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

Federal RegisterJun 10, 2022

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 60 and 63

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

RIN 2060-AU97

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

AGENCY:

Environmental Protection Agency (EPA).

ACTION:

Proposed rule.

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 in-person public meetings at this time.

To request a virtual public hearing, contact the public hearing team at (888) 372-8699 or by email at

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-gact-national-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-gact-national-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-sources-air-pollution/gasoline-distribution-mact-and-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-gact-national-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

such as audio description, please pre-register for the hearing with the public hearing team and describe your needs by June 17, 2022. The EPA may not be able to arrange accommodations without advanced notice.

Docket.

The EPA has established a docket for this rulemaking under Docket ID No. EPA-HQ-OAR-2020-0371. All documents in the docket are listed in

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

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

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

sulfur dioxide

SSM startup, shutdown, and malfunction

TOC total organic carbon

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

require quarterly instrument monitoring.

3. Costs and Benefits

To satisfy requirements of E.O. 12866, the EPA projected the emissions reductions, costs, and benefits that may result from these proposed rulemakings. These results are presented in detail in the regulatory impact analysis (RIA) accompanying this proposal developed in response to E.O. 12866. We present these results for each of the three rules included in this proposed action, and also cumulatively. This action is economically significant according to E.O. 12866 primarily due to the proposed amendments to NESHAP subpart BBBBBB. The RIA focuses on the elements of the proposed rulemaking that are likely to result in quantifiable cost or emissions changes compared to a baseline without the proposal that incorporates changes to regulatory requirements. We estimated the cost, emissions, and benefit impacts for the 2026 to 2040 period. We show the present value (PV) and equivalent annual value (EAV) of costs, benefits, and net benefits of this action in 2019 dollars.

The initial analysis year in the RIA is 2026 as we assume the large majority of impacts associated with the proposed rulemakings will be finalized in that year. The NSPS will take effect immediately upon the effective date of the final rule and impact sources constructed after publication of the proposed rule, but these impacts are much lower than those of the other two rulemakings in this action. The other two rules, both under the provisions of section 112 of the Clean Air Act, will take effect three years after their effective date, which will occur in 2026 given promulgation of this rulemaking in 2023. Therefore, their impacts will begin in 2026. The final analysis year is 2040, which allows us to provide 15 years of projected impacts after all of these rules are assumed to take effect.

The cost analysis presented in the RIA reflects a nationwide engineering analysis of compliance cost and emissions reductions, of which there are two main components. The first component is a set of representative or model plants for each regulated facility, segment, and control option. The characteristics of the model plant include typical equipment, operating characteristics, and representative factors including baseline emissions and the costs, emissions reductions, and product recovery resulting from each control option. The second component is a set of projections of data for affected facilities, distinguished by vintage, year, and other necessary attributes (

e.g.,

precise content of material in storage tanks). Impacts are calculated by setting parameters on how and when affected facilities are assumed to respond to a particular regulatory regime, multiplying data by model plant cost and emissions estimates, differencing from the baseline scenario, and then summing to the desired level of aggregation. In addition to emissions reductions, some control options result in gasoline recovery, which can then be sold where possible. Where applicable, we present projected compliance costs with and without the projected revenues from product recovery.

The EPA expects health benefits due to the emissions reductions projected under these proposed rulemakings. We expect that hazardous air pollutants (HAP) emission reductions will improve health and welfare associated with exposure by those affected by these emissions. In addition, the EPA expects that volatile organic compounds (VOC) emission reductions that will occur concurrent with the reductions of HAP emissions will improve air quality and are likely to improve health and welfare associated with exposure to ozone, particulate matter 2.5 (PM

2.5

), and HAP. The EPA also expects disbenefits from secondary increases of carbon dioxide (CO

), nitrogen oxides (NO

), sulfur dioxide (SO

), and carbon monoxide (CO) emissions associated with the control options included in the cost analysis. Discussion of the non-monetized benefits and climate disbenefits can be found in Chapter 4 of the RIA.

Tables 1 through 3 of this document presents the emission changes, and PV and EAV of the projected monetized benefits, compliance costs, and net benefits over the 2026 to 2040 period under the proposed rulemaking for each subpart. Table 4 of this document presents the same results for the cumulative impact of these rulemakings. All discounting of impacts presented uses discount rates of 3 and 7 percent.

Table 1—Short-Term and Long-Term Monetized Benefits, Costs, Net Benefits, and Emissions Reductions of the Proposed NESHAP Subpart BBBBBB Amendments, 2026 Through 2040

[Dollar estimates in millions of 2019 dollars]

3 Percent discount rate

EAV

7 Percent discount rate

EAV

Benefits

$180(ST) and $1,500(LT)

$15(ST) and $130(LT)

$110(ST) and $900(LT)

$12(ST) and $99(LT).

Climate Disbenefits (3%)

$28

$2.3

$28

$2.0.

Net Compliance Costs

−$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.

490,000.

290.

3.5.

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 (NO

) emissions by 290 short tons, sulfur dioxide (SO

) by 3.5 short tons, and carbon monoxide (CO) by 1,300 short tons from 2026-2040.

Visibility benefits.

Reduced vegetation effects.

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

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 CO

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 NO

, SO

, and CO emissions. Please see Section 4.6 of the RIA for more discussion of the climate disbenefits.

Climate disbenefits are based on changes (increases) in CO

emissions and are calculated using four different estimates of the social cost of carbon (SC-CO

) (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-CO

at a 3 percent discount rate, but the Agency does not have a single central SC-CO

point estimate. We emphasize the importance and value of considering the disbenefits calculated using all four SC-CO

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-CO

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.

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]

3 Percent discount rate

EAV

7 Percent discount rate

EAV

Benefits

$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

$23

$2.0

$15

$1.8.

Compliance Costs

$34

$2.9

$23

$2.6.

Value of Product Recovery

$11

$1.0

$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.

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

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.

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 XX

, 2026 Through 2040

[Dollar estimates in millions of 2019 dollars]

3 Percent discount rate

EAV

7 Percent discount rate

EAV

Benefits

$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%)

$4.4

$0.37

$4.4

$0.37.

Net Compliance Costs

$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.

74,000.

50.

42.

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 NO

emissions by 50 short tons, and SO

by 42 short tons from 2026-2040.

Visibility benefits.

Reduced vegetation effects.

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

, SO

and CO emissions. Please see Section 4.6 of the RIA for more discussion of the climate disbenefits.

Climate disbenefits are based on changes (increases) in CO

emissions and are calculated using four different estimates of the social cost of carbon (SC-CO

at a 3 percent discount rate, but the Agency does not have a single central SC-CO

point estimate. We emphasize the importance and value of considering the disbenefits calculated using all four SC-CO

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-CO

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]

3 Percent discount rate

EAV

7 Percent discount rate

EAV

Benefits

$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%)

$32

$2.7

$32

$2.7.

Net Compliance Costs

−$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.

560,000.

340.

46.

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 NO

emissions by 340 short tons, SO

by 42 short tons, and CO by 1,300 short tons from 2026-2040.

Visibility benefits.

Reduced vegetation effects.

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

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 NO

, SO

and CO emissions. Please see Section 4.6 of the RIA for more discussion of the climate disbenefits.

Climate disbenefits are based on changes (increases) in CO

emissions and are calculated using four different estimates of the social cost of carbon (SC-CO

at a 3 percent discount rate, but the Agency does not have a single central SC-CO

point estimate. We emphasize the importance and value of considering the disbenefits calculated using all four SC-CO

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-CO

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?

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

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/gasoline-distribution-mact-and-gact-national-emission-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-sources-air-pollution/gasoline-distribution-mact-and-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 standard-setting focuses on identifying and addressing any remaining (

i.e.,

“residual”) risk pursuant to CAA section 112(f) and concurrently conducting a technology review pursuant to CAA section 112(d)(6). The EPA set MACT standards for the Gasoline Distribution major source category in 1994 and conducted the residual risk and technology review in 2006.

CAA section 112(d)(6) requires the EPA to review standards promulgated under CAA section 112 and revise them “as necessary (taking into account developments in practices, processes, and control technologies)” no less often than every 8 years following promulgation of those standards. This is referred to as a “technology review” and is required for all standards established under CAA section 112(d) including GACT standards that apply to area sources.

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)

EPA,

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

Association of Battery Recyclers, Inc.

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)

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.

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

Several additional CAA sections are relevant to this action as they specifically address regulation of hazardous air pollutant emissions from area sources. Collectively, CAA sections 112(c)(3), (d)(5), and (k)(3) are the basis of the Area Source Program under the Urban Air Toxics Strategy, which provides the framework for regulation of area sources under CAA section 112.

Section 112(k)(3)(B) of the CAA requires the EPA to identify at least 30 HAP that pose the greatest potential health threat in urban areas with a primary goal of achieving a 75-percent reduction in cancer incidence attributable to HAP emitted from stationary sources. As discussed in the Integrated Urban Air Toxics Strategy (64 FR 38706, 38715, July 19, 1999), the EPA identified 30 HAP emitted from area sources that pose the greatest potential health threat in urban areas, and these HAP are commonly referred to as the “30 urban HAP.”

Section 112(c)(3), in turn, requires the EPA to list sufficient categories or subcategories of area sources to ensure that area sources representing 90 percent of the emissions of the 30 urban HAP are subject to regulation. The EPA implemented these requirements through the Integrated Urban Air Toxics Strategy by identifying and setting standards for categories of area sources including the Gasoline Distribution source category that is addressed in this action.

CAA section 112(d)(5) provides that for area source categories, in lieu of setting MACT standards (which are

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.”

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.

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

2. NESHAP Subpart BBBBBB

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

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.

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).

Allowance is provided to meet 80 mg/L for affected facilities with an “existing vapor processing system.”

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

The EPA used several data sources to determine the facilities that are subject to the Gasoline Distribution NESHAP and the Bulk Gasoline Terminals NSPS. We identified facilities in the 2017 National Emissions Inventory (NEI) and the Toxics Release Inventory system having a primary facility NAICS code beginning with 4247, Petroleum and Petroleum Products Merchant Wholesalers. We also used information from the original Gasoline Distribution NESHAP, Bulk Terminal list of petrochemical storage facilities from the Internal Revenue Service, the Office of Enforcement and Compliance Assurance's Enforcement and Compliance History Online tool (

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

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, cost-effectiveness is a measure of the outcomes produced by resources spent. In the context of air pollution control options, cost-effectiveness typically refers to the annualized cost of implementing an air pollution control option divided by the amount of pollutant reductions realized annually.

After the EPA evaluates the factors described above, the EPA then compares the various systems of emission reductions and determines which system is “best”. The EPA then establishes a standard of performance that reflects the degree of emission limitation achievable through the implementation of the BSER. In doing this analysis, the EPA can determine whether subcategorization is appropriate based on classes, types, and sizes of sources, and may identify a different BSER and establish different performance standards for each subcategory. The result of the analysis and BSER determination leads to standards of performance that apply to facilities that begin construction, reconstruction, or modification after the date of publication of the proposed standards in the

Federal Register

. Because the new source performance standards reflect the best system of emission reduction under conditions of proper operation and maintenance, in doing its review, the EPA also evaluates and determines the proper testing, monitoring, recordkeeping and reporting requirements needed to ensure compliance with the emission standards.

See section II.C of this preamble for information on the specific data sources that were reviewed as part of this action.

III. Proposed Rule Summary and Rationale

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

We evaluated developments in practices, processes, and control technologies for loading operations, storage vessels, and equipment leaks for NESHAP subpart R and NESHAP subpart BBBBBB. For the NSPS XX, we evaluated BSER for loading operations and equipment leaks. We analyzed costs and impacts for each emission source (

e.g.,

loading operations) by each subpart. We also included product recovery in the cost calculation, where appropriate. We based the product recovery on the average pre-tax retail price of regular conventional gasoline in 2019 at a value of gasoline recovered of $1.50 per gallon.

This yielded a product recovery of $480 per ton of VOC. For NSPS, we determined cost-effectiveness, cost per ton of emissions reduced, on a VOC basis. For NESHAP, we determined cost-effectiveness on a HAP basis from the VOC emissions. In general, gasoline (liquid) is approximately 20 weight percent HAP, but gasoline vapors are only 3 to 4 weight percent HAP. We estimated that loading operation VOC emissions were 4 weight percent HAP, storage vessel VOC emissions were 5 weight percent HAP, and equipment leak VOC emissions were 10 weight percent HAP. Although we considered the options cumulatively, we also calculated the incremental cost effectiveness, which allowed us to assess the impacts of the incremental change between the options under consideration.

The VOC recovery credit was calculated based on the average retail price of regular conventional gasoline in 2019, which was $2.50/gallon, and that 60 to 70 percent of retail price is for taxes and distribution/marketing costs (

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).

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

performance test, with operating limits established as means to ensure continuous compliance. Alternative means to express the emission limit may make the emission limit more amenable to direct monitoring.

a. NESHAP Subpart R

We identified one development for loading racks which is an emission limit of 1 mg/L using the same types of control that we expect are used to meet the current major source emission limit of 10 mg/L of gasoline loaded. Therefore, we assessed maintaining the 10 mg/L emission limit or reducing it to 1 mg/L. For the major source NESHAP subpart R impacts analysis, we estimated that most facilities used VRUs and that approximately 75 percent of the facilities could comply with the 1 mg/L emission limit by modifying their operating characteristics (cycle times) and 25 percent would need to upgrade their control system.

Table 5 of this document summarizes the resulting impacts for the control option considered for 210 major source (NESHAP subpart R) facilities. Based on the costs associated with further HAP emission reductions, we determined it is not cost-effective to lower the 10 mg/L standard, since the cost effectiveness of the option is over $100,000 per ton of HAP reduced—a level that is over an order of magnitude higher than we have considered cost-effective in previous rulemakings to limit organic HAP. Accordingly, we are not proposing any changes to the current emission limit for loading operations for the NESHAP subpart R. Our assessment of control options is summarized in the memorandum “Major Source Technology Review for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations) NESHAP” in EPA Docket No. EPA-HQ-OAR-2020-0371.

As noted in section V of this preamble, the EPA requests public comment on all aspects of this proposed rule, including our evaluation of the costs and efficacy of control options for loading operations under NESHAP subpart R. Among other issues, EPA requests comment on whether we have accurately assessed the costs, pollution reduction benefits, and cost-effectiveness of applying a 1 mg/L emission limit to major sources subject to this NESHAP; experience from implementing state regulations or local ordinances for these sources that could inform this technology review; and whether there are other factors that EPA should consider that would support a revision of the current NESHAP subpart R. For example, we note that there are at least 5.9 million people located within 5 km of these sources (see Table 18 of this document), and the EPA is concerned that these communities may already be overburdened by air pollution from multiple sources. Information on the contributions that HAPs from these sources make to overall pollution burdens in neighboring communities may be useful in determining whether a more stringent standard is warranted.

Table 5—Control Option Impacts for Loading Operations for NESHAP Subpart R

Emission limit

VOC emission reduction

(tpy)

TCI

($)

AOC

($/yr)

TAC

w/o product

recovery

($/yr)

TAC

w/product

recovery

($/yr)

($/ton VOC)

($/ton HAP)

1 mg/L

1,686

34,160,000

5,764,000

8,677,000

7,868,000

4,667

116,700

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

Total capital investment (TCI).

Annualized operating costs (AOC).

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

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

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

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 cost-effectiveness of reducing the area source emission limit for large bulk gasoline terminals to 35 mg/L are $9,700 per ton of HAP emissions reduced, which we determined is cost-effective. The cost-effectiveness and incremental cost effectiveness of reducing the area source emission limit for large bulk gasoline terminals to 10 mg/L are approximately $12,000 and $13,000 per ton of HAP emissions reduced, respectively, which we determined is not cost-effective. Therefore, we are proposing to lower the area source emission limits for loading racks at large bulk gasoline terminals to 35 mg/L.

We note, however, that there are at least 35.7 million people located within 5 km of these sources (see Table 19 of this document), and EPA is concerned that this population has the potential to be overburdened from air pollution from multiple sources. In this case, we have

identified a more stringent standard (

i.e.,

10 mg/L) that could further reduce HAP emissions exposure in communities near these large bulk terminals. We project that this more stringent standard would impose slightly higher, but not unreasonable, capital and annualized costs on these terminals. EPA seeks comment on whether this more protective standard, although it is less cost effective for these type of HAP emissions controls than we would typically find acceptable, is nevertheless appropriate given the reductions in HAPs that would occur in potentially over-burdened communities surrounding these large bulk terminals. EPA also requests information on the costs, efficacy, and feasibility of control options for loading racks at area source gasoline distribution facilities, and the contributions of these sources to overall pollution burdens in surrounding communities, to inform our consideration of whether a more protective area source standard is warranted. Our assessment of control options is summarized in the memorandum “Area Source Technology Review for the Gasoline Distribution Bulk Terminals, Bulk Plants, and Pipeline Facilities NESHAP” in EPA Docket No. EPA-HQ-OAR-2020-0371.

As in the major source rule, we are proposing to replace the current mass-based limits with a direct concentration limit for facilities operating VRUs because it provides consistent implementation of the federal standard when considering continuous compliance requirements. The corresponding concentration limit equivalent to a 35 mg/L emission limit is 19,200 ppmv as propane. Therefore, we are proposing to express the emission limit for VRUs in terms of a concentration limit of 19,200 ppmv TOC as propane on a three-hour rolling average. As noted previously, a concentration limit provides a more enforceable and consistent continuous compliance requirement that is directly related to the emissions limit. To prevent dilution, we are proposing that only vacuum breaker valves can be used to introduce ambient air into the VRU control system. Our assessment of monitoring options is summarized in the memorandum “Monitoring Options and Costs for Gasoline Distribution Facilities” in EPA Docket No. EPA-HQ-OAR-2020-0371.

Because of the need for combustion air, this concentration limit is not directly applicable for VCUs. We considered developing an equivalent concentration limit for VCUs, but this would require both a TOC monitor and an oxygen monitor, to correct the concentration limit to 0 percent excess oxygen. This standard becomes problematic at low TOC loading rates, where the oxygen concentration may approach that of the ambient air.

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.

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

Table 6—Control Option Impacts for Loading Operations at Large Area Source Bulk Gasoline Terminals

Emission limit

VOC emission reduction

(tpy)

TCI

($1,000)

AOC

($/yr)

TAC

w/o product

recovery

($/yr)

TAC

w/product

recovery

($/yr)

($/ton HAP)

ICE

($/ton HAP)

35 mg/L

820

385,000

319,000

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

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

Total capital investment (TCI).

Annual operating costs (AOC).

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

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

HAP content assumed to be 4% of VOC.

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

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

(tpy)

TCI

($1,000)

AOC

($/yr)

TAC

w/o product

recovery

($/yr)

TAC

w/product

recovery

($/yr)

($/ton HAP)

ICE

($/ton HAP)

80 mg/L

2,015

11,870

1,909,000

2,922,000

1,954,000

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

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

Total capital investment (TCI).

Annual operating costs (AOC).

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

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

HAP content assumed to be 4% of VOC.

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

(tpy)

TCI

($1,000)

AOC

($1,000/yr)

TAC

w/o product

recovery

($/yr)

TAC

w/product

recovery

($/yr)

($/ton HAP)

ICE

($/ton HAP)

Vapor Balancing

23,739

42,310

2,116

7,140

-4,255

-4,481

80 mg/L

20,215

455,800

247,900

286,800

277,100

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

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

Total capital investment (TCI).

Annual operating costs (AOC).

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

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

HAP content assumed to be 4% of VOC.

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

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

c. NSPS Subpart XXa

The current NSPS (40 CFR part 60, subpart XX

) 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.

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.

Part 60, subpart XX applies to bulk gasoline terminals that commenced construction, modification or construction after December 17, 1980. This proposal would modify subpart XX so that it applies to bulk gasoline terminals that commenced construction, modification or reconstruction after December 17, 1980 and on or before the publication date of the proposed part 60, subpart XXa.

Allowance is provided to meet 80 mg/L for affected facilities with an “existing vapor processing system.”

In 40 CFR 60.501“gasoline tank” is defined as “. . . a delivery tank truck. . . .” The major and area source NESHAP definition of “gasoline cargo tank” includes loading of tank trucks and railcars. In NSPS subpart XXa, we are proposing nomenclature revisions to generalize the loading requirements similar to the NESHAP definitions which apply to a “gasoline cargo tank” rather than just a “gasoline tank” to expressly include railcar loading operations. The control techniques and costs of control for loading operations apply equally to tank truck and rail car loading racks and we therefore find no basis for excluding rail car loading operations at bulk gasoline terminals from the NSPS requirements.

Additionally, we assessed either maintaining the current NSPS 35 mg/L emission limit for loading operations or reducing it to either 10 mg/L or 1 mg/L. We assessed costs differently between facilities that are new versus modified or reconstructed, because the incremental cost of designing a system to meet 1 mg/L versus 10 mg/L for a new system is small, but the costs for upgrading an existing control system that currently meets a 10 mg/L or 35 mg/L emissions limit to meet 1 mg/L can be high and may require complete replacement of the existing controls.

We projected nationwide impacts for different control options in the fifth year of the NSPS considering separately 5 newly constructed bulk gasoline terminals and 15 modified or reconstructed facilities that currently meet a 35 or 80 mg/L emission limit. These costs are summarized in Table 9 of this document. Considering the expected range of throughputs for newly constructed bulk gasoline terminals, the incremental cost to meet a 1 mg/L limit rather than a 10 mg/L limit is about $1,300 per ton of VOC reduced, which we determined is cost-effective. As shown in Table 9 of this document, the incremental cost for modified or reconstructed facilities to meet a 1 mg/L limit rather than a 10 mg/L limit exceeds $8,300 per ton of VOC reduced, which we determined is not cost-effective. The incremental cost for modified or reconstructed facilities to meet a 10 mg/L limit, on the other hand, rather than a 35 mg/L limit is about $350 per ton of VOC reduced, which we determined is cost-effective. Therefore, we are proposing in the proposed subpart XXa that facilities that commence construction after June 10, 2022) must meet a 1 mg/L limit and facilities that commence modification, or reconstruction after June 10, 2022 must meet a 10 mg/L limit. Our assessment of control options is summarized in the memorandum “New Source Performance Standards Review for Bulk Gasoline Terminals” in EPA Docket No. EPA-HQ-OAR-2020-0371.

Table 9—Control Option Impacts for Loading Operations at NSPS Bulk Gasoline Terminals

Emission limit

VOC emissions

(tpy)

VOC emission reduction

(tpy)

TCI

($1,000)

AOC

($/yr)

TAC

w/o product

recovery

($/yr)

TAC

w/product

recovery

($/yr)

($/ton VOC)

ICE

($/ton VOC)

New:

Submerged Loading

2,402

35 mg/L

171

2,231

5,900

671,000

1,170,000

103,000

10 mg/L

2,354

6,210

706,000

1,240,000

106,000

1 mg/L

2,397

6,830

730,000

1,310,000

162,000

1,290

Modified/Reconstructed:

Submerged Loading

332

35 mg/L

286

19,500

−2,330

−51

10 mg/L

144

188

351

107,000

137,000

46,900

250

346

1 mg/L

317

6,530

725,000

1,280,000

1,130,000

3,560

8,350

Total capital investment (TCI).

Annual operating costs (AOC).

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

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

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

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

w/o product

recovery

($/year)

TAC

w/product

recovery

($/year)

($/ton VOC)

($/ton HAP)

ICE

($/ton VOC)

ICE

($/ton HAP)

3″ water

33,602

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

Total annualized costs (TAC) considering annualized operating costs.

Cost effectiveness (CE) compared to baseline (3″ water).

HAP content assumed to be 4% of VOC.

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

3. Standards for Gasoline Storage Vessels

The area source and major source NESHAP (subparts R and BBBBBB) have standards for storage vessels that are largely based on the requirements for volatile organic liquid storage vessels in 40 CFR part 60, subpart Kb (NSPS subpart Kb), but include some exceptions to the NSPS subpart Kb requirements, primarily related to floating roof deck fitting controls. Because VOC emissions from storage vessels are regulated under NSPS subpart Kb, storage vessels are not part of affected facilities under NSPS subpart XX.

We reviewed Federal, state, and local requirements for gasoline storage vessels. We identified potential improvements in the requirements for primary seals, secondary seals (for internal floating roofs), and improved fitting controls (particularly for guidepoles) as developments in practices and processes. Additionally, we identified a new practice for monitoring internal floating roof storage vessels using a lower explosive limit (LEL) monitor to identify floating roofs with poorly functioning seals or fitting controls. We assessed the cost and impacts of moving from the current standards to full compliance with NSPS subpart Kb requirements and for including LEL monitoring. Our assessments for each subpart are detailed in the following subsections. For more information on the storage vessel assessments, see memorandum “Control Options for Storage Tanks at Gasoline Distribution Facilities” available in Docket No. EPA-HQ-OAR-2020-0371.

a. NESHAP Subpart R

The major source rule contains standards for gasoline storage vessels at bulk gasoline terminals and pipeline breakout stations. The standards cross-reference NSPS subpart Kb requirements but exclude fitting control requirements in NSPS subpart Kb provided the storage vessel was already equipped with a floating roof meeting the seal requirements in NSPS subpart Kb. We estimated that about 95 percent of storage vessels in the gasoline distribution industry are equipped with internal floating roofs based on review of NEI data. We assessed costs and impacts of requiring fitting controls separately for internal and external floating roofs. Specifically, we evaluated the control options of (1) requiring upgrades of fitting requirements for external floating roofs and (2) requiring upgrades of fitting requirements for both external and internal floating roofs. Table 11 of this document summarizes the national impacts projected for major source gasoline distribution facilities. Based on our analysis, we determined installing/upgrading fitting controls for external floating roof tanks is cost effective. On the other hand, the projected cost-effectiveness of installing/upgrading fitting controls for internal floating roof tanks is approximately $350,000 per ton of HAP emissions reduced (incremental costs between Option 1 and 2), and therefore, we determined these controls are not cost effective. Accordingly, we are proposing to require fitting controls for external floating roof tanks consistent with the requirements in NSPS subpart Kb and are not proposing to require fitting controls for internal floating roof tanks. Our assessment of control options is summarized in the memorandum “Major Source Technology Review for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations) NESHAP” in EPA Docket No. EPA-HQ-OAR-2020-0371.

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

(tpy)

TCI

($1,000)

TAC

w/o product

recovery

($1,000/yr)

TAC

w/product

recovery

($1,000/yr)

($/ton VOC)

($/ton HAP)

ICE

($/ton VOC)

ICE

($/ton HAP)

Upgrade EFRT fittings

546

1,857

173

−89

−164

−3,272

−164

−3,272

Upgrade IFRT and EFRT fittings

772

45,240

4,205

3,835

4,966

99,320

17,330

346,500

Compared to baseline emissions of 4,977 tpy.

Total capital investment (TCI).

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

Cost effectiveness (CE) compared to baseline.

HAP content assumed to be 5% of VOC.

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

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

While we are not directly proposing additional fitting controls for internal floating roof tanks, we identified the use of LEL monitoring within the headspace of an internal floating roof tank as a means to enhance the annual inspections and more readily identify malfunctioning internal floating roofs. We estimated the cost of the LEL monitoring requirement based on the additional time needed to monitor LEL during the annual inspections. We estimated the impacts of annual LEL monitoring based on the number of internal floating roof tanks at major source gasoline distribution facilities and assuming LEL monitoring identifies defects in about 2 percent of internal floating roofs resulting in a 2 percent reduction in baseline emissions of internal floating roofs. Based on our review of available LEL monitoring data, we expect that this is a conservative estimate of the emission reductions that would be achieved. Table 12 of this document summarizes the projected impact of requiring annual LEL monitoring for internal floating roof tanks as part of the annual roof-top inspections.

The added cost for conducting LEL monitoring is under $70 per year per tank and LEL monitoring is expected to result in cost-effective emission reductions for major source gasoline distribution facilities (costs of $4,200 per ton of HAP reduced). Therefore, we are proposing to require LEL monitoring as part of the annual visual inspections conducted for internal floating roof tanks at major source gasoline distribution facilities. Our assessment of LEL monitoring at major sources is summarized in the memorandum “Major Source Technology Review for Gasoline Distribution Facilities (Bulk Gasoline Terminals and Pipeline Breakout Stations) NESHAP” in EPA Docket No. EPA-HQ-OAR-2020-0371.

Table 12—LEL Monitoring Impacts at Nationwide Major Source Facilities

Facility type

VOC emission

reduction

(tpy)

TAC

w/o product

recovery

($/yr)

TAC

w/product

recovery

($/yr)

($/ton VOC)

($/ton HAP)

Total Major Source Facilities

56,290

17,130

210

4,200

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

Cost effectiveness (CE).

HAP content assumed to be 5% of VOC.

b. NESHAP Subpart BBBBBB

The area source rule contains standards for gasoline storage tanks at bulk gasoline plants, bulk gasoline terminals, and pipeline breakout stations. The current requirements for bulk gasoline plants require the use of submerged filling for all gasoline storage tanks with a capacity of greater than 250 gallons. As noted in section III.A.1.b of this preamble, we are proposing to require vapor balancing at bulk plants, both when filling cargo tanks and when unloading cargo tanks (

i.e.,

filling storage tanks). The use of vapor balancing when unloading cargo tanks into the storage tanks will reduce the working losses from the storage tanks. Several state and local agencies already require the use of vapor balancing when filling storage tanks at bulk plants with a maximum design capacity throughput of 4,000 gallons per day or more. Bulk plants with capacities below 4,000 gallons per day would retain the requirement to use submerge fill.

The storage tank standards for area source bulk gasoline terminals and pipeline breakout stations cross-reference NSPS subpart Kb requirements or the National Emission Standards for Storage Vessels at 40 CFR part 63, subpart WW, but exclude the floating roof fitting control requirements for both internal and external floating roofs and secondary seal requirements for internal floating roofs with a vapor-mounted primary seal. We assessed costs and impacts of requiring fitting controls separately for internal and external floating roofs. Specifically, we evaluated the control options of (1) requiring upgrades of fitting requirements for external floating roofs consistent with NSPS subpart Kb requirements and (2) requiring upgrades of fitting requirements for external floating roof tanks plus requiring upgrades of fitting and seal requirements for internal floating roofs tanks consistent with NSPS subpart Kb requirements. Table 13 of this document summarizes the national impacts projected for area source gasoline distribution facilities. Again, based on our analysis, we consider adding fitting controls for external floating roof tanks at area source gasoline distribution facilities to be cost effective. Alternatively, the projected cost effectiveness of installing secondary seals and fitting controls for internal floating roof tanks is approximately $45,000 per ton of HAP emissions reduced (incremental costs between Option 1 and 2) and therefore, we determined these controls are not cost effective. Accordingly, we are proposing to require fitting controls for external

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

(tpy)

TCI

($1,000)

TAC

w/o product

recovery

($1,000/yr)

TAC

w/product

recovery

($1,000/yr)

($/ton VOC)

($/ton HAP)

ICE

($/ton VOC)

ICE

($/ton HAP)

(1) Upgrade EFRT fittings

3,338

9,488

882

−720

−216

−4,315

−216

−4,315

(2) Upgrade IFRT and EFRT fittings

10,143

211,100

19,630

14,760

1,455

29,100

2,275

45,500

Compared to baseline emissions of 26,510 tpy.

Total capital investment (TCI).

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

Cost effectiveness (CE) compared to baseline.

HAP content assumed to be 5% of VOC.

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

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

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

Table 14—Nationwide LEL Monitoring Impacts for Area Source Facilities

Facility type

VOC emission

reduction

(tpy)

TAC

w/o product

recovery

($/yr)

TAC

w/product

recovery

($/yr)

($/ton VOC)

($/ton HAP)

Total Area Source Facilities

430

353,200

146,700

341

6,820

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

Cost effectiveness (CE).

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

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

($1000)

TAC

w/o product recovery

($1000/yr)

TAC

w/product

recovery

($1000/yr)

($/ton VOC)

($/ton HAP)

ICE

($/ton VOC)

ICE

($/ton HAP)

AVO (monthly inspection)

1,124

Annual instrument

664

461

217.5

−380

−602

−1,310

−13,100

−1,310

−13,100

Semiannual instrument

439

686

217.5

−47.8

−377

−550

−5,550

999

9,990

Quarterly instrument

309

816

217.5

557

166

203

2,030

4,170

41,700

Total capital investment (TCI).

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

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

HAP content assumed to be 10% of VOC.

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

Facilities would be allowed to select EPA Method 21 or OGI monitoring. If EPA Method 21 is selected, valves and pumps would be required to be monitored at the frequency specified, however, connectors are only monitored annually. If OGI is selected, all applicable valves, pumps, and connectors would be required to be monitored at the frequency specified.

The semiannual instrument monitoring is projected to yield a net cost savings compared to monthly AVO inspections. The incremental cost-effectiveness from going from annual to semiannual instrument monitoring is just under $10,000 per ton of HAP emissions reduced. Taken together, we determined that semiannual instrument monitoring is cost effective. The incremental cost-effectiveness of going to quarterly instrument monitoring is over $40,000 per ton of HAP emissions reduced; therefore, we determined this option is not cost-effective. Considering the developments in equipment leak monitoring practices, we are proposing to require semiannual instrument monitoring for major source gasoline distribution facilities.

b. NESHAP Subpart BBBBBB

The area source rule contains equipment leak standards for bulk gasoline terminals, pipeline breakout stations, bulk gasoline plants, and pipeline pumping stations. Prior to the initial performance test, the area source

rule requires equipment leak monitoring to be conducted using EPA Method 21 using a leak definition of 500 ppm. The area source rule requires subsequent monitoring monthly and allows the use of any leak identification method, including AVO techniques. We evaluated the current monthly AVO inspection requirements with LDAR programs based on periodic instrument monitoring.

Table 16 of this document shows the estimated impacts of applying instrument monitoring for equipment leaks at area source gasoline distribution facilities. For the smaller area source facilities, EPA Method 21 was generally less costly than OGI as an instrument monitoring method. For the larger area sources, we expect facilities to use OGI. The annual instrument monitoring requirement combined with a general requirement to fix any leaks identified (via AVO methods) during the normal course of activities is projected to be less costly than monthly AVO and yield additional emission reductions. Thus, we determined that annual instrument monitoring is cost effective. The relative cost of moving from annual monitoring to semi-annual monitoring is approximately $18,000 per ton of HAP removed which we determined is not cost-effective. Therefore, semi-annual instrument monitoring was rejected because of the high incremental cost-effectiveness compared to annual instrument monitoring and we are proposing to require annual instrument monitoring combined with a requirement to repair any leaks identified (

i.e.,

observed using AVO methods) during the course of regular business activities. Again, EPA is seeking comment on adopting more protective standards at costs above levels that we generally consider to be cost effective for these type of HAP given that many of these sources are located in highly populated areas where the communities surrounding these facilities already have the potential to be overburdened from multiple sources of air pollution. Our assessment of control options is summarized in the memorandum “Area Source Technology Review for the Gasoline Distribution Bulk Terminals, Bulk Plants, and Pipeline Facilities NESHAP” in EPA Docket No. EPA-HQ-OAR-2020-0371.

Table 16—Estimated Emissions and Cost Impacts of Equipment Leak Control Options for Area Source Gasoline Distribution Facilities

Option

VOC

emissions

(tpy)

VOC emission reduction

(tpy)

TCI

($1000)

TAC

w/o product

recovery

($1000/yr)

TAC

w/product

recovery

($1000/yr)

($/ton VOC)

($/ton HAP)

ICE

($/ton VOC)

ICE

($/ton HAP)

AVO

17,080

Annual instrument

9,800

7,280

5,750

−4,180

−7,670

−1,050

−10,500

−1,050

−10,500

Semiannual instrument

6,950

10,100

5,750

2,290

−2,570

−254

−2,540

1,790

17,900

Quarterly instrument

5,320

11,800

5,750

14,600

8,980

764

7,640

7,100

71,000

Total capital investment (TCI).

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

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

HAP content assumed to be 10% of VOC.

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

c. NSPS Subpart XXa

The NSPS subpart XX contains equipment leak standards for bulk gasoline terminals. Prior to the initial performance test, the NSPS requires monitoring to be conducted of the vapor collection system using EPA Method 21 using a leak definition of 10,000 ppm. The NSPS also requires subsequent monitoring of the loading racks, vapor collection system and vapor processing system monthly using any leak identification method, including AVO techniques.

Regarding monitoring requirements prior to performance tests, we determined that these requirements are effective requirements for the closed vent system used to transfer vapors from the loading racks to the control system. Generally, the EPA requires these closed vent systems to operate with no detectable emissions (which is defined as less than 500 ppmv above background using EPA Method 21). Both major and area source NESHAP subparts R and BBBBBB require the monitoring of the vapor collection system prior to a performance test using this no detectable emissions threshold (500 ppmv using EPA Method 21). Consistent with current practices for closed vent systems, we are proposing in subpart XXa to require that monitoring of the vapor collection system prior to a performance test be conducted using EPA Method 21 and that the vapor collection system be operated with no detectable emissions (no leaks greater than 500 ppmv).

For the ongoing leak monitoring requirements, we evaluated the current monthly AVO inspection requirements compared to LDAR programs based on periodic instrument monitoring along with a general requirement to fix any leaks identified (via AVO methods) during the normal course of activities. Table 17 of this document provides estimated costs for newly affected bulk gasoline terminals. When considering VOC emission impacts, the overall cost effectiveness of the quarterly monitoring option is $259 per ton VOC reduced and the incremental cost effectiveness of quarterly monitoring compared to semi-annual monitoring is $4,020 per ton of VOC reduced. Taken together, we determined that quarterly instrument monitoring is cost effective for reducing VOC emissions. Therefore, we are proposing to require quarterly monitoring for bulk gasoline terminals in NSPS subpart XXa along with a general requirement to fix any leaks identified (via AVO methods) during normal duties. Our assessment of control options is summarized in the memorandum “New Source Performance Standards Review for Bulk Gasoline Terminals” in EPA Docket No. EPA-HQ-OAR-2020-0371.

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

($)

TAC

w/o product

recovery

($/yr)

TAC

w/product

recovery

($/yr)

($/ton VOC)

ICE

($/ton VOC)

AVO (monthly inspection)

4.47

Annual instrument

2.64

1.83

1,000

−1,240

−2,120

−1,160

Semiannual instrument

1.74

2.73

1,000

−1,250

−458

962

Quarterly instrument

1.22

3.25

1,000

2,405

843

259

4,020

Total capital investment (TCI).

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

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

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

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

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

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

to reflect the court vacatur that revised the 40 CFR part 63 General Provisions to remove the SSM exemptions at 40 CFR 63.6(f)(1) and (h)(1). In this action, we are proposing to eliminate references to these SSM exemptions that are null and void, remove any additional SSM exemptions or references to SSM exemptions, and remove any cross-references to provisions in 40 CFR part 63 (General Provisions) that are unnecessary, inappropriate or redundant in the absence of the SSM exemption. The EPA determined the reasoning in the court's decision in

Sierra Club

applies equally to CAA section 111. Consistent with

Sierra Club

EPA,

the standards that we are proposing in NSPS subpart XXa would apply at all times.

U.S. EPA,

Court Vacatur of Exemption From Emission Standards During Periods of Startup, Shutdown, and Malfunction.

(86 FR 13819, March 11, 2021).

a. Proposed Elimination of the SSM Exemption in NESHAP Subpart R

We are proposing the elimination of the vacated exemption provision and several revisions to Table 1 of this document, (the General Provisions Applicability Table to subpart R of part 63, hereafter referred to as the “General Provisions table to subpart R”) as is explained in more detail below. For example, we are proposing to eliminate the incorporation of the General Provisions' requirement that the source develop an SSM plan. We also are proposing to eliminate and revise certain recordkeeping and reporting requirements related to the SSM exemption. The EPA has attempted to ensure that the provisions we are proposing to eliminate are inappropriate, unnecessary, or redundant in the absence of the SSM exemption.

The EPA considers that processes at Gasoline Distribution facilities are not continuous and that there will be variation in emission stream characteristics over time. The standards consider this variation and provide sources the ability to meet the standards at all times. Therefore, we have not proposed alternate standards for startup and shutdown.

U.S. Sugar Corp.

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

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

EPA,

the exemption language in 63.6(f)(1) and (h)(1) are null and void and any cross reference to those provisions have no effect. The EPA amended 40 CFR 63.6(f)(1) and (h)(1) on March 11, 2021, to reflect the court order and revise the CFR to remove the SSM exemption. However, the second sentence of 40 CFR 63.6(f)(1) contains language that is premised on the existence of an exemption and is inappropriate in the absence of the exemption. Thus, rather than cross-referencing 63.6(f)(1), we are adding the language of 63.6(f)(1) that requires compliance with standards at all times to the regulatory text at 40 CFR 63.420(k). The court in

Sierra Club

vacated the exemptions contained in this provision and held that the CAA requires that some CAA section 112 standards apply continuously.

As noted in the General Provisions table to subpart R entry for 40 CFR 63.6(h), there are no opacity standards in NESHAP subpart R, so the General Provisions at 40 CFR 63.6(h) were marked as “no” in column 2. There are visible emissions observations for flares, so we are proposing to revise the comment in column 3 to note that NESHAP subpart R specifies the requirements for visible emissions observations for flares.

4. Performance Testing

We are proposing to revise the General Provisions table to subpart R of Part 63 entry for 40 CFR 63.7(e)(1) by changing the “yes” in column 2 to a “no.” Section 63.7(e)(1) describes performance testing requirements. The EPA is instead proposing to add a performance testing requirement at 40 CFR 63.425(a). The performance testing requirements we are proposing to add differ from the General Provisions performance testing provisions in several respects. The regulatory text does not include the language in 40 CFR 63.7(e)(1) that restated the SSM exemption and language that precluded startup and shutdown periods from being considered “representative” for purposes of performance testing. The proposed performance testing provisions specifically note the batch operation of gasoline loading operations and include periods when cargo tanks are being changed out when a full cargo tank is disconnected, and a new cargo tank is moved into position for loading. As in 40 CFR 63.7(e)(1), performance tests conducted under this subpart should not be conducted during malfunctions because conditions during malfunctions are often not representative of normal operating conditions. The EPA is proposing to add language that requires the owner or operator to record the process information that is necessary to document operating conditions during the test and include in such record an explanation to support that such conditions represent normal operation. Section 63.7(e)(1) requires that the owner or operator make such records “as may be necessary to determine the condition of the performance test” available to the Administrator upon request but does not specifically require the information to be recorded. The regulatory text the EPA is proposing to add to this provision builds on that requirement and makes explicit the requirement to record the information.

5. Monitoring

We are proposing to revise the General Provisions table to subpart R of Part 63 by adding separate entries for 40 CFR 63.8(c)(1)(i) and (iii) and including a “no” in column 2. The cross-references to the general duty and SSM plan requirements in those subparagraphs are not necessary in light of other requirements of 40 CFR 63.8 that require good air pollution control practices (40 CFR 63.8(c)(1)) and that set out the requirements of a quality control program for monitoring equipment (40 CFR 63.8(d)).

We are proposing to revise the major source General Provisions table to subpart R of Part 63 by splitting the entry for 40 CFR 63.8(d) into two separate entries, one for 40 CFR 63.8(d)(1) and (2) and retaining the “yes” in column 2 and one for 40 CFR 63.8(d)(3) and including a “no” in column 2. The final sentence in 40 CFR 63.8(d)(3) refers to the General Provisions' SSM plan requirement which is no longer applicable. The EPA is proposing to add provisions to subpart R at 40 CFR 63.428(d)(4) that is identical to 40 CFR 63.8(d)(3) except that the final sentence is replaced with the following sentence: “The program of corrective action should be included in the plan as required under § 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

a description of the method used to estimate the emissions. Examples of such methods would include product-loss calculations, mass balance calculations, measurements when available, or engineering judgment based on known process parameters. The EPA is proposing to require that sources keep records of this information to ensure that there is adequate information to allow the EPA to determine the severity of any failure to meet a standard, and to provide data that may document how the source met the general duty to minimize emissions when the source has failed to meet an applicable standard.

• 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 cross-reference to 40 CFR 63.10(d)(5)(ii). Section 63.10(d)(5)(ii) describes an immediate report for startups, shutdown, and malfunctions when a source failed to meet an applicable standard but did not follow the SSM plan. We will no longer require owners or operators to report when actions taken during a startup, shutdown, or malfunction were not consistent with an SSM plan, because plans would no longer be required.

b. Proposed Revisions To Address SSM Provisions in NESHAP Subpart BBBBBB

We are proposing to remove references to malfunction throughout NESHAP subpart BBBBBB. Specifically, we are removing the requirements at 40 CFR 63.11092(b)(1)(i)(B)(

)(

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

)(

), 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)(

)(

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

)(

), 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

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.

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

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.

https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-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.

The EPA specifically requests comment on the content, layout, and overall design of the templates.

See Gasoline Distribution Semiannual Reporting Template, available at Docket ID. No. EPA-HQ-OAR-2020-0371.

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)

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