                                                              notification of compliance   evaluation results
                                                              status; keep data for 5      are reported.
                                                              years.
Sec.   63.7(h).....................  Waiver of Tests.......  Procedures for               Yes.
                                                              Administrator to waive
                                                              performance test.
Sec.   63.8(a)(1)..................  Applicability of        Subject to all monitoring    Yes.
                                      Monitoring              requirements in standard.
                                      Requirements.
Sec.   63.8(a)(2)..................  Performance             Performance specifications   Yes.
                                      Specifications.         in appendix B to part 60
                                                              of this chapter apply.
Sec.   63.8(a)(3)..................  [Reserved].
Sec.   63.8(a)(4)..................  Monitoring of Flares..  Monitoring requirements for  Yes.
                                                              flares in Sec.   63.11
                                                              apply.
Sec.   63.8(b)(1)..................  Monitoring............  Must conduct monitoring      Yes.
                                                              according to standard
                                                              unless Administrator
                                                              approves alternative.
Sec.   63.8(b)(2) and (3)..........  Multiple Effluents and  Specific requirements for    Yes.
                                      Multiple Monitoring     installing monitoring
                                      Systems.                systems; must install on
                                                              each affected source or
                                                              after combined with
                                                              another affected source
                                                              before it is released to
                                                              the atmosphere provided
                                                              the monitoring is
                                                              sufficient to demonstrate
                                                              compliance with the
                                                              standard; if more than one
                                                              monitoring system on an
                                                              emission point, must
                                                              report all monitoring
                                                              system results, unless one
                                                              monitoring system is a
                                                              backup.
Sec.   63.8(c)(1) introductory text  Monitoring System       Maintain monitoring system   Yes.
                                      Operation and           in a manner consistent
                                      Maintenance.            with good air pollution
                                                              control practices.
Sec.   63.8(c)(1)(i)...............  Operation and           Must maintain and operate    No.
                                      Maintenance of CMS.     each CMS as specified in
                                                              Sec.   63.6(e)(1).
Sec.   63.8(c)(1)(ii)..............  Operation and           Must keep parts for routine  Yes.
                                      Maintenance of CMS.     repairs readily available.
Sec.   63.8(c)(1)(iii).............  Operation and           Requirement to develop SSM   No.
                                      Maintenance of CMS.     Plan for CMS.

[[Page 39389]]

 
Sec.   63.8(c)(2) through (8)......  CMS Requirements......  Must install to get          Yes.
                                                              representative emission or
                                                              parameter measurements;
                                                              must verify operational
                                                              status before or at
                                                              performance test.
Sec.   63.8(d)(1) and (2)..........  CMS Quality Control...  Requirements for CMS         Yes.
                                                              quality control, including
                                                              calibration, etc..
Sec.   63.8(d)(3)..................  CMS Quality Control     Must keep quality control    No. This subpart
                                      Records.                plan on record for 5         specifies CMS records
                                                              years; keep old versions     requirements.
                                                              for 5 years after
                                                              revisions.
Sec.   63.8(e).....................  CMS Performance         Notification, performance    Yes, except this
                                      Evaluation.             evaluation test plan,        subpart specifies how
                                                              reports.                     and when the
                                                                                           performance
                                                                                           evaluation results
                                                                                           are reported.
Sec.   63.8(f)(1) through (5)......  Alternative Monitoring  Procedures for               Yes.
                                      Method.                 Administrator to approve
                                                              alternative monitoring.
Sec.   63.8(f)(6)..................  Alternative to          Procedures for               Yes.
                                      Relative Accuracy       Administrator to approve
                                      Test.                   alternative relative
                                                              accuracy tests for CEMS.
Sec.   63.8(g).....................  Data Reduction........  COMS 6-minute averages       Yes.
                                                              calculated over at least
                                                              36 evenly spaced data
                                                              points; CEMS 1 hour
                                                              averages computed over at
                                                              least 4 equally spaced
                                                              data points; data that
                                                              cannot be used in average.
Sec.   63.9(a).....................  Notification            Applicability and State      Yes.
                                      Requirements.           delegation.
Sec.   63.9(b)(1), (2), (4), and     Initial Notifications.  Submit notification of       Yes.
 (5).                                                         being subject to standard;
                                                              notification of intent to
                                                              construct/reconstruct,
                                                              notification of
                                                              commencement of
                                                              construction/
                                                              reconstruction,
                                                              notification of startup;
                                                              contents of each.
Sec.   63.9(b)(3)..................  [Reserved].
Sec.   63.9(c).....................  Request for Compliance  Can request if cannot        Yes.
                                      Extension.              comply by date or if
                                                              installed best available
                                                              control technology or
                                                              lowest achievable emission
                                                              rate.
Sec.   63.9(d).....................  Notification of         Notification for new         Yes.
                                      Special Compliance      sources subject to special
                                      Requirements for New    compliance requirements.
                                      Sources.
Sec.   63.9(e).....................  Notification of         Notify Administrator 60      Yes.
                                      Performance Test.       days prior.
Sec.   63.9(f).....................  Notification of VE/     Notify Administrator 30      No.
                                      Opacity Test.           days prior.
Sec.   63.9(g).....................  Additional              Notification of performance  Yes, however, there
                                      Notifications When      evaluation; notification     are no opacity
                                      Using CMS.              about use of COMS data;      standards.
                                                              notification that exceeded
                                                              criterion for relative
                                                              accuracy alternative.
Sec.   63.9(h)(1) through (3), (5),  Notification of         Contents due 60 days after   Yes, except as
 and (6).                             Compliance Status.      end of performance test or   specified in Sec.
                                                              other compliance             63.11095(c).
                                                              demonstration, except for
                                                              opacity/VE, which are due
                                                              30 days after; when to
                                                              submit to Federal vs.
                                                              State authority.
Sec.   63.9(h)(4)..................  [Reserved].
Sec.   63.9(i).....................  Adjustment of           Procedures for               Yes.
                                      Submittal Deadlines.    Administrator to approve
                                                              change when notifications
                                                              must be submitted.
Sec.   63.9(j).....................  Change in Previous      Must submit within 15 days   Yes.
                                      Information.            after the change.
Sec.   63.9(k).....................  Notifications.........  Electronic reporting         Yes.
                                                              procedures.
Sec.   63.10(a)....................  Recordkeeping/          Applies to all, unless       Yes.
                                      Reporting.              compliance extension; when
                                                              to submit to Federal vs.
                                                              State authority;
                                                              procedures for owners of
                                                              more than one source.
Sec.   63.10(b)(1).................  Recordkeeping/          General requirements; keep   Yes.
                                      Reporting.              all records readily
                                                              available; keep for 5
                                                              years.
Sec.   63.10(b)(2)(i)..............  Records related to SSM  Recordkeeping of occurrence  No.
                                                              and duration of startups
                                                              and shutdowns.
Sec.   63.10(b)(2)(ii).............  Records related to SSM  Recordkeeping of             No. See Sec.
                                                              malfunctions.                63.11094(k) for
                                                                                           recordkeeping
                                                                                           requirements for
                                                                                           deviations.
Sec.   63.10(b)(2)(iii)............  Maintenance records...  Recordkeeping of             Yes.
                                                              maintenance on air
                                                              pollution control and
                                                              monitoring equipment.
Sec.   63.10(b)(2)(iv).............  Records Related to SSM  Actions taken to minimize    No.
                                                              emissions during SSM.
Sec.   63.10(b)(2)(v)..............  Records Related to SSM  Actions taken to minimize    No.
                                                              emissions during SSM.
Sec.   63.10(b)(2)(vi) through (xi)  CMS Records...........  Malfunctions, inoperative,   Yes.
                                                              out-of-control periods.
Sec.   63.10(b)(2)(xii)............  Records...............  Records when under waiver..  Yes.
Sec.   63.10(b)(2)(xiii)...........  Records...............  Records when using           Yes.
                                                              alternative to relative
                                                              accuracy test.
Sec.   63.10(b)(2)(xiv)............  Records...............  All documentation            Yes.
                                                              supporting initial
                                                              notification and
                                                              notification of compliance
                                                              status.
Sec.   63.10(b)(3).................  Records...............  Applicability                Yes.
                                                              determinations.
Sec.   63.10(c)....................  Records...............  Additional records for CMS.  No. This subpart
                                                                                           specifies CMS
                                                                                           records.

[[Page 39390]]

 
Sec.   63.10(d)(1).................  General Reporting       Requirement to report......  Yes.
                                      Requirements.
Sec.   63.10(d)(2).................  Report of Performance   When to submit to Federal    No. This subpart
                                      Test Results.           or State authority.          specifies how and
                                                                                           when the performance
                                                                                           test results are
                                                                                           reported.
Sec.   63.10(d)(3).................  Reporting Opacity or    What to report and when....  No.
                                      VE Observations.
Sec.   63.10(d)(4).................  Progress Reports......  Must submit progress         Yes.
                                                              reports on schedule if
                                                              under compliance extension.
Sec.   63.10(d)(5).................  SSM Reports...........  Contents and submission....  No.
Sec.   63.10(e)(1) and (2).........  Additional CMS Reports  Must report results for      No.
                                                              each CEMS on a unit;
                                                              written copy of CMS
                                                              performance evaluation; 2-
                                                              3 copies of COMS
                                                              performance evaluation.
Sec.   63.10(e)(3)(i) through (iii)  Reports...............  Schedule for reporting       No.
                                                              excess emissions.
Sec.   63.10(e)(3)(iv) and (v).....  Excess Emissions        Requirement to revert to     No.
                                      Reports.                quarterly submission if
                                                              there is an excess
                                                              emissions and parameter
                                                              monitor exceedances (now
                                                              defined as deviations);
                                                              provision to request
                                                              semiannual reporting after
                                                              compliance for 1 year;
                                                              submit report by 30th day
                                                              following end of quarter
                                                              or calendar half; if there
                                                              has not been an exceedance
                                                              or excess emissions (now
                                                              defined as deviations),
                                                              report contents in a
                                                              statement that there have
                                                              been no deviations; must
                                                              submit report containing
                                                              all of the information in
                                                              Sec.  Sec.   63.8(c)(7)
                                                              and (8) and 63.10(c)(5)
                                                              through (13).
Sec.   63.10(e)(3)(vi) through       Excess Emissions        Requirements for reporting   No.
 (viii).                              Report and Summary      excess emissions for CMS;
                                      Report.                 requires all of the
                                                              information in Sec.  Sec.
                                                               63.8(c)(7) and (8) and
                                                              63.10(c)(5) through (13).
Sec.   63.10(e)(4).................  Reporting COMS Data...  Must submit COMS data with   No. This subpart
                                                              performance test data.       specifies COMS
                                                                                           reporting.
Sec.   63.10(f)....................  Waiver for              Procedures for               Yes.
                                      Recordkeeping/          Administrator to waive.
                                      Reporting.
Sec.   63.11(a)....................  Applicability.........  Specifies applicability of   Yes.
                                                              control device and work
                                                              practice requirements
                                                              within Sec.   63.11.
Sec.   63.11(b)....................  Flares................  Requirements for flares....  Yes, except these
                                                                                           provisions no longer
                                                                                           apply for flares used
                                                                                           to comply with the
                                                                                           flare provisions in
                                                                                           item 2 of table 3 to
                                                                                           this subpart.
Sec.   63.11(c) through (e)........  Alternative Work        Requirements for using       Yes, except these
                                      Practice for            optical gas imaging for      provisions do not
                                      Monitoring Equipment    EPA Method 21 monitoring.    apply to monitoring
                                      for Leaks.                                           required under Sec.
                                                                                           63.11092(a)(1)(i) or
                                                                                           (e)(1) and these
                                                                                           provisions no longer
                                                                                           apply upon compliance
                                                                                           with the provisions
                                                                                           in Sec.
                                                                                           63.11089(c).
Sec.   63.12.......................  Delegation............  State authority to enforce   Yes.
                                                              standards.
Sec.   63.13.......................  Addresses.............  Addresses where reports,     Yes.
                                                              notifications, and
                                                              requests are sent.
Sec.   63.14.......................  Incorporations by       Test methods incorporated    Yes.
                                      Reference.              by reference.
Sec.   63.15.......................  Availability of         Public and confidential      Yes.
                                      Information.            information.
Sec.   63.16.......................  Performance Track       Special reporting provision  Yes.
                                      Provisions.             for Performance Track
                                                              member facilities..
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[FR Doc. 2024-04629 Filed 5-7-24; 8:45 am]
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