35608 Federal Register / Vol. 87, No. 112 / Friday, June 10, 2022 / Proposed Rules 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 60 and 63 

[EPA–HQ–OAR–2020–0371; FRL–8202–01– 

OAR] 

RIN 2060–AU97 

National Emission Standards for 

Hazardous Air Pollutants: Gasoline 

Distribution Technology Review and 

Standards of Performance for Bulk 

Gasoline Terminals Review 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Proposed rule. 

SUMMARY: The U.S. Environmental 

Protection Agency (EPA) is proposing 

amendments to the National Emissions 

Standards for Hazardous Air Pollutants 

(NESHAP) for Gasoline Distribution 

facilities and the Standards of 

Performance for Bulk Gasoline 

Terminals. The EPA is proposing to 

revise NESHAP requirements for storage 

tanks, loading operations, and 

equipment leaks to reflect cost-effective 

developments in practices, process, or 

controls. The EPA is also proposing 

New Source Performance Standards to 

reflect best system of emissions 

reduction for loading operations and 

equipment leaks. In addition, the EPA is 

proposing revisions related to emissions 

during periods of startup, shutdown, 

and malfunction; to add requirements 

for electronic reporting of performance 

test results, performance evaluation 

reports, and compliance reports; to 

revise monitoring and operating 

requirements for control devices; and to 

make other minor technical 

improvements. We estimate that these 

proposed amendments would reduce 

emissions of hazardous air pollutants 

from this source category by 2,220 tons 

per year (tpy) and would reduce 

emissions of volatile organic 

compounds by 45,400 tpy. 

DATES: Comments must be received on 

or before August 9, 2022. Under the 

Paperwork Reduction Act (PRA), 

comments on the information collection 

provisions are best assured of 

consideration if the Office of 

Management and Budget (OMB) 

receives a copy of your comments on or 

before August 9, 2022. 

Public hearing: If anyone contacts us 

requesting a public hearing on or before 

June 15, 2022, we will hold a virtual 

public hearing. See SUPPLEMENTARY

INFORMATION for information on 

requesting and registering for a public 

hearing. 

ADDRESSES: You may send comments, 

identified by Docket ID No. EPA–HQ– 

OAR–2020–0371, by any of the 

following methods: 

• Federal eRulemaking Portal: 

https://www.regulations.gov/ (our 

preferred method). Follow the online 

instructions for submitting comments. 

• Email: a-and-r-docket@epa.gov. 

Include Docket ID No. EPA–HQ–OAR– 

2020–0371 in the subject line of the 

message. 

• Fax: (202) 566–9744. Attention 

Docket ID No. EPA–HQ–OAR–2020– 

0371. 

• Mail: U.S. Environmental 

Protection Agency, EPA Docket Center, 

Docket ID No. EPA–HQ–OAR–2020– 

0371, Mail Code 28221T, 1200 

Pennsylvania Avenue NW, Washington, 

DC 20460. 

• Hand/Courier Delivery: EPA Docket 

Center, WJC West Building, Room 3334, 

1301 Constitution Avenue NW, 

Washington, DC 20004. The Docket 

Center’s hours of operation are 8:30 

a.m.–4:30 p.m., Monday–Friday (except 

federal holidays). 

Instructions: All submissions received 

must include the Docket ID No. for this 

rulemaking. Comments received may be 

posted without change to https://

www.regulations.gov/, including any 

personal information provided. For 

detailed instructions on sending 

comments and additional information 

on the rulemaking process, see the 

SUPPLEMENTARY INFORMATION section of 

this document. 

FOR FURTHER INFORMATION CONTACT: For 

questions about this proposed action, 

contact Mr. Neil Feinberg, Sector 

Policies and Programs Division (E143– 

01), Office of Air Quality Planning and 

Standards, U.S. Environmental 

Protection Agency, Research Triangle 

Park, North Carolina 27711; telephone 

number: (919) 541–2214; fax number: 

(919) 541–0516; and email address: 

feinberg.stephen@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Participation in virtual public 

hearing. Please note that because of 

current Centers for Disease Control and 

Prevention (CDC) recommendations, as 

well as state and local orders for social 

distancing to limit the spread of 

COVID–19, the EPA cannot hold inperson public meetings at this time. 

To request a virtual public hearing, 

contact the public hearing team at (888) 

372–8699 or by email at 

SPPDpublichearing@epa.gov. If 

requested, the virtual hearing will be 

held on June 27, 2022. The hearing will 

convene at 11:00 a.m. Eastern Time (ET) 

and will conclude at 7:00 p.m. ET. The 

EPA may close a session 15 minutes 

after the last pre-registered speaker has 

testified if there are no additional 

speakers. The EPA will announce 

further details at https://www.epa.gov/ 

stationary-sources-air-pollution/ 

gasoline-distribution-mact-and-gactnational-emission-standards. 

If a public hearing is requested, the 

EPA will begin pre-registering speakers 

for the hearing no later than 1 business 

day after a request has been received. To 

register to speak at the virtual hearing, 

please use the online registration form 

available at https://www.epa.gov/ 

stationary-sources-air-pollution/ 

gasoline-distribution-mact-and-gactnational-emission-standards or contact 

the public hearing team at (888) 372– 

8699 or by email at 

SPPDpublichearing@epa.gov. The last 

day to pre-register to speak at the 

hearing will be June 22, 2022. Prior to 

the hearing, the EPA will post a general 

agenda that will list pre-registered 

speakers in approximate order at: 

https://www.epa.gov/stationary-sourcesair-pollution/gasoline-distribution-mactand-gact-national-emission-standards. 

The EPA will make every effort to 

follow the schedule as closely as 

possible on the day of the hearing; 

however, please plan for the hearings to 

run either ahead of schedule or behind 

schedule. 

Each commenter will have 5 minutes 

to provide oral testimony. The EPA 

encourages commenters to provide the 

EPA with a copy of their oral testimony 

electronically (via email) by emailing it 

to feinberg.stephen@epa.gov. The EPA 

also recommends submitting the text of 

your oral testimony as written 

comments to the rulemaking docket. 

The EPA may ask clarifying questions 

during the oral presentations but will 

not respond to the presentations at that 

time. Written statements and supporting 

information submitted during the 

comment period will be considered 

with the same weight as oral testimony 

and supporting information presented at 

the public hearing. 

Please note that any updates made to 

any aspect of the hearing will be posted 

online at https://www.epa.gov/ 

stationary-sources-air-pollution/ 

gasoline-distribution-mact-and-gactnational-emission-standards. While the 

EPA expects the hearing to go forward 

as set forth above, please monitor our 

website or contact the public hearing 

team at (888) 372–8699 or by email at 

SPPDpublichearing@epa.gov to 

determine if there are any updates. The 

EPA does not intend to publish a 

document in the Federal Register 

announcing updates. 

If you require the services of a 

translator or a special accommodation 


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such as audio description, please preregister for the hearing with the public 

hearing team and describe your needs 

by June 17, 2022. The EPA may not be 

able to arrange accommodations without 

advanced notice. 

Docket. The EPA has established a 

docket for this rulemaking under Docket 

ID No. EPA–HQ–OAR–2020–0371. All 

documents in the docket are listed in 

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

listed, some information is not publicly 

available, e.g., Confidential Business 

Information (CBI) or other information 

whose disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the internet and will be publicly 

available only in hard copy. With the 

exception of such material, publicly 

available docket materials are available 

electronically in Regulations.gov or in 

hard copy at the EPA Docket Center, 

Room 3334, WJC West Building, 1301 

Constitution Avenue NW, Washington, 

DC. The Public Reading Room is open 

from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal 

holidays. The telephone number for the 

Public Reading Room is (202) 566–1744, 

and the telephone number for the EPA 

Docket Center is (202) 566–1742. 

Instructions. Direct your comments to 

Docket ID No. EPA–HQ–OAR–2020– 

0371. The EPA’s policy is that all 

comments received will be included in 

the public docket without change and 

may be made available online at https:// 

www.regulations.gov/, including any 

personal information provided, unless 

the comment includes information 

claimed to be CBI or other information 

whose disclosure is restricted by statute. 

Do not submit electronically to https:// 

www.regulations.gov any information 

that you consider to be CBI or other 

information whose disclosure is 

restricted by statute. This type of 

information should be submitted as 

discussed below. 

The EPA may publish any comment 

received to its public docket. 

Multimedia submissions (audio, video, 

etc.) must be accompanied by a written 

comment. The written comment is 

considered the official comment and 

should include discussion of all points 

you wish to make. The EPA will 

generally not consider comments or 

comment contents located outside of the 

primary submission (i.e., on the Web, 

cloud, or other file sharing system). For 

additional submission methods, the full 

EPA public comment policy, 

information about CBI or multimedia 

submissions, and general guidance on 

making effective comments, please visit 

https://www.epa.gov/dockets/ 

commenting-epa-dockets. 

The https://www.regulations.gov/ 

website allows you to submit your 

comment anonymously, which means 

the EPA will not know your identity or 

contact information unless you provide 

it in the body of your comment. If you 

send an email comment directly to the 

EPA without going through https://

www.regulations.gov/, your email 

address will be automatically captured 

and included as part of the comment 

that is placed in the public docket and 

made available on the internet. If you 

submit an electronic comment, the EPA 

recommends that you include your 

name and other contact information in 

the body of your comment and with any 

digital storage media you submit. If the 

EPA cannot read your comment due to 

technical difficulties and cannot contact 

you for clarification, the EPA may not 

be able to consider your comment. 

Electronic files should not include 

special characters or any form of 

encryption and be free of any defects or 

viruses. For additional information 

about the EPA’s public docket, visit the 

EPA Docket Center homepage at https:// 

www.epa.gov/dockets. 

Submitting CBI. Do not submit 

information containing CBI to the EPA 

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

Clearly mark the part or all of the 

information that you claim to be CBI. 

For CBI information on any digital 

storage media that you mail to the EPA, 

note the docket ID, mark the outside of 

the digital storage media as CBI and 

identify electronically within the digital 

storage media the specific information 

that is claimed as CBI. In addition to 

one complete version of the comments 

that includes information claimed as 

CBI, you must submit a copy of the 

comments that does not contain the 

information claimed as CBI directly to 

the public docket through the 

procedures outlined in Instructions 

section of this document. If you submit 

any digital storage media that does not 

contain CBI, mark the outside of the 

digital storage media clearly that it does 

not contain CBI and note the docket ID. 

Information not marked as CBI will be 

included in the public docket and the 

EPA’s electronic public docket without 

prior notice. Information marked as CBI 

will not be disclosed except in 

accordance with procedures set forth in 

40 Code of Federal Regulations (CFR) 

part 2. 

Our preferred method to receive CBI 

is for it to be transmitted electronically 

using email attachments, File Transfer 

Protocol (FTP), or other online file 

sharing services (e.g., Dropbox, 

OneDrive, Google Drive). Electronic 

submissions must be transmitted 

directly to the Office of Air Quality 

Planning and Standards (OAQPS) CBI 

Office at the email address oaqpscbi@

epa.gov, and as described above, should 

include clear CBI markings and note the 

docket ID. If assistance is needed with 

submitting large electronic files that 

exceed the file size limit for email 

attachments, and if you do not have 

your own file sharing service, please 

email oaqpscbi@epa.gov to request a file 

transfer link. If sending CBI information 

through the postal service, please send 

it to the following address: OAQPS 

Document Control Officer (C404–02), 

OAQPS, U.S. Environmental Protection 

Agency, Research Triangle Park, North 

Carolina 27711, Attention Docket ID No. 

EPA–HQ–OAR–2020–0371. The mailed 

CBI material should be double wrapped 

and clearly marked. Any CBI markings 

should not show through the outer 

envelope. Preamble acronyms and 

abbreviations. Throughout this notice 

the use of ‘‘we,’’ ‘‘us,’’ or ‘‘our’’ is 

intended to refer to the EPA. We use 

multiple acronyms and terms in this 

preamble. While this list may not be 

exhaustive, to ease the reading of this 

preamble and for reference purposes, 

the EPA defines the following terms and 

acronyms here: 

AVO audio, visual, or olfactory 

BSER best system of emissions reduction 

CAA Clean Air Act 

CBI Confidential Business Information 

CEMS continuous emission monitoring 

system 

CFR Code of Federal Regulations 

CO carbon monoxide 

CO2 carbon dioxide 

DOT U.S. Department of Transportation 

EJ environmental justice 

EPA Environmental Protection Agency 

ERT Electronic Reporting Tool 

GACT generally available control 

technology 

HAP hazardous air pollutant(s) 

ICR information collection request 

km kilometer 

LDAR leak detection and repair 

LEL lower explosive limit 

mg/L milligrams per liter 

MACT maximum achievable control 

technology 

NAICS North American Industry 

Classification System 

NESHAP national emission standards for 

hazardous air pollutants 

NO2 nitrogen oxides 

NSPS new source performance standards 

OAQPS Office of Air Quality Planning and 

Standards 

OGI optical gas imaging 

OMB Office of Management and Budget 

ppm parts per million 

ppmv parts per million by volume 

PRA Paperwork Reduction Act 

RFA Regulatory Flexibility Act 

RIA Regulatory Impact Analysis 

SO2 sulfur dioxide 

SSM startup, shutdown, and malfunction 

TOC total organic carbon 


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tpy tons per year 

U.S.C. United States Code 

VCU vapor combustion unit 

VOC volatile organic compound(s) 

VRU vapor recovery unit 

Organization of this document. The 

information in this preamble is 

organized as follows: 

I. General Information 

A. Executive Summary 

B. Does this action apply to me? 

C. Where can I get a copy of this document 

and other related information? 

II. Background 

A. What is the statutory authority for this 

action? 

B. What are the source categories and how 

do the current standards regulate 

emissions? 

C. What data collection activities were 

conducted to support this action? 

D. What other relevant background 

information and data are available? 

E. How does the EPA perform the NESHAP 

technology review and NSPS review? 

III. Proposed Rule Summary and Rationale 

A. What are the results and proposed 

decisions based on our technology 

reviews and NSPS review, and what is 

the rationale for those decisions? 

B. What other actions are we proposing, 

and what is the rationale for those 

actions? 

C. What compliance dates are we 

proposing, and what is the rationale for 

the proposed compliance dates? 

IV. Summary of Cost, Environmental, and 

Economic Impacts 

A. What are the affected sources? 

B. What are the air quality impacts? 

C. What are the cost impacts? 

D. What are the economic impacts? 

E. What are the benefits? 

F. What analysis of environmental justice 

did we conduct? 

V. Request for Comments 

VI. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act (PRA) 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions 

Concerning Regulations That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

J. Executive Order 12898: Federal Actions 

to Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

I. General Information 

A. Executive Summary 

1. Purpose of the Regulatory Action 

The source categories that are the 

subject of this proposal are Gasoline 

Distribution regulated under 40 CFR 

part 63, subparts R and BBBBBB and 

Petroleum Transportation and 

Marketing regulated under 40 CFR part 

60, subpart XX. The EPA set maximum 

achievable control technology (MACT) 

standards for the Gasoline Distribution 

major source category in 1994 and 

conducted the residual risk and 

technology review in 2006. The sources 

affected by the major source National 

Emissions Standards for Hazardous Air 

Pollutants (NESHAP) for the Gasoline 

Distribution source category (part 63, 

subpart R) are bulk gasoline terminals 

and pipeline breakout stations. The EPA 

set generally available control 

technology (GACT) standards for the 

Gasoline Distribution area source 

category in 2008. The sources affected 

by the area source NESHAP for the 

Gasoline Distribution source category 

(part 63, subpart BBBBBB) are bulk 

gasoline terminals, bulk gasoline plants, 

and pipeline facilities. The EPA set New 

Source Performance Standards (NSPS) 

for the Petroleum Transportation and 

Marketing source category in 1983. The 

sources affected by the current NSPS 

(part 60, subpart XX) are bulk gasoline 

terminals that commenced construction 

or modification after December 17, 

1980. 

The statutory authority for these 

proposed rulemakings is sections 111 

and 112 of the Clean Air Act (CAA). 

Section 111(b)(1)(B) of the CAA requires 

the EPA to ‘‘at least every 8 years review 

and, if appropriate, revise’’ NSPS. 

Section 111(a)(1) of the CAA provides 

that performance standards are to 

‘‘reflect the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction which (taking into 

account the cost of achieving such 

reduction and any nonair quality health 

and environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated.’’ We refer to this level of 

control as the best system of emission 

reduction or ‘‘BSER.’’ Section 112(d)(6) 

of the CAA requires the EPA to review 

standards promulgated under CAA 

section 112 and revise them ‘‘as 

necessary (taking into account 

developments in practices, processes, 

and control technologies)’’ no less often 

than every 8 years following 

promulgation of those standards. This is 

referred to as a ‘‘technology review’’ and 

is required for all standards established 

under CAA section 112(d). 

The proposed Standards of 

Performance for Bulk Gasoline 

Terminals and the proposed 

amendments to the NESHAP for 

Gasoline Distribution facilities fulfill the 

Agency’s requirement, respectively, to 

review and, if appropriate, revise the 

NSPS and to review and revise as 

necessary the NESHAP at least every 8 

years. 

2. Summary of the Major Provisions of 

the Regulatory Action In Question 

a. NESHAP Subpart R 

We are proposing to require a 

graduated vapor tightness certification 

from 0.5 to 1.25 inches of water pressure 

drop over a 5-minute period, depending 

on the cargo tank compartment size for 

gasoline cargo tanks. We are also 

proposing to require fitting controls for 

external floating roof tanks consistent 

with the requirement in NSPS subpart 

Kb. In addition, we are proposing to 

require semiannual instrument 

monitoring for major source gasoline 

distribution facilities. 

b. NESHAP Subpart BBBBBB 

We are proposing to lower the area 

source emission limits for loading racks 

at large bulk gasoline terminals to 35 

milligrams of total organic carbon (TOC) 

per liter of gasoline loaded (mg/L) and 

require vapor balancing for loading 

storage vessels and gasoline cargo tanks 

at bulk gasoline plants with maximum 

design capacity throughput of 4,000 

gallons per day or more. We are also 

proposing to require a graduated vapor 

tightness certification from 0.5 to 1.25 

inches of water pressure drop over a 5- 

minute period, depending on the cargo 

tank compartment size for gasoline 

cargo tanks. Additionally, we are 

proposing to require fitting controls for 

external floating roof tanks consistent 

with the requirement in NSPS subpart 

Kb. Also, we are proposing to require 

annual instrument monitoring for area 

source gasoline distribution facilities. 

c. NSPS Subpart XXa 

We are proposing in a new NSPS 

subpart XXa that facilities that 

commence construction after June 10, 

2022) must meet a 1 mg/L limit and 

facilities that commence modification, 

or reconstruction after June 10, 2022 

must meet a 10 mg/L limit. We are also 

proposing to require a graduated vapor 

tightness certification from 0.5 to 1.25 

inches of water pressure drop over a 5- 

minute period, depending on the cargo 

tank compartment size for gasoline 

cargo tanks. Also, we are proposing to 


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require quarterly instrument 

monitoring. 

3. Costs and Benefits 

To satisfy requirements of E.O. 12866, 

the EPA projected the emissions 

reductions, costs, and benefits that may 

result from these proposed rulemakings. 

These results are presented in detail in 

the regulatory impact analysis (RIA) 

accompanying this proposal developed 

in response to E.O. 12866. We present 

these results for each of the three rules 

included in this proposed action, and 

also cumulatively. This action is 

economically significant according to 

E.O. 12866 primarily due to the 

proposed amendments to NESHAP 

subpart BBBBBB. The RIA focuses on 

the elements of the proposed 

rulemaking that are likely to result in 

quantifiable cost or emissions changes 

compared to a baseline without the 

proposal that incorporates changes to 

regulatory requirements. We estimated 

the cost, emissions, and benefit impacts 

for the 2026 to 2040 period. We show 

the present value (PV) and equivalent 

annual value (EAV) of costs, benefits, 

and net benefits of this action in 2019 

dollars. 

The initial analysis year in the RIA is 

2026 as we assume the large majority of 

impacts associated with the proposed 

rulemakings will be finalized in that 

year. The NSPS will take effect 

immediately upon the effective date of 

the final rule and impact sources 

constructed after publication of the 

proposed rule, but these impacts are 

much lower than those of the other two 

rulemakings in this action. The other 

two rules, both under the provisions of 

section 112 of the Clean Air Act, will 

take effect three years after their 

effective date, which will occur in 2026 

given promulgation of this rulemaking 

in 2023. Therefore, their impacts will 

begin in 2026. The final analysis year is 

2040, which allows us to provide 15 

years of projected impacts after all of 

these rules are assumed to take effect. 

The cost analysis presented in the RIA 

reflects a nationwide engineering 

analysis of compliance cost and 

emissions reductions, of which there are 

two main components. The first 

component is a set of representative or 

model plants for each regulated facility, 

segment, and control option. The 

characteristics of the model plant 

include typical equipment, operating 

characteristics, and representative 

factors including baseline emissions and 

the costs, emissions reductions, and 

product recovery resulting from each 

control option. The second component 

is a set of projections of data for affected 

facilities, distinguished by vintage, year, 

and other necessary attributes (e.g., 

precise content of material in storage 

tanks). Impacts are calculated by setting 

parameters on how and when affected 

facilities are assumed to respond to a 

particular regulatory regime, 

multiplying data by model plant cost 

and emissions estimates, differencing 

from the baseline scenario, and then 

summing to the desired level of 

aggregation. In addition to emissions 

reductions, some control options result 

in gasoline recovery, which can then be 

sold where possible. Where applicable, 

we present projected compliance costs 

with and without the projected revenues 

from product recovery. 

The EPA expects health benefits due 

to the emissions reductions projected 

under these proposed rulemakings. We 

expect that hazardous air pollutants 

(HAP) emission reductions will improve 

health and welfare associated with 

exposure by those affected by these 

emissions. In addition, the EPA expects 

that volatile organic compounds (VOC) 

emission reductions that will occur 

concurrent with the reductions of HAP 

emissions will improve air quality and 

are likely to improve health and welfare 

associated with exposure to ozone, 

particulate matter 2.5 (PM2.5), and HAP. 

The EPA also expects disbenefits from 

secondary increases of carbon dioxide 

(CO2), nitrogen oxides (NO2), sulfur 

dioxide (SO2), and carbon monoxide 

(CO) emissions associated with the 

control options included in the cost 

analysis. Discussion of the nonmonetized benefits and climate 

disbenefits can be found in Chapter 4 of 

the RIA. 

Tables 1 through 3 of this document 

presents the emission changes, and PV 

and EAV of the projected monetized 

benefits, compliance costs, and net 

benefits over the 2026 to 2040 period 

under the proposed rulemaking for each 

subpart. Table 4 of this document 

presents the same results for the 

cumulative impact of these rulemakings. 

All discounting of impacts presented 

uses discount rates of 3 and 7 percent. 

TABLE 1—SHORT-TERM AND LONG-TERM MONETIZED BENEFITS, COSTS, NET BENEFITS, AND EMISSIONS REDUCTIONS OF

THE PROPOSED NESHAP SUBPART BBBBBB AMENDMENTS, 2026 THROUGH 2040 

[Dollar estimates in millions of 2019 dollars] a

3 Percent discount rate 7 Percent discount rate 

PV EAV PV EAV 

Benefits b ....................................................................... $180(ST) and $1,500(LT) $15(ST) and $130(LT) .... $110(ST) and $900(LT) .. $12(ST) and $99(LT). 

Climate Disbenefits (3%) c ............................................ $28 .................................. $2.3 ................................. $28 .................................. $2.0. 

Net Compliance Costs d ................................................ ¥$70 .............................. ¥$5.0 ............................. ¥$42 .............................. ¥$5.0. 

Compliance Costs ................................................. $140 ................................ $12 .................................. $98 .................................. $11. 

Value of Product Recovery ................................... $210 ................................ $17 .................................. $140 ................................ $16. 

Net Benefits .................................................................. $230(ST) and $1,500(LT) $18(ST) and $130(LT) .... $130(ST) and $910(LT) .. $15(ST) and $100(LT). 

Emissions Reductions (short tons) ............................... 2026–2040 Total. 

VOC ....................................................................... 605,000. 

HAP ....................................................................... 31,000. 

Secondary Emissions Increases (short tons) ............... 2026–2040 Total. 

CO2 ........................................................................ 490,000. 

NO2 ........................................................................ 290. 

SO2 ........................................................................ 3.5. 

CO ......................................................................... 1,300. 

Non-monetized Impacts in this Table ........................... HAP benefits from reducing 31,000 short tons of HAP from 2026–2040, VOC benefits from reductions outside of the ozone season (October–April). 

Health and climate disbenefits from increasing nitrogen oxides (NO2) emissions by 290 short tons, sulfur dioxide (SO2) by 3.5 short tons, and carbon monoxide (CO) by 1,300 short tons from 2026–2040. 

Visibility benefits. 

Reduced vegetation effects. 

aValues rounded to two significant figures. Totals may not appear to add correctly due to rounding. Short tons are standard English tons (2,000 pounds). 


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b Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent for both short-(ST) and long-term (LT) benefits. The two benefits estimates are separated by the 

word ‘‘and’’ to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound estimates. Benefits from HAP reductions and 

VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table. Disbenefits from additional CO2 emissions resulting from application of control options are monetized and included in the table as climate disbenefits. Climate disbenefits are monetized at a real discount rate of 3 percent. The 

unmonetized effects also include disbenefits resulting from the secondary impact of an increase in NO2, SO2, and CO emissions. Please see Section 4.6 of the RIA 

for more discussion of the climate disbenefits. c Climate disbenefits are based on changes (increases) in CO2 emissions and are calculated using four different estimates of the social cost of carbon (SC–CO2) 

(model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). For the presentational purposes of this table, we 

show the disbenefits associated with the average SC–CO2 at a 3 percent discount rate, but the Agency does not have a single central SC–CO2 point estimate. We 

emphasize the importance and value of considering the disbenefits calculated using all four SC–CO2 estimates; the additional disbenefit estimates range from PV 

(EAV) $5.4 million ($0.5 million) to $84 million ($7.0 million) from 2026–2040 for the proposed amendments. Please see Table 4–7 in the RIA for the full range of SC– 

CO2 estimates. As discussed in Chapter 4 of the RIA, a consideration of climate disbenefits calculated using discount rates below 3 percent, including 2 percent and 

lower, is also warranted when discounting intergenerational impacts. d Net compliance costs are the rulemaking costs minus the value of recovered product. A negative net compliance costs occurs when the value of the recovered 

product exceeds the compliance costs. 

TABLE 2—SHORT-TERM AND LONG-TERM MONETIZED BENEFITS, COMPLIANCE COSTS, NET BENEFITS, AND EMISSIONS

REDUCTIONS OF THE PROPOSED NESHAP SUBPART R AMENDMENTS, 2026 THROUGH 2040 

[Dollar estimates in millions of 2019 dollars] a

3 Percent discount rate 7 Percent discount rate 

PV EAV PV EAV 

Benefits b ....................................................................... $9.9(ST) and $81(LT) ..... $0.83(ST) and $6.8(LT) .. $5.6(ST) and $48(LT) ..... $0.65(ST) and $5.3(LT). 

Net Compliance Costs c ................................................ $23 .................................. $2.0 ................................. $15 .................................. $1.8. 

Compliance Costs ................................................. $34 .................................. $2.9 ................................. $23 .................................. $2.6. 

Value of Product Recovery ................................... $11 .................................. $1.0 ................................. $8 .................................... $0.90. 

Net Benefits .................................................................. ¥$13(ST) and $58(LT) .. ¥$1.2(ST) and $4.8(LT) ¥$9.4(ST) and $33(LT) ¥$1.2(ST) and $3.5(LT). 

Emissions Reductions (short tons) ............................... 2026–2040 Total. 

VOC ....................................................................... 32,000. 

HAP ....................................................................... 2,010. 

Non-monetized Impacts in this Table ........................... HAP benefits from reducing 2,010 short tons of HAP from 2026–2040, VOC benefits from reductions outside 

of the ozone season (October–April). 

Visibility benefits. 

Reduced vegetation effects. 

aValues rounded to two significant figures. Totals may not appear to add correctly due to rounding. Short tons are standard English tons (2,000 pounds). 

b Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent for both short-(ST) and long-term (LT) benefits. The two benefits estimates are separated by the 

word ‘‘and’’ to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound estimates and should not be summed. Benefits 

from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table. c Net compliance costs are the rulemaking costs minus the value of recovered product. A negative net compliance costs occurs when the value of the recovered 

product exceeds the compliance costs. 

TABLE 3—SHORT-TERM AND LONG-TERM MONETIZED BENEFITS, COSTS, NET BENEFITS, AND EMISSIONS REDUCTIONS OF

PROPOSED NSPS SUBPART XXa, 2026 THROUGH 2040 

[Dollar estimates in millions of 2019 dollars] a

3 Percent discount rate 7 Percent discount rate 

PV EAV PV EAV 

Benefits b ....................................................................... $29(ST) and $240(LT) .... $2.4(ST) and $20(LT) ..... $16(ST) and $130(LT) .... $1.7(ST) and $15(LT). 

Climate Disbenefits (3%) c ............................................ $4.4 ................................. $0.37 ............................... $4.4 ................................. $0.37. 

Net Compliance Costs d ................................................ $9.0 ................................. $0.70 ............................... $5.0 ................................. $0.60. 

Compliance Costs ................................................. $41 .................................. $3.4 ................................. $26 .................................. $2.9. 

Value of Product Recovery ................................... $32 .................................. $2.7 ................................. $21 .................................. $2.3. 

Net Benefits .................................................................. $16(ST) and $230(LT) .... $1.3(ST) and $19(LT) ..... $6.6(ST) and $130(LT) ... $0.73(ST) and $14(LT). 

Emissions Reductions (short tons) ............................... 2026–2040 Total. 

VOC ....................................................................... 97,000. 

HAP ....................................................................... 4,020. 

Secondary Emissions Increases (short tons) ............... 2026–2040 Total. 

CO2 ........................................................................ 74,000. 

NO2 ........................................................................ 50. 

SO2 ........................................................................ 42. 

CO ......................................................................... 0. 

Non-monetized Impacts in this Table ........................... HAP benefits from reducing 4,020 short tons of HAP from 2026–2040, VOC benefits from reductions outside 

of the ozone season (October–April). 

Health and climate disbenefits from increasing NO2 emissions by 50 short tons, and SO2 by 42 short tons 

from 2026–2040. 

Visibility benefits. 

Reduced vegetation effects. 

aValues rounded to two significant figures. Totals may not appear to add correctly due to rounding. Short tons are standard English tons (2,000 pounds). 

b Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent for both short-(ST) and long-term (LT) benefits. The two benefits estimates are separated by the 

word ‘‘and’’ to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound estimates. Benefits from HAP reductions and 

VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table. Climate disbenefits are estimated at a real discount rate of 3 

percent. The unmonetized effects also include disbenefits resulting from the secondary impact of an increase in NO2, SO2 and CO emissions. Please see Section 4.6 

of the RIA for more discussion of the climate disbenefits. 


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c Climate disbenefits are based on changes (increases) in CO2 emissions and are calculated using four different estimates of the social cost of carbon (SC–CO2) 

(model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). For the presentational purposes of this table, we 

show the disbenefits associated with the average SC–CO2 at a 3 percent discount rate, but the Agency does not have a single central SC–CO2 point estimate. We 

emphasize the importance and value of considering the disbenefits calculated using all four SC–CO2 estimates; the additional disbenefit estimates range from PV 

(EAV) $0.78 million ($0.08 million) to $13 million ($1.1 million) from 2026–2040 for the proposed amendments. Please see Table 4–7 for the full range of SC–CO2 estimates. As discussed in Chapter 4 of the RIA, a consideration of climate disbenefits calculated using discount rates below 3 percent, including 2 percent and lower, is 

also warranted when discounting intergenerational impacts. d Net compliance costs are the rulemaking costs minus the value of recovered product. A negative net compliance costs occurs when the value of the recovered 

product exceeds the compliance costs. 

TABLE 4—SHORT-TERM AND LONG-TERM CUMULATIVE MONETIZED BENEFITS, COSTS, NET BENEFITS, AND EMISSIONS

REDUCTIONS OF THE PROPOSED RULEMAKINGS, 2026 THROUGH 2040 

[Dollar estimates in millions of 2019 dollars] a

3 Percent discount rate 7 Percent discount rate 

PV EAV PV EAV 

Benefits b ....................................................................... $220(ST) and $1,800(LT) $19(ST) and $150(LT) .... $130(ST) and $1,100(LT) $15(ST) and $120(LT). 

Climate Disbenefits (3%) c ............................................ $32 .................................. $2.7 ................................. $32 .................................. $2.7. 

Net Compliance Costs d ................................................ ¥$38 .............................. ¥$2.4 ............................. ¥$22 .............................. ¥$2.7. 

Compliance Costs ................................................. $220 ................................ $18 .................................. $150 ................................ $17. 

Value of Product Recovery ................................... $250 ................................ $20 .................................. $170 ................................ $19. 

Net Benefits .................................................................. $230(ST) and $1,800(LT) $19(ST) and $150(LT) .... $120(ST) and $1,090(LT) $15(ST) and $120(LT). 

Emissions Reductions (short tons) ............................... 2026–2040 Total. 

VOC ....................................................................... 730,000. 

HAP ....................................................................... 37,000. 

Secondary Emissions Increases (short tons) ............... 2026–2040 Total. 

CO2 ........................................................................ 560,000. 

NO2 ........................................................................ 340. 

SO2 ........................................................................ 46. 

CO ......................................................................... 1,300. 

Non-monetized Impacts in this Table ........................... HAP benefits from reducing 37,000 short tons of HAP from 2026–2040, VOC benefits from reductions outside of the ozone season (October–April). 

Health and climate disbenefits from increasing NO2 emissions by 340 short tons, SO2 by 42 short tons, and 

CO by 1,300 short tons from 2026–2040. 

Visibility benefits. 

Reduced vegetation effects. 

aValues rounded to two significant figures. Totals may not appear to add correctly due to rounding. Short tons are standard English tons (2,000 pounds). 

b Monetized benefits include ozone related health benefits associated with reductions in VOC emissions. The health benefits are associated with several point estimates and are presented at real discount rates of 3 and 7 percent for both short-(ST) and long-term (LT) benefits. The two benefits estimates are separated by the 

word ‘‘and’’ to signify that they are two separate estimates. The estimates do not represent lower- and upper-bound estimates and should not be summed. Benefits 

from HAP reductions and VOC reductions outside of the ozone season remain unmonetized and are thus not reflected in the table. Climate disbenefits are estimated 

at a real discount rate of 3 percent. The unmonetized effects also include disbenefits resulting from the secondary impact of an increase in NO2, SO2 and CO emissions. Please see Section 4.6 of the RIA for more discussion of the climate disbenefits. c Climate disbenefits are based on changes (increases) in CO2 emissions and are calculated using four different estimates of the social cost of carbon (SC–CO2) 

(model average at 2.5 percent, 3 percent, and 5 percent discount rates; 95th percentile at 3 percent discount rate). For the presentational purposes of this table, we 

show the disbenefits associated with the average SC–CO2 at a 3 percent discount rate, but the Agency does not have a single central SC–CO2 point estimate. We 

emphasize the importance and value of considering the disbenefits calculated using all four SC–CO2 estimates; the additional disbenefit estimates range from PV 

(EAV) $6.2 million ($0.6 million) to $97 million ($8.1 million) from 2026–2040 for the proposed amendments. Please see Table 4–7 of the RIA for the full range of 

SC–CO2 estimates. As discussed in Chapter 4 of the RIA, a consideration of climate disbenefits calculated using discount rates below 3 percent, including 2 percent 

and lower, is also warranted when discounting intergenerational impacts. d Net compliance costs are the rulemaking costs minus the value of recovered product. A negative net compliance costs occurs when the value of the recovered 

product exceeds the compliance costs. 

B. Does this action apply to me? 

The source categories that are the 

subject of this proposal are Gasoline 

Distribution regulated under 40 CFR 

part 63, subparts R and BBBBBB and 

Petroleum Transportation and 

Marketing regulated under 40 CFR part 

60, subpart XX. The North American 

Industry Classification System (NAICS) 

codes for the Gasoline Distribution 

industry are 324110, 493190, 486910, 

and 424710. This list of NAICS codes is 

not intended to be exhaustive, but rather 

provides a guide for readers regarding 

the entities that this proposed action is 

likely to affect. The proposed standards, 

once promulgated, will be directly 

applicable to the affected sources. 

Federal, state, local, and tribal 

government entities would not be 

affected by this proposed action. 

As defined in the Initial List of 

Categories of Sources Under Section 

112(c)(1) of the Clean Air Act 

Amendments of 1990 (see 57 FR 31576, 

July 16, 1992) and Documentation for 

Developing the Initial Source Category 

List, Final Report (see EPA–450/3–91– 

030, July 1992), the Gasoline 

Distribution (Stage 1) source category is 

any facility engaged in ‘‘the storage and 

transfer facilities associated with the 

movement of gasoline. This category 

includes, but is not limited to, the 

gasoline vapor emissions associated 

with the loading of transport trucks or 

rail cars, storage tank emissions, and 

equipment leaks from leaking pumps, 

valves, and connections at bulk 

terminals, bulk plants, and pipeline 

facilities.’’ Subsequently, on July 19, 

1999, we added this category to the list 

of area source categories for regulation 

under a Federal Register publication for 

the Integrated Urban Air Toxics Strategy 

(64 FR 38706). The Gasoline 

Distribution (Stage 1) source category 

also includes storage tank filling 

operations that occur at public and 

private gasoline dispensing facilities 

(e.g., service stations and convenience 

stores). Gasoline dispensing facilities 

are regulated under 40 CFR part 63, 

subpart CCCCCC. The EPA did not 

review the standards for gasoline 

dispensing facilities. 

The EPA Priority List (40 CFR 60.16, 

44 FR 49222, August 21, 1979) included 

Petroleum Transportation and 

Marketing as a source category for 

which standards of performance were to 

be promulgated under CAA section 111. 

The New Source Performance Standards 

for this source category applies to the 

total of all the loading racks at a bulk 

gasoline terminal that deliver liquid 

product into gasoline tank trucks. A 

bulk gasoline terminal is defined as any 

gasoline facility which receives gasoline 


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1For categories of area sources subject to GACT 

standards, CAA sections 112(d)(5) and (f)(5) provide 

that the CAA section 112(f)(2) residual risk review 

is not required. However, the CAA section 112(d)(6) 

technology review is required for such categories. 

by pipeline, ship or barge, and has a 

gasoline throughput greater than 75,700 

liters per day. 

C. Where can I get a copy of this 

document and other related 

information? 

In addition to being available in the 

docket, an electronic copy of this action 

is available on the internet. Following 

signature by the EPA Administrator, the 

EPA will post a copy of this proposed 

action at https://www.epa.gov/gasolinedistribution-mact-and-gact-nationalemission-standards. Following 

publication in the Federal Register, the 

EPA will post the Federal Register 

version of the proposal and key 

technical documents at this same 

website. 

A redline strikeout version of each 

standard showing the edits that would 

be necessary to incorporate the changes 

to 40 CFR part 60, subparts XX and XXa 

and Part 63, subparts R and BBBBBB 

proposed in this action is available in 

the docket (Docket ID No. EPA–HQ– 

OAR–2020–0371). Following signature 

by the EPA Administrator, the EPA will 

also post a copy of these documents to 

https://www.epa.gov/stationary-sourcesair-pollution/gasoline-distribution-mactand-gact-national-emission-standards. 

II. Background 

A. What is the statutory authority for 

this action? 

1. National Emissions Standards for 

Hazardous Air Pollutants (NESHAP) 

The statutory authority for this action 

is provided by sections 112 and 301 of 

the CAA, as amended (42 U.S.C. 7401 et 

seq.). Section 112 of the CAA 

establishes a two-stage regulatory 

process to develop standards for 

emissions of hazardous air pollutants 

(HAP) from stationary sources. 

Generally, the first stage involves 

establishing technology-based standards 

and the second stage involves 

evaluating those standards that are 

based on MACT to determine whether 

additional standards are needed to 

address any remaining risk associated 

with HAP emissions. This second stage 

is commonly referred to as the ‘‘residual 

risk review.’’ In addition to the residual 

risk review, the CAA also requires the 

EPA to review standards set under CAA 

section 112 every 8 years and revise the 

standards as necessary taking into 

account any ‘‘developments in 

practices, processes, or control 

technologies.’’ This review is commonly 

referred to as the ‘‘technology review,’’ 

and is the subject of this proposal. The 

discussion that follows identifies the 

most relevant statutory sections and 

briefly explains the contours of the 

methodology used to implement these 

statutory requirements. 

In the first stage of the CAA section 

112 standard setting process, the EPA 

promulgates technology-based standards 

under CAA section 112(d) for categories 

of sources identified as emitting one or 

more of the HAP listed in CAA section 

112(b). Sources of HAP emissions are 

either major sources or area sources, and 

CAA section 112 establishes different 

requirements for major source standards 

and area source standards. ‘‘Major 

sources’’ are those that emit or have the 

potential to emit 10 tons per year (tpy) 

or more of a single HAP or 25 tpy or 

more of any combination of HAP. All 

other sources are ‘‘area sources.’’ For 

major sources, CAA section 112(d)(2) 

provides that the technology-based 

NESHAP must reflect the maximum 

degree of emission reductions of HAP 

achievable (after considering cost, 

energy requirements, and nonair quality 

health and environmental impacts). 

These standards are commonly referred 

to as MACT standards. CAA section 

112(d)(3) also establishes a minimum 

control level for MACT standards, 

known as the MACT ‘‘floor.’’ In certain 

instances, as provided in CAA section 

112(h), the EPA may set work practice 

standards in lieu of numerical emission 

standards. The EPA must also consider 

control options that are more stringent 

than the floor. Standards more stringent 

than the floor are commonly referred to 

as beyond-the-floor standards. For 

categories of major sources and any area 

source categories subject to MACT 

standards, the second stage in standardsetting focuses on identifying and 

addressing any remaining (i.e., 

‘‘residual’’) risk pursuant to CAA 

section 112(f) and concurrently 

conducting a technology review 

pursuant to CAA section 112(d)(6). The 

EPA set MACT standards for the 

Gasoline Distribution major source 

category in 1994 and conducted the 

residual risk and technology review in 

2006. 

CAA section 112(d)(6) requires the 

EPA to review standards promulgated 

under CAA section 112 and revise them 

‘‘as necessary (taking into account 

developments in practices, processes, 

and control technologies)’’ no less often 

than every 8 years following 

promulgation of those standards. This is 

referred to as a ‘‘technology review’’ and 

is required for all standards established 

under CAA section 112(d) including 

GACT standards that apply to area 

sources.1 In conducting this review, the 

EPA is not required to recalculate the 

MACT floors that were established in 

earlier rulemakings. Natural Resources 

Defense Council (NRDC) v. EPA, 529 

F.3d 1077, 1084 (D.C. Cir. 2008). 

Association of Battery Recyclers, Inc. v. 

EPA, 716 F.3d 667 (D.C. Cir. 2013). The 

EPA may consider cost in deciding 

whether to revise the standards 

pursuant to CAA section 112(d)(6). The 

EPA is required to address regulatory 

gaps, such as missing MACT standards 

for listed air toxics known to be emitted 

from major source categories, and any 

new MACT standards must be 

established under CAA sections 

112(d)(2) and (3), or, in specific 

circumstances, CAA sections 112(d)(4) 

or (h). Louisiana Environmental Action 

Network (LEAN) v. EPA, 955 F.3d 1088 

(D.C. Cir. 2020). This action constitutes 

the 112(d)(6) technology review for the 

Gasoline Distribution major source and 

area source NESHAP. 

Several additional CAA sections are 

relevant to this action as they 

specifically address regulation of 

hazardous air pollutant emissions from 

area sources. Collectively, CAA sections 

112(c)(3), (d)(5), and (k)(3) are the basis 

of the Area Source Program under the 

Urban Air Toxics Strategy, which 

provides the framework for regulation of 

area sources under CAA section 112. 

Section 112(k)(3)(B) of the CAA 

requires the EPA to identify at least 30 

HAP that pose the greatest potential 

health threat in urban areas with a 

primary goal of achieving a 75-percent 

reduction in cancer incidence 

attributable to HAP emitted from 

stationary sources. As discussed in the 

Integrated Urban Air Toxics Strategy (64 

FR 38706, 38715, July 19, 1999), the 

EPA identified 30 HAP emitted from 

area sources that pose the greatest 

potential health threat in urban areas, 

and these HAP are commonly referred 

to as the ‘‘30 urban HAP.’’ 

Section 112(c)(3), in turn, requires the 

EPA to list sufficient categories or 

subcategories of area sources to ensure 

that area sources representing 90 

percent of the emissions of the 30 urban 

HAP are subject to regulation. The EPA 

implemented these requirements 

through the Integrated Urban Air Toxics 

Strategy by identifying and setting 

standards for categories of area sources 

including the Gasoline Distribution 

source category that is addressed in this 

action. 

CAA section 112(d)(5) provides that 

for area source categories, in lieu of 

setting MACT standards (which are 


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

per day. 

generally required for major source 

categories), the EPA may elect to 

promulgate standards or requirements 

for area sources ‘‘which provide for the 

use of generally available control 

technology or management practices 

[GACT] by such sources to reduce 

emissions of hazardous air pollutants.’’ 

In developing such standards, the EPA 

evaluates the control technologies and 

management practices that reduce HAP 

emissions that are generally available 

for each area source category. Consistent 

with the legislative history, we can 

consider costs and economic impacts in 

determining what constitutes GACT. 

GACT standards were set for the 

Gasoline Distribution area source 

category in 2008. As noted above, this 

proposed action presents the required 

CAA 112(d)(6) technology review for 

that source category. 

2. NSPS 

The statutory authority for this action 

is provided by section 111 of the CAA, 

which governs the establishment of 

standards of performance for stationary 

sources. Section 111(b)(1)(A) of the CAA 

requires the EPA Administrator to list 

categories of stationary sources that in 

the Administrator’s judgement cause or 

contribute significantly to air pollution 

that may reasonably be anticipated to 

endanger public health or welfare. The 

EPA must then issue performance 

standards for new (and modified or 

reconstructed) sources in each source 

category pursuant to CAA section 

111(b)(1)(B). These standards are 

referred to as new source performance 

standards, or NSPS. The EPA has the 

authority under CAA section 111(b) to 

define the scope of the source 

categories, determine the pollutants for 

which standards should be developed, 

set the emission level of the standards, 

and distinguish among classes, type and 

sizes within categories in establishing 

the standards. 

Section 111(b)(1)(B) of the CAA 

requires the EPA to ‘‘at least every 8 

years review and, if appropriate, revise’’ 

new source performance standards. 

Section 111(a)(1) of the CAA provides 

that performance standards are to 

‘‘reflect the degree of emission 

limitation achievable through the 

application of the best system of 

emission reduction which (taking into 

account the cost of achieving such 

reduction and any nonair quality health 

and environmental impact and energy 

requirements) the Administrator 

determines has been adequately 

demonstrated.’’ We refer to this level of 

control as the best system of emission 

reduction or ‘‘BSER.’’ The term 

‘‘standard of performance’’ in CAA 

111(a)(1) makes clear that the EPA is to 

determine both the BSER for the 

regulated sources in the source category 

and the degree of emission limitation 

achievable through application of the 

BSER. The EPA must then, under CAA 

section 111(b)(1)(B), promulgate 

standards of performance for new 

sources that reflect that level of 

stringency. Section 111(b)(5) of the CAA 

precludes the EPA from prescribing a 

particular technological system that 

must be used to comply with a standard 

of performance. Rather, sources can 

select any measure or combination of 

measures that will achieve the standard. 

Pursuant to the definition of new source 

in CAA 111(a), standards of 

performance apply to facilities that 

begin construction, reconstruction, or 

modification after the date of 

publication of such proposed standards 

in the Federal Register. 

The EPA Priority List (44 FR 49222, 

August 21, 1979) included Petroleum 

Transportation and Marketing as a 

source category for which standards of 

performance were to be promulgated 

under CAA section 111. The NSPS for 

this source category was promulgated 

on August 18, 1983 (48 FR 37578) and 

applies to the total of all the loading 

racks at a bulk gasoline terminal that 

deliver liquid product into gasoline tank 

trucks. This proposed action presents 

the required CAA 111(b)(1)(B) review 

for the bulk gasoline terminals NSPS. 

B. What are the source categories and 

how do the current standards regulate 

emissions? 

1. NESHAP Subpart R 

The sources affected by the current 

major source NESHAP for the Gasoline 

Distribution source category subpart R 

are bulk gasoline terminals and pipeline 

breakout stations. A bulk gasoline 

terminal is defined at 40 CFR 63.421 as 

‘‘any gasoline facility which receives 

gasoline by pipeline, ship, or barge, and 

has a gasoline throughput greater than 

75,700 liters per day.’’ 2 A pipeline 

breakout station is defined as ‘‘a facility 

along a pipeline containing storage 

vessels used to relieve surges or receive 

and store gasoline from the pipeline for 

reinjection and continued transportation 

by pipeline or to other facilities.’’ The 

HAP emitted by Gasoline Distribution 

sources are benzene, hexane, toluene, 

xylene, ethylbenzene, 2,2,4- 

trimethylpentane, cumene, and 

napthalene. The emission standards are 

the same for new sources and existing 

sources. Emissions from loading racks 

are controlled by vapor collection and 

processing systems meeting 10 

milligrams (mg) total organic carbon 

(TOC) per liter (L) of gasoline loaded 

and the cargo tanks being loaded must 

be certified to be vapor tight. Emissions 

from storage vessels with a design 

capacity greater than or equal to 75 

cubic meters are controlled by 

equipment designed to capture and 

control emissions. Equipment leaks are 

required to be repaired upon detection 

using audio, visual, or olfactory (AVO) 

methods. 

2. NESHAP Subpart BBBBBB 

The sources affected by the current 

area source NESHAP for the Gasoline 

Distribution source category subpart 

BBBBBB are bulk gasoline terminals, 

bulk gasoline plants, and pipeline 

facilities. A bulk gasoline terminal is 

defined at 40 CFR 63.11100 as ‘‘any 

gasoline storage and distribution facility 

that receives gasoline by pipeline, ship 

or barge, or cargo tank and has a 

gasoline throughput of 20,000 gallons 

per day or greater.’’ A bulk gasoline 

plant is defined as ‘‘any gasoline storage 

and distribution facility that receives 

gasoline by pipeline, ship or barge, or 

cargo tank, and subsequently loads the 

gasoline into gasoline cargo tanks for 

transport to gasoline dispensing 

facilities, and has a gasoline throughput 

of less than 20,000 gallons per day.’’ A 

pipeline breakout station is defined as 

‘‘a facility along a pipeline containing 

storage vessels used to relieve surges or 

receive and store gasoline from the 

pipeline for re-injection and continued 

transportation by pipeline or to other 

facilities.’’ A pipeline pumping station 

is defined as ‘‘a facility along a pipeline 

containing pumps to maintain the 

desired pressure and flow of product 

through the pipeline, and not containing 

gasoline storage tanks other than surge 

control tanks.’’ The HAP emitted by 

Gasoline Distribution sources are 

benzene, hexane, toluene, xylene, 

ethylbenzene, 2,24-trimethylpentane, 

cumene, and napthalene. The emission 

standards are the same for new sources 

and existing sources. Emissions from 

loading racks at large bulk gasoline 

terminals (those with gasoline 

throughput of 250,000 gallons per day 

or greater) are controlled by vapor 

collection and processing systems 

meeting 80 mg TOC per L of gasoline 

loaded (mg/L) and the cargo tanks being 

loaded must be certified to be vapor 

tight. Small bulk gasoline terminals and 

bulk gasoline plants must use 

submerged filling when loading 

gasoline. Emissions from storage vessels 

with a design capacity greater than or 

equal to 75 cubic meters are required to 


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3Allowance is provided to meet 80 mg/L for 

affected facilities with an ‘‘existing vapor 

processing system.’’ 

be controlled by equipment designed to 

capture and control emissions. 

Equipment leaks are required to be 

repaired upon detection using AVO 

methods. 

3. NSPS Subpart XX 

The sources affected by the current 

NSPS for the Bulk Gasoline Terminals 

source category subpart XX are bulk 

gasoline terminals that commenced 

construction or modification after 

December 17, 1980. NSPS subpart XX at 

40 CFR 60.501 defines bulk gasoline 

terminals as ‘‘any gasoline facility 

which receives gasoline by pipeline, 

ship or barge, and has a gasoline 

throughput greater than 75,700 liters per 

day.’’ Emissions from loading racks at 

bulk gasoline terminals are controlled 

by vapor collection and processing 

systems meeting 35 mg/L and the cargo 

tanks being loaded must be certified to 

be vapor tight.3 Equipment leaks are 

required to be repaired upon detection 

using AVO methods. Emissions from 

storage vessels are regulated under a 

separate NSPS (40 CFR part 60, subpart 

K, Ka, or Kb). 

C. What data collection activities were 

conducted to support this action? 

The EPA used several data sources to 

determine the facilities that are subject 

to the Gasoline Distribution NESHAP 

and the Bulk Gasoline Terminals NSPS. 

We identified facilities in the 2017 

National Emissions Inventory (NEI) and 

the Toxics Release Inventory system 

having a primary facility NAICS code 

beginning with 4247, Petroleum and 

Petroleum Products Merchant 

Wholesalers. We also used information 

from the original Gasoline Distribution 

NESHAP, Bulk Terminal list of 

petrochemical storage facilities from the 

Internal Revenue Service, the Office of 

Enforcement and Compliance 

Assurance’s Enforcement and 

Compliance History Online tool (https:// 

echo.epa.gov), and the Energy 

Information Administration. To inform 

our reviews for these emission sources, 

we reviewed the EPA’s Reasonably 

Available Control Technology (RACT)/ 

Best Available Control Technology 

(BACT)/Lowest Achievable Emission 

Rate (LAER) Clearinghouse (RBLC) and 

regulatory development efforts for 

similar sources published after the 

Gasoline Distribution NESHAP and 

Bulk Terminals NSPS were developed. 

The EPA also reviewed air permits to 

determine facilities subject to the 

Gasoline Distribution NESHAP and 

Bulk Gasoline Terminals NSPS. 

We met with industry representatives 

from Marathon, the American Petroleum 

Institute, the International Liquid 

Terminals Association, and the 

International Fuel Terminal Operators 

Association to collect data and discuss 

industry practices. We also met with 

control device suppliers to obtain 

information on the cost and design of 

control devices. We met with 

representatives of the U.S. Department 

of Transportation (DOT) to discuss cargo 

tank requirements. 

D. What other relevant background 

information and data are available? 

We relied on certain technical reports 

and memoranda that the EPA developed 

for flares used as air pollution control 

devices in the Petroleum Refinery 

Sector residual risk and technology 

review and NSPS rulemaking (80 FR 

75178, December 1, 2015). The 

Petroleum Refinery sector docket is at 

Docket ID No. EPA–HQ–OAR–2010– 

0682. For completeness of the 

rulemaking record for this action and for 

ease of reference in finding these items 

in the publicly available petroleum 

refinery sector rulemaking docket, we 

are including the most relevant 

technical support documents in the 

docket for this proposed action (Docket 

ID No. EPA–HQ–OAR–2020–0371) and 

including a list of the of all documents 

used to inform the original flare 

provision in the Petroleum Refinery 

Sector residual risk and technology 

review and NSPS rulemaking in 

Attachment 2 of the memorandum titled 

Monitoring Options and Costs for 

Gasoline Distribution Facilities, which 

is available in the docket for this 

rulemaking. 

Additional information related to the 

promulgation and subsequent 

amendments of the NSPS and NESHAPs 

is available in Docket ID Nos. A–79–52, 

A–92–38, EPA–HQ–OAR–2002–0029, 

EPA–HQ–OAR–2004–0019, EPA–HQ– 

OAR–2004–0164, and EPA–HQ–OAR– 

2006–0406. 

E. How does the EPA perform the 

NESHAP technology review and NSPS 

review? 

1. NESHAP Technology Review 

Our technology review primarily 

focuses on the identification and 

evaluation of developments in practices, 

processes, and control technologies that 

have occurred since the NESHAPs were 

promulgated. Where we identify such 

developments, we analyze their 

technical feasibility, estimated costs, 

energy implications, and nonair 

environmental impacts. We also 

consider the emission reductions 

associated with applying each 

development. This analysis informs our 

decision of whether it is ‘‘necessary’’ to 

revise the CAA section 112 emissions 

standards. In addition, we consider the 

appropriateness of applying controls to 

new sources versus retrofitting existing 

sources. For this exercise, we consider 

any of the following to be a 

‘‘development:’’ 

• Any add-on control technology or 

other equipment that was not identified 

and considered during development of 

the original MACT and GACT 

standards; 

• Any improvements in add-on 

control technology or other equipment 

(that were identified and considered 

during development of the original 

MACT and GACT standards) that could 

result in additional emissions reduction; 

• Any work practice or operational 

procedure that was not identified or 

considered during development of the 

original MACT and GACT standards; 

• Any process change or pollution 

prevention alternative that could be 

broadly applied to the industry and that 

was not identified or considered during 

development of the original MACT and 

GACT standards; and 

• Any significant changes in the cost 

(including cost effectiveness) of 

applying controls (including controls 

the EPA considered during the 

development of the original MACT and 

GACT standards). 

In addition to reviewing the practices, 

processes, and control technologies that 

were considered at the time we 

originally developed each NESHAP, we 

review a variety of data sources in our 

investigation of potential practices, 

processes, or controls to consider. We 

also review each NESHAP and the 

available data to determine if there are 

any unregulated emissions of HAP 

within the source categories, and 

evaluate these data for use in 

developing new emission standards. 

When reviewing MACT standards, we 

also address regulatory gaps, such as 

missing standards for listed air toxics 

known to be emitted from the source 

category. See sections II.C and II.D of 

this preamble for information on the 

specific data sources that were reviewed 

as part of the technology review. 

2. NSPS Review 

As noted in the section II.A.2 of this 

document, CAA section 111 requires the 

EPA, at least every 8 years to review 

and, if appropriate revise the standards 

of performance applicable to new, 

modified, and reconstructed sources. If 

the EPA revises the standards of 


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4The VOC recovery credit was calculated based 

on the average retail price of regular conventional 

gasoline in 2019, which was $2.50/gallon, and that 

60 to 70 percent of retail price is for taxes and 

distribution/marketing costs (https://www.eia.gov/ 

petroleum/gasdiesel/; EIA, 2021). Therefore, we 

estimated the value of gasoline recovered to be 

$1.50/gallon ($2.50 × 0.60). Using a density of 

gasoline of 6.25 lb/gallon, this yields a VOC credit 

of $480/ton [($1.50/6.25) × 2000]. The average 

refiner’s wholesale spot price for all gasoline types 

in 2019 was $1.85/gallon (https://www.eia.gov/ 

dnav/pet/hist/LeafHandler.ashx?n=PET&s=EMA_

EPM0_PBR_NUS_DPG&f=M; EIA, 2021). 

performance, they must reflect the 

degree of emission limitation achievable 

through the application of the BSER 

taking into account the cost of achieving 

such reduction and any nonair quality 

health and environmental impact and 

energy requirements. CAA section 

111(a)(1). 

In reviewing an NSPS to determine 

whether it is ‘‘appropriate’’ to revise the 

standards of performance, the EPA 

evaluates the statutory factors including 

the following information: 

• Expected growth for the source 

category, including how many new 

facilities, reconstructions, and 

modifications may trigger NSPS in the 

future. 

• Pollution control measures, 

including advances in control 

technologies, process operations, design 

or efficiency improvements, or other 

systems of emission reduction, that are 

‘‘adequately demonstrated’’ in the 

regulated industry. 

• Available information from the 

implementation and enforcement of 

current requirements indicating that 

emission limitations and percent 

reductions beyond those required by the 

current standards are achieved in 

practice. 

• Costs (including capital and annual 

costs) associated with implementation 

of the available pollution control 

measures. 

• The amount of emission reductions 

achievable through application of such 

pollution control measures. 

• Any nonair quality health and 

environmental impact and energy 

requirements associated with those 

control measures. 

In evaluating whether the cost of a 

particular system of emission reduction 

is reasonable, the EPA considers various 

costs associated with the particular air 

pollution control measure or a level of 

control, including capital costs and 

operating costs, and the emission 

reductions that the control measure or 

particular level of control can achieve. 

The agency considers these costs in the 

context of the industry’s overall capital 

expenditures and revenues. The agency 

also considers cost-effectiveness 

analysis as a useful metric, and a means 

of evaluating whether a given control 

achieves emission reduction at a 

reasonable cost. A cost-effectiveness 

analysis allows comparisons of relative 

costs and outcomes (effects) of two or 

more options. In general, costeffectiveness is a measure of the 

outcomes produced by resources spent. 

In the context of air pollution control 

options, cost-effectiveness typically 

refers to the annualized cost of 

implementing an air pollution control 

option divided by the amount of 

pollutant reductions realized annually. 

After the EPA evaluates the factors 

described above, the EPA then compares 

the various systems of emission 

reductions and determines which 

system is ‘‘best’’. The EPA then 

establishes a standard of performance 

that reflects the degree of emission 

limitation achievable through the 

implementation of the BSER. In doing 

this analysis, the EPA can determine 

whether subcategorization is 

appropriate based on classes, types, and 

sizes of sources, and may identify a 

different BSER and establish different 

performance standards for each 

subcategory. The result of the analysis 

and BSER determination leads to 

standards of performance that apply to 

facilities that begin construction, 

reconstruction, or modification after the 

date of publication of the proposed 

standards in the Federal Register. 

Because the new source performance 

standards reflect the best system of 

emission reduction under conditions of 

proper operation and maintenance, in 

doing its review, the EPA also evaluates 

and determines the proper testing, 

monitoring, recordkeeping and 

reporting requirements needed to ensure 

compliance with the emission 

standards. 

See section II.C of this preamble for 

information on the specific data sources 

that were reviewed as part of this action. 

III. Proposed Rule Summary and 

Rationale 

A. What are the results and proposed 

decisions based on our technology 

reviews and NSPS review, and what is 

the rationale for those decisions? 

We evaluated developments in 

practices, processes, and control 

technologies for loading operations, 

storage vessels, and equipment leaks for 

NESHAP subpart R and NESHAP 

subpart BBBBBB. For the NSPS XX, we 

evaluated BSER for loading operations 

and equipment leaks. We analyzed costs 

and impacts for each emission source 

(e.g., loading operations) by each 

subpart. We also included product 

recovery in the cost calculation, where 

appropriate. We based the product 

recovery on the average pre-tax retail 

price of regular conventional gasoline in 

2019 at a value of gasoline recovered of 

$1.50 per gallon.4 This yielded a 

product recovery of $480 per ton of 

VOC. For NSPS, we determined costeffectiveness, cost per ton of emissions 

reduced, on a VOC basis. For NESHAP, 

we determined cost-effectiveness on a 

HAP basis from the VOC emissions. In 

general, gasoline (liquid) is 

approximately 20 weight percent HAP, 

but gasoline vapors are only 3 to 4 

weight percent HAP. We estimated that 

loading operation VOC emissions were 

4 weight percent HAP, storage vessel 

VOC emissions were 5 weight percent 

HAP, and equipment leak VOC 

emissions were 10 weight percent HAP. 

Although we considered the options 

cumulatively, we also calculated the 

incremental cost effectiveness, which 

allowed us to assess the impacts of the 

incremental change between the options 

under consideration. 

1. Standards for Loading Racks 

We evaluated the control efficiency 

and costs of common control systems 

used for loading racks, including 

thermal/vapor combustion units (VCUs), 

carbon adsorption vapor recovery units 

(VRUs), flares, and refrigerated 

condensers. We assessed the loading 

rates to the control systems based on 

both splash loading and submerged 

loading for 5 different ‘‘model plant’’ 

gasoline throughputs. We also assessed 

cost for vapor balancing controls. Our 

assessment of control systems is 

summarized in the memorandum 

‘‘Control Options for Loading 

Operations at Gasoline Distribution 

Facilities’’ included in EPA Docket No. 

EPA–HQ–OAR–2020–0371. 

We did not identify any new control 

technologies, but we did identify some 

state and local permits that required 

emission limits as low as 1 mg/L (less 

than the most stringent federal limit of 

10 mg/L). We therefore considered the 

costs for upgrades needed to retrofit a 

current control system to achieve more 

stringent emission limits for each of the 

current rules. The emission limits 

assessed included 80 mg/L, 35 mg/L, 10 

mg/L, and 1 mg/L, depending on the 

emission limits for each subpart, which 

are discussed in detail in sections 

III.A.1.a–c. We also assessed alternative 

means of expressing the loading rack 

emissions limit. The emissions limit 

expressed in terms of mg TOC/L of 

gasoline loaded is difficult to directly 

monitor continuously as discussed 

below. As such, the emission limit is 

generally assessed via an initial 


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performance test, with operating limits 

established as means to ensure 

continuous compliance. Alternative 

means to express the emission limit may 

make the emission limit more amenable 

to direct monitoring. 

a. NESHAP Subpart R 

We identified one development for 

loading racks which is an emission limit 

of 1 mg/L using the same types of 

control that we expect are used to meet 

the current major source emission limit 

of 10 mg/L of gasoline loaded. 

Therefore, we assessed maintaining the 

10 mg/L emission limit or reducing it to 

1 mg/L. For the major source NESHAP 

subpart R impacts analysis, we 

estimated that most facilities used VRUs 

and that approximately 75 percent of 

the facilities could comply with the 1 

mg/L emission limit by modifying their 

operating characteristics (cycle times) 

and 25 percent would need to upgrade 

their control system. 

Table 5 of this document summarizes 

the resulting impacts for the control 

option considered for 210 major source 

(NESHAP subpart R) facilities. Based on 

the costs associated with further HAP 

emission reductions, we determined it 

is not cost-effective to lower the 10 mg/ 

L standard, since the cost effectiveness 

of the option is over $100,000 per ton 

of HAP reduced—a level that is over an 

order of magnitude higher than we have 

considered cost-effective in previous 

rulemakings to limit organic HAP. 

Accordingly, we are not proposing any 

changes to the current emission limit for 

loading operations for the NESHAP 

subpart R. Our assessment of control 

options is summarized in the 

memorandum ‘‘Major Source 

Technology Review for Gasoline 

Distribution Facilities (Bulk Gasoline 

Terminals and Pipeline Breakout 

Stations) NESHAP’’ in EPA Docket No. 

EPA–HQ–OAR–2020–0371. 

As noted in section V of this 

preamble, the EPA requests public 

comment on all aspects of this proposed 

rule, including our evaluation of the 

costs and efficacy of control options for 

loading operations under NESHAP 

subpart R. Among other issues, EPA 

requests comment on whether we have 

accurately assessed the costs, pollution 

reduction benefits, and costeffectiveness of applying a 1 mg/L 

emission limit to major sources subject 

to this NESHAP; experience from 

implementing state regulations or local 

ordinances for these sources that could 

inform this technology review; and 

whether there are other factors that EPA 

should consider that would support a 

revision of the current NESHAP subpart 

R. For example, we note that there are 

at least 5.9 million people located 

within 5 km of these sources (see Table 

18 of this document), and the EPA is 

concerned that these communities may 

already be overburdened by air 

pollution from multiple sources. 

Information on the contributions that 

HAPs from these sources make to 

overall pollution burdens in 

neighboring communities may be useful 

in determining whether a more stringent 

standard is warranted. 

TABLE 5—CONTROL OPTION IMPACTS FOR LOADING OPERATIONS FOR NESHAP SUBPART R 

Emission limit 

VOC emission 

reduction a

(tpy) 

TCI b

($) 

AOC c

($/yr) 

TAC d w/o 

product 

recovery 

($/yr) 

TAC d

w/product 

recovery 

($/yr) 

CEe

($/ton VOC) 

CEe

($/ton HAP)f

1 mg/L .......................... 1,686 34,160,000 5,764,000 8,677,000 7,868,000 4,667 116,700 

a Compared to baseline (10 mg/L) emissions of 1,873 tpy. 

bTotal capital investment (TCI). 

cAnnualized operating costs (AOC). 

dTotal annualized cost (TAC) considering annual operating costs and annualized cost of capital. 

e Cost effectiveness (CE) as compared to baseline (10 mg/L). 

f HAP content of gasoline vapors assumed to be 4% of VOC. 

In our review of the developments in 

practices, processes, or control 

technologies, we noted that there were 

inconsistencies regarding continuous 

parameter monitoring requirements 

associated with complying with the 

loading standard as expressed in terms 

of 10 mg/L of gasoline loaded. For 

example, most VRUs have a continuous 

TOC concentration monitor, but do not 

have flow meters needed to convert the 

concentration limit to a mass emission 

rate that can be used to calculate the 

emissions in terms of mg/L. State and 

local permitting agencies set continuous 

concentration limits based on 

performance tests, but also factor in 

more variability to account for different 

loading rates and operational 

characteristics of the VRU. While we 

noted some variability in exhaust flow 

rates with product loading rates, the 

exhaust flow rate is well correlated with 

the product loading rates, such that a 

direct concentration limit can be 

established that is equivalent to the 10 

mg/L standard. We determined that the 

concentration limit for VRU has several 

advantages to the 10 mg/L emission 

limit. First, a concentration limit could 

be directly and continuously monitored. 

In this case, the TOC monitor would be 

used as a continuous emission 

monitoring system (CEMS) and 

exceedances of the concentration limit 

would be a violation of the emission 

limit. When the emission limit is 

expressed in mg/L, the TOC monitor is 

used as a continuous parameter 

monitoring system (CPMS) and 

exceedance of the concentration limit is 

a deviation of the operating limit. Thus, 

the concentration-based standard 

provides improved enforceability of the 

emission limit. Second, providing a 

concentration limit directly in the rule 

reduces the variability in the way the 

operating limits are established in 

different states and localities. Thus, it 

provides consistent implementation of 

the federal standard when considering 

continuous compliance requirements. 

The potential disadvantage of a 

concentration limit is the ability to draw 

in ambient air to dilute the exhaust gas 

concentration. 

Upon careful consideration of the 

potential options to improve continuous 

compliance monitoring requirements, 

we are proposing to express the 

emission limit for VRUs in terms of a 

concentration limit of 5,500 parts per 

million by volume (ppmv) TOC as 

propane on a three-hour rolling average. 

As noted previously, this provides a 

more enforceable and consistent 

continuous compliance requirement 

that is directly related to the emissions 

limit. To prevent dilution, we are 

proposing that only vacuum breaker 

valves can be used to introduce ambient 

air into the VRU control system. 

Because of the need for combustion 

air and products of combustion, this 

concentration limit is not directly 

applicable for VCUs. We considered 

developing an equivalent concentration 

limit for VCUs, but this would require 


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both a TOC monitor and an oxygen 

monitor, to correct the concentration 

limit to 0 percent excess oxygen. This 

standard becomes problematic at low 

TOC loading rates, where the oxygen 

concentration may approach that of the 

ambient air. We consider that periodic 

performance test along with continuous 

monitoring of combustion zone 

temperature provides adequate 

assurance that the VCU is operating in 

a manner consistent with the TOC 

emissions limit. NESHAP subpart R 

already includes requirements for using 

a temperature operating limit to 

demonstrate continuous compliance 

with the 10 mg/L emission limit; 

however, these requirements do not 

provide adequate instructions on how to 

establish the operating limit, 

particularly with respect to the 

averaging time. For example, the 

performance test requires readings be 

taken every 5 minutes over a 6-hour test 

period, but there are no instructions on 

how to develop the temperature 

operating limit from these readings. At 

times, the 5-minute temperature 

readings can fluctuate significantly, 

particularly during periods of low 

loading rates. Establishing the operating 

limit based on the lowest 5-minute 

reading during a time of little or no 

loading of product into gasoline cargo 

tanks can lead to erroneously low 

temperature operating limits that do not 

ensure adequate combustion 

efficiencies. We considered establishing 

a minimum operating temperature, such 

as 1,400 °F or 1,500 °F as required for 

VCU in general standards for closed 

vent system and control devices [see 40 

CFR 63.985(b)(1)(i)(B) or 40 CFR 

60.482–10a(c)]. However, we recognized 

that there is a wide variety of VCU 

designs and that a single set temperature 

operating limit may not be appropriate 

for all applications. Therefore, we 

elected to maintain that the temperature 

operating limit be set during the 

performance test, but we are proposing 

additional instructions on how to 

develop and assess the temperature 

operating limit. First, we are proposing 

the temperature operating limit be 

established and evaluated on a 3-hour 

rolling average basis. We are proposing 

that, for each 5-minute block of the 

performance test, the combustion 

(flame) zone must be determined, either 

via a single temperature reading or an 

average temperature of all readings 

during the 5-minute block), and a record 

of the volume of liquid product loading 

into gasoline cargo tanks must be kept. 

We are proposing that hourly average 

combustion zone temperatures be 

developed from the 5-minute 

measurements using only those 5- 

minute periods when product is loaded 

into gasoline cargo tanks. From those 

hourly averages, 3-hour rolling averages 

are to be determined. During the 6-hour 

performance test, 4 different 3-hour 

rolling averages will be determined. We 

are proposing that the temperature 

operating limit be established as the 

lowest of the 3-hour averages. We 

consider that this approach will 

establish a temperature operating limit 

that is indicative of VCU performance 

while accounting for variability in 

loading operations. We are proposing 

that compliance with the operating limit 

will be determined on a 3-hour rolling 

average basis following the same 

procedures used during the performance 

tests (5-minute measurements used to 

calculate 1-hour average values 

considering only 5-minute periods 

when product was loaded into gasoline 

cargo tanks). 

We also determined that periodic 

emission testing should be required to 

help ensure continuous compliance. 

Currently, facilities conduct a one-time 

performance test and then monitor 

operating limits. We are proposing to 

require on-going performance tests at a 

minimum frequency of once every 5 

years to supplement the parameter 

monitoring and ensure emission 

controls continue to operate as 

demonstrated during the initial 

performance test. Our assessment of 

monitoring options is summarized in 

the memorandum ‘‘Monitoring Options 

and Costs for Gasoline Distribution 

Facilities’’ in EPA Docket No. EPA–HQ– 

OAR–2020–0371. 

Finally, we expect all or nearly all 

facilities use submerged loading as they 

fill product into cargo tanks. However, 

the NESHAP subpart R does not require 

submerged filling. The lack of a direct 

requirement for submerged loading may 

cause problems for several reasons. 

First, organic loading rates to the control 

system when using splash loading are 

expected to be more than double that of 

the organic loading rates when using 

submerged loading. With the 

preponderance of use of submerged 

loading, performance tests would almost 

certainly be conducted when the cargo 

tanks are loaded via submerged fill. The 

periodic performance test and operating 

limits may not be adequate to ensure 

compliance while splash loading is 

used. We also note that the 10 mg/L 

emission limit is essentially equivalent 

to 98 percent TOC control efficiency 

when using submerged fill, but requires 

over 99 percent control efficiency when 

splash loading is used. Because the flare 

requirements were specifically 

developed to ensure a 98 percent flare 

destruction efficiency, the flare 

operating limits are not considered 

adequate to ensure compliance with the 

10 mg/L emissions limit when splash 

loading is used. Therefore, we are 

proposing to expressly include 

submerged fill requirements as an 

integral part of the loading rack 

standards. 

b. NESHAP Subpart BBBBBB 

The requirements for loading racks at 

area source gasoline distribution 

facilities are dependent on the total 

throughput capacity of all racks. Large 

gasoline bulk terminals have loading 

racks with a combined throughput of 

250,000 gallons per day or greater and 

are required to reduce emissions of TOC 

to less than or equal to 80 mg/L of 

gasoline loaded. Small gasoline bulk 

terminals, which have loading racks 

with a combined throughput between 

20,000 and 250,000 gallons per day, are 

required to use submerged filling with 

a submerged fill pipe that is no more 

than 6 inches from the bottom of the 

cargo tank. Bulk gasoline plants are 

facilities with gasoline throughput of 

20,000 gallons per day or less and are 

required to use submerged filling in all 

gasoline storage tanks with a capacity of 

greater than 250 gallons and in all cargo 

tanks. 

For large bulk gasoline terminals at 

area sources (i.e., combined throughput 

of 250,000 gallons per day or greater), 

we evaluated control options of either 

maintaining the current 80 mg/L control 

option or lowering that limit to either 35 

mg/L, 10 mg/L, or 1 mg/L. Table 6 of 

this document presents the estimated 

nationwide impacts of these alternative 

emission limits for 232 large bulk 

gasoline terminals at area sources. The 

cost-effectiveness and incremental costeffectiveness of reducing the area source 

emission limit for large bulk gasoline 

terminals to 35 mg/L are $9,700 per ton 

of HAP emissions reduced, which we 

determined is cost-effective. The costeffectiveness and incremental cost 

effectiveness of reducing the area source 

emission limit for large bulk gasoline 

terminals to 10 mg/L are approximately 

$12,000 and $13,000 per ton of HAP 

emissions reduced, respectively, which 

we determined is not cost-effective. 

Therefore, we are proposing to lower the 

area source emission limits for loading 

racks at large bulk gasoline terminals to 

35 mg/L. 

We note, however, that there are at 

least 35.7 million people located within 

5 km of these sources (see Table 19 of 

this document), and EPA is concerned 

that this population has the potential to 

be overburdened from air pollution from 

multiple sources. In this case, we have 


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5Some VCU are essentially enclosed flares that 

do not have a means to reduce air inlet draft at low 

TOC loading rates. 

identified a more stringent standard 

(i.e., 10 mg/L) that could further reduce 

HAP emissions exposure in 

communities near these large bulk 

terminals. We project that this more 

stringent standard would impose 

slightly higher, but not unreasonable, 

capital and annualized costs on these 

terminals. EPA seeks comment on 

whether this more protective standard, 

although it is less cost effective for these 

type of HAP emissions controls than we 

would typically find acceptable, is 

nevertheless appropriate given the 

reductions in HAPs that would occur in 

potentially over-burdened communities 

surrounding these large bulk terminals. 

EPA also requests information on the 

costs, efficacy, and feasibility of control 

options for loading racks at area source 

gasoline distribution facilities, and the 

contributions of these sources to overall 

pollution burdens in surrounding 

communities, to inform our 

consideration of whether a more 

protective area source standard is 

warranted. Our assessment of control 

options is summarized in the 

memorandum ‘‘Area Source Technology 

Review for the Gasoline Distribution 

Bulk Terminals, Bulk Plants, and 

Pipeline Facilities NESHAP’’ in EPA 

Docket No. EPA–HQ–OAR–2020–0371. 

As in the major source rule, we are 

proposing to replace the current massbased limits with a direct concentration 

limit for facilities operating VRUs 

because it provides consistent 

implementation of the federal standard 

when considering continuous 

compliance requirements. The 

corresponding concentration limit 

equivalent to a 35 mg/L emission limit 

is 19,200 ppmv as propane. Therefore, 

we are proposing to express the 

emission limit for VRUs in terms of a 

concentration limit of 19,200 ppmv TOC 

as propane on a three-hour rolling 

average. As noted previously, a 

concentration limit provides a more 

enforceable and consistent continuous 

compliance requirement that is directly 

related to the emissions limit. To 

prevent dilution, we are proposing that 

only vacuum breaker valves can be used 

to introduce ambient air into the VRU 

control system. Our assessment of 

monitoring options is summarized in 

the memorandum ‘‘Monitoring Options 

and Costs for Gasoline Distribution 

Facilities’’ in EPA Docket No. EPA–HQ– 

OAR–2020–0371. 

Because of the need for combustion 

air, this concentration limit is not 

directly applicable for VCUs. We 

considered developing an equivalent 

concentration limit for VCUs, but this 

would require both a TOC monitor and 

an oxygen monitor, to correct the 

concentration limit to 0 percent excess 

oxygen. This standard becomes 

problematic at low TOC loading rates, 

where the oxygen concentration may 

approach that of the ambient air.5

Because most VCUs used at area source 

gasoline distribution facilities are 

enclosed, air-assisted flares, we 

determined that operating limits, either 

temperature operating limits (as 

described for the major sources 

NESHAP subpart R) or flare operating 

limits (net combustion zone heating 

value and air-assist dilution parameter 

values, as provided in the Petroleum 

Refinery MACT rule: 40 CFR part 63, 

subpart CC) are the most appropriate. 

We anticipate that facilities electing to 

meet the flare operating limits for their 

VCU would conduct two-week sampling 

to assess the variability of heat content 

while loading gasoline and develop 

minimum natural gas assist rates as a 

means of demonstrating continuous 

compliance. Alternatively, facilities may 

elect to install a calorimeter to monitor 

heat content and only add natural gas as 

needed if the vent gas stream falls below 

the minimum required heat content. We 

are proposing to require VCUs at area 

source facilities to monitor temperature 

or meet the flare operating limits in 40 

CFR part 63, subpart CC. 

TABLE 6—CONTROL OPTION IMPACTS FOR LOADING OPERATIONS AT LARGE AREA SOURCE BULK GASOLINE TERMINALS

Emission limit 

VOC emission 

reduction a

(tpy) 

TCI b

($1,000) 

AOC c

($/yr) 

TAC d w/o 

product 

recovery 

($/yr) 

TAC d

w/product 

recovery 

($/yr) 

CEe

($/ton HAP)f

ICEg

($/ton HAP)f

35 mg/L ........................ 820 0 385,000 385,000 319,000 9,742 9,742 

10 mg/L ........................ 2,619 1,878 1,371,000 1,531,000 1,275,000 12,170 13,270 

1 mg/L .......................... 3,945 68,400 15,560,000 21,400,000 20,990,000 133,000 371,900 

a Compared to baseline (80 mg/L) emissions of 4,097 tpy. 

bTotal capital investment (TCI). 

cAnnual operating costs (AOC). 

dTotal annualized costs (TAC) considering annual operating costs and annualized cost of capital. 

e Cost effectiveness (CE) compared to baseline (80 mg/L). 

f HAP content assumed to be 4% of VOC. 

g Incremental cost effectiveness (ICE) compared to previous option in table. 

Similarly, for small bulk gasoline 

terminals at area sources (i.e., combined 

throughput between 20,000 and 250,000 

gallons per day), we evaluated control 

options of maintaining the current 

submerged loading requirements and 

potentially adding loading rack 

emission limits of either 80 mg/L, 35 

mg/L, 10 mg/L, or 1 mg/L. Table 7 of 

this document presents the estimated 

nationwide impacts of these alternative 

emission limits for 858 small bulk 

gasoline terminals at area sources. We 

evaluated the 80 mg/L emission limit for 

loading racks, but the cost-effectiveness 

of this option exceeds $24,000 per ton 

of HAP emissions reduced. The other 

options are less cost-effective. Based on 

this analysis, we are not proposing any 

changes to the current area source 

provisions for small bulk gasoline 

terminals subject to NESHAP subpart 

BBBBBB. 

However, as noted above in the 

context of large bulk gasoline terminals 

at area sources, EPA is concerned about 

the large number of people living within 

5 km of these facilities and the potential 

for these affected populations to be 

located in communities that already face 

a significant burden of air pollution 

from multiple sources. Although we 

estimate that a standard of 80 mg/L or 

less would have a cost per ton that is 

higher than we have traditionally 


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considered to be acceptable for organic 

HAP, it is also possible that other cost 

metrics we have discretion to 

consider—such as total capital and 

operating costs—could support the 

reasonableness of such an emissions 

limit. EPA therefore seeks comment on 

whether an emissions limit of 80 mg/L 

or less would be appropriate in light of 

these alternative cost metrics and the 

reductions in HAPs that would occur in 

potentially over-burdened communities 

surrounding these small bulk terminals. 

EPA also requests information on the 

costs, efficacy, and feasibility of control 

options for these sources, and the 

contributions of these sources to overall 

pollution burdens in surrounding 

communities, to inform our 

consideration of whether it is 

appropriate to establish an emissions 

limit for loading operations at small area 

source bulk gasoline terminals. Our 

assessment of control options is 

summarized in the memorandum ‘‘Area 

Source Technology Review for the 

Gasoline Distribution Bulk Terminals, 

Bulk Plants, and Pipeline Facilities 

NESHAP’’ in EPA Docket No. EPA–HQ– 

OAR–2020–0371. 

TABLE 7—CONTROL OPTION IMPACTS FOR LOADING OPERATIONS AT SMALL AREA SOURCE BULK GASOLINE TERMINALS

Emission limit 

VOC emission 

reduction a

(tpy) 

TCI b

($1,000) 

AOC c

($/yr) 

TAC d

w/o product 

recovery 

($/yr) 

TAC d

w/product 

recovery 

($/yr) 

CEe

($/ton HAP)f

ICEg

($/ton HAP)f

80 mg/L ........................ 2,015 11,870 1,909,000 2,922,000 1,954,000 24,250 24,250 

35 mg/L ........................ 2,974 12,370 3,758,000 4,813,000 4,457,000 37,460 65,240 

10 mg/L ........................ 5,056 38,470 9,579,000 12,860,000 12,260,000 60,600 93,650 

1 mg/L .......................... 5,789 326,400 43,310,000 71,140,000 70,450,000 304,200 1,984,000 

a Compared to baseline (submerged loading) emissions of 5,870 tpy. 

bTotal capital investment (TCI). 

cAnnual operating costs (AOC). 

dTotal annualized costs (TAC) considering annual operating costs and annualized cost of capital. 

e Cost effectiveness (CE) compared to baseline (submerged loading). 

f HAP content assumed to be 4% of VOC. 

g Incremental cost effectiveness (ICE) compared to previous option in table. 

We expect that storage tanks at bulk 

gasoline plants typically have fixed 

roofs. As such, vapor balancing is a 

potential control option for bulk 

gasoline plants. In reviewing state and 

local requirements, we found that a 

number of state requirements include 

requirements for vapor balancing at bulk 

gasoline plants but have a minimum 

applicability threshold of 4,000 gallons 

per day. Therefore, we evaluated the 

costs of requiring vapor balancing for a 

variety of differently-sized bulk gasoline 

plants. Vapor balancing is projected to 

result in a net cost savings relative to 

submerged loading (when considering 

the value of gasoline vapors not emitted) 

for bulk gasoline plants with throughput 

of about 8,000 to 10,000 gallons per day 

or more. The cost effectiveness of vapor 

balancing begins to diminish at smaller 

bulk gasoline plants, exceeding $10,000 

per ton of HAP reduced at bulk plants 

with throughputs less than 4,000 gallon 

per day. Considering the state rules and 

diminishing cost effectiveness for small 

bulk gasoline plants, we are proposing 

to require vapor balancing both for 

loading storage vessels and for loading 

cargo tanks, for bulk gasoline plants 

with maximum design capacity 

throughput of 4,000 gallons per day or 

more. Bulk gasoline plants with 

capacities below 4,000 gallons per day 

would retain the requirement to use 

submerge fill. 

We also considered including loading 

rack emission limits of either 80 mg/L, 

35 mg/L, 10 mg/L, or 1 mg/L. Table 8 

of this document presents the estimated 

nationwide impacts of the alternative 

emission limits considered for 5,913 

bulk gasoline plants. Note that vapor 

balancing is projected to achieve 

emission reductions similar to that 

achieved by an emission limit of 35 mg/ 

L, but at much lower costs. Each loading 

rack emission limit option at bulk 

gasoline plants had a cost-effectiveness 

exceeding $275,000 per ton of HAP 

emissions reduced. Based on this 

analysis, we are not proposing to add an 

emission limit for bulk gasoline plants 

subject to NESHAP subpart BBBBBB. 

Our assessment of control options is 

summarized in the memorandum ‘‘Area 

Source Technology Review for the 

Gasoline Distribution Bulk Terminals, 

Bulk Plants, and Pipeline Facilities 

NESHAP’’ in EPA Docket No. EPA–HQ– 

OAR–2020–0371. 

TABLE 8—CONTROL OPTION IMPACTS FOR LOADING OPERATIONS AT AREA SOURCE BULK PLANTS

Emission limit 

VOC emission 

reduction a

(tpy) 

TCI b

($1,000) 

AOC c

($1,000/yr) 

TAC d

w/o product 

recovery 

($/yr) 

TAC d

w/product 

recovery 

($/yr) 

CEe

($/ton HAP)f

ICEg

($/ton HAP)f

Vapor Balancing ........... 23,739 42,310 2,116 7,140 -4,255 -4,481 -4,481 

80 mg/L ........................ 20,215 455,800 247,900 286,800 277,100 342,600 h 342,600 

35 mg/L ........................ 23,100 455,800 247,900 286,800 275,700 298,400 -12,000 

10 mg/L ........................ 24,969 455,800 247,900 286,800 274,800 275,100 -12,000 

1 mg/L .......................... 25,627 1,367,000 297,500 414,100 401,800 392,000 4,824,000 

a Compared to baseline (uncontrolled) emissions of 25,700 tpy. 

bTotal capital investment (TCI). 

cAnnual operating costs (AOC). 

dTotal annualized costs (TAC) considering annual operating costs and annualized cost of capital. 

e Cost effectiveness (CE) compared to baseline (uncontrolled). 

f HAP content assumed to be 4% of VOC. 

g Incremental cost effectiveness (ICE) compared to previous option in table. 

h ICE compared to submerged fill rather than previous option of vapor balancing. 


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6Part 60, subpart XX applies to bulk gasoline 

terminals that commenced construction, 

modification or construction after December 17, 

1980. This proposal would modify subpart XX so 

that it applies to bulk gasoline terminals that 

commenced construction, modification or 

reconstruction after December 17, 1980 and on or 

before the publication date of the proposed part 60, 

subpart XXa. 

7Allowance is provided to meet 80 mg/L for 

affected facilities with an ‘‘existing vapor 

processing system.’’ 

c. NSPS Subpart XXa 

The current NSPS (40 CFR part 60, 

subpart XX 6) that applies to bulk 

gasoline terminals (gasoline throughput 

exceeding 20,000 gallons per day) has a 

loading rack emission limit of 35 mg/L 

of gasoline loaded.7 We are proposing to 

add a new subpart at part 60, subpart 

XXa that would be applicable to bulk 

gasoline terminals that commenced 

construction, modification or 

reconstruction after June 10, 2022. 

In 40 CFR 60.501‘‘gasoline tank’’ is 

defined as ‘‘. . . a delivery tank 

truck. . . .’’ The major and area source 

NESHAP definition of ‘‘gasoline cargo 

tank’’ includes loading of tank trucks 

and railcars. In NSPS subpart XXa, we 

are proposing nomenclature revisions to 

generalize the loading requirements 

similar to the NESHAP definitions 

which apply to a ‘‘gasoline cargo tank’’ 

rather than just a ‘‘gasoline tank’’ to 

expressly include railcar loading 

operations. The control techniques and 

costs of control for loading operations 

apply equally to tank truck and rail car 

loading racks and we therefore find no 

basis for excluding rail car loading 

operations at bulk gasoline terminals 

from the NSPS requirements. 

Additionally, we assessed either 

maintaining the current NSPS 35 mg/L 

emission limit for loading operations or 

reducing it to either 10 mg/L or 1 mg/ 

L. We assessed costs differently between 

facilities that are new versus modified 

or reconstructed, because the 

incremental cost of designing a system 

to meet 1 mg/L versus 10 mg/L for a 

new system is small, but the costs for 

upgrading an existing control system 

that currently meets a 10 mg/L or 35 

mg/L emissions limit to meet 1 mg/L 

can be high and may require complete 

replacement of the existing controls. 

We projected nationwide impacts for 

different control options in the fifth year 

of the NSPS considering separately 5 

newly constructed bulk gasoline 

terminals and 15 modified or 

reconstructed facilities that currently 

meet a 35 or 80 mg/L emission limit. 

These costs are summarized in Table 9 

of this document. Considering the 

expected range of throughputs for newly 

constructed bulk gasoline terminals, the 

incremental cost to meet a 1 mg/L limit 

rather than a 10 mg/L limit is about 

$1,300 per ton of VOC reduced, which 

we determined is cost-effective. As 

shown in Table 9 of this document, the 

incremental cost for modified or 

reconstructed facilities to meet a 1 mg/ 

L limit rather than a 10 mg/L limit 

exceeds $8,300 per ton of VOC reduced, 

which we determined is not costeffective. The incremental cost for 

modified or reconstructed facilities to 

meet a 10 mg/L limit, on the other hand, 

rather than a 35 mg/L limit is about 

$350 per ton of VOC reduced, which we 

determined is cost-effective. Therefore, 

we are proposing in the proposed 

subpart XXa that facilities that 

commence construction after June 10, 

2022) must meet a 1 mg/L limit and 

facilities that commence modification, 

or reconstruction after June 10, 2022 

must meet a 10 mg/L limit. Our 

assessment of control options is 

summarized in the memorandum ‘‘New 

Source Performance Standards Review 

for Bulk Gasoline Terminals’’ in EPA 

Docket No. EPA–HQ–OAR–2020–0371. 

TABLE 9—CONTROL OPTION IMPACTS FOR LOADING OPERATIONS AT NSPS BULK GASOLINE TERMINALS

Emission limit VOC emissions 

(tpy) 

VOC emission 

reduction 

(tpy) 

TCI a

($1,000) 

AOC b

($/yr) 

TAC c

w/o product 

recovery 

($/yr) 

TAC c

w/product 

recovery 

($/yr) 

CEd

($/ton VOC) 

ICEe

($/ton VOC) 

New: 

Submerged Loading ..... 2,402 

35 mg/L ........................ 171 2,231 5,900 671,000 1,170,000 103,000 46 46 

10 mg/L ........................ 48 2,354 6,210 706,000 1,240,000 106,000 45 23 

1 mg/L .......................... 5 2,397 6,830 730,000 1,310,000 162,000 67 1,290 

Modified/Reconstructed: 

Submerged Loading ..... 332 

35 mg/L ........................ 286 46 0 19,500 19,500 ¥2,330 ¥51 ¥51 

10 mg/L ........................ 144 188 351 107,000 137,000 46,900 250 346 

1 mg/L .......................... 14 317 6,530 725,000 1,280,000 1,130,000 3,560 8,350 

aTotal capital investment (TCI). 

bAnnual operating costs (AOC). 

cTotal annualized costs (TAC) considering annual operating costs and annualized cost of capital. 

d Cost effectiveness (CE) compared to the first option listed. 

e Incremental cost effectiveness (ICE) compared to previous option in table. 

2. Standards for Cargo Tank Vapor 

Tightness 

The area source NESHAP subpart 

BBBBBB and the NSPS subpart XX both 

have vapor tightness requirements for 

cargo tanks that allow up to 3 inches of 

water pressure drop over a 5-minute 

period. The major source NESHAP 

subpart R has a graduated vapor 

tightness certification that allows from 1 

to 2.5 inches (′′) of water pressure drop 

over a 5-minute period, depending on 

the compartment size in the cargo tank. 

Further, DOT requirements that were 

last amended in 2003 (see 68 FR 19285, 

April 18, 2003) indicate ‘‘A cargo tank 

used to transport a petroleum distillate 

fuel that is equipped with vapor 

recovery equipment may be leakage 

tested in accordance with 40 CFR 

63.425(e)’’ [49 CFR 178.346–5]. As such, 

it appears that most cargo tanks (those 

less than 18 years of age) are minimally 

required to comply with the major 

source NESHAP vapor tightness 

requirements pursuant to the DOT 

requirements. In discussion with 

industry representatives, facility 

operators indicated there generally is a 

single vapor-tightness certification and 

cargo tanks are not certified for NSPS 

subpart XX or the area source NESHAP 

separate from cargo tanks certified for 

the major source NESHAP. Since cargo 

tanks can be used across gasoline 

distribution facilities subject to different 

standards, we considered cargo tank 

vapor-tightness requirements 

consistently across all rules. 

Another development we identified is 

state requirements for vapor tightness 

that have allowable pressure drops that 


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are half those allowed under the major 

source NESHAP subpart R. As such, we 

assessed options ranging from 

maintaining current requirements 

(which has different requirements for 

facilities subject to NESHAP subpart 

BBBBBB and NSPS subpart XX than for 

NESHAP subpart R); requiring NESHAP 

subpart R limits for all gasoline 

distribution facilities (including 

facilities subject to NESHAP subpart 

BBBBBB and NSPS subpart XX); and 

requiring more stringent vapor tightness 

requirements based on state 

requirements (half those in NESHAP 

subpart R) for all gasoline distribution 

facilities (across all three rules). Table 

10 of this document summarizes the 

results of these analyses. Based on these 

results, we concluded that the state rule 

requirements (one-half the current 

NESHAP subpart R requirements) are 

cost-effective developments that would 

further harmonize certification 

requirements across all gasoline 

distribution facilities and cargo tank 

operators. We also considered requiring 

even more stringent vapor tightness 

requirements, at about one-quarter of 

those in NESHAP subpart R, but these 

required allowable pressure drop limits 

that were less than the allowable 

precision of EPA Method 27. As such, 

we determined that further reductions 

of the vapor tightness requirements 

beyond those identified in state 

requirements have not been 

demonstrated in practice. Therefore, we 

are proposing to require a graduated 

vapor tightness certification from 0.5 to 

1.25 inches of water pressure drop over 

a 5-minute period, depending on the 

cargo tank compartment size for 

gasoline cargo tanks subject to NSPS 

subpart XXa, NESHAP subpart R and 

NESHAP subpart BBBBBB. Our 

assessment of control options is 

summarized in the memorandum 

‘‘Control Options for Loading Operation 

at Gasoline Distribution Facilities’’ in 

EPA Docket No. EPA–HQ–OAR–2020– 

0371. 

TABLE 10—IMPACTS FOR 10,000 CARGO TANKS UNDER DIFFERENT CONTROL OPTIONS

Option 

VOC 

emissions 

(tpy) 

VOC 

emission 

reduction 

(tpy) 

TAC a

w/o product 

recovery 

($/year) 

TAC a

w/product 

recovery 

($/year) 

CEb

($/ton VOC) 

CEb

($/ton HAP) c

ICEd

($/ton VOC) 

ICEd

($/ton HAP) c

3′′ water ................................................... 33,602 0 250,000 250,000 

NESHAP Subpart R (1′′–2.5′′ water) ....... 28,047 5,555 997,375 ¥1,669,14 ¥300 ¥7,512 ¥345 ¥8,637 

State Rule (0.5′′–1.25′′ water) ................. 25,718 7,883 1,766,000 ¥2,017,984 ¥256 ¥6,400 ¥150 ¥3,746 

aTotal annualized costs (TAC) considering annualized operating costs. 

b Cost effectiveness (CE) compared to baseline (3′′ water). c HAP content assumed to be 4% of VOC. 

d Incremental cost effectiveness (ICE) compared to previous option in table. 

3. Standards for Gasoline Storage 

Vessels 

The area source and major source 

NESHAP (subparts R and BBBBBB) have 

standards for storage vessels that are 

largely based on the requirements for 

volatile organic liquid storage vessels in 

40 CFR part 60, subpart Kb (NSPS 

subpart Kb), but include some 

exceptions to the NSPS subpart Kb 

requirements, primarily related to 

floating roof deck fitting controls. 

Because VOC emissions from storage 

vessels are regulated under NSPS 

subpart Kb, storage vessels are not part 

of affected facilities under NSPS subpart 

XX. 

We reviewed Federal, state, and local 

requirements for gasoline storage 

vessels. We identified potential 

improvements in the requirements for 

primary seals, secondary seals (for 

internal floating roofs), and improved 

fitting controls (particularly for 

guidepoles) as developments in 

practices and processes. Additionally, 

we identified a new practice for 

monitoring internal floating roof storage 

vessels using a lower explosive limit 

(LEL) monitor to identify floating roofs 

with poorly functioning seals or fitting 

controls. We assessed the cost and 

impacts of moving from the current 

standards to full compliance with NSPS 

subpart Kb requirements and for 

including LEL monitoring. Our 

assessments for each subpart are 

detailed in the following subsections. 

For more information on the storage 

vessel assessments, see memorandum 

‘‘Control Options for Storage Tanks at 

Gasoline Distribution Facilities’’ 

available in Docket No. EPA–HQ–OAR– 

2020–0371. 

a. NESHAP Subpart R 

The major source rule contains 

standards for gasoline storage vessels at 

bulk gasoline terminals and pipeline 

breakout stations. The standards crossreference NSPS subpart Kb 

requirements but exclude fitting control 

requirements in NSPS subpart Kb 

provided the storage vessel was already 

equipped with a floating roof meeting 

the seal requirements in NSPS subpart 

Kb. We estimated that about 95 percent 

of storage vessels in the gasoline 

distribution industry are equipped with 

internal floating roofs based on review 

of NEI data. We assessed costs and 

impacts of requiring fitting controls 

separately for internal and external 

floating roofs. Specifically, we evaluated 

the control options of (1) requiring 

upgrades of fitting requirements for 

external floating roofs and (2) requiring 

upgrades of fitting requirements for both 

external and internal floating roofs. 

Table 11 of this document summarizes 

the national impacts projected for major 

source gasoline distribution facilities. 

Based on our analysis, we determined 

installing/upgrading fitting controls for 

external floating roof tanks is cost 

effective. On the other hand, the 

projected cost-effectiveness of 

installing/upgrading fitting controls for 

internal floating roof tanks is 

approximately $350,000 per ton of HAP 

emissions reduced (incremental costs 

between Option 1 and 2), and therefore, 

we determined these controls are not 

cost effective. Accordingly, we are 

proposing to require fitting controls for 

external floating roof tanks consistent 

with the requirements in NSPS subpart 

Kb and are not proposing to require 

fitting controls for internal floating roof 

tanks. Our assessment of control options 

is summarized in the memorandum 

‘‘Major Source Technology Review for 

Gasoline Distribution Facilities (Bulk 

Gasoline Terminals and Pipeline 

Breakout Stations) NESHAP’’ in EPA 

Docket No. EPA–HQ–OAR–2020–0371. 


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TABLE 11—CONTROL OPTION IMPACTS FOR STORAGE VESSELS AT MAJOR SOURCE GASOLINE DISTRIBUTION FACILITIES

[Bulk terminals and pipeline breakout stations] 

Control option 

VOC 

emission 

reduction a

(tpy) 

TCI b

($1,000) 

TAC c w/o 

product 

recovery 

($1,000/yr) 

TAC c

w/product 

recovery 

($1,000/yr) 

CEd

($/ton VOC) 

CEd

($/ton HAP) e

ICEf

($/ton VOC) 

ICEf

($/ton HAP) e

Upgrade EFRT fittings g ........................... 546 1,857 173 ¥89 ¥164 ¥3,272 ¥164 ¥3,272 

Upgrade IFRT and EFRT fittings g ........... 772 45,240 4,205 3,835 4,966 99,320 17,330 346,500 

a Compared to baseline emissions of 4,977 tpy. 

bTotal capital investment (TCI). 

cTotal annualized costs (TAC) considering annual operating costs and annualized cost of capital. 

d Cost effectiveness (CE) compared to baseline. 

e HAP content assumed to be 5% of VOC. 

f Incremental cost effectiveness (ICE) compared to previous option in table. 

gEFRT = external floating roof tank; IFRT = internal floating roof tank. 

While we are not directly proposing 

additional fitting controls for internal 

floating roof tanks, we identified the use 

of LEL monitoring within the headspace 

of an internal floating roof tank as a 

means to enhance the annual 

inspections and more readily identify 

malfunctioning internal floating roofs. 

We estimated the cost of the LEL 

monitoring requirement based on the 

additional time needed to monitor LEL 

during the annual inspections. We 

estimated the impacts of annual LEL 

monitoring based on the number of 

internal floating roof tanks at major 

source gasoline distribution facilities 

and assuming LEL monitoring identifies 

defects in about 2 percent of internal 

floating roofs resulting in a 2 percent 

reduction in baseline emissions of 

internal floating roofs. Based on our 

review of available LEL monitoring data, 

we expect that this is a conservative 

estimate of the emission reductions that 

would be achieved. Table 12 of this 

document summarizes the projected 

impact of requiring annual LEL 

monitoring for internal floating roof 

tanks as part of the annual roof-top 

inspections. 

The added cost for conducting LEL 

monitoring is under $70 per year per 

tank and LEL monitoring is expected to 

result in cost-effective emission 

reductions for major source gasoline 

distribution facilities (costs of $4,200 

per ton of HAP reduced). Therefore, we 

are proposing to require LEL monitoring 

as part of the annual visual inspections 

conducted for internal floating roof 

tanks at major source gasoline 

distribution facilities. Our assessment of 

LEL monitoring at major sources is 

summarized in the memorandum 

‘‘Major Source Technology Review for 

Gasoline Distribution Facilities (Bulk 

Gasoline Terminals and Pipeline 

Breakout Stations) NESHAP’’ in EPA 

Docket No. EPA–HQ–OAR–2020–0371. 

TABLE 12—LEL MONITORING IMPACTS AT NATIONWIDE MAJOR SOURCE FACILITIES

Facility type 

VOC emission 

reduction 

(tpy) 

TAC a

w/o product 

recovery 

($/yr) 

TAC a

w/product 

recovery 

($/yr) 

CEb

($/ton VOC) 

CEb

($/ton HAP) c

Total Major Source Facilities ............................................... 82 56,290 17,130 210 4,200 

aTotal annualized cost (TAC) considering annual operating costs; there are no annualized cost of capital for this option. 

b Cost effectiveness (CE). 

c HAP content assumed to be 5% of VOC. 

b. NESHAP Subpart BBBBBB 

The area source rule contains 

standards for gasoline storage tanks at 

bulk gasoline plants, bulk gasoline 

terminals, and pipeline breakout 

stations. The current requirements for 

bulk gasoline plants require the use of 

submerged filling for all gasoline storage 

tanks with a capacity of greater than 250 

gallons. As noted in section III.A.1.b of 

this preamble, we are proposing to 

require vapor balancing at bulk plants, 

both when filling cargo tanks and when 

unloading cargo tanks (i.e., filling 

storage tanks). The use of vapor 

balancing when unloading cargo tanks 

into the storage tanks will reduce the 

working losses from the storage tanks. 

Several state and local agencies already 

require the use of vapor balancing when 

filling storage tanks at bulk plants with 

a maximum design capacity throughput 

of 4,000 gallons per day or more. Bulk 

plants with capacities below 4,000 

gallons per day would retain the 

requirement to use submerge fill. 

The storage tank standards for area 

source bulk gasoline terminals and 

pipeline breakout stations crossreference NSPS subpart Kb 

requirements or the National Emission 

Standards for Storage Vessels at 40 CFR 

part 63, subpart WW, but exclude the 

floating roof fitting control requirements 

for both internal and external floating 

roofs and secondary seal requirements 

for internal floating roofs with a vapormounted primary seal. We assessed 

costs and impacts of requiring fitting 

controls separately for internal and 

external floating roofs. Specifically, we 

evaluated the control options of (1) 

requiring upgrades of fitting 

requirements for external floating roofs 

consistent with NSPS subpart Kb 

requirements and (2) requiring upgrades 

of fitting requirements for external 

floating roof tanks plus requiring 

upgrades of fitting and seal 

requirements for internal floating roofs 

tanks consistent with NSPS subpart Kb 

requirements. Table 13 of this document 

summarizes the national impacts 

projected for area source gasoline 

distribution facilities. Again, based on 

our analysis, we consider adding fitting 

controls for external floating roof tanks 

at area source gasoline distribution 

facilities to be cost effective. 

Alternatively, the projected cost 

effectiveness of installing secondary 

seals and fitting controls for internal 

floating roof tanks is approximately 

$45,000 per ton of HAP emissions 

reduced (incremental costs between 

Option 1 and 2) and therefore, we 

determined these controls are not cost 

effective. Accordingly, we are proposing 

to require fitting controls for external 


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floating roof tanks consistent with the 

requirements in NSPS subpart Kb and 

are not proposing to revise the 

secondary seal and fitting control 

requirements for internal floating roof 

tanks. Our assessment of control options 

is summarized in the memorandum 

‘‘Area Source Technology Review for 

the Gasoline Distribution Bulk 

Terminals, Bulk Plants, and Pipeline 

Facilities NESHAP’’ in EPA Docket No. 

EPA–HQ–OAR–2020–0371. 

TABLE 13—CONTROL OPTION IMPACTS FOR STORAGE VESSELS AT AREA SOURCE GASOLINE DISTRIBUTION FACILITIES

[Bulk terminals and pipeline breakout stations] 

Control option 

VOC emission 

reduction a

(tpy) 

TCI b

($1,000) 

TAC c

w/o product 

recovery 

($1,000/yr) 

TAC c

w/product 

recovery 

($1,000/yr) 

CEd

($/ton VOC) 

CEd

($/ton HAP) e

ICEf

($/ton VOC) 

ICEf

($/ton HAP) e

(1) Upgrade EFRT fittings g ....... 3,338 9,488 882 ¥720 ¥216 ¥4,315 ¥216 ¥4,315 

(2) Upgrade IFRT and EFRT fittings g ..................................... 10,143 211,100 19,630 14,760 1,455 29,100 2,275 45,500 

a Compared to baseline emissions of 26,510 tpy. 

bTotal capital investment (TCI). 

cTotal annualized costs (TAC) considering annual operating costs and annualized cost of capital. 

d Cost effectiveness (CE) compared to baseline. 

e HAP content assumed to be 5% of VOC. 

f Incremental cost effectiveness (ICE) compared to previous option in table. 

gEFRT = external floating roof tank; IFRT = internal floating roof tank. 

As noted for major source gasoline 

distribution facilities, we identified the 

use of LEL monitoring within the 

headspace of an internal floating roof 

tank as a means to enhance the annual 

inspections and more readily identify 

malfunctioning internal floating roofs. 

We estimated the cost of the LEL 

monitoring requirement based on the 

additional time needed to monitor LEL 

during the annual inspections. We 

estimated the impact of annual LEL 

monitoring based on the number of 

internal floating roof tanks at area 

source gasoline distribution facilities 

and assuming LEL monitoring identifies 

defects in 2 percent of internal floating 

roofs resulting in a 2 percent reduction 

in the baseline emissions for internal 

floating roof tanks. Based on our review 

of available LEL monitoring data, we 

expect that this is a conservative 

estimate of the emission reductions that 

would be achieved. Table 14 of this 

document summarizes the projected 

impact of requiring annual LEL 

monitoring for internal floating roof 

tanks as part of the annual roof-top 

inspections for different types of area 

source gasoline distribution facilities. 

Our assessment of LEL monitoring at 

area sources is summarized in the 

memorandum ‘‘Area Source Technology 

Review for the Gasoline Distribution 

Bulk Terminals, Bulk Plants, and 

Pipeline Facilities NESHAP’’ in EPA 

Docket No. EPA–HQ–OAR–2020–0371. 

TABLE 14—NATIONWIDE LEL MONITORING IMPACTS FOR AREA SOURCE FACILITIES

Facility type 

VOC emission 

reduction 

(tpy) 

TAC a

w/o product 

recovery 

($/yr) 

TAC a

w/product 

recovery 

($/yr) 

CEb

($/ton VOC) 

CEb

($/ton HAP) c

Total Area Source Facilities ................................................. 430 353,200 146,700 341 6,820 

aTotal annualized costs (TAC) considering annual operating costs; there are no annualized cost of capital for this option. 

b Cost effectiveness (CE). 

c HAP content assumed to be 5% of VOC. 

Because area source gasoline 

distribution facilities are expected to 

have smaller storage tanks on average 

than major source facilities, LEL 

monitoring is expected to be somewhat 

less cost-effective for area source 

facilities than major source facilities. 

Nonetheless, LEL monitoring is 

projected to have costs of $6,800 per ton 

of HAP reduced when applied to 

internal floating roof tanks at area 

source gasoline distribution facilities. 

We consider these costs to be 

reasonable. Therefore, we are proposing 

to require LEL monitoring as part of the 

annual visual inspections conducted for 

internal floating roof tanks at area 

source bulk gasoline terminals and 

pipeline breakout stations. 

4. Standards for Equipment Leaks 

All gasoline distribution rules (40 

CFR part 60, subpart XX; 40 CFR part 

63, subparts R and BBBBBB) have 

standards for equipment leaks from 

equipment components in gasoline or 

gasoline vapor service. The current leak 

detection and repair (LDAR) program 

requirements rely on identifying leaks 

using AVO methods. We reviewed 

Federal, state, and local requirements 

for identifying and repairing equipment 

leaks. Although the option to use optical 

gas imaging (OGI) for monitoring 

equipment leaks has been available 

since 2008 in the General Provisions to 

40 CFR parts 60 and 63 as part of an 

alternative work practice to EPA 

Method 21 monitoring, the EPA has 

only recently proposed the use of OGI 

in leak detection surveys (40 CFR part 

60, Appendix K; see 86 FR 63110, 

November 15, 2021). Therefore, we 

considered OGI monitoring as a 

potential development in equipment 

leak monitoring. For each subpart, we 

assessed LDAR programs based on AVO, 

EPA Method 21, and OGI. We 

developed a Monte Carlo model to 

randomly initiate leaks from individual 

equipment components present at 

gasoline distribution facilities. We 

assumed no leaks were present initially 

and randomly generated leaks at the 

facility on a monthly basis for a period 

of 5 years. We assessed the emissions 

that occurred in the 5th year of the 

simulation to assess the relative 

performance of different LDAR 

programs. For more information on the 

Monte Carlo model and modeling 

assumptions used to assess alternative 


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equipment LDAR programs, see 

memorandum entitled ‘‘Control Options 

for Equipment Leaks at Gasoline 

Distribution Facilities’’ available in 

Docket No. EPA–HQ–OAR–2020–0371. 

Based on our Monte Carlo 

simulations, we found that periodic 

monitoring using EPA Method 21 with 

a leak definition of 10,000 ppmv 

achieved similar emission reductions as 

OGI monitoring at the same frequency. 

We evaluated options of (1) maintaining 

the monthly AVO inspections, (2) using 

instrument monitoring (EPA Method 21 

or OGI following Appendix K) on an 

annual basis, (3) using instrument 

monitoring on a semiannual basis, and 

(4) using instrument monitoring on a 

quarterly basis. The periodic instrument 

requirement also includes a requirement 

to fix any readily identified leaks 

observed using AVO methods during 

the normal duties. The results of our 

assessment of alternative LDAR 

programs by rule are detailed in the 

following subsections. 

Costs for EPA Method 21 monitoring 

and OGI monitoring were developed 

based on information collected from 

equipment leak monitoring contractors. 

OGI monitoring contractors commonly 

include a daily instrument rental 

charge, but they can monitor many more 

components per day than EPA Method 

21 monitoring contractors. For facilities 

with a large number of equipment 

components to be monitored, OGI 

monitoring costs less than EPA Method 

21 monitoring (the savings in time to 

conduct OGI monitoring more than 

makes up for the equipment rental 

charge). However, for facilities with a 

small number of equipment components 

to be monitored, EPA Method 21 

monitoring costs less than OGI 

monitoring because the time saving to 

conduct OGI monitoring is not 

significant enough to cover the added 

equipment rental charge. When 

evaluating ‘‘instrument monitoring’’ 

costs for different types of gasoline 

distribution facilities, we assumed 

facilities would elect to use the lowest 

cost instrument monitoring option 

between EPA Method 21 and OGI. For 

more information on the cost 

assumptions used to assess alternative 

equipment LDAR programs, see 

memorandum ‘‘Control Options for 

Equipment Leaks at Gasoline 

Distribution Facilities’’ available in 

Docket No. EPA–HQ–OAR–2020–0371. 

a. NESHAP Subpart R 

The major source rule contains 

equipment leak standards for bulk 

gasoline terminals and pipeline 

breakout stations. Prior to the initial 

performance test, the major source rule 

requires equipment leak monitoring to 

be conducted using EPA Method 21 

using a leak definition of 500 parts per 

million (ppm). The major source rule 

also requires subsequent monitoring 

monthly and allows the use of any leak 

identification method, including AVO 

techniques. We evaluated the current 

monthly AVO inspection requirements 

with LDAR programs based on periodic 

instrument monitoring. 

Table 15 of this document 

summarizes the projected impacts of 

requiring periodic instrument 

monitoring combined with a general 

requirement to fix any leaks identified 

(via AVO methods) during normal 

duties. For the major source gasoline 

distribution facilities (bulk gasoline 

terminals and pipeline breakout 

stations), OGI is the least costly of the 

instrument monitoring alternatives. 

Annual OGI instrument monitoring was 

projected to result in cost savings 

compared to monthly AVO inspections 

and semi-annual instrument monitoring 

was projected to be about the same cost 

as monthly AVO inspections. Even with 

uncertainty in the relative performance 

of monthly AVO monitoring, we 

conclude that periodic instrument 

monitoring along with a general 

requirement to fix any readily identified 

leaks during the normal course of 

activities yields similar to better 

reductions at a net cost savings. Our 

assessment of control options is 

summarized in the memorandum 

‘‘Major Source Technology Review for 

Gasoline Distribution Facilities (Bulk 

Gasoline Terminals and Pipeline 

Breakout Stations) NESHAP’’ in EPA 

Docket No. EPA–HQ–OAR–2020–0371. 

TABLE 15—ESTIMATED EMISSIONS AND COST IMPACTS OF EQUIPMENT LEAK CONTROL OPTIONS FOR MAJOR SOURCE

GASOLINE DISTRIBUTION FACILITIES

Option 

VOC 

emissions 

(tpy) 

VOC emission 

reduction 

(tpy) 

TCI a

($1000) 

TAC b

w/o product 

recovery 

($1000/yr) 

TAC b

w/product 

recovery 

($1000/yr) 

CEc

($/ton VOC) 

CEc

($/ton HAP) d

ICEe

($/ton VOC) 

ICEe

($/ton HAP) d

AVO (monthly inspection) ............ 1,124 

Annual instrument f 664 461 217.5 ¥380 ¥602 ¥1,310 ¥13,100 ¥1,310 ¥13,100 

Semiannual instrument f ................. 439 686 217.5 ¥47.8 ¥377 ¥550 ¥5,550 999 9,990 

Quarterly instrument f ................. 309 816 217.5 557 166 203 2,030 4,170 41,700 

aTotal capital investment (TCI). 

bTotal annualized costs (TAC) considering annual operating costs and annualized cost of capital. 

c Cost effectiveness (CE) compared to baseline (AVO). 

d HAP content assumed to be 10% of VOC. 

e Incremental cost effectiveness (ICE) compared to previous option in table. 

fFacilities would be allowed to select EPA Method 21 or OGI monitoring. If EPA Method 21 is selected, valves and pumps would be required to be monitored at the 

frequency specified, however, connectors are only monitored annually. If OGI is selected, all applicable valves, pumps, and connectors would be required to be monitored at the frequency specified. 

The semiannual instrument 

monitoring is projected to yield a net 

cost savings compared to monthly AVO 

inspections. The incremental costeffectiveness from going from annual to 

semiannual instrument monitoring is 

just under $10,000 per ton of HAP 

emissions reduced. Taken together, we 

determined that semiannual instrument 

monitoring is cost effective. The 

incremental cost-effectiveness of going 

to quarterly instrument monitoring is 

over $40,000 per ton of HAP emissions 

reduced; therefore, we determined this 

option is not cost-effective. Considering 

the developments in equipment leak 

monitoring practices, we are proposing 

to require semiannual instrument 

monitoring for major source gasoline 

distribution facilities. 

b. NESHAP Subpart BBBBBB 

The area source rule contains 

equipment leak standards for bulk 

gasoline terminals, pipeline breakout 

stations, bulk gasoline plants, and 

pipeline pumping stations. Prior to the 

initial performance test, the area source 


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rule requires equipment leak monitoring 

to be conducted using EPA Method 21 

using a leak definition of 500 ppm. The 

area source rule requires subsequent 

monitoring monthly and allows the use 

of any leak identification method, 

including AVO techniques. We 

evaluated the current monthly AVO 

inspection requirements with LDAR 

programs based on periodic instrument 

monitoring. 

Table 16 of this document shows the 

estimated impacts of applying 

instrument monitoring for equipment 

leaks at area source gasoline distribution 

facilities. For the smaller area source 

facilities, EPA Method 21 was generally 

less costly than OGI as an instrument 

monitoring method. For the larger area 

sources, we expect facilities to use OGI. 

The annual instrument monitoring 

requirement combined with a general 

requirement to fix any leaks identified 

(via AVO methods) during the normal 

course of activities is projected to be 

less costly than monthly AVO and yield 

additional emission reductions. Thus, 

we determined that annual instrument 

monitoring is cost effective. The relative 

cost of moving from annual monitoring 

to semi-annual monitoring is 

approximately $18,000 per ton of HAP 

removed which we determined is not 

cost-effective. Therefore, semi-annual 

instrument monitoring was rejected 

because of the high incremental costeffectiveness compared to annual 

instrument monitoring and we are 

proposing to require annual instrument 

monitoring combined with a 

requirement to repair any leaks 

identified (i.e., observed using AVO 

methods) during the course of regular 

business activities. Again, EPA is 

seeking comment on adopting more 

protective standards at costs above 

levels that we generally consider to be 

cost effective for these type of HAP 

given that many of these sources are 

located in highly populated areas where 

the communities surrounding these 

facilities already have the potential to be 

overburdened from multiple sources of 

air pollution. Our assessment of control 

options is summarized in the 

memorandum ‘‘Area Source Technology 

Review for the Gasoline Distribution 

Bulk Terminals, Bulk Plants, and 

Pipeline Facilities NESHAP’’ in EPA 

Docket No. EPA–HQ–OAR–2020–0371. 

TABLE 16—ESTIMATED EMISSIONS AND COST IMPACTS OF EQUIPMENT LEAK CONTROL OPTIONS FOR AREA SOURCE

GASOLINE DISTRIBUTION FACILITIES

Option 

VOC 

emissions 

(tpy) 

VOC emission 

reduction 

(tpy) 

TCI a

($1000) 

TAC b

w/o product 

recovery 

($1000/yr) 

TAC b

w/product 

recovery 

($1000/yr) 

CEc

($/ton VOC) 

CEc

($/ton HAP) d

ICEe

($/ton VOC) 

ICEe

($/ton HAP) d

AVO ....................... 17,080 

Annual instrument f 9,800 7,280 5,750 ¥4,180 ¥7,670 ¥1,050 ¥10,500 ¥1,050 ¥10,500 

Semiannual instrument f ................. 6,950 10,100 5,750 2,290 ¥2,570 ¥254 ¥2,540 1,790 17,900 

Quarterly instrument f ................. 5,320 11,800 5,750 14,600 8,980 764 7,640 7,100 71,000 

aTotal capital investment (TCI). 

bTotal annualized costs (TAC) considering annual operating costs and annualized cost of capital. 

c Cost effectiveness (CE) compared to baseline (AVO). 

d HAP content assumed to be 10% of VOC. 

e Incremental cost effectiveness (ICE) compared to previous option in table. 

fFacilities would be allowed to select EPA Method 21 or OGI monitoring. If EPA Method 21 is selected, valves and pumps would be required to be monitored at the 

frequency specified, however, connectors are only monitored annually. If OGI is selected, all applicable valves, pumps, and connectors would be required to be monitored at the frequency specified. 

c. NSPS Subpart XXa 

The NSPS subpart XX contains 

equipment leak standards for bulk 

gasoline terminals. Prior to the initial 

performance test, the NSPS requires 

monitoring to be conducted of the vapor 

collection system using EPA Method 21 

using a leak definition of 10,000 ppm. 

The NSPS also requires subsequent 

monitoring of the loading racks, vapor 

collection system and vapor processing 

system monthly using any leak 

identification method, including AVO 

techniques. 

Regarding monitoring requirements 

prior to performance tests, we 

determined that these requirements are 

effective requirements for the closed 

vent system used to transfer vapors from 

the loading racks to the control system. 

Generally, the EPA requires these closed 

vent systems to operate with no 

detectable emissions (which is defined 

as less than 500 ppmv above 

background using EPA Method 21). 

Both major and area source NESHAP 

subparts R and BBBBBB require the 

monitoring of the vapor collection 

system prior to a performance test using 

this no detectable emissions threshold 

(500 ppmv using EPA Method 21). 

Consistent with current practices for 

closed vent systems, we are proposing 

in subpart XXa to require that 

monitoring of the vapor collection 

system prior to a performance test be 

conducted using EPA Method 21 and 

that the vapor collection system be 

operated with no detectable emissions 

(no leaks greater than 500 ppmv). 

For the ongoing leak monitoring 

requirements, we evaluated the current 

monthly AVO inspection requirements 

compared to LDAR programs based on 

periodic instrument monitoring along 

with a general requirement to fix any 

leaks identified (via AVO methods) 

during the normal course of activities. 

Table 17 of this document provides 

estimated costs for newly affected bulk 

gasoline terminals. When considering 

VOC emission impacts, the overall cost 

effectiveness of the quarterly monitoring 

option is $259 per ton VOC reduced and 

the incremental cost effectiveness of 

quarterly monitoring compared to semiannual monitoring is $4,020 per ton of 

VOC reduced. Taken together, we 

determined that quarterly instrument 

monitoring is cost effective for reducing 

VOC emissions. Therefore, we are 

proposing to require quarterly 

monitoring for bulk gasoline terminals 

in NSPS subpart XXa along with a 

general requirement to fix any leaks 

identified (via AVO methods) during 

normal duties. Our assessment of 

control options is summarized in the 

memorandum ‘‘New Source 

Performance Standards Review for Bulk 

Gasoline Terminals’’ in EPA Docket No. 

EPA–HQ–OAR–2020–0371. 


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8U.S. EPA, Court Vacatur of Exemption From 

Emission Standards During Periods of Startup, 

Shutdown, and Malfunction. (86 FR 13819, March 

11, 2021). 

TABLE 17—ESTIMATED EMISSIONS AND COST IMPACTS OF EQUIPMENT LEAK CONTROL OPTIONS PER NEWLY AFFECTED

BULK GASOLINE TERMINAL

Option 

VOC 

emissions 

(tpy) 

VOC emission 

reduction 

(tpy) 

TCI a

($) 

TAC b w/o 

product 

recovery 

($/yr) 

TAC b

w/product 

recovery 

($/yr) 

CEc

($/ton VOC) 

ICEd

($/ton VOC) 

AVO (monthly inspection) ........................... 4.47 

Annual instrument e ...... 2.64 1.83 1,000 ¥1,240 ¥2,120 ¥1,160 ¥1,160 

Semiannual instrument e ....................... 1.74 2.73 1,000 60 ¥1,250 ¥458 962 

Quarterly instrument e .. 1.22 3.25 1,000 2,405 843 259 4,020 

aTotal capital investment (TCI). 

bTotal annualized costs (TAC) considering annual operating costs and annualized cost of capital. 

c Cost effectiveness (CE) compared to baseline (AVO). 

d Incremental cost effectiveness (ICE) compared to previous option in table. 

eFacilities would be allowed to select EPA Method 21 or OGI monitoring. If EPA Method 21 is selected, valves and pumps would be required 

to be monitored at the frequency specified, however, connectors are only monitored annually. If OGI is selected, all applicable valves, pumps, 

and connectors would be required to be monitored at the frequency specified. 

B. What other actions are we proposing, 

and what is the rationale for those 

actions? 

In addition to the proposed actions 

described above, we are proposing to 

remove exemptions from the 

requirement to comply during periods 

of startup, shutdown, and malfunction 

(SSM). We also are proposing changes to 

the recordkeeping and reporting 

requirements to require the use of 

electronic reporting of performance test 

reports and semiannual reports. We also 

are proposing to correct section 

reference errors and make other minor 

editorial revisions. Our rationale and 

proposed changes related to these issues 

are discussed below. 

1. SSM 

In its 2008 decision in Sierra Club v. 

EPA, 551 F.3d 1019 (DC Cir. 2008), the 

United States Court of Appeals for the 

District of Columbia Circuit (the court) 

vacated portions of two provisions in 

the EPA’s CAA section 112 regulations 

governing the emissions of HAP during 

periods of SSM. Specifically, the court 

vacated the SSM exemption contained 

in 40 CFR 63.6(f)(1) and (h)(1), holding 

that under section 302(k) of the CAA, 

emissions standards or limitations must 

be continuous in nature and that the 

SSM exemption violates the CAA’s 

requirement that some section 112 

standards apply continuously. With the 

issuance of the mandate in Sierra Club 

v EPA, the exemption language in 

63.6(f)(1) and (h)(1) are null and void 

and any cross reference to those 

provisions have no effect. 

In March 2021, the EPA issued a rule 8

to reflect the court vacatur that revised 

the 40 CFR part 63 General Provisions 

to remove the SSM exemptions at 40 

CFR 63.6(f)(1) and (h)(1). In this action, 

we are proposing to eliminate references 

to these SSM exemptions that are null 

and void, remove any additional SSM 

exemptions or references to SSM 

exemptions, and remove any crossreferences to provisions in 40 CFR part 

63 (General Provisions) that are 

unnecessary, inappropriate or 

redundant in the absence of the SSM 

exemption. The EPA determined the 

reasoning in the court’s decision in 

Sierra Club applies equally to CAA 

section 111. Consistent with Sierra Club 

v. EPA, the standards that we are 

proposing in NSPS subpart XXa would 

apply at all times. 

a. Proposed Elimination of the SSM 

Exemption in NESHAP Subpart R 

We are proposing the elimination of 

the vacated exemption provision and 

several revisions to Table 1 of this 

document, (the General Provisions 

Applicability Table to subpart R of part 

63, hereafter referred to as the ‘‘General 

Provisions table to subpart R’’) as is 

explained in more detail below. For 

example, we are proposing to eliminate 

the incorporation of the General 

Provisions’ requirement that the source 

develop an SSM plan. We also are 

proposing to eliminate and revise 

certain recordkeeping and reporting 

requirements related to the SSM 

exemption. The EPA has attempted to 

ensure that the provisions we are 

proposing to eliminate are 

inappropriate, unnecessary, or 

redundant in the absence of the SSM 

exemption. 

The EPA considers that processes at 

Gasoline Distribution facilities are not 

continuous and that there will be 

variation in emission stream 

characteristics over time. The standards 

consider this variation and provide 

sources the ability to meet the standards 

at all times. Therefore, we have not 

proposed alternate standards for startup 

and shutdown. 

Periods of startup, normal operations, 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

Malfunctions, in contrast, are neither 

predictable nor routine. Instead, they 

are, by definition, sudden, infrequent, 

and not reasonably preventable failures 

of emissions control, process, or 

monitoring equipment. (40 CFR 60.2 

and 63.2) (definition of malfunction). 

The EPA interprets CAA section 112 as 

not requiring emissions that occur 

during periods of malfunction to be 

factored into development of CAA 

section 112 standards and this reading 

has been upheld as reasonable by the 

D.C. Circuit in U.S. Sugar Corp. v. EPA, 

830 F.3d 579, 606–610 (2016). 

Therefore, the standards that apply 

during normal operation apply during 

periods of malfunction. 

We are also proposing the following 

revisions to the General Provisions table 

to subpart R as detailed below. 

1. General Duty 

We are proposing to revise the 

General Provisions table to subpart R 

entry for 40 CFR 63.6(e) by changing the 

‘‘yes’’ in column 2 to ‘‘no.’’ Section 

63.6(e) describes the general duty to 

minimize emissions and requirements 

for an SSM plan. Some of the language 

in that section is no longer necessary or 

appropriate in light of the elimination of 

the SSM exemption. We are proposing 

instead to add general duty regulatory 

text at 40 CFR 63.420(k) that reflects the 

general duty to minimize emissions 

while eliminating the reference to 

periods covered by an SSM exemption. 

The current language in 40 CFR 

63.6(e)(1)(i) characterizes what the 


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general duty entails during periods of 

SSM. With the elimination of the SSM 

exemption, there is no need to 

differentiate between normal operations, 

startup and shutdown, and malfunction 

events in describing the general duty. 

Section 63.6(e)(1)(ii) imposes 

requirements that are not necessary with 

the elimination of the SSM exemption 

or are redundant with the general duty 

requirement being added at 40 CFR 

63.420(k). Therefore, in addition to 

changing the applicability of 63.6(e) 

from ‘‘yes’’ to ‘‘no’’ in the table, the 

language the EPA is proposing for 40 

CFR 63.420(k) does not include the 

language from 40 CFR 63.6(e) 

2. SSM Plan 

As noted in the previous paragraph, 

the proposed revisions to the General 

Provisions table to subpart R for 40 CFR 

63.6(e) will also remove provisions to 

that require an SSM plan. Generally, the 

paragraphs under 40 CFR 63.6(e)(3) 

require development of an SSM plan 

and specify SSM recordkeeping and 

reporting requirements related to the 

SSM plan. As noted, the EPA is 

proposing to remove the SSM 

exemptions. Therefore, affected units 

are subject to an emission standard 

during such events. The applicability of 

a standard during such events will 

ensure that sources have ample 

incentive to plan for and achieve 

compliance and thus the SSM plan 

requirements are no longer necessary. 

3. Compliance With Standards 

We are proposing to revise the 

General Provisions table to subpart R 

entry for 40 CFR 63.6(f)(1) from ‘‘yes’’ in 

column 2 to ‘‘no.’’ As noted above, with 

the issuance of the mandate in Sierra 

Club v EPA, the exemption language in 

63.6(f)(1) and (h)(1) are null and void 

and any cross reference to those 

provisions have no effect. The EPA 

amended 40 CFR 63.6(f)(1) and (h)(1) on 

March 11, 2021, to reflect the court 

order and revise the CFR to remove the 

SSM exemption. However, the second 

sentence of 40 CFR 63.6(f)(1) contains 

language that is premised on the 

existence of an exemption and is 

inappropriate in the absence of the 

exemption. Thus, rather than crossreferencing 63.6(f)(1), we are adding the 

language of 63.6(f)(1) that requires 

compliance with standards at all times 

to the regulatory text at 40 CFR 

63.420(k). The court in Sierra Club 

vacated the exemptions contained in 

this provision and held that the CAA 

requires that some CAA section 112 

standards apply continuously. 

As noted in the General Provisions 

table to subpart R entry for 40 CFR 

63.6(h), there are no opacity standards 

in NESHAP subpart R, so the General 

Provisions at 40 CFR 63.6(h) were 

marked as ‘‘no’’ in column 2. There are 

visible emissions observations for flares, 

so we are proposing to revise the 

comment in column 3 to note that 

NESHAP subpart R specifies the 

requirements for visible emissions 

observations for flares. 

4. Performance Testing 

We are proposing to revise the 

General Provisions table to subpart R of 

Part 63 entry for 40 CFR 63.7(e)(1) by 

changing the ‘‘yes’’ in column 2 to a 

‘‘no.’’ Section 63.7(e)(1) describes 

performance testing requirements. The 

EPA is instead proposing to add a 

performance testing requirement at 40 

CFR 63.425(a). The performance testing 

requirements we are proposing to add 

differ from the General Provisions 

performance testing provisions in 

several respects. The regulatory text 

does not include the language in 40 CFR 

63.7(e)(1) that restated the SSM 

exemption and language that precluded 

startup and shutdown periods from 

being considered ‘‘representative’’ for 

purposes of performance testing. The 

proposed performance testing 

provisions specifically note the batch 

operation of gasoline loading operations 

and include periods when cargo tanks 

are being changed out when a full cargo 

tank is disconnected, and a new cargo 

tank is moved into position for loading. 

As in 40 CFR 63.7(e)(1), performance 

tests conducted under this subpart 

should not be conducted during 

malfunctions because conditions during 

malfunctions are often not 

representative of normal operating 

conditions. The EPA is proposing to add 

language that requires the owner or 

operator to record the process 

information that is necessary to 

document operating conditions during 

the test and include in such record an 

explanation to support that such 

conditions represent normal operation. 

Section 63.7(e)(1) requires that the 

owner or operator make such records 

‘‘as may be necessary to determine the 

condition of the performance test’’ 

available to the Administrator upon 

request but does not specifically require 

the information to be recorded. The 

regulatory text the EPA is proposing to 

add to this provision builds on that 

requirement and makes explicit the 

requirement to record the information. 

5. Monitoring 

We are proposing to revise the 

General Provisions table to subpart R of 

Part 63 by adding separate entries for 40 

CFR 63.8(c)(1)(i) and (iii) and including 

a ‘‘no’’ in column 2. The crossreferences to the general duty and SSM 

plan requirements in those 

subparagraphs are not necessary in light 

of other requirements of 40 CFR 63.8 

that require good air pollution control 

practices (40 CFR 63.8(c)(1)) and that set 

out the requirements of a quality control 

program for monitoring equipment (40 

CFR 63.8(d)). 

We are proposing to revise the major 

source General Provisions table to 

subpart R of Part 63 by splitting the 

entry for 40 CFR 63.8(d) into two 

separate entries, one for 40 CFR 

63.8(d)(1) and (2) and retaining the 

‘‘yes’’ in column 2 and one for 40 CFR 

63.8(d)(3) and including a ‘‘no’’ in 

column 2. The final sentence in 40 CFR 

63.8(d)(3) refers to the General 

Provisions’ SSM plan requirement 

which is no longer applicable. The EPA 

is proposing to add provisions to 

subpart R at 40 CFR 63.428(d)(4) that is 

identical to 40 CFR 63.8(d)(3) except 

that the final sentence is replaced with 

the following sentence: ‘‘The program of 

corrective action should be included in 

the plan as required under § 63.8(d)(2).’’ 

6. Recordkeeping 

We are proposing to revise the 

General Provisions table to subpart R of 

Part 63 by adding a separate entry for 40 

CFR 63.10(b)(2)(i), (ii), (iv) and (v) and 

including a ‘‘no’’ in column 2. 

• Section 63.10(b)(2)(i) describes the 

recordkeeping requirements for startup 

and shutdown periods when the source 

exceeds any applicable emission 

limitation in a relevant standard and 

section 63.10(b)(2)(ii) describes the 

recordkeeping requirements for 

malfunctions. We are instead proposing 

to add recordkeeping and reporting 

requirements of for all exceedances. 

The EPA is proposing to add such 

requirements to 40 CFR 63.428(g). The 

regulatory text we are proposing to add 

differs from the General Provisions it is 

replacing in that the General Provisions 

requires the creation and retention of a 

record of the occurrence and duration of 

each malfunction of process, air 

pollution control, and monitoring 

equipment. The EPA is proposing that 

this requirement apply to any failure to 

meet an applicable standard and is 

requiring that the source record the 

date, time, and duration of the failure 

rather than the ‘‘occurrence.’’ The EPA 

is also proposing to add requirements to 

40 CFR 63.428(g) that sources keep 

records that include a list of the affected 

source or equipment and actions taken 

to minimize emissions, an estimate of 

the quantity of each regulated pollutant 

emitted over the standard for which the 

source failed to meet the standard, and 


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35630 Federal Register / Vol. 87, No. 112 / Friday, June 10, 2022 / Proposed Rules 

a description of the method used to 

estimate the emissions. Examples of 

such methods would include productloss calculations, mass balance 

calculations, measurements when 

available, or engineering judgment 

based on known process parameters. 

The EPA is proposing to require that 

sources keep records of this information 

to ensure that there is adequate 

information to allow the EPA to 

determine the severity of any failure to 

meet a standard, and to provide data 

that may document how the source met 

the general duty to minimize emissions 

when the source has failed to meet an 

applicable standard. 

• We are proposing to revise the 

General Provisions table to subpart R of 

Part 63 entry for 40 CFR 63.10(b)(2)(iv) 

by changing the ‘‘yes’’ in column 2 to 

a ‘‘no.’’ Section 63.10(b)(2)(iv), when 

applicable, requires sources to record 

actions taken during SSM events when 

actions were inconsistent with their 

SSM plan. The requirement is no longer 

appropriate because SSM plans will no 

longer be required. The requirement 

previously applicable under 40 CFR 

63.10(b)(2)(iv)(B) to record actions to 

minimize emissions and record 

corrective actions is now applicable by 

the proposed requirements in 40 CFR 

63.428(g). 

• We are proposing to revise the 

General Provisions table to subpart R of 

Part 63 entry for 40 CFR 63.10(b)(2)(v) 

by changing the ‘‘yes’’ in column 2 to 

a ‘‘no.’’ Section 63.10(b)(2)(v), when 

applicable, requires sources to record 

actions taken during SSM events to 

show that actions taken were consistent 

with their SSM plan. The requirement is 

no longer appropriate because SSM 

plans will no longer be required. 

• We are proposing to revise the 

General Provisions table to subpart R of 

Part 63 by adding a separate entry for 40 

CFR 63.10(c)(15) and including a ‘‘no’’ 

in column 2. The EPA is proposing that 

40 CFR 63.10(c)(15) no longer apply. 

When applicable, the provision allows 

an owner or operator to use the affected 

source’s SSM plan or records kept to 

satisfy the recordkeeping requirements 

of the SSM plan, specified in 40 CFR 

63.6(e), to also satisfy the requirements 

of 40 CFR 63.10(c)(10) through (12). The 

EPA is proposing to eliminate this 

requirement because SSM plans would 

no longer be required, and, therefore, 40 

CFR 63.10(c)(15) no longer serves any 

useful purpose for affected units. 

7. Reporting 

We are proposing to revise the 

General Provisions table to subpart R of 

Part 63 entry for 40 CFR 63.10(d)(5) by 

changing the ‘‘yes’’ in column 2 to a 

‘‘no.’’ Section 63.10(d)(5) describes the 

reporting requirements for SSM. To 

replace the General Provisions reporting 

requirement, the EPA is proposing to 

add reporting requirements to 40 CFR 

63.428(m). The replacement language 

differs from the General Provisions 

requirement in that it eliminates 

periodic SSM reports as a stand-alone 

report. We are proposing language that 

requires sources that fail to meet an 

applicable standard at any time to report 

the information concerning such events 

in the semiannual report already 

required under this rule. We are 

proposing that the report must contain 

the number, date, time, duration, and 

the cause of such events (including 

unknown cause, if applicable), a list of 

the affected source or equipment, an 

estimate of the quantity of each 

regulated pollutant emitted over any 

emission limit, and a description of the 

method used to estimate the emissions. 

Examples of such methods would 

include product-loss calculations, mass 

balance calculations, measurements 

when available, or engineering 

judgment based on known process 

parameters. The EPA is proposing this 

requirement to ensure that there is 

adequate information to determine 

compliance, to allow the EPA to 

determine the severity of the failure to 

meet an applicable standard, and to 

provide data that may document how 

the source met the general duty to 

minimize emissions during a failure to 

meet an applicable standard. 

We will no longer require owners or 

operators to determine whether actions 

taken to correct a malfunction are 

consistent with an SSM plan, because 

plans would no longer be required. The 

proposed amendments at 63.10(d)(5), 

therefore, eliminate the cross-reference 

to 40 CFR 63.10(d)(5)(i) that contains 

the description of the previously 

required SSM report format and 

submittal schedule from this section. 

These specifications are no longer 

necessary because the events will be 

reported in otherwise required reports 

with similar format and submittal 

requirements. 

The proposed amendments at 

63.10(d)(5) will also eliminate the crossreference to 40 CFR 63.10(d)(5)(ii). 

Section 63.10(d)(5)(ii) describes an 

immediate report for startups, 

shutdown, and malfunctions when a 

source failed to meet an applicable 

standard but did not follow the SSM 

plan. We will no longer require owners 

or operators to report when actions 

taken during a startup, shutdown, or 

malfunction were not consistent with an 

SSM plan, because plans would no 

longer be required. 

b. Proposed Revisions To Address SSM 

Provisions in NESHAP Subpart BBBBBB 

We are proposing to remove 

references to malfunction throughout 

NESHAP subpart BBBBBB. Specifically, 

we are removing the requirements at 40 

CFR 63.11092(b)(1)(i)(B)(2)(iv), 

63.11092(b)(1)(iii)(B)(2)(iv), 

63.11092(d)(4), 63.11095(b)(4), and 

63.11095(d) and revising the 

requirements at 40 CFR 

63.11092(b)(1)(i)(B)(2)(v), 

63.11092(b)(1)(iii)(B)(2)(v), 63.11092(d), 

63.11092(d)(3), 63.11094(f)(4), and 

63.11094(g). We are also proposing 

limited revisions to Table 4 of this 

document (as proposed, formerly Table 

3), the General Provisions Applicability 

Table to subpart BBBBBB of part 63, 

hereafter referred to as the ‘‘General 

Provisions table to subpart BBBBBB’’ to 

address selected SSM provisions. 

NESHAP subpart BBBBBB was 

amended on January 24, 2011 (76 FR 

4156) to address SSM provisions. We 

are proposing one additional SSM 

revision. Specifically, we are proposing 

to revise the area source General 

Provisions table to subpart BBBBBB by 

splitting the entry for 40 CFR 63.8(d) 

into two separate entries, one for 40 CFR 

63.8(d)(1)–(2) and retaining the ‘‘yes’’ in 

column 2 and one for 40 CFR 63.8(d)(3) 

and including a ‘‘no’’ in column 2. The 

final sentence in 40 CFR 63.8(d)(3) 

refers to the General Provisions’ SSM 

plan requirement which is no longer 

applicable. The EPA is proposing to add 

provisions to subpart BBBBBB at 40 

CFR 63.11094(h) that is identical to 40 

CFR 63.8(d)(3) except that the final 

sentence is replaced with the following 

sentence: ‘‘The program of corrective 

action should be included in the plan as 

required under § 63.8(d)(2).’’ 

c. Proposal of NSPS Subpart XXa 

Without SSM Exemptions 

We are proposing standards in the 

NSPS subpart XXa that apply at all 

times. We are proposing that emission 

limits will apply at all times, including 

during SSM. The NSPS general 

provisions in 40 CFR 60.8(c) contains an 

exemption from non-opacity standards. 

We are proposing in NSPS subpart XXa 

specific requirements at 40 CFR 

60.500a(c) that override the general 

provisions for SSM. We are proposing 

that all standards in NSPS subpart XXa 

apply at all times. 

In proposing the standards in this 

rule, the EPA has taken into account 

startup and shutdown periods and, for 

the reasons explained below, has not 

proposed alternate standards for those 

periods. Startups and shutdowns are 

part of normal operations at Bulk 


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Federal Register / Vol. 87, No. 112 / Friday, June 10, 2022 / Proposed Rules 35631 

9https://www.epa.gov/electronic-reporting-airemissions/electronic-reporting-tool-ert. 

10See Gasoline Distribution Semiannual 

Reporting Template, available at Docket ID. No. 

EPA–HQ–OAR–2020–0371. 

11EPA’s Final Plan for Periodic Retrospective 

Reviews, August 2011. Available at: https://

www.regulations.gov/document?D=EPA-HQ-OA2011-0156-0154. 

12E-Reporting Policy Statement for EPA 

Regulations, September 2013. Available at: https:// 

www.epa.gov/sites/production/files/2016-03/ 

documents/epa-ereporting-policy-statement-2013- 

09-30.pdf. 

13 Digital Government: Building a 21st Century 

Platform to Better Serve the American People, May 

2012. Available at: https://

obamawhitehouse.archives.gov/sites/default/files/ 

omb/egov/digital-government/digitalgovernment.html. 

Gasoline Terminals. The proposed 

emission standards adequately control 

emissions during these startup and 

shutdown periods. 

Periods of startup, normal operations, 

and shutdown are all predictable and 

routine aspects of a source’s operations. 

Malfunctions, in contrast, are neither 

predictable nor routine. Instead they 

are, by definition, sudden, infrequent, 

and not reasonably preventable failures 

of emissions control, process, or 

monitoring equipment. (40 CFR 60.2). 

The EPA interprets CAA section 111 as 

not requiring emissions that occur 

during periods of malfunction to be 

factored into development of CAA 

section 111 standards. Nothing in CAA 

section 111 or in case law requires that 

the EPA consider malfunctions when 

determining what standards of 

performance reflect the degree of 

emission limitation achievable through 

‘‘the application of the best system of 

emission reduction’’ that the EPA 

determines is adequately demonstrated. 

While the EPA accounts for variability 

in setting emissions standards, the EPA 

is not required to treat a malfunction in 

the same manner as the type of variation 

in performance that occurs during 

routine operations of a source. A 

malfunction is a failure of the source to 

perform in a ‘‘normal or usual manner’’ 

and no statutory language compels EPA 

to consider such events in setting 

section 111 standards of performance. 

The EPA’s approach to malfunctions in 

the analogous circumstances (setting 

‘‘achievable’’ standards under section 

112) has been upheld as reasonable by 

the D.C. Circuit in U.S. Sugar Corp. v. 

EPA, 830 F.3d 579, 606–610 (D.C. Cir. 

2016). 

2. Electronic Reporting 

The EPA is proposing that owners and 

operators of gasoline distribution 

facilities submit electronic copies of 

required performance test reports, 

performance evaluation reports, and 

semi-annual reports through the EPA’s 

Central Data Exchange (CDX) using the 

Compliance and Emissions Data 

Reporting Interface (CEDRI). A 

description of the electronic data 

submission process is provided in the 

memorandum Electronic Reporting 

Requirements for New Source 

Performance Standards (NSPS) and 

National Emission Standards for 

Hazardous Air Pollutants (NESHAP) 

Rules, available in the docket for this 

action. 

The proposed rules require that 

performance test results collected using 

test methods that are supported by the 

EPA’s Electronic Reporting Tool (ERT) 

as listed on the ERT website 9 at the time 

of the test be submitted in the format 

generated through the use of the ERT or 

an electronic file consistent with the 

xml schema on the ERT website, and 

other performance test results be 

submitted in portable document format 

(PDF) using the attachment module of 

the ERT. Similarly, performance 

evaluation results of CEMS measuring 

relative accuracy test audit pollutants 

that are supported by the ERT at the 

time of the test must be submitted in the 

format generated through the use of the 

ERT or an electronic file consistent with 

the xml schema on the ERT website, and 

other performance evaluation results be 

submitted in PDF using the attachment 

module of the ERT. 

For semi-annual reports, the proposed 

rules require that owner and operators 

use the appropriate spreadsheet 

template to submit information to 

CEDRI. A draft version of the proposed 

templates for these reports are included 

in the docket for this action.10 The EPA 

specifically requests comment on the 

content, layout, and overall design of 

the templates. 

Additionally, the EPA has identified 

two broad circumstances in which 

electronic reporting extensions may be 

provided. These circumstances are (1) 

outages of the EPA’s CDX or CEDRI 

which preclude an owner or operator 

from accessing the system and 

submitting required reports and (2) force 

majeure events, which are defined as 

events that will be or have been caused 

by circumstances beyond the control of 

the affected facility, its contractors, or 

any entity controlled by the affected 

facility that prevent an owner or 

operator from complying with the 

requirement to submit a report 

electronically. Examples of force 

majeure events are acts of nature, acts 

of war or terrorism, or equipment failure 

or safety hazards beyond the control of 

the facility. The EPA is providing these 

potential extensions in NSPS subpart 

XXa to protect owners and operators 

from noncompliance in cases where 

they cannot successfully submit a report 

by the reporting deadline for reasons 

outside of their control. In both 

circumstances, the decision to accept 

the claim of needing additional time to 

report is within the discretion of the 

Administrator, and reporting should 

occur as soon as possible. These 

potential extensions are not necessary to 

add to NESHAP subpart R and NESHAP 

subpart BBBBBB, because they were 

recently added to the part 63, subpart A, 

General Provisions at 40 CFR 63.9(k). 

The electronic submittal of the reports 

addressed in these proposed 

rulemakings will increase the usefulness 

of the data contained in those reports, 

is in keeping with current trends in data 

availability and transparency, will 

further assist in the protection of public 

health and the environment, will 

improve compliance by facilitating the 

ability of regulated facilities to 

demonstrate compliance with 

requirements and by facilitating the 

ability of delegated state, local, tribal, 

and territorial air agencies and the EPA 

to assess and determine compliance, 

and will ultimately reduce burden on 

regulated facilities, delegated air 

agencies, and the EPA. Electronic 

reporting also eliminates paper-based, 

manual processes, thereby saving time 

and resources, simplifying data entry, 

eliminating redundancies, minimizing 

data reporting errors, and providing data 

quickly and accurately to the affected 

facilities, air agencies, the EPA, and the 

public. Moreover, electronic reporting is 

consistent with the EPA’s plan 11 to 

implement Executive Order 13563 and 

is in keeping with the EPA’s Agencywide policy 12 developed in response to 

the White House’s Digital Government 

Strategy.13 For more information on the 

benefits of electronic reporting, see the 

memorandum Electronic Reporting 

Requirements for New Source 

Performance Standards (NSPS) and 

National Emission Standards for 

Hazardous Air Pollutants (NESHAP) 

Rules, referenced earlier in this section. 

3. Technical and Editorial Changes 

We are proposing several technical 

amendments and definition revisions to 

improve the clarity and enforceability of 

the provision of the gasoline 

distribution facility standards. These 

additional proposed revisions and our 

rationale for the proposed revisions are 

described in this section. 


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35632 Federal Register / Vol. 87, No. 112 / Friday, June 10, 2022 / Proposed Rules 

a. Applicability Equations in NESHAP 

Subpart R 

The current major source rule 

includes applicability equations that 

can be used to exempt facilities from the 

major source requirements. The 

equations exclude all bulk gasoline 

terminals or pipeline breakout stations 

with an emissions screening factor (Et or 

Ep, respectively) of less than one. Upon 

reviewing the applicability equations, 

we determined the equations can 

potentially exempt facilities that are 

major sources of HAP emissions. 

Specifically, it is possible for gasoline 

storage tanks to be larger and have 

higher emissions than the model tanks 

used to derive the applicability 

equation. Additionally, the terms used 

in the different equations, particularly 

the fixed roof tank term, are different. A 

combination of tanks that exceeds 1 

(indicating major source facility) using 

the equation in paragraph 40 CFR 

63.420(b) for pipeline breakout stations 

can be below 1 (suggesting an area 

source facility) using the equation in 

paragraph 40 CFR 63.420(a) for bulk 

gasoline terminals. Thus, it appears 

some true major source facilities may 

only need to comply with major 

equipment counts associated with these 

applicability equations and not have 

ongoing requirements to ensure, for 

example, their floating roof seals are 

intact. Additionally, facilities that used 

these equations to become exempt from 

the major source rule are not covered by 

the area source rule if they are truly 

major sources of HAP emissions. In 

meeting with industry representatives, 

none of the industry representatives 

indicated that they used these equations 

to determine applicability with the rule. 

Therefore, we are proposing to remove 

the applicability equations in the major 

source rule to ensure that all major 

sources are subject to the emission 

limitations in NESHAP subpart R. 

b. Definitions of Bulk Gasoline 

Terminal, Pipeline Breakout Station, 

and Pipeline Pumping Station 

The major source rule applies to bulk 

gasoline terminals and to pipeline 

breakout stations. These terms are 

defined, but there appears to be 

significant potential overlap in these 

definitions. Based on the applicability 

equations and the fact that the loading 

rack requirements apply only to bulk 

gasoline terminals, the key difference 

between a bulk gasoline terminal and a 

pipeline breakout station is the presence 

(or absence) of gasoline loading racks. 

Application of subpart R requirements 

to ‘‘pipeline breakout station’’ facilities 

that have loading racks is inconsistent. 

We identified a title V permit that 

considers these separate affected 

facilities, with one portion of the facility 

regulated as a pipeline breakout station 

and the loading racks (and perhaps 

associated tanks and equipment) 

regulated as a bulk gasoline terminal. 

We also identified a title V permit 

where the loading racks at a pipeline 

breakout station were listed as having 

no applicable Federal requirements. To 

ensure consistent application of the rule 

and to clarify that all loading racks at 

major source facilities are to comply 

with the loading rack requirements in 

40 CFR 63.422, we are proposing to 

clarify the definitions of ‘‘bulk gasoline 

terminal’’ to clearly delineate that these 

facilities load gasoline into cargo tanks 

(i.e., have gasoline loading racks). 

Similarly, we are proposing to clarify 

the definitions of ‘‘pipeline breakout 

stations’’ to clearly delineate that these 

facilities do not have gasoline loading 

racks and that if a facility loads gasoline 

into cargo tanks, that facility is a bulk 

gasoline terminal. Since the 

requirements for storage vessels and 

equipment leak are the same for these 

facility types, the only difference the 

proposed revisions make is to clarify 

that loading racks at facilities that 

primarily transport gasoline via pipeline 

are still required to be meet the 

emission limitations for gasoline 

loading racks. 

We are also proposing similar 

definitions for area source standards 

(NESHAP subpart BBBBBB) and for 

NSPS subpart XXa. At 40 CFR 63.11088 

of the area source NESHAP, the header 

includes bulk gasoline terminals, 

pipeline breakout stations and pipeline 

pumping stations. However, Table 2 to 

subpart BBBBBB only specifies loading 

rack control requirements for ‘‘bulk 

gasoline terminal loading rack(s).’’ The 

proposed revisions to bulk gasoline 

terminals, pipeline breakout stations 

and pipeline pumping stations clarify 

that pipeline breakout stations and 

pipeline pumping stations do not 

contain loading racks. We are also 

proposing to revise the header of 40 CFR 

63.11088 to delete reference to pipeline 

breakout stations or pipeline pumping 

stations. For the NSPS subpart XXa, we 

are simply proposing the definition of 

bulk gasoline terminals consistent with 

the definitions being proposed in the 

major and area source NESHAP. 

c. Definition of Gasoline 

We are also proposing to add a 

definition of gasoline to NESHAP 

subpart R to clarify the definition of 

gasoline that applies to this subpart. The 

proposed definition is based on the 

definition in NSPS subpart XX and is 

consistent with the definition of 

gasoline in both NSPS subpart XXa and 

NESHAP subpart BBBBBB. 

d. Definition of Submerged Filling 

Because we are proposing in NSPS 

subpart XXa and NESHAP subpart R to 

require submerged filling when loading 

cargo tanks, we are also proposing to 

add a definition of ‘‘submerged filling’’ 

similar to the definition include in 

NESHAP subpart BBBBBB to clearly 

define this term for use in complying 

with the proposed requirements for 

submerged filling. Specifically, 

submerged filling is either the use of a 

pipe whose discharge is no more than 

the 6 inches from the bottom of the tank 

or the use of bottom filling. The 

proposed definitions of ‘‘submerged 

filling’’ in NSPS subpart XXa and 

NESHAP subpart R do not include 

references to stationary storage tanks 

that are included in the NESHAP 

subpart BBBBBB definition of 

‘‘submerged filling’’ because NSPS 

subpart XXa and NESHAP subpart R do 

not require submerged filling of storage 

tanks (although the floating roof 

requirements essentially demand use of 

submerged filling). 

e. Definition of Flare and Thermal 

Oxidation System 

We are proposing to further clarify the 

distinction between a flare and a 

thermal oxidation system. For the 

gasoline distribution rules, the term 

flare refers to thermal combustion 

system using an open flame (without 

enclosure), whereas a thermal oxidation 

system has an enclosed combustion 

chamber. Some flares may have shrouds 

or other ‘‘partial’’ enclosures, which 

make it difficult to classify these devices 

based on the current definitions. We are 

proposing to clarify the definition of a 

flare to include shrouded flares or flares 

with partial enclosures that are 

insufficient to capture the emitted 

pollutants and convey them to the 

atmosphere in a conveyance that can be 

used to conduct a performance test to 

determine the emissions. Thus, a 

performance test cannot be performed 

on a flare. We are also proposing to 

clarify that thermal oxidation systems 

are enclosed to the point that the 

pollutants are emitted through a 

conveyance that affords quantification 

of emissions through application of 

performance tests. This clarification is 

consistent with the current 

requirements to conduct initial 

performance tests for thermal oxidation 

systems but not for flares. 


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f. Additional Part 63 General Provision 

Revisions 

We are proposing to correct a 

typographical error in the General 

Provisions table to subpart R entry for 

40 CFR ‘‘63.1(a)(6)(8)’’ to delete ‘‘(8)’’. 

We expect that this was meant to 

reference paragraphs ‘‘(a)(6)–(8)’’ but 

paragraphs (a)(7) and (8) are reserved. 

Therefore, we are proposing to delete 

the ‘‘(8)’’ from this entry and add 

reference to paragraphs (a)(7) and (8) 

with the existing reference to 40 CFR 

63.1(a)(9) so the entry reads ‘‘63.1(a)(7)– 

(a)(9). We are proposing to revise the 

comment in column 3 to note these 

sections (plural) are reserved. 

We are proposing to correct a 

typographical error in the General 

Provisions table to subpart R entry for 

40 CFR ‘‘63.1(a)(12))–(14)’’ to delete ‘‘)– 

(14)’’. Paragraph (a)(12) is the last 

paragraph in 40 CFR 63.1(a) and the 

added ‘‘)’’ is a typographical error. 

We are proposing to revise the 

General Provisions table to subpart R 

entry for 40 CFR 63.1(b)(3) to change the 

‘‘no’’ in column 2 to ‘‘yes’’ and revise 

the comment in column 3. Paragraph 

(b)(3) requires records be kept for 

stationary sources within the source 

category, but not subject to the relevant 

standard. The comment explaining the 

‘‘no’’ indicated that ‘‘Subpart R specifies 

reporting and recordkeeping for some 

large area sources in § 63.428.’’ As noted 

in section III.B.3.a, we are proposing to 

remove the applicability equations and 

related recordkeeping and reporting 

requirements. Therefore, we are 

proposing that the General Provisions 

requirements in 40 CFR 63.1(b)(3) apply 

and revising the comment to note 

‘‘Except that subpart R specifies 

additional reporting and recordkeeping 

for some large area sources in § 63.428. 

These additional requirements only 

apply prior to the date the applicability 

equations are no longer applicable.’’ 

We are proposing to revise the 

General Provisions table to subpart R 

and General Provisions table to subpart 

BBBBBB to add a row for 40 CFR 

63.7(a)(4) and indicating a ‘‘yes’’ in the 

appropriate column. This is a recently 

added paragraph in the NESHAP 

General Provisions that describes 

procedures for requesting an extension 

in the case a force majeure event delays 

required performance testing. This 

paragraph did not exist in the NESHAP 

General Provisions when the major 

source and area source standards were 

developed, so no reference to this 

paragraph was included. We consider 

these provisions reasonable and should 

be available for Gasoline Distribution 

facilities in the unlikely event 

performance testing is delayed due to a 

force majeure event. 

We are proposing to revise the 

General Provisions table to subpart R 

and General Provisions table to subpart 

BBBBBB entries for 40 CFR 63.7(g) and 

63.8(e) to add that subparts R and 

BBBBBB specify how and when the 

performance test and performance 

evaluation results are reported. We are 

revising these comments to note that 

there are specific performance test and 

performance evaluation results 

reporting requirements in the major 

source and area source rules. 

We are proposing to revise the 

General Provisions table to subpart R 

rows for 40 CFR 63.1(c)(4), 63.5(b)(5), 

and 63.9(b)(3) from ‘‘yes’’ in column 2 

to ‘‘no’’ because these paragraphs are 

reserved. We are proposing to indicate 

these paragraphs are reserved in column 

3. We are also proposing to revise the 

General Provisions table to subpart R 

row for 40 CFR ‘‘63.4(a)(1)–(a)(3)’’ to 

‘‘63.4(a)(1)–(a)(2)’’ because 40 CFR 

63.4(a)(3) is reserved and no longer 

applies. We are also proposing to revise 

the General Provisions table to subpart 

R row for 40 CFR ‘‘63.4(a)(4)’’ to 

‘‘63.4(a)(3)–(a)(5)’’ to add reference to 

paragraph (a)(3) which we are proposing 

to remove from the previous table entry 

and to add reference to paragraph (a)(5) 

and delete the entry for 40 CFR 

63.4(a)(5). Paragraph (a)(5) is also 

reserved and no longer applies. We are 

proposing to revise the comment in 

column 3 for ‘‘63.4(a)(3)–(a)(5)’’ to note 

these sections (plural) are reserved. 

We are proposing to revise the 

General Provisions table to subpart R 

entry for 40 CFR 63.9(b)(2) from ‘‘no’’ in 

column 2 to ‘‘yes’’ and revising the 

comment to, ‘‘Except subpart R allows 

additional time for existing sources to 

submit initial notification. Sec. 

63.428(a) specifies submittal by 1 year 

after being subject to the rule or 

December 16, 1996, whichever is later.’’ 

We are proposing to revise the 

General Provisions table to subpart 

BBBBBB to add a row for 40 CFR 

63.9(b)(3) and indicating that this 

paragraph is reserved. This follows the 

manner in which reserved sections are 

included elsewhere in the General 

Provisions table to subpart R and 

General Provisions table to subpart 

BBBBBB (rather than being omitted). 

We are proposing to revise the 

General Provisions table to subpart R 

entry for 40 CFR 63.9(h)(1) through (3) 

to add that subpart R specifies how to 

submit the Notification of Compliance 

Status. We are revising this comment to 

note that there are specific submittal 

requirements in the major source rule. 

We are proposing to revise the 

General Provisions table to subpart 

BBBBBB entry for 40 CFR 63.9(h)(1)–(6) 

to provide separate entry ‘‘63.9(h)(4)’’ 

from ‘‘63.9(h)(1)–(3), (5)–(6)’’ and 

including ‘‘[Reserved]’’ in column 2 of 

the new 40 CFR 63.9(h)(4) entry because 

this General Provision paragraph is 

reserved. We are also proposing to 

revise the note for the revised entry 40 

CFR 63.9(h)(1)–(3), (5)–(6) to read ‘‘Yes, 

except as specified in § 63.11095(c)’’ 

rather than ‘‘Yes, except as specified in 

§ 63.11095(a)(4); also, there are no 

opacity standards’’ because we 

proposed revisions to reporting 

requirements in 40 CFR 63.11095 and 

proposed visible emission requirements 

for flares. 

We are proposing to revise the 

General Provisions table to subpart R 

and the General Provisions table to 

subpart BBBBBB entries for 40 CFR 

63.9(k) to delete, ‘‘only as specified in 

§ 63.9(j).’’ 

We are also proposing to clarify the 

General Provisions table to subpart 

BBBBBB entry for 40 CFR 63.10(c) to 

include ‘‘Subpart BBBBBB specifies 

CMS records.’’ As described in section 

III.B.1 of this preamble, we are also 

proposing revisions to NESHAP subpart 

BBBBBB recordkeeping requirements 

that detail the CMS records that must be 

kept, and we are proposing to include 

this additional note to clarify that these 

recordkeeping requirements apply 

rather than those outlined in the 

General Provisions. 

We are proposing to revise the 

General Provisions table to subpart R 

and General Provisions table to subpart 

BBBBBB entries for 40 CFR 63.10(d)(2) 

from ‘‘yes’’ to ‘‘no’’ because the subparts 

specify how and when the performance 

test results are reported. We are revising 

these comments to note that there are 

specific performance test and 

performance evaluation results 

reporting requirements in the major 

source and area source rules. 

We are proposing to revise the 

General Provisions table to subpart R 

entry for 40 CFR 63.10(d)(3) from ‘‘yes’’ 

to ‘‘no’’ because subpart R specifies 

reporting requirements for visible 

emissions observations for flares. 

We are proposing to revise the 

General Provisions table to subpart R to 

provide separate entries for 40 CFR 

63.10(e)(1) and (e)(2) through (4) and by 

changing the entries for 40 CFR 

63.10(e)(2) through (4) from ‘‘yes’’ in 

column 2 to a ‘‘no.’’ We are also 

proposing to revise the General 

Provisions table to subpart BBBBBB to 

revise the entries for 40 CFR 

63.10(e)(3)(i)–(iii), (iv)–(v), (vi)–(viii), 

and (e)(4) from ‘‘yes’’ in column 4 to a 


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‘‘no.’’ Given the transition to electronic 

reporting as described in section III.B.2 

of this preamble, we are also proposing 

to include electronic reporting for CEMS 

performance evaluations in the major 

and area source rules so the reporting 

requirements in 40 CFR 63.10(e)(2) are 

no longer applicable. Also, as described 

in section III.B.1 of this preamble, we 

are proposing all relevant CEMS 

deviation reporting requirements 

directly in 40 CFR 63.428(l) and similar 

reporting requirements in 40 CFR 

63.11095(e), rather than relying on 

cross-reference to 40 CFR 63.10(e)(3). 

These edits are not expected to alter the 

reporting burden; however, the direct 

inclusion of the 40 CFR 63.10(e)(3) 

reporting requirements into 40 CFR 

63.428(l) and 40 CFR 63.11095(e) will 

provide clarity of the reporting 

requirements to gasoline distribution 

owners and operators. 

We are proposing to revise the 

General Provisions table to subpart R 

entry for 40 CFR 63.11(a)–(b) to add the 

comment, ‘‘Except these provisions no 

longer apply upon compliance with the 

provisions in § 63.425(a)(2) for flares to 

meet the requirements specified in 

§§ 60.502a(c)(3) and 60.504a(c) of this 

chapter.’’ 

We are proposing to revise the 

General Provisions table to subpart 

BBBBBB to include missing entries for 

40 CFR 63.11(a) and 63.11(c)–(e). 40 

CFR 63.11(a) specifies the applicability 

of § 63.11 and we are proposing to 

include ‘‘yes’’ in column 4 to clarify that 

this paragraph applies. 40 CFR 63.11(c)– 

(e) describe alternative work practice 

standards for using optical gas imaging 

as an alternative to EPA Method 21 for 

monitoring equipment for leaks. We are 

proposing to include ‘‘no’’ in column 4 

because the proposed leak monitoring 

provisions specifically allow the use of 

optical gas imaging for leak detection. 

We are also proposing for revise the 

comment in column 4 of the entry for 

40 CFR 63.11(b) to read, ‘‘Yes, until 

compliance with the flare provisions in 

Item 2.b of Table 3 to Subpart 

BBBBBB.’’ As described in Section 

III.A.1 of this preamble, we are 

proposing more detailed provisions for 

operating and monitoring flares to 

ensure the performance of flares used as 

control devices. After compliance with 

these flare provisions in Item 2.b of 

Table 3 to Subpart BBBBBB, the 

provisions in NESHAP subpart BBBBBB 

apply rather than those specified in for 

40 CFR 63.11(b). 

We are proposing to revise the 

General Provisions table to subpart R to 

revise the entries for 40 CFR 63.12(a)– 

(c) from ‘‘63.12(a)–(c)’’ to ‘‘63.12’’, for 40 

CFR 63.13(a)–(c) from ‘‘63.13(a)–(c)’’ to 

‘‘63.13’’, for 40 CFR 63.14(a)–(b) from 

‘‘63.14(a)–(b)’’ to ‘‘63.14’’, and for 40 

CFR 63.15(a)–(b) from ‘‘63.15(a)–(b)’’ to 

‘‘63.15’’. 

We are proposing to revise the 

General Provisions table to subpart R 

and the General Provisions table to 

subpart BBBBBB to add a row for 40 

CFR 63.16 and indicating a ‘‘yes’’ in the 

appropriate column. This paragraph in 

the NESHAP General Provisions, which 

describes special reporting provision for 

Performance Track member facilities 

procedures, was missing from the major 

source and area source General 

Provisions tables and adding it provides 

clarity regarding the applicability of 

these special provisions. 

g. Editorial Corrections 

The EPA is proposing an additional 

change that addresses technical and 

editorial corrections for 40 CFR part 63, 

subpart BBBBBB as follows. 

• Revise 40 CFR 63.11100, definition 

of ‘‘vapor-tight gasoline cargo tank’’ to 

update cross-reference to annual 

certification test requirements from in 

§ 63.11092(f) to § 63.11092(g) based on 

location of this provision in the 

proposed amendments. 

C. What compliance dates are we 

proposing, and what is the rationale for 

the proposed compliance dates? 

1. NESHAP Subpart R 

The EPA is not proposing to revise the 

primary loading rack emission limits for 

the major source NESHAP subpart R; 

however, we are proposing to revise the 

format of the standard and certain 

testing and monitoring provisions. We 

are proposing to maintain the current 

compliance options until the time that 

a new performance test or performance 

evaluation is conducted. We are 

proposing that performance tests for 

loading racks with thermal oxidation 

systems be required at least once every 

60 months. We are proposing that 

owners or operators must conduct a 

performance test within three years of 

the promulgation of the proposed 

standards if the thermal oxidation 

system has not been tested by that time 

in the past 60 months. Because we are 

proposing to revise the ongoing 

performance requirements in some 

cases, we consider three years is as 

expedient as can be required for 

facilities that may have to purchase and 

install new monitoring systems. For 

vapor recovery systems, we are 

proposing to revise the format of the 

standard and require a CEMS to 

demonstrate continuous compliance. 

While we expect most vapor recovery 

systems have continuous TOC monitors, 

some owners or operators may need to 

upgrade their monitoring system to 

comply with the proposed CEMS 

requirements. We consider 3 years is as 

expedient as can be required 

considering the potential need to 

upgrade or replace TOC monitoring 

systems. For facilities using flares, we 

are proposing to require the more 

detailed requirements in the Refinery 

MACT Rule (40 CFR part 63, subpart 

CC). For these provisions, we allow up 

to 3 years to meet the new operating and 

monitoring requirements, consistent 

with the timeframe we provided for 

petroleum refineries when first 

proposing those requirements. The new 

requirements may require substantial 

upgrades to monitoring systems and 3 

years is as expedient as can be required 

considering the number of monitoring 

systems to be upgraded. 

We are proposing revisions to the 

cargo tank vapor tightness requirements 

apply no later than 3 years after the 

promulgation date of the proposed 

standards. Facilities that conduct the 

cargo tank certifications will need time 

to review and implement the new vapor 

tightness requirements and it will take 

at least one year after they implement 

the new vapor tightness requirements 

before the fleet of cargo tanks can be 

certified at the new vapor tightness 

levels. 

We are proposing revisions to the 

storage vessel requirements for both 

internal and external floating roofs. For 

external floating roofs, we are proposing 

to require fitting controls, which will 

require the degassing of the storage 

vessel. We are proposing that these 

controls be installed at the first 

degassing of the storage vessel after 3 

years from the promulgation date of the 

proposed standards, but in no case more 

than 10 years from the promulgation 

date of the proposed standards. We are 

allowing 3 years to identify storage 

vessels that need to be upgraded and 

identify appropriate fitting control 

systems that need to be installed. We are 

allowing up to 10 years in order to align 

the installation of the controls with a 

planned degassing event, to the extent 

practicable, to minimize the offsetting 

emissions that occur due to a degassing 

event solely to install the fitting 

controls. For internal floating roofs, we 

are proposing to add LEL monitoring 

requirements. Compliance with this 

requirement may require significant 

upgrades of the internal floating roof. 

For example, internal floating roofs are 

typically installed in pieces, with the 

pieces either welded or riveted together. 

Welded roofs do not have ‘‘seam’’ 

emissions whereas riveted roofs have 

emission losses from these seams. While 


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Federal Register / Vol. 87, No. 112 / Friday, June 10, 2022 / Proposed Rules 35635 

the current rule requirements do not 

prohibit the use of riveted seams for the 

internal floating roof, poor rivet closures 

along the seams could result in excess 

emissions wherein the LEL limit may be 

exceeded. In these cases, it is likely a 

new roof would need to be installed, or 

at minimum, the seams repaired or 

welded. Because the LEL emissions 

limitation may require full replacement 

of existing internal floating roofs, we are 

proposing to provide up to 3 years to 

comply with these new requirements. 

We are proposing new requirements 

to conduct instrument monitoring to 

identify equipment leaks. This 

requirement will require owners or 

operators to identify all affected 

equipment components, implement 

training on the new requirements, and 

identify contractors to conduct the 

instrument monitoring. Therefore, we 

are proposing to provide up to 3 years 

to comply with these new requirements. 

We are proposing to phase out the 

applicability equations. While we 

expect very few facilities may be using 

these equations while otherwise being a 

major source, facilities that may be 

using these equations could require 

significant upgrades to their existing 

control systems. As such, we 

determined that three years be provided 

for the phase out of these applicability 

equations. 

We are proposing to revise the 

General Provisions applicability table to 

remove references to vacated provisions. 

As these provisions have been vacated 

for several years, we are proposing that 

these revisions be applicable upon 

promulgation. We do not expect any of 

the proposed revisions will increase 

burden to any facility and can be 

implemented without delay. 

We are proposing to require electronic 

reporting. We are providing up to 3 

years to comply with these new 

provisions. Because we are proposing to 

allow owners or operators to comply 

with existing requirements and 

electronic reporting forms will not be 

available for the existing reporting 

requirements, it is expedient to 

harmonize the timing of the proposed 

revisions to the electronic reporting 

requirements with the revisions to the 

requirements. 

2. NESHAP Subpart BBBBBB 

The EPA is proposing to revise the 

primary loading rack emission limits for 

the large bulk gasoline terminals and 

bulk plants at area source gasoline 

distribution facilities subject to 

NESHAP subpart BBBBBB. We are also 

proposing to revise the format of the 

standard and certain testing and 

monitoring provisions. We are 

proposing up to 3 years to meet the new 

emission limits and operating and 

monitoring requirements. These 

revisions may require significant control 

system upgrades and monitoring system 

installations. We determined that 3 

years is as expedient as can be required 

considering the number of control 

systems and monitoring systems to be 

upgraded. 

We are proposing revisions to the 

cargo tank vapor tightness requirements 

apply no later than 3 years after the 

promulgation date of the proposed 

standards. Facilities that conduct the 

cargo tank certifications will need time 

to review and implement the new vapor 

tightness requirements and it will take 

at least one year after they implement 

the new vapor tightness requirements 

before the fleet of cargo tanks can be 

certified at the new vapor tightness 

levels. 

We are proposing revisions to the 

storage vessel requirements for both 

internal and external floating roofs. For 

external floating roofs, we are proposing 

to require fitting controls, which will 

require the degassing of the storage 

vessel. We are proposing that these 

controls be installed at the first 

degassing of the storage vessel after 3 

years from the promulgation date of the 

proposed standards, but in no case more 

than 10 years from the promulgation 

date of the proposed standards. We are 

allowing 3 years to identify storage 

vessels that need to be upgraded and 

identify appropriate fitting control 

systems that need to be installed. We are 

allowing up to 10 years in order to align 

the installation of the controls with a 

planned degassing event, to the extent 

practicable, to minimize the offsetting 

emissions that occur due to a degassing 

event solely to install the fitting 

controls. For internal floating roofs, we 

are proposing to add LEL monitoring 

requirements. Compliance with these 

requirements may require significant 

upgrades of the internal floating roof. 

Therefore, we are proposing to provide 

up to 3 years to comply with these new 

requirements. 

We are proposing new requirements 

to conduct instrument monitoring to 

identify equipment leaks. This 

requirement will require owners/ 

operators to identify all affected 

equipment components, implement 

training on the new requirements, and 

identify contractors to conduct the 

instrument monitoring. Therefore, we 

are proposing to provide up to 3 years 

to comply with these new requirements. 

We are proposing to revise the 

General Provisions applicability table to 

remove references to vacated provisions. 

As these provisions have been vacated 

for several years, we are proposing that 

these revisions be applicable upon 

promulgation. We do not expect any of 

the proposed revisions will increase 

burden to any facility and can be 

implemented without delay. 

We are proposing to require electronic 

reporting. We are providing up to 3 

years to comply with these new 

provisions. Because we are proposing to 

allow owners or operators to comply 

with existing requirements and 

electronic reporting forms will not be 

available for the existing reporting 

requirements, it is expedient to 

harmonize the timing of the proposed 

revisions to the electronic reporting 

requirements with the revisions to the 

requirements. 

3. NSPS Subpart XXa 

We are proposing that all bulk 

gasoline terminal sources that 

commenced construction, 

reconstruction, or modification on or 

after June 10, 2022, would need to meet 

the requirements of 40 CFR part 60, 

subpart XXa upon startup of the new, 

reconstructed or modified facility or the 

effective date of the final rule, 

whichever is later. This proposed 

compliance schedule is consistent with 

the requirements in Section 111(e) of 

the CAA. 

IV. Summary of Cost, Environmental, 

and Economic Impacts 

A. What are the affected sources? 

There are approximately 9,500 

facilities subject to the Gasoline 

Distribution NESHAP and the Bulk 

Gasoline Terminals NSPS. An estimated 

210 facilities are classified as major 

sources and more than 9,250 are area 

sources. We estimated there would be 5 

new facilities and 15 modified/ 

reconstructed subject to the NSPS in the 

next 5 years. 

B. What are the air quality impacts? 

This proposed action would reduce 

HAP and VOC emissions from the 

Gasoline Distribution NESHAP and the 

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 proposed 

action 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 subpart 

are listed below. 


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35636 Federal Register / Vol. 87, No. 112 / Friday, June 10, 2022 / Proposed Rules 

14U.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-scienceassessment-isa-ozone-and-related-photochemicaloxidants. 

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 proposed action would not have any 

secondary pollutant impacts. More 

information about the estimated 

emission reductions and secondary 

impacts of this proposed action for the 

major source rule can be found in the 

document, ‘‘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 proposed action 

would 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 proposed 

action for the area source rule can be 

found in the document, ‘‘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 proposed action 

would result in additional emissions of 

2,229 tpy of carbon dioxide, 2 tpy of 

nitrogen oxides, and 1 tpy of sulfur 

dioxide. More information about the 

estimated emission reductions and 

secondary impacts of this proposed 

action for the NSPS can be found in the 

document, ‘‘New Source Performance 

Standards Review for Bulk Gasoline 

Terminals.’’ 

C. What are the cost impacts? 

This proposed action would cost (in 

2019 dollars) approximately $66.8 

million in total capital costs and total 

annualized cost savings of $3.42 million 

per year (including product recovery), 

based on our analysis of the proposed 

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 proposed action would 

cost approximately $2.07 million in 

total capital costs and $2.11 million per 

year in total annualized costs (including 

product recovery). More information 

about the estimated cost of this 

proposed action for the major source 

rule can be found in the document, 

‘‘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 proposed action would 

cost approximately $57.6 million in 

total capital costs and have cost savings 

of $5.91 million per year in total 

annualized costs (including product 

recovery). More information about the 

estimated cost of this proposed action 

for the area source rule can be found in 

the document, ‘‘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 

proposed action would cost 

approximately $7.20 million in total 

capital costs and $387,000 per year in 

total annualized costs (including 

product recovery). More information 

about the estimated cost of this 

proposed action for the NSPS can be 

found in the document, ‘‘New Source 

Performance Standards Review for Bulk 

Gasoline Terminals.’’ 

D. What are the economic impacts? 

The EPA conducted economic impact 

analyses for this proposal, Regulatory 

Impact Analysis, which is available in 

the docket for this action. The economic 

impact analyses contain two parts. The 

economic impacts of the proposal 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 the average 

small entity impacted by the proposal 

will incur total annualized costs of 0.42 

percent of their revenue, with none 

exceeding 6.75 percent. We estimate 

fewer than 10 percent of impacted small 

entities will incur total annualized costs 

greater than 1 percent of their revenue, 

and fewer than 5 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 are 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 the Regulatory 

Flexibility Act (RFA) later in this 

preamble and in the Regulatory Impact 

Analysis (RIA) for this proposed 

rulemaking. 

The EPA also prepared a model of the 

U.S. gasoline market in order to project 

changes caused by the rulemaking to the 

price and quantity of gasoline sold from 

2026 to 2040. Using this model, the 

price of gasoline is projected to rise by 

less than .003 percent in all years from 

2026 to 2040, whereas the quantity of 

gasoline consumed is projected to fall 

by less than .001 percent in all years 

from 2026 to 2040. These projections 

consider the costs imposed by 

amendments to NESHAP subpart 

BBBBBB, NESHAP subpart R, and 

amendments to NSPS subpart XX (as 

proposed in subpart XXa). 

Thus, these economic impacts are low 

for affected companies and the 

industries impacted by this proposed 

rulemaking, and there will not be 

substantial impacts on the markets for 

affected products. The costs of the 

proposal 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. The 

RIA for this proposed rulemaking 

includes more details and discussion of 

these projected impacts. 

E. What are the benefits? 

The emission controls installed to 

comply with these proposed rules 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 ozonerelated 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) 14 as 

summarized in the Technical Support 

Document for the Final Revised Cross 


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Federal Register / Vol. 87, No. 112 / Friday, June 10, 2022 / Proposed Rules 35637 

15U.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. 16https://www.epa.gov/environmentaljustice. 

State Air Pollution Rule Update.15 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. 

In brief, the Ozone ISA found shortterm (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 longterm effects for the 15-year analysis 

period of these rules discounted back to 

2022 rounded to 2 significant figures. 

For the full set of underlying 

calculations see the Gasoline 

Distribution Benefits workbook (docket 

number EPA–HQ–OAR–2020–0371). In 

addition, we include the monetized 

disbenefits from additional CO2 

emissions using a 3 percent rate, which 

occur with NESHAP subpart BBBBBB 

and NSPS XXa, but not NESHAP 

subpart R since there are no additional 

CO2 emissions as a result of this 

proposed rule. 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). Due to methodology and 

data limitations, we did not attempt to 

monetize the health benefits of 

reductions in HAP in this analysis. A 

qualitative discussion of the health 

effects associated with HAP emitted 

from sources subject to control under 

the proposed action is included in the 

Regulatory Impact Analysis for the 

proposed action. 

1. NESHAP Subpart R 

The PV of the benefits for the 

proposed amendments for NESHAP 

subpart R are $9.9 million at the 3 

percent discount rate to $5.6 million at 

the 7 percent discount rate for shortterm effects and $81 million at the 3 

percent discount rate to $48 million at 

the 7 percent discount rate for long-term 

effects. The EAV of the benefits for the 

proposed amendments for NESHAP 

subpart R are $0.83 million at the 3 

percent discount rate to $0.65 million at 

the 7 percent discount rate for shortterm effects and $6.8 million at the 3 

percent discount rate to $5.3 million at 

the 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 proposed 

amendments for NESHAP BBBBBB are 

$160 million at the 3 percent discount 

rate to $83 million at the 7 percent 

discount rate for short-term effects and 

$1,500 million at the 3 percent discount 

rate to $870 million at the 7 percent 

discount rate for long-term. The EAV of 

the benefits for the proposed 

amendments for NESHAP BBBBBB are 

$13 million at the 3 percent discount 

rate to $9.7 million at the 7 percent 

discount rate for short-term effects and 

$120 million at the 3 percent discount 

rate to $97 million at the 7 percent 

discount rate for long-term effects. 

3. NSPS Subpart XXa 

Because the estimated emissions 

reductions due to this rule are small and 

because we cannot be confident of the 

location of new facilities under the 

NSPS, the EPA elected to use the benefit 

per-ton (BPT) approach. BPT estimates 

provide the total monetized human 

health benefits (the sum of premature 

mortality and premature morbidity) of 

reducing one ton of the VOC precursor 

for ozone from a specified source. 

Specifically, in this analysis, we 

multiplied the estimates from the 

‘‘Gasoline Distribution’’ sector by the 

corresponding emission reductions. 

The PV of the net benefits (monetized 

health benefits minus monetized 

climate disbenefits) for the proposed 

NSPS subpart XXa are $25 million at the 

3 percent discount rate to $12 million at 

the 7 percent discount rate for shortterm effects and $240 million at the 3 

percent discount rate to $130 million at 

the 7 percent discount rate for long-term 

effects. The EAV of the benefits for the 

proposed NSPS subpart XXa are $2.0 

million at the 3 percent discount rate to 

$1.4 million at the 7 percent discount 

rate for short-term effects and $20 

million at the 3 percent discount rate to 

$15 million at the 7 percent discount 

rate for long-term effects. 

F. What analysis of environmental 

justice did we conduct? 

Consistent with EPA’s commitment to 

integrating environmental justice (EJ) in 

the Agency’s actions, and following the 

directives set forth in multiple 

Executive Orders, the Agency has 

carefully considered the impacts of this 

action on communities with EJ 

concerns. 

Executive Order 12898 directs EPA to 

identify the populations of concern who 

are most likely to experience unequal 

burdens from environmental harms; 

specifically, minority populations, lowincome populations, and indigenous 

peoples (59 FR 7629, February 16, 

1994). Additionally, Executive Order 

13985 is intended to advance racial 

equity and support underserved 

communities through federal 

government actions (86 FR 7009, 

January 20, 2021). The EPA defines EJ 

as ‘‘the fair treatment and meaningful 

involvement of all people regardless of 

race, color, national origin, or income, 

with respect to the development, 

implementation, and enforcement of 

environmental laws, regulations, and 

policies.’’ 16 The EPA further defines 

fair treatment to mean that ‘‘no group of 

people should bear a disproportionate 

burden of environmental harms and 

risks, including those resulting from the 

negative environmental consequences of 

industrial, governmental, and 

commercial operations or programs and 

policies’’. In recognizing that minority 

and low-income populations 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 this proposal, the EPA examined 

the potential for Gasoline Distribution 

facilities to pose potential concerns to EJ 

communities by analyzing the 

distribution of demographic groups 

living in close proximity to these 

facilities in the baseline. Specifically, 

the EPA conducted a demographic 

screening analysis that shows that the 

proportion of the population of people 

of color living in proximity to these 

facilities is significantly higher than the 


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17The EPA estimates there are approximately 210 

major source Gasoline Distribution facilities; 

however, we had location information for only 117 

of the facilities. 

national average. The EPA expects that 

the National Emission Standards for 

Hazardous Air Pollutants: Gasoline 

Distribution Technology Review and 

Standards of Performance for Bulk 

Gasoline Terminals Review will reduce 

VOC and HAP emissions by 45,400 and 

2,200 tpy, respectively. The EPA is 

proposing to require stricter cargo tank 

vapor tightness standards, improved 

storage vessel fittings, equipment leak 

instrument monitoring, lower emission 

limits for loading operations at large 

area source bulk gasoline terminals and 

NSPS subpart XXa affected facilities, 

and vapor balancing at bulk gasoline 

plants. These proposed changes to 

control requirements for affected 

facilities are anticipated to improve 

human health exposures for most 

populations, including for surrounding 

communities with EJ concerns. 

Based on these analyses of potentially 

exposed populations and actions taken 

to reduce adverse human health 

impacts, the EPA anticipates that this 

action is not likely to result in 

disproportionate impacts on minority 

populations and/or low-income 

populations, as specified in Executive 

Order 12898 (59 FR 7629, February 16, 

1994) and referenced in Executive Order 

13985 (86 FR 7009, January 20, 2021). 

EPA remains committed to engaging 

with communities and stakeholders 

throughout the development of air 

pollution regulations. Following is a 

more detailed description of how the 

agency considers EJ in the context of 

regulatory development, and specific 

actions taken to address EJ concerns for 

this action. 

1. NESHAP Subpart R 

As a starting point, to examine the 

potential for any EJ issues that might be 

associated with Gasoline Distribution 

facilities, we performed a baseline 

demographic analysis, which is an 

assessment of individual demographic 

groups of the populations living within 

5 kilometers (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. 

The results of the demographic 

analysis (see Table 18 of this document) 

indicate that, for populations within 5 

km of the 117 major source Gasoline 

Distribution facilities,17 the percent 

minority population (being the total 

population minus the white population) 

is larger than the national average (59 

percent versus 40 percent). This 

difference is largely driven by the 

percent Hispanic or Latino population 

that is significantly higher than the 

national average (33 percent versus 19 

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 was higher 

than the national average (9 percent 

versus 5 percent). 

The results of the analysis of 

populations within 50 km of the 117 

major source Gasoline Distribution 

facilities was similar to the 5 km 

analysis for minorities, with higher total 

minorities being driven by a larger 

Hispanic or Latino population. 

However, the percent of the population 

living below the poverty level and the 

percent of the population over 25 

without a high school diploma were 

similar to the national averages. The 

percent of people living in linguistic 

isolation was still higher than the 

national average (8 percent versus 5 

percent). 

A summary of the proximity 

demographic assessment performed for 

the major source Gasoline Distribution 

Facilities is included as Table 18. The 

methodology and the results of the 

demographic analysis are presented in a 

technical report, Analysis of 

Demographic Factors for Populations 

Living Near Gasoline Distribution 

Facilities, available in this docket for 

this action (Document ID EPA–HQ– 

OAR–2020–0371). 

TABLE 18—PROXIMITY DEMOGRAPHIC ASSESSMENT RESULTS FOR MAJOR SOURCE GASOLINE DISTRIBUTION FACILITIES

Demographic group Nationwide 

Population 

within 50 km 

of 117 facilities 

Population 

within 5 km of 

117 facilities 

Total Population ............................................................................................................................................................ 328,016,242 114,588,509 5,884,976 

White and Minority by Percent 

White ............................................................................................................................................................................. 60% 50% 41% 

Minority .......................................................................................................................................................................... 40% 50% 59% 

Minority by Percent 

African American ........................................................................................................................................................... 12% 15% 15% 

Native American ............................................................................................................................................................ 0.7% 0.3% 0.4% 

Hispanic or Latino (includes white and nonwhite) ........................................................................................................ 19% 24% 33% 

Other and Multiracial ..................................................................................................................................................... 8% 11% 10% 

Income by Percent 

Below Poverty Level ..................................................................................................................................................... 13% 13% 17% 

Above Poverty Level ..................................................................................................................................................... 87% 87% 83% 

Education by Percent 

Over 25 and without a High School Diploma ............................................................................................................... 12% 13% 18% 

Over 25 and with a High School Diploma .................................................................................................................... 88% 87% 82% 

Linguistically Isolated by Percent 

Linguistically Isolated .................................................................................................................................................... 5% 8% 9% 

Notes: 


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18The 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 nationwide population count and all demographic percentages are based on the Census’ 2015–2019 American Community Survey five-year block group 

averages and include Puerto Rico. Demographic percentages based on different averages may differ. The total population counts within 5 km and 50 km of all facilities are based on the 2010 Decennial Census block populations. • Minority population is the total population minus the white population. • To avoid double counting, the ‘‘Hispanic or Latino’’ category is treated as a distinct demographic category for these analyses. A person is identified as one of five 

racial/ethnic categories above: White, African American, Native American, Other and Multiracial, or Hispanic/Latino. A person who identifies as Hispanic or Latino is 

counted as Hispanic/Latino for this analysis, regardless of what race this person may have also identified as in the Census. 

As noted above, the EPA determined 

that the standards should be revised to 

reflect cost-effective developments in 

practices, process, or controls. 

Typically, the EPA would seek to 

estimate the impact of the proposed 

changes by either estimating the 

emissions changes likely to result from 

the adoption of new controls by specific 

sources or groups of sources, or (where 

data is more limited, as is typically the 

case) by analyzing a model plant 

scenario. In this case, we evaluated the 

impact of these standards by applying 

the revised standards to a set of model 

plants. 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 proposed rule. However, 

we anticipate the proposed changes to 

NESHAP subpart R will generally 

improve human health exposures for 

populations in surrounding 

communities, including those 

communities with higher percentages of 

people of color. The proposed changes 

will have beneficial effects on air 

quality and public health for 

populations exposed to emissions from 

Gasoline Distribution facilities and will 

provide additional health protection for 

most populations, including 

communities already overburdened by 

pollution, which are often minority, 

low-income, and indigenous 

communities. 

2. NESHAP Subpart BBBBBB 

As a starting point, to examine the 

potential for any EJ issues that might be 

associated with Gasoline Distribution 

facilities, we performed a baseline 

demographic analysis, 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. 

The results of the demographic 

analysis (see Table 19 of this document) 

indicate that, for populations within 5 

km of 1,229 area source Gasoline 

Distribution facilities,18 the percent 

minority population (being the total 

population minus the white population) 

is larger than the national average (54 

percent versus 40 percent). This 

difference is largely driven by the 

Hispanic or Latino (26 percent) and 

African American (18 percent) 

populations that are significantly larger 

than the national averages (19 percent 

and 12 percent, respectively). 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) were 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). 

The results of the analysis of 

populations within 50 km of the 1,229 

area source Gasoline Distribution 

facilities were similar to the national 

averages for all demographics. This is 

due to the fact that the large number of 

facilities (1,229) and larger study area 

(50 km) captured approximately 75% of 

the national population. 

A summary of the proximity 

demographic assessment performed for 

the area source Gasoline Distribution 

facilities is included as Table 19. The 

methodology and the results of the 

demographic analysis are presented in a 

technical report, Analysis of 

Demographic Factors for Populations 

Living Near Gasoline Distribution 

Facilities, available in this docket for 

this action (Document ID EPA–HQ– 

OAR–2020–0371). 

TABLE 19—PROXIMITY DEMOGRAPHIC ASSESSMENT RESULTS FOR AREA SOURCE GASOLINE DISTRIBUTION FACILITIES

Demographic group Nationwide 

Population 

within 50 km 

of 1,229 

facilities 

Population 

within 5 km of 

1,229 facilities 

Total Population ............................................................................................................................................................ 328,016,242 252,008,837 35,679,430 

White and Minority by Percent 

White ............................................................................................................................................................................. 60% 58% 46% 

Minority .......................................................................................................................................................................... 40% 42% 54% 

Minority by Percent 

African American ........................................................................................................................................................... 12% 13% 18% 

Native American ............................................................................................................................................................ 0.7% 0.5% 0.5% 

Hispanic or Latino (includes white and nonwhite) ........................................................................................................ 19% 20% 26% 

Other and Multiracial ..................................................................................................................................................... 8% 9% 10% 

Income by Percent 

Below Poverty Level ..................................................................................................................................................... 13% 13% 18% 

Above Poverty Level ..................................................................................................................................................... 87% 87% 82% 

Education by Percent 

Over 25 and without a High School Diploma ............................................................................................................... 12% 12% 16% 

Over 25 and with a High School Diploma .................................................................................................................... 88% 88% 84% 


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TABLE 19—PROXIMITY DEMOGRAPHIC ASSESSMENT RESULTS FOR AREA SOURCE GASOLINE DISTRIBUTION FACILITIES— 

Continued 

Demographic group Nationwide 

Population 

within 50 km 

of 1,229 

facilities 

Population 

within 5 km of 

1,229 facilities 

Linguistically Isolated by Percent 

Linguistically Isolated .................................................................................................................................................... 5% 6% 9% 

Notes: 

• The nationwide population count and all demographic percentages are based on the Census’ 2015–2019 American Community Survey five-year block group 

averages and include Puerto Rico. Demographic percentages based on different averages may differ. The total population counts within 5 km and 50 km of all facilities are based on the 2010 Decennial Census block populations. • Minority population is the total population minus the white population. • To avoid double counting, the ‘‘Hispanic or Latino’’ category is treated as a distinct demographic category for these analyses. A person is identified as one of five 

racial/ethnic categories above: White, African American, Native American, Other and Multiracial, or Hispanic/Latino. A person who identifies as Hispanic or Latino is 

counted as Hispanic/Latino for this analysis, regardless of what race this person may have also identified as in the Census. 

As noted above, the EPA determined 

that the standards should be revised to 

reflect cost-effective developments in 

practices, process, or controls. 

Typically, the EPA would seek to 

estimate the impact of the proposed 

changes by either estimating the 

emissions changes likely to result from 

the adoption of new controls by specific 

sources or groups of sources, or (where 

data is more limited, as is typically the 

case) by analyzing a model plant 

scenario. In this case, we evaluated the 

impact of these standards by applying 

the revised standards to a set of model 

plants. 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 proposed rule. However, 

we anticipate the proposed changes to 

NESHAP subpart BBBBBB will 

generally improve human health 

exposures for populations in 

surrounding communities, including 

those communities with higher 

percentages of people of color. The 

proposed changes will provide 

additional health protection for all 

populations, including communities 

already overburdened by pollution, 

which are often minority, low-income, 

and indigenous communities. The 

proposed 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 minority, low-income, 

and indigenous communities. 

3. NSPS Subpart XXa 

The locations of any new Bulk 

Gasoline Terminals that would 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 proposed 

rule. However, we anticipate the 

proposed changes to NSPS XXa will 

generally improve human health 

exposures for populations in 

surrounding communities, including 

those communities with higher 

percentages of people of color. See 

Subsections 2 and 3 of this section for 

a summary of the demographic analysis 

results for major and area sources. 

The proposed changes to NSPS 

subpart XXa will improve human health 

exposures for populations in these 

demographic groups. The EPA 

determined that the standards should be 

revised to reflect BSER. The proposed 

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 minority, low-income, and 

indigenous communities. 

V. Request for Comments 

We solicit comments on this proposed 

action. In this proposal, EPA has noted 

multiple times where we are concerned 

that this source category impacts large 

populations of people that have the 

potential to be overburdened by air 

pollution from multiple sources. In 

reviewing standards for this source 

category, we have identified more 

stringent standards that could further 

reduce HAP emissions exposure in 

communities but impose higher capital 

and annualized costs. The cost per ton 

of HAP of these options is greater than 

what we have considered cost-effective 

for these type of HAP in previous 

rulemakings. EPA seeks comment on 

whether these more protective 

standards, although less cost effective 

for these type of HAP emissions controls 

than we would typically find 

acceptable, are nevertheless appropriate 

given the reductions in HAPs that 

would occur in potentially overburdened communities surrounding 

these sources. EPA also requests 

information on the costs, efficacy, and 

feasibility of control options for major 

and area source gasoline distribution 

facilities, and the contributions of these 

sources to overall pollution burdens in 

surrounding communities, to inform our 

consideration of whether more 

protective standards are warranted. 

In addition to general comments on 

this proposed action, we are also 

interested in additional data that may 

improve the analyses. We are 

specifically interested in receiving any 

information regarding developments in 

practices, processes, and control 

technologies that reduce emissions. We 

are also interested in receiving 

information on costs, emissions, and 

product recovery. Finally, the EPA 

attempted to ensure that the SSM 

provisions we are proposing to 

eliminate are inappropriate, 

unnecessary, or redundant in the 

absence of the SSM exemption and are 

specifically seeking comment on 

whether we have successfully done so. 

VI. Statutory and Executive Order 

Reviews 

Additional information about these 

statutes and Executive Orders can be 

found at https://www.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is a significant regulatory 

action that was submitted to OMB for 

review. This action is a significant 

regulatory action because it likely to 


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have an annual effect on the economy 

of $100 million or more or adversely 

affect in a material way the economy, a 

sector of the economy, productivity, 

competition, jobs, the environment, 

public health or safety, or state, local, or 

tribal governments or communities. Any 

changes made in response to OMB 

recommendations have been 

documented in the docket for this 

action. The EPA has prepared an 

economic analysis that is included in 

the Regulatory Impact Analysis which is 

available in the docket for these 

proposed rules. 

B. Paperwork Reduction Act (PRA) 

1. NESHAP Subpart R 

The information collection activities 

in this proposed rule have been 

submitted for approval to the OMB 

under the PRA. You can find a copy of 

the Information Collection Request (ICR) 

in the docket for this rule, and it is 

briefly summarized here. 

The EPA is proposing 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 the Gasoline 

Distribution 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 

the next 3 years). Frequency of response: 

Initially, semiannually, and annually. 

• Total estimated burden: 16,300 (per 

year) to comply with the proposed 

amendments in the NESHAP. Burden is 

defined at 5 CFR 1320.3(b). 

• Total estimated cost: $1,263,464 

(per year), including no annualized 

capital or operation and maintenance 

costs, to comply with the proposed 

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. 

Submit your comments on the 

Agency’s need for this information, the 

accuracy of the provided burden 

estimates, and any suggested methods 

for minimizing respondent burden to 

the EPA using the docket identified at 

the beginning of this rule. You may also 

send your ICR-related comments to 

OMB’s Office of Information and 

Regulatory Affairs via email to OIRA_

submission@omb.eop.gov, Attention: 

Desk Officer for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

receipt, OMB must receive comments no 

later than August 9, 2022. The EPA will 

respond to any ICR-related comments in 

the final rule. 

2. NESHAP Subpart BBBBBB 

The information collection activities 

in this proposed rule have been 

submitted for approval to the OMB 

under the PRA. You can find a copy of 

the ICR in the docket for this rule, and 

it is briefly summarized here. 

The EPA is proposing 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 the Gasoline 

Distribution 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 

proposed amendments in the NESHAP. 

Burden is defined at 5 CFR 1320.3(b). 

• Total estimated cost: $6,501,788 

(per year), including no annualized 

capital or operation and maintenance 

costs, to comply with the proposed 

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. 

Submit your comments on the 

Agency’s need for this information, the 

accuracy of the provided burden 

estimates, and any suggested methods 

for minimizing respondent burden to 

the EPA using the docket identified at 

the beginning of this rule. You may also 

send your ICR-related comments to 

OMB’s Office of Information and 

Regulatory Affairs via email to OIRA_

submission@omb.eop.gov, Attention: 

Desk Officer for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

receipt, OMB must receive comments no 

later than August 9, 2022. The EPA will 

respond to any ICR-related comments in 

the final rule. 

3. NSPS Subpart XXa 

The information collection activities 

in this proposed rule have been 

submitted for approval to the OMB 

under the PRA. You can find a copy of 

the ICR in the docket for this rule, and 

it is briefly summarized here. 

The EPA is proposing provisions to 

require 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 the 

Gasoline Distribution 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: $86,899 (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. 

Submit your comments on the 

Agency’s need for this information, the 

accuracy of the provided burden 

estimates, and any suggested methods 

for minimizing respondent burden to 

the EPA using the docket identified at 

the beginning of this rule. You may also 

send your ICR-related comments to 

OMB’s Office of Information and 

Regulatory Affairs via email to OIRA_

submission@omb.eop.gov, Attention: 

Desk Officer for the EPA. Since OMB is 

required to make a decision concerning 

the ICR between 30 and 60 days after 

receipt, OMB must receive comments no 

later than August 9, 2022. The EPA will 

respond to any ICR-related comments in 

the final rule. 

C. Regulatory Flexibility Act (RFA) 

I certify that each of the rules 

included in this proposed action will 

not have a significant economic impact 

on a substantial number of small entities 

under the RFA. The small entities 


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subject to the requirements of this 

proposed rulemaking are all small 

businesses. For NESHAP subpart R, EPA 

certifies that this rule will not have a 

significant economic impact on a 

substantial number of small entities 

under the RFA. The Agency has 

determined that two small entities are 

affected by these proposed amendments, 

which is 4.9 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, EPA certifies that this 

rule will not have a significant 

economic impact on a substantial 

number of small entities under the RFA. 

The Agency has determined that 111 

small entities are affected by these 

proposed amendments, which is 42 

percent of all affected ultimate parent 

businesses. Less than 10 percent of 

these small entities (10 total) are 

projected to incur costs from the 

proposed rules of greater than 1 percent 

of their annual sales, and less than 4 

percent (4 total) are projected to incur 

costs greater than 3 percent of their 

annual sales (with a maximum of 6.75 

percent). Finally, for NSPS subpart XXa, 

EPA certifies that this rule will not have 

a significant economic impact on a 

substantial number of small entities 

under the RFA. The Agency has not 

identified any small entities that are 

affected by this proposed NSPS and 

does not project that any entities 

affected by the proposed NSPS will 

incur costs greater than 1 percent of 

their annual sales. Details of the 

analyses for each proposed rule are 

presented in the Regulatory Impact 

Analysis for these proposed 

rulemakings. 

D. Unfunded Mandates Reform Act 

(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. The 

action imposes no enforceable duty on 

any state, local or tribal governments or 

the private sector. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the states, on the 

relationship between the national 

government and the states, or on the 

distribution of power and 

responsibilities among the various 

levels of government. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications as specified in Executive 

Order 13175. 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 and 

Coordination with Indian Tribes, the 

EPA will offer government-togovernment consultation with tribes as 

requested. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

This action is not subject to Executive 

Order 13045 because the EPA does not 

believe that the environmental health 

risks or safety risks addressed by this 

action present a disproportionate risk to 

children. The proposed rules lower the 

emissions of gasoline and gasoline 

vapors and are projected to improve 

overall health including children. 

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 this proposed action 

would not reduce crude oil supply, fuel 

production, coal production, natural gas 

production, or electricity production. 

We estimate that this proposed action 

would 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 the Regulatory Impact Analysis for 

this proposed rulemaking. 

I. National Technology Transfer and 

Advancement Act (NTTAA) 

This action involves technical 

standards. The EPA proposes to use 

EPA Method 18. While the EPA 

identified ASTM 6420–18 as being 

potentially applicable, the Agency does 

not propose 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 

The EPA believes that this action does 

not have disproportionately high and 

adverse human health or environmental 

effects on minority populations, lowincome populations and/or indigenous 

peoples, as specified in Executive Order 

12898 (59 FR 7629, February 16, 1994). 

The documentation for this decision 

is contained in sections III, IV.E, and 

IV.F of this preamble. All relevant 

documents are available in the docket 

for this action (Docket ID No. EPA–HQ– 

OAR–2020–0371). 

The assessment of populations in 

close proximity of gasoline distribution 

facilities shows some demographic 

groups that are higher than the national 

average, however, we determined that 

the human health impacts are not 

disproportionate for these groups 

because this action proposes changes to 

the standards that will increase 

protection for communities. The EPA 

determined that the standards should be 

revised to reflect cost-effective 

developments in practices, process, or 

controls and BSER. The proposed 

changes will provide additional health 

protection for all populations, including 

communities already overburdened by 

pollution, which are often minority, 

low-income, and indigenous 

communities. The proposed changes 

will have beneficial effects on air 

quality and public health for 

populations exposed to emissions from 

facilities in the source category. Further, 

this rulemaking complements other 

actions already taken by the EPA to 

reduce emissions and improve health 

outcomes for overburdened and 

underserved communities. 

Michael S. Regan, 

Administrator. 

[FR Doc. 2022–12223 Filed 6–9–22; 8:45 am] 

BILLING CODE 6560–50–P 


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