Home/Federal/Federal Register/2026-07800

Proposed Rule2026-07800

National Emission Standards for Hazardous Air Pollutants: Crude Oil and Natural Gas Production Facilities and Natural Gas Transmission and Storage Facilities; Technology Review and Reconsideration

Primary source

Metadata and text below are from the Federal Register, a public-domain U.S. government work. Always verify the official published version before relying on it for any legal matter.

Published

April 22, 2026

Issuing agencies

Environmental Protection Agency

Abstract

The U.S. Environmental Protection Agency (EPA) is proposing an action related to the National Emission Standards for Hazardous Air Pollutants (NESHAP) from Crude Oil and Natural Gas Production Facilities and from Natural Gas Transmission and Storage Facilities (Oil and Gas NESHAP) in connection with a technology review pursuant to Clean Air Act (CAA) section 112. Based on the EPA's review the Agency is not proposing any revision to the current standards in the NESHAP. With respect to unregulated pollutants, the EPA is proposing standards for methanol from regulated emission points at crude oil and natural gas production facilities that will result in no additional control requirements. The EPA is further proposing two alternative approaches to emission points not currently regulated in these NESHAP. Under the first approach, we are proposing that the Agency does not have an obligation to regulate previously unregulated emission points when conducting a CAA section 112(d)(6) review and to defer action on that basis. Under the second approach, we are proposing new control standards for previously unregulated emission points, which include: acid gas removal units, transport vessel loading operations, and storage vessels without flash emissions at crude oil and natural gas production facilities, as well as storage vessels, transport vessel loading and natural gas-driven process controllers and pumps at natural gas transmission and storage facilities. The EPA is also concurrently proposing changes to the definition of "associated equipment" with respect to a major source to align with the CAA that, if finalized, would reduce burdens on industry. Finally, the EPA is proposing minor technical corrections to the existing regulations.

Full Text

<html>
<head>
<title>Federal Register, Volume 91 Issue 77 (Wednesday, April 22, 2026)</title>
</head>
<body><pre>
[Federal Register Volume 91, Number 77 (Wednesday, April 22, 2026)]
[Proposed Rules]
[Pages 21672-21705]
From the Federal Register Online via the Government Publishing Office [<a href="http://www.gpo.gov">www.gpo.gov</a>]
[FR Doc No: 2026-07800]

[[Page 21671]]

Vol. 91

Wednesday,

No. 77

April 22, 2026

Part III

Environmental Protection Agency

-----------------------------------------------------------------------

40 CFR Part 63

National Emission Standards for Hazardous Air Pollutants: Crude Oil and
Natural Gas Production Facilities and Natural Gas Transmission and
Storage Facilities; Technology Review and Reconsideration; Proposed
Rule

Federal Register / Vol. 91 , No. 77 / Wednesday, April 22, 2026 /
Proposed Rules

[[Page 21672]]

-----------------------------------------------------------------------

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 63

[EPA-HQ-OAR-2025-1348; FRL-5732-02-OAR]
RIN 2060-AS13

National Emission Standards for Hazardous Air Pollutants: Crude
Oil and Natural Gas Production Facilities and Natural Gas Transmission
and Storage Facilities; Technology Review and Reconsideration

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

-----------------------------------------------------------------------

SUMMARY: The U.S. Environmental Protection Agency (EPA) is proposing an
action related to the National Emission Standards for Hazardous Air
Pollutants (NESHAP) from Crude Oil and Natural Gas Production
Facilities and from Natural Gas Transmission and Storage Facilities
(Oil and Gas NESHAP) in connection with a technology review pursuant to
Clean Air Act (CAA) section 112. Based on the EPA's review the Agency
is not proposing any revision to the current standards in the NESHAP.
With respect to unregulated pollutants, the EPA is proposing standards
for methanol from regulated emission points at crude oil and natural
gas production facilities that will result in no additional control
requirements. The EPA is further proposing two alternative approaches
to emission points not currently regulated in these NESHAP. Under the
first approach, we are proposing that the Agency does not have an
obligation to regulate previously unregulated emission points when
conducting a CAA section 112(d)(6) review and to defer action on that
basis. Under the second approach, we are proposing new control
standards for previously unregulated emission points, which include:
acid gas removal units, transport vessel loading operations, and
storage vessels without flash emissions at crude oil and natural gas
production facilities, as well as storage vessels, transport vessel
loading and natural gas-driven process controllers and pumps at natural
gas transmission and storage facilities. The EPA is also concurrently
proposing changes to the definition of ``associated equipment'' with
respect to a major source to align with the CAA that, if finalized,
would reduce burdens on industry. Finally, the EPA is proposing minor
technical corrections to the existing regulations.

DATES: Comments must be received on or before June 22, 2026. Under the
Paperwork Reduction Act (PRA), comments on the information collection
provisions are best assured of consideration if the Office of
Management and (OMB) receives a copy of your comments on or before May
22, 2026.
Public hearing: If anyone contacts us requesting a public hearing
on or before April 27, 2026, 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-2025-1348, by any of the following methods:
<bullet> Federal eRulemaking Portal: <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>
(our preferred method). Follow the online instructions for submitting
comments.
<bullet> Email: <a href="/cdn-cgi/l/email-protection#8deca0ece3e9a0ffa0e9e2eee6e8f9cde8fdeca3eae2fb">[email&#160;protected]</a>. Include Docket ID No. EPA-
HQ-OAR-2025-1348 in the subject line of the message.
<bullet> Fax: (202) 566-9744. Attention Docket ID No. EPA-HQ-OAR-
2025-1348.
<bullet> Mail: U.S. Environmental Protection Agency, EPA Docket
Center, Docket ID No. EPA-HQ-OAR-2025-1348, Mail Code 28221T, 1200
Pennsylvania Avenue NW, Washington, DC 20460.
<bullet> Hand/Courier Delivery: EPA Docket Center, WJC West
Building, Room 3334, 1301 Constitution Avenue NW, Washington, DC 20004.
The Docket Center's hours of operation are 8:30 a.m. to 4:30 p.m.,
Monday through Friday (except Federal holidays).
Instructions: All submissions received must include the Docket ID
No. for this rulemaking. Comments received may be posted without change
to <a href="https://www.regulations.gov/">https://www.regulations.gov/</a> including any personal information
provided. For detailed instructions on sending comments and additional
information on the rulemaking process, see the SUPPLEMENTARY
INFORMATION section of this document.

FOR FURTHER INFORMATION CONTACT: For information about this proposed
rulemaking, contact U.S. EPA, Attn: Matthew Witosky, Mail Drop: E143-
05, 109 T.W. Alexander Drive, P.O. Box 12055, RTP, North Carolina
27711; telephone number: (919) 541-2865 and email address:
<a href="/cdn-cgi/l/email-protection#0b7c627f6478607225666a7f7f636e7c4b6e7b6a256c647d">[email&#160;protected]</a>.

SUPPLEMENTARY INFORMATION:
Participation in virtual public hearing. To request a virtual
public hearing, contact the public hearing team at (888) 372-8699 or by
email at <a href="/cdn-cgi/l/email-protection#1d534f596d687f71747e75787c6f74737a5d786d7c337a726b">[email&#160;protected]</a>. If requested, the hearing will be
held via virtual platform on May 12, 2026. The EPA will announce
further details, at <a href="https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/actions-and-notices-about-oil-and-0">https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/actions-and-notices-about-oil-and-0</a>. The EPA
will begin pre-registering speakers for the hearing no later than one
business day after a request has been received. To register to speak at
the virtual hearing, please use the online registration form available
at <a href="https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/actions-and-notices-about-oil-and-0">https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/actions-and-notices-about-oil-and-0</a> or contact the public
hearing team at (888) 372-8699 or by email at <a href="/cdn-cgi/l/email-protection#1d534f596d687f71747e75787c6f74737a5d786d7c337a726b">[email&#160;protected]</a>.
The last day to pre-register to speak at the hearing will be May 4,
2026. Prior to the hearing, the EPA will post a general agenda that
will list pre-registered speakers at: <a href="https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/actions-and-notices-about-oil-and-0">https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/actions-and-notices-about-oil-and-0</a>.
The EPA will make every effort to follow the schedule as closely as
possible on the day of the hearing; however, please plan for the
hearings to run either ahead of schedule or behind schedule. The EPA
may close a session 15 minutes after the last pre-registered speaker
has testified if there are no additional speakers.
Each commenter will have four minutes to provide oral testimony.
The EPA encourages commenters to submit a copy of their oral testimony
as written comments electronically to the rulemaking docket.
The EPA may ask clarifying questions during the oral presentations
but will not respond to the presentations at that time. Written
statements and supporting information submitted during the comment
period will be considered with the same weight as oral testimony and
supporting information presented at the public hearing.
Please note that any updates made to any aspect of the hearing will
be posted online at <a href="https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/actions-and-notices-about-oil-and-0">https://www.epa.gov/controlling-air-pollution-oil-and-natural-gas-operations/actions-and-notices-about-oil-and-0</a>. While
the EPA expects the hearing to go forward as set forth above, please
monitor our website or contact the public hearing team at (888) 372-
8699 or by email at <a href="/cdn-cgi/l/email-protection#c9879b8db9bcaba5a0aaa1aca8bba0a7ae89acb9a8e7aea6bf">[email&#160;protected]</a> to determine if there are
any updates. The EPA does not intend to publish a document in the
Federal Register announcing updates.
If you require special accommodations such as audio

[[Page 21673]]

description, please pre-register for the hearing with the public
hearing team and describe your needs by April 29, 2026. The EPA may not
be able to arrange accommodations without advanced notice.
Docket. The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2025-1348. All documents in the docket are
listed in <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>. Although listed, some
information is not publicly available, e.g., Confidential Business
Information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the internet and will be publicly available only as
Portable Document Format (PDF) versions that can only be accessed on
the EPA computers in the docket office reading room. Certain databases
and physical items cannot be downloaded from the docket but may be
requested by contacting the docket office at 202-566-1744. The docket
office has up to 10 business days to respond to these requests. With
the exception of such material, publicly available docket materials are
available electronically at <a href="https://www.regulations.gov">https://www.regulations.gov</a>.
Instructions. Direct your comments to Docket ID No. EPA-HQ-OAR-
2025-1348. The EPA's policy is that all comments received will be
included in the public docket without change and may be made available
online at <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>, including any personal
information provided, unless the comment includes information claimed
to be CBI or other information whose disclosure is restricted by
statute. Do not submit electronically to <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>
any information that you consider to be CBI or other information whose
disclosure is restricted by statute. This type of information should be
submitted as discussed below.
The EPA may publish any comment received to its public docket.
Multimedia submissions (audio, video, etc.) must be accompanied by a
written comment. The written comment is considered the official comment
and should include discussion of all points you wish to make. The EPA
will generally not consider comments or comment contents located
outside of the primary submission (i.e., on the Web, cloud, or other
file sharing system). For additional submission methods, the full EPA
public comment policy, information about CBI or multimedia submissions,
and general guidance on making effective comments, please visit <a href="https://www.epa.gov/dockets/commenting-epa-dockets">https://www.epa.gov/dockets/commenting-epa-dockets</a>.
The <a href="https://www.regulations.gov/">https://www.regulations.gov/</a> website allows you to submit your
comment anonymously, which means the EPA will not know your identity or
contact information unless you provide it in the body of your comment.
If you send an email comment directly to the EPA without going through
<a href="https://www.regulations.gov/">https://www.regulations.gov/</a>, your email address will be automatically
captured and included as part of the comment that is placed in the
public docket and made available on the internet. If you submit an
electronic comment, the EPA recommends that you include your name and
other contact information in the body of your comment and with any
digital storage media you submit. If the EPA cannot read your comment
due to technical difficulties and cannot contact you for clarification,
the EPA may not be able to consider your comment. Electronic files
should not include special characters or any form of encryption and be
free of any defects or viruses. For additional information about the
EPA's public docket, visit the EPA Docket Center homepage at <a href="https://www.epa.gov/dockets">https://www.epa.gov/dockets</a>.
The EPA is soliciting comments on numerous aspects of this proposed
rulemaking. The EPA has indexed each comment solicitation with an
identifier (e.g., Question 1, Question 2.) to provide a consistent
framework for effective and efficient provision of comments.
Accordingly, we ask that commenters include the corresponding
identifier when providing comments relevant to that comment
solicitation. We ask that commenters include the identifier in either a
heading, or within the text of each comment (e.g., In response to
Question 1, . . .) to make clear which comment solicitation is being
addressed. We emphasize that we are not limiting comments to these
identified areas and encourage provision of any other comments relevant
to this proposal.
Submitting CBI. Do not submit information containing CBI to the EPA
through <a href="https://www.regulations.gov/">https://www.regulations.gov/</a>. Clearly mark the part or all of
the information that you claim to be CBI. For CBI information on any
digital storage media that you mail to the EPA, note the docket ID,
mark the outside of the digital storage media as CBI, and identify
electronically within the digital storage media the specific
information that is claimed as CBI. In addition to one complete version
of the comments that includes information claimed as CBI, you must
submit a copy of the comments that does not contain the information
claimed as CBI directly to the public docket through the procedures
outlined in the Instructions section above. 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 OCAP
CBI Office at the email address <a href="/cdn-cgi/l/email-protection#3758564647446854555e7752475619505841">[email&#160;protected]</a>, and as described
above, should include clear CBI markings and note the docket ID. If
assistance is needed with submitting large electronic files that exceed
the file size limit for email attachments, and if you do not have your
own file sharing service, please email <a href="/cdn-cgi/l/email-protection#9df2fcecedeec2fefff4ddf8edfcb3faf2eb">[email&#160;protected]</a> to request a
file transfer link. If sending CBI information through the postal
service, please send it to the following address: OCAP Document Control
Officer (C404-02), OCAP, U.S. Environmental Protection Agency, Research
Triangle Park, North Carolina 27711, Attention Docket ID No. EPA-HQ-
OAR-2025-1348. 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 preamble 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:

AGRUs acid gas removal units
AWP alternative work practice
BACT Best Available Control Technology
BID Background Information Document
BTEX benzene, toluene, ethylbenzene, and xylenes
[deg] C degrees Centigrade
CAA Clean Air Act
CBI Confidential Business Information
CFR Code of Federal Regulations
COS carbonyl sulfide
CS<INF>2</INF> carbon disulfide
CO<INF>2</INF> carbon dioxide
DEG diethylene glycol
EPA Environmental Protection Agency
ERT Electronic Reporting Tool
EAV equivalent annualized value
[ordm] F degrees Fahrenheit
FR Federal Register

[[Page 21674]]

FTP File Transfer Protocol
GACT generally available control technology
Gr grain
HAP hazardous air pollutant(s)
H<INF>2</INF>S hydrogen sulfide
ICR Information Collection Request
IR infrared
LAER Lowest Achievable Emission Rate
LDAR leak detection and repair
LEAN Louisiana Environmental Action Network
MACT maximum achievable control technology
Mg/yr megagrams per year
MMscf million standard cubic feet
MMscf million standard cubic feet per day
NAICS North American Industry Classification System
NEI National Emissions Inventory
NESHAP national emission standards for hazardous air pollutants
NGL natural gas liquids
NO<INF>X</INF> nitrogen oxide
NSPS New Source Performance Standards
OCAP Office of Clean Air Programs
OGI optical gas imaging
OMB Office of Management and Budget
PFE potential for flash emissions
PM particulate matter
ppm parts per million
ppmv parts per million by volume
psig pounds per square inch gauge
PV present value
RACT Reasonably Available Control Technology
RBLC RACT/BACT/LAER Clearinghouse
RTR Risk and Technology Review
SBA Small Business Administration
scf standard cubic feet
scfh standard cubic feet per hour
SO<INF>2</INF> sulfur dioxide
TEG triethylene glycol
TOC total organic compound
tpy tons per year
UPL Upper Prediction Limit
U.S.C. United States Code
VCS voluntary consensus standards
VOC volatile organic compounds
VRU vapor recovery unit

Table of Contents

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 does the current
NESHAP regulate its HAP 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 technology review?
III. Analytical Results and Proposed Decisions
A. What are the results and proposed decisions based on our
technology review for emission points and HAP currently regulated in
NESHAP Subpart HH and NESHAP Subpart HHH, and what is the rationale
for those decisions?
B. What other actions are we proposing, and what is the
rationale for those actions?
C. Technical Corrections to Subparts HH and HHH
D. What compliance dates are we proposing, and what is the
rationale for the proposed compliance dates?
IV. Request for Comments
V. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 13563: Improving Regulation and Regulatory Review
B. Executive Order 14192: Unleashing Prosperity Through
Deregulation
C. Paperwork Reduction Act (PRA)
D. Regulatory Flexibility Act (RFA)
E. Unfunded Mandates Reform Act (UMRA)
F. Executive Order 13132: Federalism
G. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
H. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use
J. National Technology Transfer and Advancement Act (NTTAA) and
1 CFR Part 51

I. General Information

A. Executive Summary

In 1999, the EPA promulgated the Oil and Gas NESHAP to regulate HAP
emissions from crude oil and natural gas production facilities and from
natural gas transmission and storage facilities under 40 CFR part 63,
subparts HH and HHH, respectively (1999 Final Rule).\1\ Section 112 of
the CAA required the EPA to review the standards within eight years to
identify and address any residual risk to human health and the
environment and, separately, to revise the standards as ``necessary''
in light of developments in practices, processes, and control
technologies every eight years. The EPA finalized the residual risk and
initial technology review for the two major source oil and natural gas
categories in 2012 (2012 Final Rule).\2\
---------------------------------------------------------------------------

\1\ 64 FR 32610 (June 17, 1999).
\2\ 77 FR 49490 (August 16, 2012).
---------------------------------------------------------------------------

Environmental and industry representatives petitioned the EPA to
reconsider and amend the residual risk review, the technology review,
and certain provisions of the 2012 Final Rule. In 2017, the Agency
agreed to reconsider two issues raised in industry and environmental
groups' administrative petition: the small dehydrator standards and the
establishment of standards that accounted for variability using an
upper prediction limit (UPL) of 99 percent. The Agency subsequently
entered into a consent decree to respond to the remaining issues in the
petition that are under reconsideration and to complete the second
technology review required by CAA section 112(d)(6).\3\
---------------------------------------------------------------------------

\3\ Cal. Cmtys. Against Toxics, et al. v. Regan, No. 1:22-cv-
10120-CRC (D.D.C.).
---------------------------------------------------------------------------

In this proposed rulemaking, the EPA is proposing amendments to
certain aspects of the Oil and Gas NESHAP in response to the petition
for reconsideration and the technology review under CAA section
112(d)(6). The proposal also includes corrections to technical errors
in the current NESHAP subparts HH and HHH. The treatment of standards
within this proposal can be divided into the following categories: (1)
already regulated emission points of currently regulated HAP; (2)
unregulated emission points; and (3) regulated emission points of HAP
not currently regulated. Additionally, the EPA is specifically
soliciting comment on several aspects of this proposed rule. See table
3 in section IV of the preamble for a complete list of the solicitation
of comments in this proposed rulemaking.
1. Already Regulated Emission Points of Currently Regulated HAP
The EPA proposes no revisions to the current standards in NESHAP
subparts HH and HHH are necessary pursuant to the CAA section 112(d)(6)
technology review. The current NESHAP subpart HH contains major source
standards for HAP emissions from glycol dehydration process vents,
storage vessels with potential for flash emissions, and natural gas
processing plant equipment leaks and area source standards for glycol
dehydrators, while subpart HHH contains major source standards for
glycol dehydration process vents. As explained below, we have not
identified cost-effective developments that, considering all relevant
factors, render it ``necessary'' to propose revisions to the existing
standards within these categories.
2. Unregulated Emission Points
With respect to emission points unregulated under these NESHAP, the
EPA proposes that we are not obligated to promulgate standards for
additional emission points at this time as part of the CAA section
112(d)(6) technology review. Under this approach, we would defer action
on expanding these NESHAP to include currently unregulated emission
points to better conform this action to the obligation conferred under
CAA section 112(d)(6) and consider at a later time whether and

[[Page 21675]]

how such HAP emissions from such emission points should be addressed.
In the alternative, the EPA is performing the analyses for a MACT
floor under CAA section 112(d)(3) and combining the beyond-the-floor
analysis of CAA section 112(d)(2) with the technology review analysis
of CAA section 112(d)(6). These analyses and the resulting proposed
standards from this alternative approach are presented in section
III.B.4 of this preamble. These proposed alternatives in NESHAP subpart
HH include standards for the following previously unregulated emission
points: acid gas removal units (AGRU), storage vessels without the
potential for flash emissions (PFE), and transport vessel loading
operations. The proposed alternatives in NESHAP subpart HHH include
standards for the following previously unregulated emission points:
storage vessels, transport vessel loading operations, controllers, and
pumps.
3. Regulated Emission Points of Previously Unregulated HAP
The EPA also proposes in this document new standards for a
previously unregulated HAP, methanol, from already regulated emission
points at crude oil and natural gas production facilities (NESHAP
subpart HH). Our proposal to regulate methanol does not include sources
at transmission and storage facilities (NESHAP subpart HHH); while
industry reported HAP emissions, including methanol, in response to the
2023 ICR questionnaire, there were no reported methanol emissions from
transportation and storage facilities. Lastly, we propose revising the
major source definition for production facilities along with several
technical corrections.
4. Impacts of Proposal
Under the proposed approach, which limits the scope of this
rulemaking to only those regulatory activities required by Congress in
CAA section 112(d)(6), the EPA anticipates that this proposed
rulemaking will not result in additional compliance costs or emissions
reductions for the proposed option. For the alternative proposed option
in which the EPA proposes new standards for previously unregulated
emission points, the Agency anticipates minimal costs (due to increased
recordkeeping and reporting requirements) and no emissions impacts
since the relevant facilities would already be able to achieve the
alternative proposed standards.
The EPA proposes to amend the definition of ``associated
equipment'' by removing ``except glycol dehydrators and storage
vessels.'' The EPA is proposing this change because glycol dehydrators
and storage vessels are clearly equipment associated with production
wells, and we do not see any language in CAA section 112(n)(4) allowing
aggregation of emissions from any associated equipment in determining
whether any such equipment is a major source. The EPA expects that this
proposed amendment will have deregulatory impacts (cost savings),
though the Agency lacks the information needed to make a quantitative
assessment at this time.

B. Does this action apply to me?

Table 1 of this preamble lists the NESHAP and associated regulated
industrial source categories that are the subject of this proposal.
Table 1 is not intended to be exhaustive but rather provides a guide
for readers regarding the entities that this proposed rulemaking is
likely to affect. The proposed standards, once promulgated, will be
directly applicable to the affected sources. Federal, State, local, and
Tribal government entities would not be affected by this proposed
rulemaking. As defined in the Initial List of Categories of Sources
Under Clean Air Act Amendments of 1990 Section 112(c)(1) (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 crude oil and natural gas production category source category is
any facility engaged in crude oil and natural gas production. The
natural gas transmission and storage category is any facility engaged
in natural gas transmission and storage. This source category includes,
but is not limited to, glycol dehydration units, storage vessel
emissions, and equipment leaks from compressors and ancillary equipment
at natural gas processing plants. Subsequently, in the Final Area
Source Rule on January 3, 2007,\4\ 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.\5\ Oil and
natural gas production is identified in the Urban Air Toxics Strategy
as an area source category for regulation under CAA section 112(c)(3)
because of benzene emissions from triethylene glycol (TEG) dehydration
units located at such facilities. The Oil and Gas Production area
source category covers glycol dehydration units.
---------------------------------------------------------------------------

\4\ 72 FR 26 (January 3, 2007).
\5\ 64 FR 38706 (July 19, 1999).
---------------------------------------------------------------------------

The source categories that are the subject of this proposal are
Crude Oil and Natural Gas Production and Natural Gas Transmission and
Storage regulated under 40 CFR part 63, subparts HH and HHH,
respectively. The EPA set maximum achievable control technology (MACT)
standards for the Crude Oil and Natural Gas Production major source
category in 1999 and conducted the residual risk and technology review
in 2012 (NESHAP subpart HH). The EPA set MACT standards for the Natural
Gas Transmission and Storage major source category in 1999 and
conducted the residual risk and technology review in 2012 (NESHAP
subpart HHH). The sources affected by the major source NESHAP for the
Crude Oil and Natural Gas Production source category (NESHAP subpart
HH) are oil and natural gas production and processing facilities. The
EPA set generally available control technology (GACT) standards for the
Crude Oil and Natural Gas area source category in the 2007 Final Area
Source Rule (NESHAP subpart HH). The sources affected by the area
source NESHAP for the Crude Oil and Natural Gas Production source
category are glycol dehydrators at oil and gas production and
processing facilities that are not major sources.

Table 1--NESHAP and Industrial Source Categories Affected by This
Proposed Action
------------------------------------------------------------------------
Source category NESHAP NAICS code \1\
------------------------------------------------------------------------
Crude Oil and Natural Gas 40 CFR part 63, 211111 211112
Production. subpart HH.
Natural Gas Transmission and 40 CFR part 63, 221210 486111
Storage. subpart HHH. 486210
------------------------------------------------------------------------
\1\ North American Industry Classification System (NAICS).

[[Page 21676]]

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 rulemaking is available on the internet. In accordance with 5
U.S.C. 553(b)(4), a brief summary of this rulemaking may be found at
<a href="http://www.regulations.gov">www.regulations.gov</a>, Docket ID No. EPA-HQ-OAR-2025-1348. Following
signature by the EPA Administrator, the Agency will post a copy of this
proposed rulemaking at <a href="https://www.epa.gov/stationary-sources-air-pollution/oil-and-natural-gas-production-facilities-national-emission">https://www.epa.gov/stationary-sources-air-pollution/oil-and-natural-gas-production-facilities-national-emission</a>.
Following publication in the Federal Register, the EPA will post the
Federal Register version of the proposal and key technical documents at
this same website.
A memorandum showing the rulemaking edits that would be necessary
to incorporate the changes to NESHAP subparts HH and HHH proposed in
this action is available in the docket (Docket ID No. EPA-HQ-OAR-2025-
1348). Following signature by the EPA Administrator, the EPA also will
post a copy of this document to <a href="https://www.epa.gov/stationary-sources-air-pollution/oil-and-natural-gas-production-facilities-national-emission">https://www.epa.gov/stationary-sources-air-pollution/oil-and-natural-gas-production-facilities-national-emission</a>.

II. Background

A. What is the statutory authority for this action?

The statutory authority for this action is provided by CAA section
112, as amended (42 U.S.C. 7412). Section 112 of the CAA establishes a
two-stage regulatory process to develop standards for emissions of HAP
from stationary sources. Generally, the first stage involves
establishing technology-based standards that reflect MACT or an
appropriate alternative.\6\ The second stage involves evaluating those
standards within eight years to determine whether additional standards
are needed to address any remaining risk associated with HAP
emissions.\7\ This second stage is commonly referred to as the
``residual risk review.'' In addition to the residual risk review, CAA
section 112 also requires the EPA to review the standards every eight
years and ``revise as necessary'' taking into account ``developments in
practices, processes, or control technologies.'' \8\ This review is
commonly referred to as the ``technology review,'' and is the subject
of this proposal unless otherwise indicated. The discussion that
follows identifies the most relevant statutory sections and briefly
explains the contours of the methodology used to implement these
statutory requirements.
---------------------------------------------------------------------------

\6\ 42 U.S.C. 7412(d)(1)-(4).
\7\ Id. 7412(f)(2).
\8\ Id. 7412(d)(6).
---------------------------------------------------------------------------

In the first stage of 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
tpy or more of a single HAP or 25 tpy or more of any combination of
HAP.\9\ All other sources are ``area sources.'' \10\ 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 non-air 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,''
based on emission controls achieved in practice by the best performing
sources. 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 also considers control options that are more
stringent than the floor.\11\ Standards more stringent than the floor
are commonly referred to as ``beyond-the-floor'' standards. For area
sources, CAA section 112(d)(5) allows the EPA to set standards based on
generally available control technologies or management practices (GACT
standards) in lieu of MACT standards. For categories of major sources
and any area source categories subject to MACT standards, the second
stage focuses on identifying and addressing any remaining (i.e.,
``residual'') risk within eight years pursuant to CAA section 112(f)
and concurrently conducting a technology review pursuant to CAA section
112(d)(6). For categories of area sources subject to GACT standards,
there is no requirement to address residual risk, but, similar to the
major source categories, the technology review is required every eight
years.\12\
---------------------------------------------------------------------------

\9\ Id. 7412(a)(1).
\10\ Id. 7412(a)(2).
\11\ Id. 7412(d)(2).
\12\ Id. 7412(d)(6).
---------------------------------------------------------------------------

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 eight years. In conducting
this review, which we call the ``technology review,'' the EPA is not
required to recalculate the MACT floors that were established in
earlier rulemakings.\13\ The EPA may consider cost in deciding whether
to revise the standards pursuant to CAA section 112(d)(6).\14\
---------------------------------------------------------------------------

\13\ Ass'n of Battery Recyclers, Inc. v. EPA, 716 F.3d 667 (D.C.
Cir. 2013); Nat. Res. Def. Council (NRDC) v. EPA, 529 F.3d 1077,
1084 (D.C. Cir. 2008).
\14\ 42 U.S.C. 7412(d)(2), (d)(6); Ass'n of Battery Recyclers,
716 F.3d at 673-74.
---------------------------------------------------------------------------

B. What are the source categories and how does the current NESHAP
regulate its HAP emissions?

This section of the preamble generally describes: the structure of
the oil and natural gas industry, the source categories regulated under
CAA section 112, how the current NESHAP regulates its HAP emissions,
and the type of HAP emissions from these source categories.
The EPA characterizes the oil and natural gas industry's operations
as being generally composed of four segments: (1) extraction and
production of crude oil and natural gas (``oil and natural gas
production''), (2) natural gas processing, (3) natural gas transmission
and storage, and (4) natural gas distribution.\15\
---------------------------------------------------------------------------

\15\ The EPA regulates oil refineries as a separate source
category.
---------------------------------------------------------------------------

The oil and natural gas production segment includes the wells and
all related processes used in the extraction, production, recovery,
lifting, stabilization, and separation or treatment of oil and/or
natural gas (including condensate). Although many wells produce a
combination of oil and natural gas, wells can generally be grouped into
two categories: oil wells and natural gas wells. There are two types of
oil wells, oil wells that produce crude oil only and oil wells that
produce both crude oil and natural gas (commonly referred to as
``associated'' gas). Production equipment and components located on the
well pad may include, but are not limited to: wells and related casing
heads; tubing heads; ``Christmas tree'' piping, pumps, and compressors;
heater treaters; separators; storage vessels; process controllers;
pumps; and dehydrators. Production operations include well drilling,
completion, and recompletion processes, including all the portable non-
self-propelled apparatuses associated with those operations.

[[Page 21677]]

Other sites that are part of the production segment include
``centralized tank batteries,'' stand-alone sites where oil,
condensate, produced water, and natural gas from several wells may be
separated, stored, or treated. The production segment also includes
gathering pipelines, gathering and boosting compressor stations, and
related components that collect and transport the oil, natural gas, and
other materials and wastes from the wells to the refineries or natural
gas processing plants.
Crude oil and natural gas undergo successive, separate processing.
The process separates crude oil from water and other impurities and
transported to a refinery via truck, railcar, or pipeline. The EPA
treats oil refineries as a separate source category; accordingly, for
present purposes, the oil component of the production segment ends at
the point of custody transfer at the refinery.\16\
---------------------------------------------------------------------------

\16\ See 40 CFR part 60, subparts J and Ja, and 40 CFR part 63,
subparts CC and UUU.
---------------------------------------------------------------------------

Industry commonly refers to separated, unprocessed natural gas as
field gas. Field gas contains methane, natural gas liquids (NGL), and
other impurities such as water vapor, hydrogen sulfide
(H<INF>2</INF>S), carbon dioxide (CO<INF>2</INF>), helium, and
nitrogen. Ethane, propane, butane, isobutane, and pentane are all
considered NGL and often are sold separately for a variety of different
uses. Natural gas with high methane content is referred to as ``dry
gas,'' while natural gas with significant amounts of ethane, propane,
or butane is referred to as ``wet gas.'' Natural gas is typically sent
to gas processing plants to separate NGLs for use as feedstock for
petrochemical plants, fuel for space heating and cooking, or a
component for blending into vehicle fuel.
The natural gas processing segment consists of separating certain
hydrocarbons (HC) and fluids from the natural gas to produce ``pipeline
quality'' dry natural gas. The degree and location of processing is
dependent on factors such as the type of natural gas (e.g., wet or dry
gas), market conditions, and company contract specifications.
Typically, processing of natural gas begins in the field and continues
as the gas is moved from the field through gathering and boosting
compressor stations to natural gas processing plants, where the
complete processing of natural gas takes place. Natural gas processing
operations separate and recover NGL or other non-methane gases and
liquids from field gas through one or more of the following processes:
oil and condensate separation, water removal, separation of NGL, sulfur
and CO<INF>2</INF> removal, fractionation of NGL, and other processes,
such as the capture of CO<INF>2</INF> separated from natural gas
streams for delivery outside the facility.
After processing, natural gas exits the natural gas processing
plant and enters the transmission and storage segment. From there, the
system transports the gas for storage and/or distribution to the end
user. Pipelines in the natural gas transmission and storage segment can
be interstate pipelines, which carry natural gas across State
boundaries, or intrastate pipelines, which transport the gas within a
single state. Basic components of the two types of pipelines are the
same, though interstate pipelines may be of a larger diameter and
operated at a higher pressure. To ensure that the natural gas continues
to flow through the pipeline, the natural gas must periodically be
compressed, thereby increasing its pressure. Compressor stations
perform this function and are usually placed at 40- to 100-mile
intervals along the pipeline. At a compressor station, reciprocating or
centrifugal compressors compress the natural gas entering the station
as it moves through the pipelines.
Another part of the transmission and storage segments are
aboveground and underground natural gas storage facilities. Storage
facilities hold natural gas for use during peak seasons. Unlike
underground sites, aboveground storage utilizes manufactured vessels
rather than earthen containment. Underground storage of natural gas
typically occurs in depleted natural gas or oil reservoirs and salt
dome caverns. One purpose of this storage site is for load balancing
(equalizing the receipt and delivery of natural gas). At an underground
storage site, typically other processes occur, including compression,
dehydration, and flow measurement.
The distribution segment provides the final step in delivering
natural gas to customers.\17\ The natural gas enters the distribution
segment from delivery points located along interstate and intrastate
transmission pipelines to business and household customers. The
delivery point where the natural gas leaves the transmission and
storage segment and enters the distribution segment is a local
distribution company's custody transfer station, commonly referred to
as the ``city-gate.'' Natural gas distribution systems consist of over
two million miles of piping, including mains and service pipelines to
the customers. Large distribution networks require compressor stations
to maintain flow. However, these stations are typically smaller than
transmission compressor stations. Distribution systems include metering
stations and regulating stations that allow distribution companies to
monitor natural gas flow.
---------------------------------------------------------------------------

\17\ The distribution segment is not included in the Crude Oil
and Natural Gas Production or Natural Gas Transmission and Storage
Source Categories in NESHAP subparts HH or HHH.
---------------------------------------------------------------------------

The Crude Oil and Natural Gas Production Source Category NESHAP
(NESHAP subpart HH) covers the production and processing segments of
the industry and applies to facilities that meet the specified
applicability criteria. For the purposes of NESHAP subpart HH, natural
gas enters the natural gas transmission and storage source category
after the natural gas processing plant, when present. If no natural gas
processing plant is present, natural gas enters the transmission and
storage source category after the point of custody transfer. Examples
of facilities in the oil and natural gas production source category
include, but are not limited to: well sites; satellite tank batteries;
central tank batteries; a compressor station that transports natural
gas to a natural gas processing plant; and natural gas processing
plants. The Crude Oil and Natural Gas Production Source Category NESHAP
(NESHAP subpart HH) contain standards for HAP emissions from glycol
dehydration process vents, storage vessels and natural gas processing
plant equipment leaks. In addition to this NESHAP for major sources,
the NESHAP for the Crude Oil and Natural Gas Production, NESHAP subpart
HH also contains area source standards for glycol dehydrators, which
are based on GACT.
The Natural Gas Transmission and Storage Category NESHAP (NESHAP
subpart HHH) covers the transmission and storage segment of the
industry and applies to facilities that meet the specified
applicability criteria and transport or store natural gas prior to
entering the pipeline to a local distribution company or to a final end
user (if there is no local distribution company). A compressor station
does not belong to the transmission and storage segment if it
transports natural gas before the custody transfer point or to a
processing plant. Facilities in this source category include an
underground natural gas storage operation; or a natural gas compressor
station that receives natural gas via pipeline, from an underground
natural gas storage operation, or from a natural gas processing plant.
Additionally, NESHAP subpart HHH contains major source standards for
HAP from glycol dehydration process vents.

[[Page 21678]]

Emissions can occur from a variety of processes and points
throughout the oil and natural gas industry sector. Emissions from the
oil and natural gas industry sector include organic HAP, volatile
organic compounds (VOCs), sulfur dioxide (SO<INF>2</INF>), nitrogen
oxide (NO<INF>X</INF>), H<INF>2</INF>S, carbon disulfide
(CS<INF>2</INF>), and carbonyl sulfide (COS) are emitted in varying
concentrations and amounts.\18\ The most common organic HAP are n-
hexane and BTEX (benzene, toluene, ethylbenzene and xylenes) compounds.
Broadly, HAP emissions cause or are suspected to cause cancer or other
serious health effects, such as reproductive effects or birth defects,
or adverse environmental effects. Exposure to HAP emissions at
sufficient concentrations and durations may increase the risk of
developing cancer or experiencing other serious health effects. These
health effects can include damage to the immune system, as well as
neurological, reproductive (e.g., reduced fertility), developmental,
respiratory and other health problems. In addition to exposure from
breathing air toxics, some toxic air pollutants can deposit onto soils
or surface waters, where they are absorbed by plants and ingested by
animals and are eventually magnified up through the food chain. Like
humans, animals may experience health problems if exposed to sufficient
quantities of HAP emissions over time.
---------------------------------------------------------------------------

\18\ In addition, there are emissions associated with the
reciprocating internal combustion engines and combustion turbines
that power compressors throughout the oil and natural gas industry
sector. However, emissions from internal combustion engines and
combustion turbines are covered by regulations specific to engines
and turbines and, thus, are not addressed in this proposed
rulemaking.
---------------------------------------------------------------------------

The Crude Oil and Natural Gas Production Category NESHAP (NESHAP
subpart HH) contain standards for HAP emissions from glycol dehydration
process vents, storage vessels, and natural gas processing plant
equipment leaks. The Natural Gas Transmission and Storage Category
NESHAP (NESHAP subpart HHH) contain standards for glycol dehydration
process vents.
In addition to these NESHAP for major sources, the NESHAP for the
Crude Oil and Natural Gas Production, NESHAP subpart HH also contains
area source standards for glycol dehydrators, which are based on GACT.

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

The EPA used several data sources to support this rulemaking. In
February 2023, the EPA issued an Information Collection Request (ICR)
pursuant to CAA section 114 to gather information to inform the
technology review and other considerations related to NESHAP subparts
HH and HHH (2023 ICR). The EPA sent ICRs to 18 entities/respondents
(nine production and processing companies and nine transmission and
storage companies). The EPA asked respondents to complete a separate
survey for each company-operated facility, choosing up to 25 per owner
that represented various geographical regions, operation types, and
sizes.
The EPA received responses from 231 production and processing
facilities and 57 transmission and storage facilities. The information
collected from respondents in Phase I included facility descriptions,
HAP emissions per unit type, control technologies and emissions
reduction work practices utilized at subject facilities. The EPA asked
respondents to identify whether the facility is a major or area source,
as defined by 40 CFR part 63. The 231 production and processing
facilities included eight major source facilities, 221 area source
facilities and two that did not self-identify. The 57 transmission and
storage facilities included 39 major source facilities and 18 area
source facilities.
Following the 2023 ICR effort, in July 2024, the EPA issued a
follow up ICR (2024 Phase II ICR) to the same nine production and
processing companies and nine transmission and storage companies. The
EPA requested glycol dehydrators and acid gas removal units testing,
and additional process controllers and pumps information. The EPA
requested an analysis to quantify the presence of metals that could be
transferred from the raw natural gas to the rich glycol during
dehydration or the rich amine solution from acid gas removal units
during acid gas removal. The EPA requested an inventory and description
of process controllers and pumps at transmission and storage
facilities. All the responses received on both the 2023 ICR and the
2024 Phase II ICR, with the exception of information claimed
confidential, are in the docket for this rulemaking (Docket ID No. EPA-
HQ-OAR-2025-1348).
The EPA collected data on units that emit HAP to help inform the
Agency in its review of the Oil and Gas NESHAP pursuant to CAA section
112(d)(6), as well as its evaluation of the issues raised in
administrative petitions for reconsideration of the prior 2012 Final
Rule amendments to these NESHAP.
The EPA used several data sources to determine the facilities that
are subject to the Oil and Gas Production and Natural Gas Transmission
and Storage NESHAP. 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.\19\ We also used information
from the original oil and gas NESHAP, the Office of Enforcement and
Compliance Assurance's Enforcement and Compliance History Online tool,
and the Energy Information Administration.20 21 To inform
our reviews for these emission points, 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.22 23 The
EPA also reviewed air permits to determine facilities subject to the
NESHAP subpart HH (Production) and NESHAP subpart HHH (Transmission and
Storage).
---------------------------------------------------------------------------

\19\ At the time the technology review was initiated, the 2017
NEI was the most recent complete inventory available.
\20\ <a href="https://echo.epa.gov">https://echo.epa.gov</a>.
\21\ <a href="https://www.eia.gov">https://www.eia.gov</a>.
\22\ <a href="https://www.epa.gov/catc/ractbactlaer-clearinghouse-rblc-basic-information">https://www.epa.gov/catc/ractbactlaer-clearinghouse-rblc-basic-information</a>.
\23\ The EPA reviewed standards for Gasoline Distribution
regulated under 40 CFR part 63, subparts R and BBBBBB, and Bulk
Gasoline Terminals regulated under 40 CFR part 60, subparts XX and
XXa.
---------------------------------------------------------------------------

We met with industry representatives from the American Petroleum
Institute, Gas Processors Association, and held a series of virtual
meetings with producers.\24\
---------------------------------------------------------------------------

\24\ See memorandum documenting meeting in the Public Docket at
<a href="https://www.regulations.gov/">https://www.regulations.gov/</a> Docket ID No. EPA-HQ-OAR-2025-1348.
---------------------------------------------------------------------------

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

In addition, we relied on certain technical reports and memoranda
that the EPA developed for glycol dehydrators and their control devices
in the 2012 Crude Oil and Natural Gas Production and the Natural Gas
Transmission and Storage residual risk and technology review.\25\ The
Risk and Technology Review (RTR) docket is at Docket ID No. EPA-HQ-OAR-
2010-0505. For completeness of this rulemaking and for ease of
reference in finding these items in the publicly available rulemaking
docket, we are including the most relevant technical support documents
in the docket for this proposed rulemaking (Docket ID No. EPA-HQ-OAR-
2025-1348).
---------------------------------------------------------------------------

\25\ See memorandum documenting meeting in the Public Docket at
<a href="https://www.regulations.gov/">https://www.regulations.gov/</a> Docket ID No. EPA-HQ-OAR-2025-1348.

---------------------------------------------------------------------------

[[Page 21679]]

E. How does the EPA perform the 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 MACT standards were
promulgated. Where we identify such developments, we analyze their
technical feasibility, estimated costs, energy implications, and non-
air environmental impacts.\26\ We also consider the emission reductions
associated with the potential application of each development. This
analysis informs our decision whether it is ``necessary'' to revise the
emissions standards.\27\ 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'': \28\
---------------------------------------------------------------------------

\26\ 42 U.S.C. 7412(d)(2).
\27\ Id. 7412(d)(6).
\28\ 76 FR 29032, 29047and 29048 (May 19, 2011); see also Nat'l
Ass'n for Surface Finishing v. EPA, 795 F.3d 1, 11 (D.C. Cir. 2015)
(upholding the EPA's interpretation of what is considered
``developments'' under CAA section 112(d)(6) and affording
persuasive weight to the EPA's methodology and balancing decisions
for a technology review).
---------------------------------------------------------------------------

<bullet> Any add-on control technology or other equipment that was
not identified and considered during development of the original MACT
standards;
<bullet> Any improvements in add-on control technology or other
equipment (that were identified and considered during development of
the original MACT standards) that could result in additional emissions
reduction;
<bullet> Any work practice or operational procedure that was not
identified or considered during development of the original MACT
standards;
<bullet> Any process change or pollution prevention alternative
that could be broadly applied to the industry and that was not
identified or considered during development of the original MACT
standards; and
<bullet> Any significant changes in the cost (including cost
effectiveness) of applying controls (including controls the EPA
considered during the development of the original MACT standards).
In addition to reviewing the practices, processes, and control
technologies that were considered at the time we last updated the
NESHAP, we reviewed a variety of data sources in our investigation of
potential practices, processes, or controls to consider. Pursuant to
the D.C. Circuit's decision in Louisiana Environmental Action Network
(LEAN) v. EPA, 955 F.3d 1088 (D.C. Cir. 2020), we also reviewed
available data to determine if there are unregulated HAP within the
source category and evaluate these data for use in developing new
emission standards.

III. Analytical Results and Proposed Decisions

In this rulemaking, the EPA is proposing decisions and regulatory
amendments in response to statutory requirements, court decisions,
petitioner issues, and technical corrections. Table 2 summaries these
decisions and actions. The description column in table 2 notes that the
proposal items include the technology review of existing standards, the
addition of methanol as a regulated HAP, the surrogacy analysis for
small dehydrators, the technical correction to the equation in the
small dehydrator standards, and the addition of additional software for
compliance analyses.
In addition, the EPA is proposing that when conducting a CAA
section 112(d)(6) technology review, the Agency is not obligated to
expand the NESHAP to previously unregulated emission points. In the
past, the Agency has previously suggested that the D.C. Circuit's
decision in LEAN mandates that the EPA expand the NESHAP to include
additional emission points as part of the technology review under CAA
section 112(d)(6). However, the Agency now proposes that LEAN does not
mandate such action pursuant to CAA section 112(d)(6), which instructs
the EPA to revise existing standards for regulated emission points ``as
necessary,'' considering developments since the last rulemaking. On
this basis, the EPA proposes to defer action on such a potential
expansion of the NESHAP to future action that looks at the problem
holistically, including consideration whether such emission points
belong within one or both of these NESHAP and what controls may or may
not be appropriate and consistent with the statute.
Although we maintain that CAA section 112(d)(6) review does not
require the EPA to expand the NESHAP to previously unregulated emission
points, we are including a tentative proposal about what standards
could be if we were not to finalize the proposed understanding as
described above. We include both approaches to ensure that the public
has an adequate opportunity to comment. The alternative proposed
standards are for the following unregulated emission points: acid gas
removal units, storage vessels without potential for flash emissions,
and transport vessel loading operations in the production and
processing source category under NESHAP subpart HH, and storage
vessels, transport vessel loading operations, process controllers, and
pumps in the transmission and storage source category under NEHAP
subpart HHH.
Table 2 of this preamble presents a summary of the EPA's proposed
decisions and actions. Specifically, the table shows the proposed
change to each emission point, corrections being proposed in this
rulemaking, and the reasoning for the corrections.

Table 2--Summary of Proposed Decision and Actions
----------------------------------------------------------------------------------------------------------------
Description of decision/ Applicable NESHAP
Emission point Reason action subpart
----------------------------------------------------------------------------------------------------------------
Technology Review of Already Regulated Emission Points of Currently Regulated HAP
----------------------------------------------------------------------------------------------------------------
Dehydrators (major and area sources) CAA section 112(d)(6) Control technique HH, HHH.
Technology Review. identified but
revision not
necessary--No revision
proposed.
----------------------------------------------------------------------------------------------------------------
Storage Vessels with the PFE........ CAA section 112(d)(6) No developments in HH.
Technology Review. practices, processes
and control techniques
identified--No action
proposed.
Leak Detection and Repair at Natural CAA section 112(d)(6) Use of OGI to detect HH.
Gas Processing Plants. Technology Review. leaks identified as
development. However,
not cost effective for
HAP--No action
proposed.
----------------------------------------------------------------------------------------------------------------

[[Page 21680]]

Definition of Associated Equipment
----------------------------------------------------------------------------------------------------------------
Large and small dehydrators and CAA section 112(n)(4) Propose revising the HH.
storage vessels with PFE. (Prohibits aggregating ``associated
emissions from wells equipment'' definition
and associated to remove the
equipment when exclusion of
determining major dehydrators and
source status). storage vessels
thereby clarify that
they are associated
equipment.
----------------------------------------------------------------------------------------------------------------
Standards for Unregulated HAP (Methanol)
----------------------------------------------------------------------------------------------------------------
Regulated emission points--small and LEAN Court Decision.... Proposing standards for HH.
large dehydrators and storage methanol from small
vessels with PFE. dehydrators.
Unregulated emission points--AGRU, LEAN Court Decision.... Proposing not required HH.
transport vessel loading to address under
operations, storage vessels without section 112(d)(6).
PFE. Alternative proposal to
adopt standards for
unregulated emission
points.
----------------------------------------------------------------------------------------------------------------
Unregulated Emission Points of Already Regulated HAP
(Proposing Not Required To Address Under Section 112(d)(6))
----------------------------------------------------------------------------------------------------------------
Storage Vessels without the PFE..... LEAN Court Decision.... Alternative proposal to HH.
adopt standards for
unregulated emission
points.
All Storage Vessels................. LEAN Court Decision.... Alternative proposal to HHH.
adopt standards for
unregulated emission
points.
Transport Vessel Loading Operations. LEAN Court Decision.... Alternative proposal to HH, HHH.
adopt standards for
unregulated emission
points at processing
plants and natural gas
transmission and
storage facilities.
Natural Gas-Driven Process LEAN Court Decision.... Alternative proposal to HHH.
Controllers. adopt standards for
unregulated emission
points at natural gas
transmission and
storage facilities.
Natural Gas-Driven Pumps............ LEAN Court Decision.... Alternative proposal to HHH.
adopt standards for
unregulated emission
points at natural gas
transmission and
storage facilities.
----------------------------------------------------------------------------------------------------------------
Regulated Emission Points of Unregulated HAP (Methanol and Other HAP Except BTEX)
----------------------------------------------------------------------------------------------------------------
Small Dehydrators................... LEAN Court Decision.... Determined that BTEX is HH, HHH.
adequate surrogate for
all HAP except
methanol; proposing
methanol standard.
----------------------------------------------------------------------------------------------------------------
Technical Corrections
----------------------------------------------------------------------------------------------------------------
Small Dehydrator Equations.......... Petitioner Issue/ Equations in rule are HH, HHH.
Technical Correction. not reasonable for
small dehydrators with
very low BTEX inlet
concentrations--Propos
ing alternative
equations for these
situations.
Dehydrators......................... Technical Correction... Add ProMaxTM as allowed HH, HHH.
methodology to
calculate dehydrator
emissions.
----------------------------------------------------------------------------------------------------------------

A. What are the results and proposed decisions based on our technology
review for emission points and HAP currently regulated in NESHAP
Subpart HH and NESHAP Subpart HHH, and what is the rationale for those
decisions?

In technology reviews under CAA section 112(d)(6), the EPA reviews
the standards that are already established to determine whether
revisions are ``necessary,'' considering developments in technology,
processes, and practices. In this rulemaking, the EPA reviewed the
existing NESHAP standards, set under NESHAP subpart HH, which are major
source requirements for storage vessels with potential flash emissions,
large and small glycol dehydration units, and equipment leaks from
ancillary equipment and compressors at natural gas processing plants.
For subpart HH area sources, the EPA reviewed standards for glycol
dehydrators. For NESHAP subpart HHH, we examined standards for large
and small glycol dehydration units at major sources.
As discussed in section II.E of this preamble, the technology
review process involves identification of development of practices,
processes, and control technologies since the MACT standards were
promulgated, and the following situations represent a ``development.''
<bullet> Any add-on control technology or other equipment that was
not identified and considered during development of the original MACT
standards;
<bullet> Any improvements in add-on control technology or other
equipment (that were identified and considered during development of
the original MACT standards) that could result in additional emissions
reduction;
<bullet> Any work practice or operational procedure that was not
identified or considered during development of the original MACT
standards;

[[Page 21681]]

<bullet> Any process change or pollution prevention alternative
that could be broadly applied to the industry and that was not
identified or considered during development of the original MACT
standards; and
<bullet> Any significant changes in the cost (including cost
effectiveness) of applying controls (including controls the EPA
considered during the development of the original MACT standards).
Below is a summary of the technology review for dehydrators,
storage vessels with the PFE, and equipment leaks at natural gas
processing plants. For the complete technology review please see Volume
II of the Technical Support Document (TSD) prepared for this
proposal.\29\ The TSD can be found in the Oil and Natural Gas NESHAP
Docket for this action, Docket ID No. EPA-HQ-OAR-2025-1348.
---------------------------------------------------------------------------

\29\ U.S. Environmental Protection Agency. (Last updated
February 2026). DRAFT Background Technical Support Document for the
National Emission Standards for Hazardous Air Pollutants: Crude Oil
and Natural Gas Production Facilities and Natural Gas Transmission
and Storage Facilities--Technology Review and Reconsideration.
NESHAP subparts HH and HHH. Proposed Rules.
---------------------------------------------------------------------------

As noted above, the EPA evaluates developments in practices,
processes, and control technologies for sources and HAP currently
regulated under NESHAP subparts HH and HHH. Section III.B of this
preamble discusses proposed actions to amend NESHAP subparts HH and
NESHAP HHH. These include a proposed modification to the major source
definition in NESHAP subpart HH for operations located prior to the
point of custody transfer to the natural gas processing plant (section
III.B.1 of this preamble), the proposed addition of methanol to the
list of regulated HAP for both NESHAP (section III.B.2 of this
preamble), the proposed decision regarding the surrogacy of BTEX for
all HAP (except methanol) emitted from small dehydrators (section
III.B.2 of this preamble), proposed standards for several unregulated
emission points (section III.B.3 preamble), and proposed alternatives
to the equations that establish unit-specific BTEX limits for small
dehydrators (section III.B.4 of this preamble).
1. Glycol Dehydrators
Glycol dehydration units remove water and other condensates in
natural gas from an individual well or several wells. These units also
operate as part of various processing units at condensate tank
batteries, natural gas processing plants, and offshore production
platforms. Dehydration prevents water vapor from forming hydrates,
which corrode and plug equipment lines. Of the dehydration units
subject to NESHAP subparts HH and HHH, TEG units comprise the majority,
while diethylene glycol (DEG), and solid desiccant units make up the
remainder.
Large dehydrators at major sources subject to NESHAP subparts HH
and HHH, and at areas sources located in urban areas subject to NESHAP
subpart HH are currently required to route emissions through a closed
vent system to a control device(s) designed and operated in accordance
with the requirements of 40 CFR 63.771(d) (NESHAP subpart HH) or 40 CFR
63.1281(d) (NESHAP subpart HHH).\30\ These control device provisions
include the option of using an enclosed combustion device that either
reduces the mass content of either total organic compound (TOC) or
total HAP by 95 percent or greater, reduces the concentration of either
TOC or total HAP in the exhaust gases at the outlet to the device to a
20 ppmv or less, or operates at a minimum temperature of 760 degrees
Centigrade ([ordm] C). If a boiler or process heater is used as the
control device, then the requirement is that the vent stream be
introduced into the flame zone of the boiler or process heater. Another
option is to use a vapor recovery device designed and operated to
reduce the mass content of either TOC or total HAP by 95 percent or
greater. The final option is to use a flare that meets the requirements
in 40 CFR 63.11(b). The EPA also notes that large dehydrators may also
comply by reducing benzene emissions to 0.9 megagrams per year (Mg/yr)
or less.
---------------------------------------------------------------------------

\30\ Large units under HH have annual average benzene emissions
equal to or greater than 0.90 Mg/yr and gas throughput equal to or
greater than 85,000 cubic meters per day. Large units under HHH have
annual average benzene emissions equal to or greater than 0.90 Mg/yr
and equal to or great than 283,000 cubic meters per day. See 40 CFR
63.761 and 63.1271 for the complete definitions.
---------------------------------------------------------------------------

Small dehydrators at major sources subject to NESHAP subparts HH
and HHH are currently required to reduce BTEX emissions to a unit-
specific BTEX emission limit determined in accordance with the
applicable equation in the rule. Compliance with these limits can be
achieved by utilizing a control device (discussed above) or via a
process modification.\31\
---------------------------------------------------------------------------

\31\ In NESHAP HH (40 CFR 63.761), a small dehydrator is defined
as a glycol dehydration unit, located at a major source, with an
actual annual average natural gas flowrate less than 85 thousand
standard cubic meters per day or actual annual average benzene
emissions less than 0.90 Mg/yr. In NESHAP HHH (40 CFR 63.1271), a
small dehydrator is defined as a glycol dehydration unit, located at
a major source, with an actual annual average natural gas flowrate
less than 283.0 thousand standard cubic meters per day or actual
annual average benzene emissions less than 0.90 Mg/yr.
---------------------------------------------------------------------------

During the development of the original 1999 NESHAP and the 2012
technology review for NESHAP subparts HH and HHH, the EPA evaluated
various practices, processes, and control technologies for dehydrators.
This evaluation included add-on controls--such as condensers, vapor
recovery units, carbon bed adsorbers, and combustion devices such as
flares and incinerators--as well as pollution prevention and process
modifications. Ultimately, the EPA found no improvements in these add-
on techniques that could result in additional emission reductions or
significant changes in the cost of applying them.
Pollution prevention practices and process modifications to reduce
emissions from dehydrators are highly specific to many conditions
unique to a site, such as the composition of the gas and oil extracted,
the climate of the site, and the other operations at the site. One
universally applicable pollution prevention measure that was evaluated
previously and is required in NESHAP HH for large dehydrators at area
sources not located in urban areas, is optimizing glycol circulation
rates. The EPA identified no other widely applicable practices or
processes that would result in additional emission reductions.
The EPA identified two technologies not evaluated in either of the
original 1999 NESHAP development or the previous technology review and
thus, represent ``developments.'' These include replacing glycol
dehydration units with methanol injections and desiccant dehydrators.
The following sections detail our decision on each technology.
In the field, operators sometimes inject methanol to inhibit
hydrate formation in high-pressure gas gathering systems. This is
especially useful when solid desiccant or glycol dehydration cannot
achieve the desired dew point to inhibit hydrate formation. Under
frigid conditions operators may use methanol over glycol because it
lowers the freezing point at which hydrates form. However, the high
volume of methanol required for hydrate inhibition may make replacing
large glycol dehydration units impracticable in many situations.
Specifically, with increasing gas flow rates, the volume of methanol
required to be injected to treat larger gas volumes for the required
temperature suppression to prevent hydrate formation can make this
option

[[Page 21682]]

impracticable for those applications. Since this is not practicable in
all cases, the EPA did not perform a cost analysis for this option. On
this basis, the EPA is not proposing to adopt a standard for methanol
injection under the CAA section 112(d)(6) technology review for glycol
dehydration units.
Under certain operating conditions, desiccant dehydration units are
used to reduce HAP emissions and can achieve a reduction of 99 percent.
Ideal operating conditions to utilize desiccant dehydrators are when
the wellhead gas temperature is low (less than 70 degrees Fahrenheit
([deg] F) and the pressure is high (greater than 100 pounds per square
inch gauge [psig]) and the volume of gas to be dried is 5 million
standard cubic feet (MMscf)/day or less. Additionally, the desiccant is
batch loaded. Our information indicates that batch loading is
frequently performed at a higher gas flow rate. Since many of these
sources are in remote areas and may not be visited by personnel for
weeks at a time, the EPA proposes to conclude that desiccant
dehydrators are infeasible for these sources.
Based on the above reasons, the EPA proposes to conclude that,
although applicable in certain situations, the desiccant dehydrator
technology is technically infeasible for broad implementation for the
glycol dehydration units that are subject to NESHAP subparts HH and
HHH. Due to this infeasibility, a cost analysis was not performed.
Therefore, the EPA proposes it is not necessary to revise the standards
for glycol dehydration units to require the use of this technology
under the CAA section 112(d)(6).
2. Storage Vessels With the Potential for Flash Emissions (PFE)
In both NESHAP subpart HH and NESHAP subpart HHH, a storage vessel
is defined as ``a tank or other vessel that is designed to contain an
accumulation of crude oil, condensate, intermediate hydrocarbon
liquids, or produced water, and that is constructed primarily of non-
earthen materials (e.g., wood, concrete, steel, plastic) that provide
structural support.'' \32\
---------------------------------------------------------------------------

\32\ NESHAP subpart HH, 40 CFR 63.761; NESHAP subpart HHH, 40
CFR 63.1274.
---------------------------------------------------------------------------

Flash emissions from storage vessels occur when a hydrocarbon
liquid with high vapor pressure flows from a pressurized vessel into a
vessel with a lower pressure. This typically happens when operators
transfer hydrocarbon liquids, such as condensate, from a production
separator to a storage vessel. The reduced pressure from the separator
to the storage vessel with PFE allows dissolved vapors in the liquid to
move to vapor phase in the headspace above the liquid and then move out
of the storage vessel through the cover into the closed vent system.
The current standards in NESHAP subpart HH for storage vessels with
the PFE require sources to route emissions through a closed vent system
to a control device(s).\33\ Enclosed combustion devices are required to
achieve a reduction in the mass content of either total organic
compound (TOC) or total HAP by 95 percent or greater, reduce the
concentration of either TOC or total HAP in the exhaust gases at the
outlet to the device to a 20 ppmv or less, or operate at a minimum
temperature of 760 degrees [deg]C. If a boiler or process heater is
used as the control device, then the requirement is that the vent
stream be introduced into the flame zone of the boiler or process
heater. Another option is to use a vapor recovery device designed and
operated to reduce the mass content of either TOC or total HAP by 95
percent or greater. The final option is to use a flare that meets the
requirements in 40 CFR 63.11(b). Subpart HHH does not include standards
for storage vessels with the PFE.
---------------------------------------------------------------------------

\33\ NESHAP subpart HH, 40 CFR 63.771(d).
---------------------------------------------------------------------------

This section presents the technology review for storage vessels
with PFE for the production (NESHAP subpart HH) category.\34\ The EPA
analyzed and made regulatory decisions for unregulated storage vessels,
which are storage vessels without PFE at production sites (NESHAP
subpart HH), and all storage vessels at natural gas transmission and
storage sites (NESHAP subpart HHH), (see section III.B.4 of this
preamble).\35\
---------------------------------------------------------------------------

\34\ Storage vessels without PFE have only working and breathing
emissions. Neither NESHAP subparts HH and HHH includes standards for
these storage vessels and are not subject to this technology review.
\35\ See sections III.B.4.b and III.B.4.c of this preamble.
---------------------------------------------------------------------------

The practices, processes, and control technologies considered and
evaluated for storage vessels with the PFE as part of the development
of the original 1999 NESHAP or the 2012 technology review and
amendments for NESHAP subpart HH included add-on controls (condensers/
vapor recovery units; combustion devices, including catalytic
incinerators, thermal incinerators, and flares; and carbon bed
adsorbers). In the development of the original 1999 NESHAP or the 2012
technology review and amendments for NESHAP subpart HH, the EPA did not
find improvements in any of these add-on techniques that could result
in additional emission reductions or significant changes in the cost of
applying them.
Operators sometimes use internal floating roof tanks to reduce
emissions from storage vessels. In the previous evaluations, internal
floating roof tanks were not considered effective for storage vessels
with the PFE because internal friction between the floating roof and
the interior sides of tanks typical for the source category would
prevent proper operation of the floating roof. In addition, the small
quantities of liquid stored in these types of tanks typically do not
provide sufficient buoyancy to support floating roofs. While a floating
roof effectively limits vaporization, the EPA considered them a
technically infeasible control method for storage tanks in the Oil and
Natural Gas Production source category. This conclusion has not changed
since we did not receive any new data that indicated otherwise.
The EPA proposes that no new practices, processes, or control
technologies under CAA section 112(d)(6) were discovered in the review
of available data, nor were significant changes in the cost or
performance of previously evaluated technologies identified to further
reduce emissions from the Oil and Natural Gas Production source
category for storage vessels with the PFE.
3. Leak Detection and Repair (LDAR) at Processing Plants
Equipment leak emissions can occur through different types of
connection points (e.g., flanges, pressure relief valves, open-ended
lines or threaded fittings) or through moving parts of valves, pumps,
and other types of process equipment. These emissions are unintentional
and occur due to changes in pressure, temperature, and mechanical
stress on equipment which may eventually cause them to leak. Equipment
leak emissions can also occur due to normal operation of equipment,
which over time can cause seals and gaskets to wear. The type and
number of equipment components, along with the HAP concentration in the
stream, determine the total volume of emissions from equipment leaks.
The practices, processes, and control technologies that were
considered and evaluated for reducing emissions from equipment leaks
from ancillary equipment and compressors at natural gas processing
plants as part of the original 1999 NESHAP development and/or the 2012
technology review and amendments for NESHAP subpart HH included
``traditional'' LDAR programs based on EPA Method 21, optical gas
imaging (OGI) to identify equipment

[[Page 21683]]

leaks, equipment standards/modifications (including low emissions
design equipment), ultrasound leak detection, directed inspection and
maintenance, compressor rod packing systems, and centrifugal compressor
seals. As a result of the 2012 technology review, the EPA determined
that as part of the traditional NESHAP subpart HH Method 21-based LDAR
program, it was warranted to lower the leak definition for valves to an
instrument reading of at least 500 ppm and add connectors to the list
of monitored components.
Regarding the 2012 technology review for NESHAP subpart HH related
to the use of OGI, we concluded that the additional costs of OGI
programs were not justified. Therefore, NESHAP subpart HH was not
updated in 2012 to include OGI as a requirement or option for the
equipment leak requirements at natural gas processing plants.
The EPA identified no developments in practices, processes, or
control technologies from its review of the RBLC or the 2023 ICR
results.
Historically, the method typically used for detecting leaking
components from oil and natural gas facilities is EPA Method 21 (40 CFR
part 60, appendix A). The EPA Method 21 procedure detects leaks from
components using a toxic vapor analyzer or an organic vapor analyzer.
For several NSPS, NESHAP, State and local regulations, EPA Method 21
has been the primary method for leak detection.
Another monitoring method for detecting leaking components from oil
and natural gas production, transmission and storage facilities is OGI
using an infrared (IR) camera. The IR camera may be passive or active.
The operators use passive IR cameras to scan an area to produce images
of equipment leaks from a number of sources. Active IR cameras point or
aim an IR beam at a potential source to indicate the presence of
gaseous emissions (equipment leaks). An equipment leak is any emissions
that are visualized by an OGI instrument. The optical imaging camera
can be very efficient in monitoring multiple pieces of equipment in a
short amount of time, but the traditional optical imaging camera cannot
quantify the amount or concentration of the equipment leak. Note that
while the current NESHAP subpart HH equipment leak standards require
EPA Method 21 monitoring, the use of OGI is allowed if owners and
operators follow the alternative work practice (AWP) titled
``Alternative Work Practice to Detect Leaks from Equipment'' in 40 CFR
part 63's General Provisions at 40 CFR 63.11(c). If a facility chooses
to monitor components following the AWP, annual EPA Method 21
monitoring must be performed in addition to periodic OGI monitoring.
The use of OGI was evaluated in the 2012 technology review but the
EPA did not elect to update NESHAP subpart HH primarily based on the
costs. As noted above, the General Provisions for NESHAP at 40 CFR
63.11(c) allows as an alternative to a traditional LDAR monitoring
program (e.g., EPA Method 21) the use of the AWP under 40 CFR 63.11(c),
which allows the use of OGI along with an annual EPA Method 21 survey
of all of the equipment. However, because the OGI protocol had not yet
been issued at the time of the 2012 technology review, standardized
operating procedures and compliance determination protocols were not
available. Without these procedures and protocols in place, replacing
the existing LDAR requirements with OGI could not have been considered
a development under CAA section 112(d)(6) at that time.
Since that time, OGI technology and its regulatory processes have
advanced significantly. Many State regulations now include OGI, but the
EPA primarily relies on CAA 40 CFR part 60, subpart OOOOb (and Emission
Guidelines for 40 CFR part 60, subpart OOOOc). Over the last few years,
OGI has matured into a prevalent technology that operators frequently
use in the field to identify emissions from leaking components and
equipment. Many oil and natural gas facilities currently use OGI to
find leaks efficiently and repair leaking equipment quickly.
Under the final rule published 89 FR 16820, March 8, 2024 for NSPS
for oil and natural gas operations (40 CFR part 60, subpart OOOOb), the
EPA finalized the protocol for using OGI for leak detection
specifically at a natural gas processing plant. The protocol is
referred to as ``Appendix K'' to 40 CFR part 60. OGI uses an infrared
camera to identify the presence and location of VOC and methane leaks
that may otherwise be invisible. Requirements in appendix K includes
performance specifications of infrared cameras, requisite operator
training and auditing, the development of operating envelopes that
define the boundary conditions for using an OGI camera, monitoring
plans for conducting OGI surveys, recordkeeping, and development of
response factors.
Based on the discussion above regarding maturity, procedures, and
protocols specifying proper OGI use now available (i.e., appendix K to
part 60), the EPA determined that the use of OGI for detecting
equipment leaks at natural gas processing facilities is considered a
development under CAA section 112(d)(6). As specified in 40 CFR part 60
appendix K section 1.2, the use of the protocol is applicable to
facilities only when incorporated through rulemaking into a specific
subpart.
The EPA is not proposing to replace the existing EPA Method 21-
based monitoring requirements with appendix K/OGI. As a method of leak
detection, EPA Method 21 is not effective on a cost-basis when seeking
to limit HAP. The EPA estimates the annual cost of bi-monthly OGI
monitoring under appendix K, as required by 40 CFR part 60, subpart
OOOOb, at approximately $62,000 for a small gas processing plant and
$122,000 for a large processing plant. The emissions reductions
achieved compared to the baseline level of no monitoring, was estimated
at 0.47 tpy of HAP removed for a small processing plant and 0.98 tpy of
HAP removed for a large processing plant. Therefore, the cost
effectiveness is $132,000 and $125,000 per ton of HAP emissions
reduced, for a small and large processing plant, respectively.
The EPA is seeking comment on whether to adopt OGI and appendix K
as an alternative to EPA Method 21 for leak detection at processing
plants, in part because OGI is an approved option in other oil and gas
regulations for leak detection.\36\ Should the EPA adopt OGI and 40 CFR
part 60 appendix K as an alternative to EPA Method 21 leak detection
and repair at processing plants? (Question #1)
---------------------------------------------------------------------------

\36\ 40 CFR part 60, subparts OOOOa and OOOOb.
---------------------------------------------------------------------------

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

In this proposal, we are proposing actions to address unregulated
HAP pursuant to the D.C. Circuit's decision in LEAN, various technical
matters, and outstanding petition issues. Based on a review of
available information pursuant to the LEAN decision, we are proposing
the following: we are proposing to add methanol as a regulated HAP for
the production and processing category (NESHAP subpart HH), and we are
proposing to change how we apply CAA section 112(n)(4) with respect to
major sources of HAP emissions in production (NESHAP subpart HH). While
the EPA is proposing that CAA section 112(d)(6) does not require the
Agency to expand the NESHAP to previously unregulated emission points,
we are proposing in the alternative emission limits for AGRUs at major
source natural gas processing plants subject to NESHAP subpart HH

[[Page 21684]]

and at major source natural gas transmission and storage facilities
subject to NESHAP subpart HHH; emission limits for storage vessels at
major source natural gas transmission and storage facilities subject to
NESHAP subpart HHH, and for storage vessels without the PFE at major
sources subject to NESHAP subpart HH; emission limits for transport
vessel loading operations at major source natural gas processing plants
subject to NESHAP subpart HH and at major source natural gas
transmission and storage facilities subject to NESHAP subpart HHH; and
emission limits for process controllers and pumps powered by natural
gas that are at major natural gas transmission and storage facilities
subject to NESHAP subpart HHH.
We are proposing the existing BTEX limits for both new and existing
small glycol dehydrators as a surrogate standard for all HAP from small
glycol dehydrators, except for methanol and ethylene glycol at sources
subject to NESHAP subparts HH and HHH 37 38. The results and
proposed decisions, as well as the rationale for those decisions, are
presented below.
---------------------------------------------------------------------------

\37\ See 40 CFR part 63, subpart HH, appendix table 1 for the
list of HAP emitted in this category, to which methanol is proposed
to be added.
\38\ Ethylene glycol was the liquid desiccant historically used
in dehydrators, resulting in the potential for emissions of ethylene
glycol. However, triethylene glycol is now the liquid desiccant
used. The EPA does not have evidence that ethylene glycol emission
occur from oil and gas operations at this time.
---------------------------------------------------------------------------

1. Major Source Definition
CAA section 112(a)(1) defines a ``major source'' as ``any
stationary source or group of stationary sources located within a
contiguous area and under common control that emits or has the
potential to emit considering controls, in the aggregate, 10 tpy or
more of any hazardous air pollutant or 25 tpy or more of any
combination of hazardous air pollutants.'' \39\ However, specifically
for oil and gas sources, CAA section 112(n)(4)(A) states that
``[n]otwithstanding [CAA section 112(a)], emissions from any oil or gas
exploration or production well (with its associated equipment) and
emissions from any pipeline compressor or pump station shall not be
aggregated with emissions from other similar units, whether or not such
units are in a contiguous area or under common control, to determine
whether such units or stations are major sources, and in the case of
any oil or gas exploration or production well (with its associated
equipment), such emissions shall not be aggregated for any purpose
under this section.'' \40\
---------------------------------------------------------------------------

\39\ 42 U.S.C. 7412(a)(1) (emphasis added).
\40\ Id. 7412(n)(4)(A) (emphasis added).
---------------------------------------------------------------------------

In 1999, the EPA promulgated the major source NESHAP for the Oil
and Gas Production Facilities (NESHAP subpart HH) and for Natural Gas
Transmission and Storage Facilities (NESHAP subpart HHH). The NESHAP
subpart HH covers production field facilities (where wells and
associated equipment are located) and processing plants. In that
rulemaking, the EPA interpreted CAA section 112(n)(4)(A) to mean ``HAP
[hazardous air pollutant] emissions from each well and each piece of
equipment considered to be associated with the well must be evaluated
separately in a major source determination. That is, any well or piece
of associated equipment would only be determined to be a major source
if HAP emissions from that well or piece of associated equipment were
major.'' \41\ To implement this provision, the EPA included in the rule
a definition for ``associated equipment.'' In the 1999 Final Rule, the
EPA defined ``associated equipment'' to exclude glycol dehydrators and
storage vessels with PFE. Specifically, ``Associated equipment, as used
in this subpart and as referred to in section 112(n)(4) of the Act,
means equipment associated with an oil or natural gas exploration or
production well, and includes all equipment from the wellbore to the
point of custody transfer to the natural gas processing plant, except
glycol dehydration units and storage vessels with PFE.'' \42\ The EPA
explained that Congress did not define ``associated equipment,'' and
the Agency wanted to ``arrive at a reasonable interpretation that would
. . . prevent aggregation of small, scattered HAP emission points in
major source determinations . . . [but] not preclude the aggregation of
significant HAP emission points in the source category.'' \43\
---------------------------------------------------------------------------

\41\ 64 FR 32610, 32619 (June 17, 1999).
\42\ Id. at 32629.
\43\ Id. at 32619.
---------------------------------------------------------------------------

As a result, glycol dehydrators and storage vessels with PFE at a
production field are major sources if their aggregate emissions at the
facility meet the ``major source'' definition. In 2012, the EPA amended
the definition of ``associated equipment'' to remove ``with potential
flash emissions,'' thereby allowing emissions from all storage vessels
and gylcol dehydrators at a production field facility to be aggregated
to determine major source status.\44\
---------------------------------------------------------------------------

\44\ 77 FR 49490, 49501 (August 16, 2012).
---------------------------------------------------------------------------

We are proposing to revise the definition of ``associated
equipment'' to remove ``except glycol dehydrators and storage
vessels.'' The EPA is proposing this change because glycol dehydrators
and storage vessels are clearly equipment associated with production
wells, and we do not see any language in CAA section 112(n)(4) allowing
aggregation of emissions from any associated equipment in determining
whether any such equipment is a major source; on the contrary, CAA
section 112(n)(4) not only prohibits aggregating emissions of
associated equipment for major source determination, it prohibits
aggregating emissions from ``any oil or gas production or exploration
well (with their associated equipment) . . . for any purpose under
[section 112].'' It is clear from CAA section 112(n)(4) that Congress
intended to regulate any associated equipment as a major source only if
such equipment individually emits (or has the potential to emit) at a
major source level of HAP (i.e., at least 10 tpy of one HAP or 25 tpy
of any combination of HAP).\45\ We therefore propose this change to
closely align with the text of the CAA.
---------------------------------------------------------------------------

\45\ See CAA section 112(a)(1), 42 U.S.C. 7412(a)(1).
---------------------------------------------------------------------------

The proposed revision to the definition of ``associated
equipment,'' prevents the aggregation of emissions from storage vessels
and glycol dehydrators when determining whether they are major sources.
Under CAA section 112(n)(4), the EPA will evaluate emissions from
glycol dehydration and storage vessels individually to determine if any
of those units qualify as ``stand-alone'' major sources. We are
soliciting comment on several subjects related to this proposal:
Approximately how many current major sources will be affected, such
that the facility or unit would convert from a major source to an area
source? (Question #2a) What cost savings will your facility achieve due
to it being converted from a major source to an area source under this
change? (Question #2b) Will facilities that would no longer be
considered major sources remove or modify their current control systems
such that the unit or facility would increase HAP emissions from
current emissions? (Question #2c)
As a result of this proposed change to the major source definition,
the universe of storage vessel and dehydrator affected sources will
likely change, making it necessary to re-examine the determination of
the level of the standards under CAA section 112(d)(2) and (3) based on
this universe. Sections III.B.1.a and b of this preamble discuss the
evaluation and proposed determination.

[[Page 21685]]

a. Glycol Dehydrators
To evaluate the MACT floor for the revised universe of major source
dehydrators, the EPA revisited the original MACT floor determination
for the original rule promulgated in 1999.\46\ Information collected
via several mechanisms was considered for this previous analysis,
including responses to a CAA section 112 ICR questionnaire distributed
in 1993, site visits, meetings with industry, and industry studies. The
1993 ICR responses formed the primary basis for the MACT floor
recommendation. The EPA based the 1999 Final Rule evaluation on the
1997 MACT memo because 30-year-old raw data are unavailable for
detailed analysis.
---------------------------------------------------------------------------

\46\ Fitzsimons & Vicononic. (1997). Memorandum:
``Recommendation of MACT Floor Levels for HAP Emission Points at
Major Sources in the Oil and Natural Gas Production Source
Category.'' (September 23, 1997).
---------------------------------------------------------------------------

Information was submitted on an individual dehydrator basis, and it
was determined that 200 dehydrators for which information was submitted
were major sources of HAP. The 1997 MACT floor recommendation was based
on the controls identified for these 200 dehydrators. The description
of these dehydrators is clear that they were ``stand-alone major''
sources (that is, the HAP emissions from each dehydrator is above 10
tons or more per year of an individual HAP or 25 tons or more of all
HAP). Therefore, the data set used to determine the MACT floor
recommendation in 1997 is directly appropriate for use in this
reassessment based on the proposed changes to the definition of major
source.
Of these 200 stand-alone major source dehydrators, 34 percent were
controlled for air emissions. These controls included condensers,
condensers operating with a flash tank, venting the non-condensable
stream to a combustion device, and incineration systems. Based on this
information, the EPA determined that a 95 percent reduction in HAP
emissions set the MACT floor for both new and existing dehydrators.
Considering the proposed change in the major source definition for
production field facilities, the EPA still views this previous
conclusion as valid.
The dehydrator standards in the 1999 final NESHAP subpart HH rule
only applied to dehydrators with an actual annual average natural gas
flowrate equal to or greater than 85 thousand standard cubic meters per
day and actual annual average benzene emissions equal to or greater
than 0.90 Mg/yr. Although the 1999 Final Rule did not specifically
define them, these criteria represent the ``Large Dehydration Unit''
definition promulgated in the 2012 Final Rule amendments to NESHAP
subpart HH. Dehydrators with a natural gas flowrate less than 85
thousand standard cubic meters per day or actual annual average benzene
emissions less than 0.90 Mg/yr were exempt from any requirements in the
1999 Final Rule. The EPA later defined this subcategory as ``Small
Dehydration Units'' and finalized standards for them in the 2012 Final
NESHAP subpart HH amendments.
As noted earlier in this section, the raw data from the 1993 ICR
responses are not available at this time. Therefore, we are unable to
determine which of the 200 stand-alone major source dehydrators were
large dehydrators or small dehydrators. However, we have concluded this
is immaterial to the revisitation of the MACT floor for the proposed
revision of the major source definition for production field facilities
in NESHAP subpart HH. The MACT floor, based on the stand-alone
dehydrators in the data set, is 95 percent control. The EPA has
concluded this as an appropriate standard for all stand-alone major
dehydrators at production field facilities, without regard to the
actual annual average natural gas flowrate or the actual annual average
benzene emissions. Therefore, we are proposing to delete the
subcategorization of dehydrators at production field facilities in
NESHAP subpart HH and require that all stand-alone major dehydrators at
production field facilities comply with the closed vent system
requirements in 40 CFR 63.771(c) and the control device requirements in
40 CFR 63.771(d), which include either: (1) route emissions to an
enclosed combustion device that reduces the mass content of either TOC
or total HAP in the gases vented to the device by 95.0 percent by
weight or greater; (2) reduces the concentration of either TOC or total
HAP in the exhaust gases at the outlet to the device to a level equal
to or less than 20 parts per million by volume; (3) operates at a
minimum temperature of 760 [deg] C or, (4) if a boiler or process
heater is used as the control device, introduce the vent stream into
the flame zone of the boiler or process heater. Other options include
routing to a compliant flare or by routing to a vapor recovery device
or other non-destructive control device that is designed and operated
to reduce the mass content of either TOC or total HAP in the gases
vented to the device by 95.0 percent by weight or greater.
These changes do not impact the NESHAP subpart HH area source
standards, the standards applicable to dehydrators at natural gas
processing plants, or the NESHAP subpart HHH standards applicable to
dehydrators at transmission and storage facilities. There are
additional proposed decisions and actions related to the small
dehydrator standards at natural gas processing plants and transmission
and storage facilities in sections III.B.3 and III.B.5 of this
preamble.
b. Storage Vessels
As with dehydrators, the EPA began the evaluation by reviewing the
1997 MACT floor determination. Unlike dehydrators, the EPA did not base
the storage vessels universe on individual stand-alone units. Instead,
the Agency identified 68 storage vessels associated with major source
facilities. Therefore, the EPA cannot determine which of these 68
storage vessels were stand-alone major sources.
Of these 68 storage vessels, operators reported that they
suppressed emissions with a cover and then routed by closed vent system
to a control device for 32 percent of units. Therefore, the EPA
determined the MACT floor as using a cover and routing emissions
through a closed vent system to a control achieving 95 percent.
While the EPA cannot separate the 68 storage vessels into stand-
alone major sources, we expect that the frequency of control for stand-
alone major source storage vessels is at least as prevalent as for the
entire data set. In fact, since these stand-alone major source storage
vessels are higher emitting sources, we would expect that they were
controlled at a higher frequency than the lower-emitting storage
vessels. Therefore, the EPA concluded the previous 1997 MACT floor
determination can be applied for the purpose of determining the MACT
floor for the universe of stand-alone major sources. Consequently, the
proposed amendments require that stand-alone major source storage
vessels at production field facilities comply with the cover, closed
vent system, and control device requirements in 40 CFR 63.771.
This does not impact the NESHAP subpart HH requirements for storage
vessels with the PFE located natural gas processing plants. In
addition, note that amendments are being proposed to NESHAP subpart HH
to regulate storage vessels without the PFE at natural gas processing
plants (see section III.B.4.b of this preamble) and storage vessels at
transmission and storage facilities under

[[Page 21686]]

NESHAP subpart HHH (see section III.B.4.c of this preamble).
2. Regulation of Methanol Emitted From Regulated Emission Points
(Except Small Dehydrators)
As required by the D.C. Circuit's decision in LEAN, we are
proposing to address unregulated HAP emissions. We recognize that the
D.C. Circuit determined that the Agency has a ``clear statutory
obligation to set emission standards for each listed HAP'' and must
address previously unregulated HAP known to be emitted by a source
category during a technology review.\47\
---------------------------------------------------------------------------

\47\ Nat'l Lime Ass'n v. EPA, 233 F.3d 625, 634 (D.C. Cir.
2000); see also LEAN, 955 F.3d at 1092.
---------------------------------------------------------------------------

NESHAP subpart HH includes the following definition: ``Hazardous
air pollutants or HAP means the chemical compounds listed in section
112(b) of the Clean Air Act. All chemical compounds listed in section
112(b) of the Act need to be considered when making a major source
determination. Only the HAP compounds listed in table 1 of NESHAP
subpart HH need to be considered when determining compliance.'' \48\
NESHAP subpart HHH includes a similar definition.
---------------------------------------------------------------------------

\48\ NESHAP subpart HH, 40 CFR 63.761.
---------------------------------------------------------------------------

In the original development of NESHAP subparts HH and HHH, the EPA
determined that the primary HAP associated with the oil and natural gas
production and natural gas transmission and storage source categories
included BTEX and n-hexane. The EPA also determined that 2,2,4-
trimethylpentane (iso-octane), formaldehyde, acetaldehyde, naphthalene,
ethylene glycol, carbon disulfide, and carbonyl sulfide were emitted.
In response, the EPA included these HAP in table 1 to NESHAP subparts
HH and HHH.
a. Proposed Changes to Table 1 of NESHAP subparts HH and HHH
In responses to the 2023 ICR questionnaire, industry reported
emissions of the HAP listed in table 1 of NESHAP subparts HH and HHH
(excluding ethylene glycol, which is no longer used in dehydrators), as
well as emissions of methanol. While methanol is not a naturally
occurring component of oil and gas, it is sometimes added as a hydrate-
preventor to keep water from being absorbed into the natural gas
stream. Respondents reported methanol emissions from approximately 20
percent of dehydrators across 22 facilities in Pennsylvania, West
Virginia, and Colorado, as well as from storage vessels at 10 sites.
The EPA concluded that methanol emissions must be addressed in NESHAP
subpart HH, and therefore we are proposing to add methanol to table 1
in NESHAP subpart HH.
The responses to the 2023 ICR questionnaire for natural gas
transmission and storage facilities did not report any methanol
emissions. We are specifically soliciting comment and request
information on whether methanol is emitted at natural gas transmission
and storage facilities (Question #3a). If we receive comments that
indicate there are no methanol emissions, we request information and
rationale for this claim (Question #3b). In the absence of clear
information to verify that methanol is emitted from natural gas
transmission and storage facilities, we are not proposing to amend
table 1 in NESHAP subpart HHH to add methanol. If we receive
information during the comment period, we will evaluate whether it is
appropriate to include methanol in a future rulemaking.
b. Regulation of Methanol From Sources Other Than Small Dehydrators
The EPA proposes methanol emissions standards for emission points
covered by NESHAP subpart HH. For storage vessels with the PFE and
large dehydrators, the current standards require 95 percent reduction
of all HAP emissions. The work practice standards for equipment leaks
also work to reduce leaks of methanol.
Currently, NESHAP subpart HH requires a combination of equipment
and work practice standards for equipment leaks at natural gas
processing plants. The EPA proposal includes similar requirements for
storage vessel requirements for storage vessels without PFE, cargo
vessel loading operations, and natural gas-driven process controllers
and pumps. These measures reduce total gas emissions, ensuring that the
system cuts methanol at the same rate as all other HAPs. Thus,
compliance with these standards guarantees methanol reduction alongside
other organic HAPs. Therefore, there would be no impact in adding
methanol to table 1 of NESHAP subpart HH for these situations.
We are proposing a 95 percent reduction performance standard for
AGRUs in the alternative. We expect all commonly used control devices
to achieve the reduction of methanol at the same levels, or higher, as
other HAP. Further, the compliance determination for these percent
reduction performance standards is based on EPA Method 25A. The EPA
Method 25A includes method procedures for the determination of total
gaseous organic concentrations. Thus, compliance with the percent
reduction performance standard would ensure that methanol emissions are
reduced along with all other organic HAP. Therefore, there would be no
impact in adding methanol to table 1 of NESHAP subparts HH for these
situations.
c. Regulation of Methanol From Small Dehydrators
The one instance identified where there may be an impact of adding
methanol to table 1 in NESHAP subpart HH is for small dehydrators. The
standards for small dehydrators are in the form of equations from which
dehydrator-specific BTEX emission limitations are calculated. We
conclude that BTEX is an appropriate surrogate for all current table 1
of NESHAP subpart HH HAP that are emitted (see section III.B.3 of this
preamble). However, we question whether it is an appropriate surrogate
for methanol. Therefore, we are proposing separate methanol-specific
limits for methanol for small dehydrators. This is discussed in detail
in section III.B.3 of this preamble. We are soliciting comment on using
BTEX limits as a surrogate for all HAP except methanol (Question #4a).
We are also soliciting data and comment as to whether BTEX is an
appropriate surrogate for methanol emitted from small dehydrators and
storage vessels (Question #4b).
3. Regulation of all HAP From Small Dehydrators
In the 2012 Final Rule, in addition to risk and technology review,
the EPA also established BTEX standards for small dehydrators but not
for other HAP; however, the EPA noted that control of BTEX reduces
emissions of VOC and HAP. The current NESHAP subparts HH and HHH rules
continue to require compliance for small dehydrators to be demonstrated
based on a BTEX emissions limit.\49\
---------------------------------------------------------------------------

\49\ U.S. Environmental Protection Agency. (2013). Oil and
Natural Gas Sector: Reconsideration of Certain Provisions of New
Source Performance Standards. Response to Public Comments on
Proposed Rule (78 FR 22126; April 12, 2013). July 2013. EPA Document
ID No. EPA-HQ-OAR-2010-0505-4639 at 247.
---------------------------------------------------------------------------

Petitioners on the August 2012 NESHAP Final Rules raised concerns
that small glycol dehydration units emit other HAP besides BTEX.\50\
Petitioners asserted that the EPA could not ignore other HAP emitted by
these sources, and that the EPA must also set limits on all other
emitted HAP.
---------------------------------------------------------------------------

\50\ Earthjustice, et al. (2012). Re: Petition for
Reconsideration of Oil and Natural Gas Sector: National Emission
Standards for Hazardous Air Pollutants Reviews; Final Rule, 77 FR
49490 (August 16, 2012), 40 CFR part 63, subparts HH and HHH. Docket
ID No. EPA-HQ-OAR-2010-0505 at 42-44 (October 15, 2012).

---------------------------------------------------------------------------

[[Page 21687]]

Petitioners also argued that CAA section 112(d)(1) and (2) and case
law require the EPA to set a limit on all emitted HAP.\51\ Petitioners
claimed the EPA acted unlawfully by setting a BTEX-only MACT for small
glycol dehydrators. The petitioners noted that the EPA's own response
to comments stated it was not using BTEX as a surrogate, which prevents
the Agency from using that principle as an ``excuse'' for failing to
limit all HAPs. They added that the EPA further stated it set a limit
only for BTEX because the data available from the 1999 rulemaking only
contained BTEX emissions for all units and the Agency intended to
further investigate the non-BTEX emissions from small glycol
dehydrators. Once we obtained sufficient data we would propose a MACT
standard for those other HAP. The petitioners argue that a lack of data
does not legally excuse the EPA from failing to control HAP under CAA
section 112(d) when the data show HAP emissions.
---------------------------------------------------------------------------

\51\ Nat'l Lime Ass'n, 233 F.3d at 634.
---------------------------------------------------------------------------

In response to petitioner concerns, the EPA requested data in 2015
on HAP emissions from regulated small glycol dehydrators.\52\ With
regards to the small glycol dehydrators, the EPA specifically requested
data regarding any emissions of HAP other than BTEX, as well as
information on available control options for any such HAP and
information regarding a potential compliance demonstration issue with
respect to the 2012 standards for small glycol dehydration units, as
they apply to units with very low emissions.\53\
---------------------------------------------------------------------------

\52\ 80 FR 74068 (November 27, 2015).
\53\ Id.
---------------------------------------------------------------------------

Several industry representatives provided information on small
dehydrator information requests.\54\ One industry response to the 2015
ICR provided that benzene, ethyl benzene, n-hexane, naphthalene,
toluene, 2,2,4-trimethylpentane, xylenes, o-xylene, m-xylene, and p-
xylene appear to be a complete list of known HAP in natural gas or
condensate/crude oil. Of these HAP, according to respondents, BTEX
(aromatics) are the HAP most preferentially absorbed in glycol (i.e.,
the only ones where greater than 10 percent of component in inlet gas
is absorbed into glycol). They contended that other HAP are absorbed
about one percent or less into glycol. For instance, they noted that
natural gas might contain n-hexane, but emissions from a glycol still
vent are predominately BTEX since such a small proportion of the n-
hexane is absorbed by the glycol. In addition, if other non-BTEX HAP
were present, respondents point out that controls required in NESHAP
subpart HH to reduce benzene or BTEX will result in the reduction of
all HAP to similar levels. Therefore, they contended that benzene is
still a good surrogate for all HAP emissions from glycol dehydrators.
Other industry responses similarly supported the use of BTEX as a
surrogacy for HAP for small dehydrators.
---------------------------------------------------------------------------

\54\ Document ID. Nos. EPA-HQ-OAR-2015-0747-0022, -0023, -0025,
and -0027.
---------------------------------------------------------------------------

The EPA considered the petitioner's concerns and researched the
situation more thoroughly. In response to the 2023 ICR questionnaire,
industry reported information for 261 dehydrators at oil and natural
gas production facilities and natural gas processing plants. For these
dehydrators, BTEX made up over 79 percent of the total HAP emissions
reported. The two other major HAP emitted n-hexane (13.5 percent) and
methanol (seven percent) also contributed to the total, while 2,2,4-
trimethylpentane accounted for less than 0.1 percent. For dehydrators
at natural gas transmission and storage facilities, BTEX comprised 91
percent of the reported HAP emissions, with n-hexane as the only other
reported pollutant.
We consider BTEX to be an excellent surrogate for organic HAP from
glycol dehydrators at oil and natural gas production facilities and
natural gas transmission and storage facilities for multiple reasons.
First, BTEX is ubiquitous at petroleum and natural gas facilities, and
is present in all natural gas inlet streams to small glycol dehydrators
that have measurable HAP content. Second, BTEX compounds have a higher
affinity for water than aliphatic compounds, such as n-hexane or 2,2,4-
trimethylpentane. Consequently, a much larger portion of the BTEX
compounds inlet to the dehydrator are absorbed with the water in the
glycol solution and potentially emitted during the regeneration of the
rich glycol solution. That is, BTEX and compounds like BTEX are much
more likely to be emitted from glycol dehydrator vents than most other
organic HAP. Modeling of n-hexane emissions from the glycol dehydrators
was used to establish the MACT floor in 1999. We found that the units
that achieved 95 percent control efficiency of BTEX emissions achieved
over 99 percent control efficiency for hexane.\55\
---------------------------------------------------------------------------

\55\ Becker & Coburn, RTI International. (2018). Memorandum to
Witosky, M., EPA. ``Evaluation of current standards for small glycol
dehydrators for limiting HAP emissions.'' (September 5, 2018). See
Docket ID No. EPA-HQ-OAR-2025-1348.
---------------------------------------------------------------------------

Therefore, we continue to conclude that BTEX is a reliable and
appropriate surrogate for HAP emissions from small glycol dehydrators,
with the possible exception of methanol. Methanol is not a naturally
occurring element that is typically present in the extracted oil and
natural gas. Rather, it is sometimes added as a hydrate-preventor to
keep water from being absorbed into the natural gas stream. As noted
above, methanol made up seven percent of the reported HAP emissions
from dehydrators in oil and natural gas production and natural gas
processing. Specifically, methanol emissions were reported from 58
dehydrators at 22 facilities. The uncontrolled methanol emissions
ranged from less than 0.1 tpy to 29 tpy per dehydrator, with an average
of 9.8 tpy per dehydrator. The EPA received no data indicating methanol
was emitted from dehydrators at transmission and storage facilities.
Like n-hexane, the EPA finds that methanol is controlled by
combustion to a greater extent than BTEX. Therefore, if compliance with
one of the small dehydrator equations is achieved by using a combustion
device, the EPA is convinced that BTEX represents a reasonable
surrogate for methanol. However, the possibility exists that if a
measure or control other than combustion is used, BTEX may not be an
appropriate surrogate for methanol. This is largely based on the fact
that, unlike the other non-BTEX HAP emitted from dehydrators, methanol
has a higher affinity for water than BTEX. Thus, if methanol is in the
inlet stream to the dehydrator, it is more likely to be emitted from
glycol dehydrator vents than BTEX in the absence of combustion. The EPA
is specifically requesting comment on whether BTEX is a surrogate for
methanol emissions from small dehydrators that comply using a method
other than combustion (Question #5a). The EPA also requests
information, analyses, and data that may support such surrogacy
(Question #5b).
However, in the absence of clear information to support BTEX as a
surrogate for methanol, the EPA is proposing a separate CAA section
112(d)(3) standard for methanol from small dehydrators in NESHAP
subpart HH. The 2023 ICR questionnaire responses for oil and natural
gas production sites and natural gas processing plants did not include
methanol emissions from dehydrators at facilities identified as major
sources. Therefore, the MACT floor determination was based on the data
from dehydrators at area sources, as they represent similar sources.

[[Page 21688]]

Of the 58 dehydrators that reported methanol emissions, 38
dehydrators (66 percent) reported that emissions were controlled using
a combustion device. Therefore, the EPA finds that the use of
combustion represents the MACT floor level of control. The EPA has long
recognized the use of properly operating flares and combustion devices
can routinely achieve 95 percent reduction, and higher efficiencies can
potentially be achieved but will require more rigorous monitoring.
Given the remote nature of many oil and natural gas production sites,
such rigorous monitoring is challenging. The EPA recognized this fact,
and even though flares are a common control device in the oil and
natural production segment, Federal air regulations for this industry
have consistently established standards that require the use of a flare
or 95 percent reduction. This is the case for numerous emission points
(including storage vessels) subject to New Source Standards of
Performance for Crude Oil and Natural Gas Facilities (40 CFR part 60,
subparts OOOO, OOOOa, and OOOOb), and for dehydrators and storage
vessels with the PFE subject to NESHAP subpart HH. Therefore, the EPA
determined that the MACT floor for methanol from small dehydrators is
95 percent reduction or the use of a flare.
As noted above, the annual average reported methanol emissions were
9.8 tons per dehydrator. The estimated capital cost of a flare is
$135,489 and the annual costs are $37,716 per year. For a 95 percent
reduction, this results in a cost-effectiveness of $4,058 per ton of
methanol reduced per year. The EPA also considered a beyond the floor
option of 98 percent control. With a capital cost of $564,769, and an
annual cost of $101,833 per year, the incremental cost effectiveness of
this additional three percent of emission reduction is $218,438 per ton
of additional annual methanol reduction. The EPA does not consider this
cost, in relation to additional emission reduction, to be reasonable.
Therefore, for NESHAP subpart HH, the EPA is proposing that small
glycol dehydrators reduce methanol emissions by 95 percent or route the
emissions to a flare.
a. Proposed Actions Related to the Regulation of All HAP From Small
Dehydrators in NESHAP Subpart HH
For small dehydrators at oil and natural gas production sites prior
to the point of custody transfer to a natural gas processing plant
where dehydrator emissions are greater than 10 tpy of a single HAP or
25 tpy of all HAP, and for major source natural gas processing plants,
the EPA is proposing that the BTEX emission limit, as determined by the
applicable equation, is a surrogate for all emitted HAP with the
exception of methanol. For small dehydrators that emit methanol, the
EPA is proposing that those emissions be reduced by 95 percent or by
routing to a flare. The EPA is requesting comment on whether this
additional standard is necessary for methanol emissions, or if the BTEX
equation can also be proven to be an appropriate surrogate for methanol
(Question #5c).
b. Proposed Actions Related to the Regulation of All HAP From Small
Dehydrators in NESHAP Subpart HHH
For small dehydrators at major source natural gas transmission and
storage facilities, the EPA is proposing to use the BTEX emission
limit, as determined by the applicable equation as a surrogate for all
emitted HAP.
Unlike dehydrators at oil and natural gas production facilities and
natural gas processing plants, there were no methanol emissions
reported in the ICR questionnaire responses for any dehydrator at a
natural gas transmission and storage facility. Since the EPA lacks data
confirming methanol emissions, the Agency is not proposing to regulate
methanol from those facilities. The EPA is requesting comment and
information on whether methanol is emitted from dehydrators at natural
gas transmission and storage facilities (Question #6a). If the comments
indicate there are no methanol emissions, the EPA is requesting
information and rationale for this claim (Question #6b).
4. Regulation of Previously Unregulated Emission Points
a. Introduction to Proposal and Alternative Proposal
The EPA is seeking comment on whether the CAA requires the EPA to
revise a major source NESHAP to set standards for unregulated emission
points or processes when conducting a CAA section 112(d)(6) review. To
ensure the public has an adequate opportunity to comment, the EPA
proposes not to regulate these sources, while simultaneously offering
an alternative proposal that would regulate these sources.
The EPA is proposing that when conducting a CAA section 112(d)(6)
technology review, the Agency is not obligated to expand the NESHAP to
include previously unregulated emission points because the review
focuses instead on whether revisions to the existing standards for the
NESHAP and source category, presently understood, are ``necessary.'' In
the past, the EPA has suggested that the D.C. Circuit's decision in
LEAN mandates that the EPA expand the NESHAP to include additional
emission points as part of the technology review under CAA section
112(d)(6). However, the Agency now proposes that LEAN does not mandate
such action pursuant to CAA section 112(d)(6) for two reasons and, on
that basis, proposes not to address potential additional emission
points and associated standards in this action.
First, while CAA section 112(d)(1) requires the EPA to ``establish
standards for each category or subcategory,'' \56\ it does not speak to
whether those standards must include emission limits for each emission
point within the category and leaves to the Agency's reasoned
discretion whether particular emission points belong in one or another
source category or subcategory. CAA section 112(d)(6) then instructs
the EPA to periodically revise these standards ``as necessary,'' \57\
considering developments since the last rulemaking, but does not
mandate that the EPA expand the standards or reconsider the scope of
the source category or subcategory to include additional emission
points at that time. This silence makes practical sense, as the EPA has
considerable discretion to determine what emission points are included
within a particular source category. Indeed, some sources (like certain
chemical production facilities), contain emission points from multiple
source categories, so it may not be entirely clear whether an
unregulated emission point is best regulated as part of one source
category or another.
---------------------------------------------------------------------------

\56\ 42 U.S.C. 7412(d)(1).
\57\ Id. 7412(d)(6).
---------------------------------------------------------------------------

Second, LEAN did not involve previously unregulated emission
points, and the D.C. Circuit did not address this distinct issue or
indicate that it must be resolved as part of the periodic and mandatory
CAA section 112(d)(6) technology review. Instead, Petitioners in LEAN
challenged the EPA's failure to promulgate emission limits for
previously unregulated HAP emitted from already regulated emission
points in the Pulp and Paper Production source category when the Agency
was reviewing the existing standards pursuant to CAA section 112(d)(6).
The D.C. Circuit remanded the standards to the EPA to ``set limits on
the remaining [HAP] emitted'' by these already regulated emission
points.\58\
---------------------------------------------------------------------------

\58\ LEAN, 955 F.3d at 1100.
---------------------------------------------------------------------------

Therefore, the EPA proposes to defer action on a potential
expansion of the NESHAP to include previously

[[Page 21689]]

unregulated emission points. The EPA is requesting comment on the
interpretation of CAA section 112(d)(6) adopted by the D.C. Circuit in
LEAN and the scope of the Agency's obligation and statutory authority
to impose additional standards under the CAA section 112(d)(6) process
for particular emission points not previously regulated (Question #7).
Although we maintain that CAA section 112(d)(6) review is not the
appropriate posture to address such issues and outstanding questions
remain as to whether such standards belong in the relevant NESHAP, we
are including below a tentative proposal about what standards could be
if we were not to finalize the proposed understanding in the previous
subsection. To derive the alternative proposed standard for each such
emission point discussed, the EPA first determines the appropriate MACT
floor under CAA section 112(d)(3) and then analyzes whether to adopt a
more stringent standard under a combined CAA section 112(d)(2) beyond
the floor review and CAA section 112(d)(6) technology review. For these
unregulated emission points, the EPA proposes to set MACT floors that
reflect the state of the industry at the time the Agency first
promulgated the Oil and Gas NESHAP in 1999 to align with the statutory
framework of CAA section 112. CAA section 112 requires that the EPA set
technology-based standards under CAA section 112(d)(2)-(3) (MACT
standards) for listed source categories, including Crude Oil and
Natural Gas Production and Natural Gas Transmission and Storage
Facilities, by the year 2000.\59\ CAA section 112(d)(6) then requires
that the EPA review and, as necessary, revise the standards every eight
years.\60\ Under the statutory framework, Congress clearly envisioned
that the initial MACT standards would be based on technological
performance around the 1990-2000 time period, and subsequent technology
developments would be evaluated every eight years. Therefore, to best
align with the statutory framework we are conducting the MACT analysis
for unregulated emission points considering the performance of units
prior to promulgation of the original NESHAP. This avoids the potential
of establishing standards decades after the year 2000 deadline, which
could create a cost burden that Congress did not intend the EPA to
impose without due consideration.\61\ In addition, the EPA would treat
the unregulated emissions fairly by setting MACT floors (which cannot
consider costs) based on the state of the oil and gas industry in 1999
(when the NESHAP was initially promulgated) instead of the industry's
performance recently. In U.S. Sugar Corp. v. EPA, 113 F.4th 984 (D.C.
Cir. 2024), the D.C. Circuit upheld the EPA's decision to use an
original dataset when it recalculated the MACT floors for certain
emission units on remand. The EPA explained that one of its reasons for
not using more recent data was to avoid a `` `potentially inequitable
outcome'--some units could be subject to `more stringent standards
solely because of the EPA error' '' at the time of initial standard
setting.\62\ Similarly here, the currently unregulated oil and gas
emission points would be unfairly subject to more stringent standards
than would have been adopted if the EPA were to set MACT floors based
on recent emissions data because the Agency did not set MACT for these
sources in 1999.
---------------------------------------------------------------------------

\59\ 42 U.S.C. 7412(e).
\60\ 42 U.S.C. 7412(d)(6).
\61\ 77 FR 49490 (August 16, 2012); 81 FR 35824 (June 3, 2016);
89 FR 16820 (March 8, 2024).
\62\ U.S. Sugar Corp., 113 F.4th at 1000.
---------------------------------------------------------------------------

After determining the MACT floor, the EPA then assesses whether the
MACT floor should be strengthened under a combined CAA 112(d)(2)/
112(d)(6) review. CAA section 112(d)(2) requires the EPA to determine
whether a more stringent standard than the MACT floor is ``achievable''
considering cost and the other factors listed in that subsection.\63\
CAA section 112(d)(6) similarly requires the EPA to assess ``whether
standards should be tightened in view of developments in technologies
and practices since the standard's promulgation or last revision, and,
in particular, the cost and feasibility of developments and
corresponding emissions savings.'' \64\ Because of the similarity of
the two reviews, the EPA is conducting one review based on current
developments and other factors, as required by CAA section 112(d)(6).
---------------------------------------------------------------------------

\63\ Nat'l Lime Ass'n, 233 F.3d at 629.
\64\ Nat'l Ass'n for Surface Finishing, 795 F.3d at 5.
---------------------------------------------------------------------------

Provided below are the EPA's analyses and the resulting proposed
standards for the following unregulated emission points: AGRUs at
natural gas processing plants; storage vessels without flash emissions
at field production facilities prior to the point of custody transfer
to natural gas processing plants and at natural gas processing plants;
storage vessels at natural gas transmission and storage facilities;
transport vessel loading operations at natural gas processing plants
and at natural gas transmission and storage facilities; and natural
gas-driven process controllers and pumps at natural gas transmission
and storage facilities. For each of these emission points, the EPA
first describes its proposed MACT standard under CAA section 112(d)(3)
and then analyzes whether a more stringent standard is necessary under
a combined CAA section 112(d)(2) beyond-the-floor and CAA section
112(d)(6) technology review.
b. AGRUs
AGRUs are used to remove acidic components in natural gas to meet
sales gas quality specifications. AGRUs include an absorber unit and a
regenerator unit. In the absorber, sour gas is contacted with amine
solvent to remove H<INF>2</INF>S and CO<INF>2</INF> to produce a
sweetened gas stream and an amine solution rich in absorbed acid gases.
The rich amine solution is routed to a regenerator to produce
regenerated or lean amine and an acid gas stream. The lean amine is
recycled for reuse in the absorber. The acid gas stream is vented to a
control device. AGRU emissions that originate from the regenerator acid
gas stream can contain H<INF>2</INF>S, CO<INF>2</INF>, BTEX, and
CS<INF>2</INF>. If high concentrations of H<INF>2</INF>S are present,
the acid gas stream is routed to a sulfur recovery unit.
i. NESHAP Subpart HH (AGRUs at Major Source Natural Gas Processing
Plants)
CAA Section 112(d)(3) MACT Floor Determination
The 1997 Background Information Document (1997 BID) for the
proposed NESHAP subpart HH standards discussed AGRUs, explaining that
AGRUs had the potential for significant HAP emissions.\65\
Specifically, the HAPs identified were BTEX, COS, and CS<INF>2</INF>.
However, there was no specific data on HAP emissions or control methods
for AGRUs.
---------------------------------------------------------------------------

\65\ National Emission Standards for Hazardous Air Pollutants
for Source Categories: Oil and Natural Gas Production and Natural
Gas Transmission and Storage Background Information for Proposed
Standards. EPA-453/R-94-079a. (April 1997).
---------------------------------------------------------------------------

Controls used for glycol dehydrators and storage vessels with the
PFE were extensively studied, and the EPA established MACT standards of
95 percent emission reduction in 1999 for these sources (both new and
existing). The EPA determined that 95 percent control reflected the
emission reductions achieved by the best performing 12 percent of these
two sources at the time.\66\ The EPA also set a 95 percent standard for
new sources, indicating that to be the performance level by the best
controlled source. The

[[Page 21690]]

types of control devices used to reduce emissions from dehydrators and
storage vessels with the PFE, particularly combustion devices, are
commonly used devices to reduce emissions from AGRUs. Because the types
of controls used for glycol dehydrators and storage vessels also are
used to control AGRUs, and in fact the same devices could be used to
co-control AGRU emissions, it is reasonable to conclude that the best
controlled 12 percent of AGRUs at the time were also achieving 95
percent control of their HAP emissions. The EPA is not aware of factors
other than control technology that would affect the emissions achieved
by the best performing AGRUs.\67\
---------------------------------------------------------------------------

\66\ 42 U.S.C. 7412(d)(3).
\67\ Cement Kiln Recycling Coal. v. EPA, 255 F.3d 855, 864-65
(D.C. Cir. 2001) (``if factors other than MACT technology do indeed
influence a source's performance, it is not sufficient that EPA
considered sources using only well-designed and properly operated
MACT controls'' because they ``may not reflect what the best-
performers actually achieve'').
---------------------------------------------------------------------------

In 1985, pursuant to CAA section 111, the EPA promulgated new
source performance standards (NSPS) for SO<INF>2</INF> emissions from
acid gas removal at natural gas processing plants. The 1985 NSPS
required control of acid gas by sulfur capture or emission reduction
ranging from 74 to 99 percent reduction of SO<INF>2</INF> emissions
(depending on the sulfur feed rate and sulfur content of the acid gas).
One of the control techniques used to meet this standard is combustion,
which would also reduce HAP in the stream by at least 95 percent.
For the reasons explained above, the EPA concludes that 95 percent
reduction in HAP emissions from AGRUs represents the level of control
for the best performing similar source, and the level of control for
the top performing 12 percent of sources. Therefore, the EPA is
proposing a 95 percent reduction as the MACT floor for both new and
existing AGRUs at major source natural gas processing plants. The EPA
is specifically soliciting comment on this determination, along with
information to support or refute these assumptions about the controls
used in 1999 to reduce emissions from AGRUs at natural gas processing
plants. (Question #7a)
CAA 112(d)(2) Beyond-the-Floor/Section 112(d)(6) Technology Review
The EPA then assesses whether the MACT floor should be strengthened
under a combined CAA 112(d)(2)/112(d)(6) review. We reviewed various
sources of information to identify potential options for standards more
stringent than the MACT floor, as well as for developments in
practices, processes, and control technology since the time frame for
which the MACT floor was determined (as discussed in the previous
section). For AGRUs, these sources included information submitted in
response to the 2023 ICR and other NESHAP regulations in the petroleum
industry.
The EPA assessed the options to revise the stringency of these MACT
floor standards by considering the cost weighed against the emission
reductions that a more stringent standard can achieve, with the
inherent energy impacts of regulating energy production.
The EPA determined that 98 percent control represents a development
in practices, processes, and control technologies from the MACT level
for AGRUs at major source natural gas processing plants. In responses
to the 2023 ICR, several sources reported controls that achieved at
least a 98 percent reduction in HAP emissions. In addition, 98 percent
reduction is a standard in the Petroleum Refinery NESHAP (NESHAP
subpart UUU). The EPA estimated the incremental cost effectiveness of
increasing the stringency from the 95 percent MACT level to 98 percent
for AGRUs is just under $15,000 per ton of additional reduction in HAP,
which is above what we had previously determined to be unreasonable. We
had determined that the cost effectiveness of $11,750 (adjusted for
inflation) was not reasonable in the 2022 technology review for the
NESHAP for the Gasoline Distribution NESHAP (NESHAP subpart R).\68\
---------------------------------------------------------------------------

\68\ 87 FR 35608 (June 10, 2022).
---------------------------------------------------------------------------

Proposed Standard for AGRUs at Major Source Natural Gas Processing
Plants
Based on the above MACT floor analysis under CAA section 112(d)(3)
and the beyond-the-floor/technology review under CAA sections
112(d)(2)/112(d)(6), we are proposing that HAP emissions from new and
existing AGRUs at major source natural gas processing plants be reduced
by 95 percent or greater.\69\
---------------------------------------------------------------------------

\69\ The proposed standard allows for routing to a flare. Flares
operated property under the General Provisions of the NESHAP are
expected to achieve 95 percent or greater reduction.
---------------------------------------------------------------------------

ii. NESHAP Subpart HHH
The 2023 ICR responses identify one AGRU at a major source natural
gas transmission and storage facility. We therefore propose standards
for HAP emissions from AGRUs at major source natural gas transmission
and storage facilities subject to NESHAP subpart HHH. We are also
requesting comments and information on the existence of AGRUs at
natural gas transmission and storage facilities, as well as emissions
and control information (Question #7b).
We are proposing the same standards for NESHAP subpart HHH for the
same basic reasons as discussed for natural gas processing plants under
NESHAP subpart HH. Controls used for glycol dehydrators at natural gas
transmission and storage facilities were extensively studied, and the
EPA established MACT standards of 95 percent emission reduction in 1999
for glycol dehydrators (both new and existing). The EPA determined that
95 percent control reflected the emission reductions achieved by the
best performing 12 percent of this source at the time.\70\ The EPA also
set a 95 percent standard for new sources, indicating that to be the
performance level by the best controlled source. The types of control
devices used to reduce emissions from dehydrators, particularly
combustion devices, are commonly used devices to reduce emissions from
AGRUs. Because the types of controls used for glycol dehydrators also
are used to control AGRUs, and in fact the same devices could be used
to co-control AGRU emissions, it is reasonable to conclude that the
best controlled 12 percent of AGRUs at the time were also achieving 95
percent control of their HAP emissions. The EPA is not aware of factors
other than control technology that would affect the emissions achieved
by the best performing AGRUs.\71\ The proposed standards require a 95
percent reduction in HAP emissions or route to a flare.
---------------------------------------------------------------------------

\70\ 42 U.S.C. 7412(d)(3).
\71\ Cement Kiln Recycling Coal., 255 F.3d at 864-65.
---------------------------------------------------------------------------

c. Storage Vessels Without the PFE Prior to the Point of Custody
Transfer and Storage Vessels Without the PFE at Natural Gas Processing
Plants (NESHAP Subpart HH)
Crude oil, condensate, and produced water are typically stored in
fixed-roof storage vessels. These fixed-roof vessels, which are
operated at or near atmospheric pressure conditions, are typically
located in tank batteries at well sites and at centralized gathering
facilities in the oil and natural gas production segment and at
transmission and storage facilities in the oil natural gas transmission
and storage segment. A tank battery refers to the collection of process
components used to separate, treat, and store crude oil, condensate,
intermediate hydrocarbon liquids, and produced water. At well sites and
centralized gathering facilities, the

[[Page 21691]]

extracted products from production wells enter the tank battery through
the production header, which may collect product from many wells.
Emissions are a result of working, breathing, and flash losses.
Working losses occur due to the emptying and filling of storage
vessels. Specifically, emissions are released through a vapor vent as
liquid is pushed into the storage vessel, displacing any built-up
vapors in the vessel. Breathing losses are the release of gas
associated with daily temperature fluctuations and other equilibrium
effects. Flash losses occur when a liquid with entrained gases is
transferred from a vessel with higher pressure to a vessel with lower
pressure, and thus, allowing entrained gases or a portion of the liquid
to vaporize or flash.
NESHAP subpart HH currently regulates storage vessels with the PFE,
but it excludes storages vessels without the PFE. Because storage
vessels without the PFE in this industry segment emit HAP, they remain
unregulated emission points. Therefore, we propose standards for
storage vessels without the PFE.
According to the information provided in the 2023 ICR responses,
there are stand-alone major source storage vessels without the PFE
located at oil and natural gas production sites located in the
producing operations (i.e., prior to the point of custody transfer to a
natural gas processing plant) and at natural gas processing plants that
have the potential to emit HAP at levels greater than the major source
thresholds.\72\
---------------------------------------------------------------------------

\72\ CAA section 112(n)(4)(A) prohibits aggregating emissions at
oil and natural gas production sites for purposes of determining
major source status. See 42 U.S.C. 7412(n)(4)(A).
---------------------------------------------------------------------------

CAA Section 112(d)(3) MACT Floor Determination
The EPA studied emissions and controls for storage vessels with the
PFE at oil and gas production sites and natural gas processing plants
for the original promulgation of NESHAP subpart HH in 1999, yet no
specific information is available regarding analysis of storage vessels
without the PFE. However, submerged fill techniques were mentioned in
the 1997 BID, and the EPA recognizes that submerged filling has long
been a standard practice in the oil and natural gas industry because
splash filling causes a considerable loss of valuable petroleum
product.
There are many similarities between the storage vessels at gasoline
bulk plants and those in at oil and natural gas production sites and at
natural gas processing plants. While the specific composition of the
oil or condensate differs from gasoline, the design, operation, size,
and HAP emitted are the same. Bulk gasoline plants have long been
studied by the EPA, beginning with the development of Control Technique
Guidelines (CTG) in 1977.\73\ Submerged filling is a primary control
technique discussed in the 1977 CTG, although the prevalence of its use
in 1977 is not discussed. However, in 2008, the EPA promulgated NESHAP
subpart BBBBBB, which covers HAP emissions from bulk gasoline plant
area sources.\74\ NSPS subpart BBBBBB requires that submerged filling
be used to load gasoline into bulk plant gasoline storage vessels.\75\
When this regulation was proposed in 2006, the EPA asserted that
``approximately 5,500 out of 5,900 bulk plants are estimated to utilize
submerged fill.'' \76\
---------------------------------------------------------------------------

\73\ Control of Volatile Organic Emissions from Bulk Gasoline
Plants. EPA-450/2-77-035. (December 1977).
\74\ 73 FR 1933 (January 10, 2008).
\75\ 40 CFR 63.11086.
\76\ 71 FR 66072 (November 9, 2006).
---------------------------------------------------------------------------

The EPA concludes that in 1999, submerged filling at oil and
natural gas production sites and at natural gas processing plants
represents the control utilized at the best performing similar source,
as well as the control utilized for the top performing 12 percent of
sources. This is based on the knowledge that it has long been the
standard industry practice utilized in the petroleum industry to save
valuable product, and the fact that in 2006, the EPA determined that
over 93 percent of the comparable storage vessels at bulk gasoline
terminals employed submerged filling.
Based on this information, the EPA concludes submerged filling for
storage vessels without the PFE that are stand-alone major sources
prior to the point of custody transfer to natural gas processing
plants, and at major source natural gas processing plants, represents
the control utilized at the best performing similar source, as well as
the control utilized for the top performing 12 percent of sources.
Therefore, the EPA established a MACT floor under CAA section 112(d)(3)
that requires submerged filling for both new and existing storage
vessels without the PFE that are stand-alone major sources prior to the
point of custody to a natural gas processing plant, and for both new
and existing storage vessels without the PFE at major source natural
gas processing plants. We are specifically soliciting comment on this
determination, along with information to support or refute these
assumptions about the use of submerged filling in 1999 to reduce
emissions from storage vessels without the PFE at oil and natural gas
production sites and at natural gas processing plants. (Question #8)
CAA 112(d)(2) Beyond-the-Floor/Section 112(d)(6) Technology Review
The EPA then assesses whether the MACT floor should be strengthened
under a combined CAA 112(d)(2)/112(d)(6) review. We reviewed various
information sources to identify standards more stringent than the MACT
floor and find developments in practices, processes, and control
technology since we determined the MACT floor (as discussed in the
previous section). For storage vessels without the PFE, our review
included basic petroleum industry practices, NESHAP subpart HH
standards for storage vessels with the PFE at these same sites, and
responses to the 2023 ICR.
The EPA assessed the options to revise the stringency of these MACT
floor standards by considering the cost weighed against the emission
reductions that a more stringent standard can achieve, with the
inherent energy impacts of regulating energy production.
Operators sometimes use internal floating roof tanks to reduce
emissions from storage vessels. The small quantities of liquid stored
in these types of tanks typically do not provide sufficient buoyancy to
support floating roofs. While a floating roof effectively limits
vaporization, the EPA still considers them a technically infeasible
control method for storage tanks in the Oil and Natural Gas Production
source category.
The EPA determined that 95 percent control represents a development
in practices, processes, and control technologies from the MACT level
of submerged filling. This is the standard for storage vessels with the
PFE in NESHAP subpart HH. In addition, a number of storage vessels
without the PFE reported controls that achieved at least 95 percent
reduction in HAP emissions. The incremental cost effectiveness to 95
percent for storage vessels without the PFE is estimated to be just
under $18,000 per ton of additional reduction in HAP. This is above a
level that we had already previously determined to be unreasonable.

[[Page 21692]]

iii. Proposed Standards for Storage Vessels Without the PFE Prior to
the Point of Custody Transfer and Storage Vessels Without the PFE at
Major Source Natural Gas Processing Plants
Based on the above MACT analysis under CAA section 112(d)(2)-(3)
and technology review under CAA section 112(d)(6), we are proposing to
require the installation and use of submerged filling to reduce HAP
emissions from new and existing stand-alone major storage vessels
without the PFE prior to point of custody transfer to a natural gas
processing plant, and for new and existing storage vessels without the
PFE at major source natural gas processing plants.
d. Storage Vessels at Natural Gas Transmission and Storage Facilities
(NESHAP Subpart HHH)
Storage vessels at natural gas transmission and storage facilities
are typically fixed-roof storage vessels at atmospheric conditions that
contain condensate and produced water. While there may be other storage
vessels that contain process fluids such as maintenance and lubricating
oils, these storage vessels are not in the scope of the NESHAP.
No storage vessels (whether with or without PFE) are currently
regulated in NESHAP subpart HHH. There were no methanol emissions
specifically reported in the 2023 ICR responses for storage vessels at
major source natural gas transmission and storage facilities. During
the 2023 ICR data collection, the EPA did not specifically request
information on storage vessel emissions. However, based on previous
analyses, the EPA found that the composition of the gas at natural gas
transmission and storage facilities included small amounts of HAP.
Specifically, a 2011 analysis concluded that 2.97 percent of the VOC
emissions in gas streams at natural gas transmission and storage
facilities was HAP.\77\ Therefore, the EPA maintains that the reported
VOC emissions contain the same type of HAP emitted from storage vessels
at oil and natural gas field production facilities and natural gas
processing plants, although in smaller quantities. Therefore, we are
proposing standards for storage vessels at major source natural gas
transmission and storage facilities. Since the EPA used previously
established HAP-to-VOC ratios to estimate HAP emissions from the VOC
emissions reported in the 2023 ICR responses for storage vessels at
major source natural gas transmission and storage facilities, the EPA
requests data on the quantities of HAP emissions as a component of VOC
emissions from these storage vessels (Question #8a).\78\ If EPA
receives information during the comment period that the 2011 analysis
was incorrect, the HAP-to-VOC ratio was incorrect, or other relevant
information that EPA's assumptions related to methanol emissions from
natural gas transmission or storage facilities are incorrect, the EPA
will revise the final rule accordingly.
---------------------------------------------------------------------------

\77\ Memorandum. Brown, H., EC/R Incorporated, to Moore, B.,
EPA/OAPS/SPPD. ``Composition of Natural Gas for Use in the Oil and
Natural Gas Sector Rulemaking.'' (July 28, 2011).
\78\ Memorandum. Wilson, D., Enoch, S., Weyl, R., ERG, to Pope,
A., EPA. ``Documentation for NEI Updates for Oil and Natural Gas
Production and Natural Gas Transmission and Storage'' (July 15,
2011).
---------------------------------------------------------------------------

CAA Section 112(d)(3) MACT Floor Determination
The discussion in section III.B.4.b of this preamble regarding the
expected use of submerged filling to reduce working losses for storage
vessels at oil and natural gas production sites and natural gas
processing plants also applies to storage vessels at natural gas
transmission and storage facilities. Therefore, the EPA concludes that
in 1999, submerged filling at natural gas transmission and storage
facilities plants represents the control utilized at the best
performing similar source, as well as the control utilized for the top
performing 12 percent of sources, to reduce working loss emissions.
Submerged filling is a measure to reduce working loss emissions, but it
does not impact flash emissions. In the 2023 ICR responses, there was
no instance where flash emissions (or any emissions from a storage
vessel at a natural gas transmission and storage facility) were
reported to be routed to a control device. If no control devices are
utilized at this time, the EPA is comfortable concluding that no
control devices were in place in 1999 to reduce flash emissions from
storage vessels at natural gas transmission and storage facilities.
Based on this information, the EPA concludes submerged filling for
storage vessels at major source natural gas transmission and storage
facilities represents the control utilized at the best performing
similar source, as well as the control utilized for the top performing
12 percent of sources. Therefore, the EPA established a MACT floor
under CAA section 112(d)(3) that requires submerged filling for both
new and existing storage vessels at major source natural gas
transmission and storage facilities. We are specifically soliciting
comment on this determination, along with information to support or
refute these assumptions about the use of submerged filling in 1999 to
reduce emissions from storage vessels without the PFE at oil and
natural gas production sites and at major source natural gas processing
plants. (Question #8b)
CAA 112(d)(2) Beyond-the-Floor/Section 112(d)(6) Technology Review
The EPA then assesses whether the MACT floor should be strengthened
under a combined CAA 112(d)(2)/112(d)(6) review.
We reviewed various sources of information to identify potential
options for standards more stringent than the MACT floor, as well as
for developments in practices, processes, and control technology since
the time frame for which the MACT floor was determined (as discussed in
the previous section). For storage vessels, the primary source was the
controls used for storage vessels at sources subject to NESHAP subpart
HH.
The EPA assessed the options to revise the stringency of these MACT
floor standards by considering the cost weighed against the limited
emission reductions that a more stringent standard can achieve, with
the inherent energy impacts of regulating energy production. The EPA
determined that the use of combustion devices (including flares) and
VRUs that achieve 95 percent control represents a development in
practices, processes, and control technologies from the MACT level.
This is the level of control for storge vessels with the PFE in NESHAP
subpart HH. The incremental cost effectiveness to 95 percent for
storage vessels at major source natural gas transmission and storage
facilities is estimated to be just under $550,000 per ton of additional
reduction in HAP. This is above a level that we had already previously
determined to be unreasonable.
iii. Proposed Standards for Storage Vessels at Major Source Natural Gas
Transmission and Storage Facilities
Based on the above MACT floor analysis under CAA section 112(d)(3)
and the beyond-the-floor/technology review under CAA section 112(d)(2)/
112(d)(6), we are proposing to require the installation and use of
submerged filling to reduce HAP emissions from new and existing storage
vessels at major source natural gas transmission and storage
facilities.
e. Transport Vessel Loading Operations
Loading operations are used to conduct a transfer of liquids from

[[Page 21693]]

storage vessels to a type of transportation (i.e., transport) vessel
using loading racks. Typically, the transfer of the liquids is for the
purpose of transporting refined or waste products to an end
destination. The types of transport vessels loaded can be tank trucks,
railcars, marine vessels (barges and ships), and smaller containers
such as drums or totes. At onshore natural gas production facilities,
natural gas processing plants, and natural gas transmission and storage
facilities, the liquids loaded primarily are crude oil, condensate, and
produced water, and the transport vessels into which the liquids are
loaded are almost exclusively tank trucks.
Loading losses from the loading of liquids into transport vessels
occur as organic vapors in ``empty'' transport vessels are displaced to
the atmosphere by the liquid being loaded into the vessels. These
vapors are a composite of (1) vapors formed in the empty vessel by
evaporation of residual product from previous loads, (2) vapors
transferred to the vessel in vapor balance systems (if present) as
product is being unloaded, and (3) vapors generated in the vessel as
the new product is being loaded. The quantity of evaporative losses
from transport vessel loading operations is a function of the physical
and chemical characteristics of the cargo, the method of unloading the
previous cargo, operations to transport the empty carrier to a loading
terminal, the method of loading the new cargo, and the physical and
chemical characteristics of the new cargo.\79\
---------------------------------------------------------------------------

\79\ U.S. Environmental Protection Agency. (Last updated in
January 1995). AP 42 Compilation of Air Pollutant Emission Factors.
Fifth Edition. Section 5.2: Transportation And Marketing Of
Petroleum Liquids.
---------------------------------------------------------------------------

i. NESHAP Subpart HH (Transport Vessel Loading Operations at Major
Source Natural Gas Processing Plants)
CAA Section 112(d)(3) MACT Floor Determination
In the 1997 BID for the proposed standards, there are statements
regarding transport vessel loading techniques at oil and natural gas
sites. Specifically, at both tank batteries and natural gas processing
plants, the EPA states ``transfer may also involve loading crude oil,
condensate, or produced water into tank trucks, railcars, and barges
through the use of splash loading or submerged fill techniques.'' \80\
---------------------------------------------------------------------------

\80\ National Emission Standards for Hazardous Air Pollutants
for Source Categories: Oil and Natural Gas Production and Natural
Gas Transmission and Storage Background Information for Proposed
Standards. EPA-453/R-94-079a. April 1997. pp. 2-16, 2-18.
---------------------------------------------------------------------------

In 1995, the EPA promulgated MACT standards for Marine Vessel
Loading Operations. \81\ \82\ While the loading of marine vessels is
not a common practice in the oil and natural gas industry, loading
petroleum-based liquids into marine vessels is analogous to the loading
of oil, condensate, and produced water into tank trucks or railcars.
Specifically, the basic design of the loading rack and the operation to
fill the transport vessel (marine vessel or tank truck) is the same, as
are the HAP emitted. In 40 CFR part 63 subpart Y, the major source MACT
requirements for existing sources with HAP emissions less than 10 and
25 tons must utilize submerged fill methods.
---------------------------------------------------------------------------

\81\ 60 FR 48399 (September 19, 1995).
\82\ 40 CFR part 63, subpart Y.
---------------------------------------------------------------------------

In 2008, the EPA promulgated NESHAP for area source gasoline
distribution bulk terminals, bulk plants, and pipeline facilities. \83\
\84\ As discussed in section III.B.4.b of this preamble, the design,
operation, size, and HAP emitted from storage vessels and transport
vessel loading operations are similar at natural gas processing plants
and gasoline bulk plants. The requirement for cargo loading at bulk
plants in 40 CFR part 63 subpart BBBBBB is submerged filling.
---------------------------------------------------------------------------

\83\ 73 FR 1933 (January 8, 2008).
\84\ 40 CFR part 63, subpart BBBBBB.
---------------------------------------------------------------------------

The EPA concludes that in 1999, for transport vessel loading
operations at natural gas processing plants, submerged filling
represents the control utilized at the best performing similar source,
as well as the control utilized for the top performing 12 percent of
sources. This is based on the knowledge that it has long been the
standard industry practice utilized to save valuable product, and the
fact that the EPA concluded that this was the appropriate standard to
reduce HAP from comparable marine vessel loading operations and at bulk
gasoline plants.
Based on this information, the EPA concludes that submerged filling
to reduce HAP emissions from transport vessel loading operations at
major source natural gas plants represents the control utilized at the
best performing similar source, as well as the control utilized for the
top performing 12 percent of sources. Therefore, the EPA established a
MACT floor under CAA section 112(d)(3) that requires submerged filling
for both new and existing transport loading operations at major source
natural gas processing plants. We are specifically soliciting comment
on this determination, along with information to support or refute
these assumptions about the use of submerged filling in 1999, and
currently, to reduce emissions from transport vessel loading operations
at major source natural gas processing plants. (Question #9a)
CAA 112(d)(2) Beyond-the-Floor/Section 112(d)(6) Technology Review
The EPA then assesses whether the MACT floor should be strengthened
under a combined CAA 112(d)(2)/112(d)(6) review.
We reviewed various sources of information to identify potential
options for standards stricter than the MACT floor, as well as for
developments in practices, processes, and control technology since the
time frame for which the MACT floor was determined (as discussed in the
previous section). For transport loading operations at major source
natural gas plants, the sources where for more stringent controls were
in the 2023 ICR responses and NESHAP subpart R, which covers loading
racks at major source bulk gasoline terminals.
The EPA assessed the options to revise the stringency of these MACT
floor standards by considering the cost weighed against the emission
reductions that a more stringent standard can achieve, with the
inherent energy impacts of regulating energy production. In the
responses to the 2023 ICR, over 25 percent of the major source natural
gas processing plants reported that HAP emissions from transport vessel
loading operations were controlled by combustion devices. NESHAP
subpart R includes a numeric emission limit of 10 milligrams of total
organic compounds per liter of gasoline loaded. This limit is unique to
gasoline, but the control devices typically employed to achieve this
standard include combustion devices and vapor recovery units. These
types of devices can be used to control emissions from cargo vessel
loading operations at natural gas processing plants, and the EPA
concludes that they can achieve a 95 percent reduction in HAP emissions
in the oil and natural gas industry. Therefore, we conclude that this
represents a development in control technology from submerged filling
alone. The incremental cost effectiveness to 95 percent for transport
vessel loading operations at major source natural gas processing plants
is estimated to be $47,000 per ton of additional reduction in HAP. This
is above a level that we had already previously determined to be
unreasonable.

[[Page 21694]]

Proposed Standards for Transport Vessel Loading Operations at Major
Source Natural Gas Processing Plants
Based on the above MACT floor analysis under CAA section 112(d)(3)
and the beyond-the-floor/technology review under CAA sections
112(d)(2)/112(d)(6), we are proposing to require the installation and
use of submerged filling to reduce HAP emissions from new and existing
transport vessel loading operations at major source natural gas
processing plants.
ii. NESHAP Subpart HHH (Transport Vessel Loading Operations at Major
Source Natural Gas Transmission and Storage Facilities)
CAA Section 112(d)(3) MACT Floor Determination
The discussion above related to the 1999 MACT floor for transport
vessel loading operations at natural gas processing plants is also
applicable for natural gas transmission and storage facilities. Based
on this information, the EPA concludes that submerged filling to reduce
HAP emissions from transport vessel loading operations at major source
natural gas transmission and storage facilities represents the control
utilized at the best performing similar source, as well as the control
utilized for the top performing 12 percent of sources. Therefore, the
EPA established a MACT floor under CAA section 112(d)(3) that requires
submerged filling for both new and existing transport loading
operations at major source natural gas transmission and storage
facilities. We are specifically soliciting comment on this
determination, along with information to support or refute these
assumptions about the use of submerged loading in 1999, and currently,
to reduce emissions from transport vessel loading operations at natural
gas transmission and storage facilities. (Question #9b)
CAA 112(d)(2) Beyond-the-Floor/Section 112(d)(6) Technology Review
The EPA then assesses whether the MACT floor should be strengthened
under a combined CAA 112(d)(2)/112(d)(6) review. As mentioned in regard
to NESHAP subpart HH, we reviewed various sources of information to
identify potential options for standards stricter than the MACT floor,
as well as for developments in practices, processes, and control
technology since the time frame for which the MACT floor was determined
(as discussed in the previous section). For transport loading
operations at major source natural gas plants, the most relevant source
identified was control information for loading racks at major source
bulk gasoline terminals related covered by NESHAP subpart R.
The EPA assessed the options to revise the stringency of these MACT
floor standards by considering the cost weighed against the emission
reductions that a more stringent standard can achieve, with the
inherent energy impacts of regulating energy production. NESHAP subpart
R includes a numeric emission limit for loading racks that is unique to
gasoline, but the control devices typically employed to achieve this
standard include combustion devices and vapor recovery units. These
types of devices can be used to control emissions from cargo vessel
loading operations at natural gas processing plants, and the EPA
concludes that they can achieve a 95 percent reduction in HAP emissions
in the oil and natural gas industry. Therefore, we conclude that this
represents a development in control technology from submerged filling
alone. The incremental cost effectiveness to 95 percent for transport
vessel loading operations at major source natural gas transmission and
storage facilities is estimated to be $64 million per ton of additional
reduction in HAP. This is above a level that we had already previously
determined to be unreasonable.
Proposed Standards for Transport Vessel Loading Operations at Major
Source Natural Gas Transmission and Storage Facilities
Based on the above MACT floor analysis under CAA section 112(d)(3)
and the beyond-the-floor/technology review under CAA sections
112(d)(2)/112(d)(6), we are proposing to require the installation and
use of submerged filling to reduce HAP emissions from transport vessel
loading operations at major source natural gas transmission and storage
facilities.
f. Regulation of Emissions From Natural Gas-Driven Process Controllers
at Major Source Natural Gas Transmission and Storage Facilities (NESHAP
Subpart HHH)
Process controllers are automated instruments used for maintaining
the process condition, such as liquid level, pressure, pressure
difference, or temperature. In the oil and gas industry, many process
controllers are powered by pressurized natural gas and emit natural gas
into the atmosphere. However, process controllers may also be powered
by electricity or compressed air, and these types of process
controllers do not use or emit natural gas. Natural gas-driven process
controllers are a source of HAP emissions. Process controllers are used
in several segments of the oil and natural gas industry, including at
well sites, gathering and boosting stations, and natural gas processing
plants. Process controllers are also used at natural gas transmission
and storage facilities. While there are many natural gas-driven process
controllers used in the industry, each individual natural gas-driven
process controller only emits an average of approximately 25 pounds of
HAP per year.
i. CAA Section 112(d)(3) MACT Floor Determination
Process controllers were not evaluated as part of the original
rulemaking efforts for NESHAP subpart HHH. Emissions of methane and VOC
are regulated under CAA section 111 of the CAA. The EPA has gathered
information on these devices through other rulemakings that have taken
place over time. New, modified, or reconstructed natural gas-driven
process controllers are subject to 40 CFR part 60, subpart OOOO since
2012, and beginning in 2016, new, modified, or reconstructed natural
gas-driven process controllers are subject to 40 CFR part 60, subpart
OOOOa. Under both regulations, new natural gas-driven process
controllers at transmission and storage facilities are required to
operate at a natural gas bleed rate of less than 6 standard cubic feet
per hour (scfh) (i.e., low-bleed), with exceptions for demonstrated
functional needs and safety. In 2024, process controllers subject to 40
CFR part 60, subparts OOOOb and OOOOc became subject to zero-emission
standards, except for those at non-electrified sites in Alaska.\85\
---------------------------------------------------------------------------

\85\ Emission Guidelines OOOOc regulating existing sources will
be implemented through a future state or Federal plan.
---------------------------------------------------------------------------

MACT Floor for New Process Controllers
Based on information provided in response to the 2023 ICR
questionnaire, all natural gas transmission major source facilities
have electrical power provided by the grid or on-site power generation.
In the final 1999 NESHAP, it was also determined that many natural gas
transmission and storage facilities had electrical service in 1999. The
existence of electricity provides the opportunity to use electric
process controllers or pneumatic process controllers that are powered
by compressed air. Both of these options eliminate organic HAP
emissions from process controllers. While there are other options
currently available to allow the use of zero-emitting process
controllers, such as solar-powered

[[Page 21695]]

electrical process controllers or pneumatic controllers that are
powered by nitrogen gas, these options were not common in 1999.
However, it is safe to assume that zero-emitting electric process
controllers or pneumatic process controllers powered by compressed air
were in use at natural gas transmission and storage facilities with
electrical service in 1999, meaning that the ``best controlled similar
source'' has zero HAP emissions.
Based on this information, the EPA concludes that zero emissions
for process controllers at natural gas transmission and storage
facilities represents the emissions level achieved by the best
performing similar source. Based on this information, the EPA
determines zero-emissions to be the MACT floor for new process
controllers at existing major source transmission and storage
facilities We are specifically soliciting comment on this
determination, along with information to support or refute these
assumptions about the use of zero emission process controllers at
natural gas transmission and storage facilities in 1999. (Question
#10a)
MACT Floor for Existing Process Controllers
While specific information is not available to confirm the
prevalence of the use of low-bleed pneumatic controllers specifically
at natural gas transmission and storage facilities in 1999, it is safe
to assume that at least 12 percent of natural gas driven process
controllers at these facilities were low-bleed devices at that time.
Therefore, the EPA concludes that the use of low-bleed natural gas
driven process controllers represents the control level utilized for
the best performing 12 percent of sources. Based on this, the EPA
established an existing source MACT floor under CAA section 112(d)(3)
that requires natural gas-driven process controllers at existing major
source transmission and storage facilities to operate at a natural gas
bleed rate of less than 6 scfh (i.e., low-bleed), with exceptions for
demonstrated functional needs and safety. We are specifically
soliciting comment on this determination, along with information to
support or refute these assumptions about the location, use, and the
types of process controllers used at natural gas transmission and
storage facilities in 1999. (Question #10b)
CAA 112(d)(2) Beyond-the-Floor/Section 112(d)(6) Technology Review
The EPA then assesses whether the MACT floor for existing sources
process controllers should be strengthened under a combined CAA
sections 112(d)(2)/112(d)(6) review. For existing natural gas-driven
process controllers at major source natural gas transmission and
storage facilities, this is based on the new source MACT floor.
The EPA assessed various factors, including considering the cost
weighed against the emission reductions that a more stringent standard
can achieve, and the inherent energy impacts of regulating energy
production. The estimated HAP emissions reductions for a facility
switching to zero-emissions process controllers is approximately 0.03
tons per year. The incremental cost effectiveness of this zero-
emissions option is estimated to be $4.5 million per ton of additional
reduction in HAP. This is above a level that we had already previously
determined to be unreasonable.
The MACT standard for new sources was determined to be the use of
zero-emission process controllers at major source natural gas
transmission and storage facilities. As this standard would eliminate
all HAP emissions from process controllers, under CAA section 112(d)(6)
technology review and a CAA section 112(d)(3) beyond-the-floor
analysis, there are no developments in practices, processes, and
control technologies that would achieve greater emission reductions
from the 1999 MACT floor for new sources.
iii. Proposed Standards for Process Controllers at Major Source Natural
Gas Transmission and Storage Facilities
Based on the above MACT floor analysis under CAA section 112(d)(3)
and the beyond-the-floor/technology review under CAA sections
112(d)(2)/112(d)(6), we are proposing standards that require all
natural gas-driven process controllers at existing major source
transmission and storage facilities to operate at a natural gas bleed
rate of less than 6 scfh (i.e., low-bleed), with exceptions for
demonstrated functional needs and safety. For new major source natural
gas transmission and storage facilities, we are proposing that all
process controllers have zero emissions.\86\
---------------------------------------------------------------------------

\86\ In terms of cost and impact, the EPA anticipates all
affected sources will emit zero emissions via instrument air
starting in 2029 due to the NSPS Emission Guidelines OOOOc. See 40
CFR 60.5394c, the model rule for States implementing controller
requirements, and the EIA in the docket.
---------------------------------------------------------------------------

g. Regulation of Emissions From Natural Gas-Driven Pumps at Natural Gas
Transmission and Storage Facilities (NESHAP Subpart HHH)
In the oil and natural gas industry, pumps are used for many
purposes, including chemical injection, hot glycol circulation for heat
tracing/freeze protection, and glycol circulation in dehydrators. These
pumps are generally either piston pumps or diaphragm pumps that can be
powered by compressed air, compressed natural gas, or electricity. Of
these pumps, those that are units driven by natural gas emit HAP to the
atmosphere as part of their normal operation. Pumps can also have
emissions from equipment leaks; however, those emissions are not
related to normal operations and are addressed separately. In many
situations across all segments of the oil and gas industry, natural
gas-driven pneumatic pumps are used where electricity is not readily
available. Natural gas-driven pumps are used in several segments of the
oil and natural gas industry, including well sites, gathering and
boosting stations, and natural gas processing plants. Natural gas-
driven pumps are also used in the natural gas transmission and storage
facilities.
i. CAA Section 112(d)(3) MACT Floor Determination
As pumps were not evaluated as part of the original rulemaking
efforts for NESHAP subpart HHH, there was no information gathered in
connection with the 1998 proposal or 1999 Final Rule. Thus, there is no
data available from that time period to perform a detailed MACT floor
analysis.
As noted in section III.B.4.e of this preamble, all natural gas
transmission major source facilities for which information was provided
in the 2023 ICR have electrical power provided by the grid or on-site
power generation. Further, the 2024 Phase II ICR data indicated that
approximately 95 percent of the pumps in the natural gas transmission
and storage category have zero emissions by using either electrical
pumps or pumps powered by compressed air rather than natural gas.
Based on information provided in response to the 2023 ICR
questionnaire, all natural gas transmission major source facilities
have electrical power provided by the grid or on-site power generation.
In the 1999 Final NESHAP, it was also determined that many natural gas
transmission and storage facilities had electrical service in 1999.
While we believe that the percentage of zero emission pumps at major
source natural gas transmission and storage

[[Page 21696]]

facilities in 1999 may have been less than 95 percent, we expect that
at least 12 percent of the pumps would have been either electrical
pumps or pumps driven by compressed air and have zero emissions, as it
has been common since at least the 1990s in the oil and gas industry to
use natural gas-powered pumps where electricity is not available and to
use electrical pump or pumps driven by compressed air where electricity
is available. As these pumps have zero emissions, there is no
technology or practice that could achieve a higher emissions reduction
rate.
Based on this information, the EPA concludes zero emissions for
pumps at major source natural gas transmission and storage facilities,
represents the emissions level achieved by the best performing similar
source, as well as the emissions level achieved by the top performing
12 percent of sources. Therefore, the EPA established a MACT floor
under CAA section 112(d)(3) that requires zero emissions for both new
and existing pumps at major source natural gas transmission and storage
facilities. We are specifically soliciting comment on this
determination, along with information to support or refute these
assumptions about the use of zero emissions pumps at natural gas
transmission and storage facilities in 1999. (Question #11a)
ii. CAA 112(d)(2) Beyond-the-Floor/Section 112(d)(6) Technology Review
As discussed above, the MACT floor was determined to be the use of
zero-emission pumps at major source natural gas transmission and
storage facilities. As this standard would eliminate all HAP emissions
from pumps, there are no developments in practices, processes, and
control technologies that would achieve greater emission reductions
from the MACT level.
iii. Proposed Standards for Pumps at Major Source Natural Gas
Transmission and Storage Facilities
Based on the above MACT floor analysis under CAA section 112(d)(3)
and the beyond-the-floor/technology review under CAA sections
112(d)(2)/112(d)(6), we are proposing that all pumps at new and
existing major source natural gas transmission and storage facilities
have zero emissions.
5. Proposed Changes to Small Dehydrator Emission Limit Equations
Dehydrators are used in the oil and gas industry to remove water
from natural gas to meet pipeline quality standards. The most common
approach to remove water from production streams is to use a liquid
desiccant like triethylene glycol (TEG). During the dehydration
process, the liquid desiccant primarily absorbs water, but it can also
inadvertently separate methane, VOCs, and other HAP out of the gaseous
stream. Once the liquid desiccant is saturated with gases, it can be
regenerated through a heat treatment in a reboiler. At this stage, the
absorbed water, methane, VOCs, and other HAP stored in the liquid
desiccant degas and are vented to the atmosphere. At some sites, the
liquid desiccant is recirculated with a natural-gas-assisted pump where
even more natural gas components are absorbed into the liquid desiccant
thereby leading to higher emissions during the degassing process. While
the total HAP emissions from dehydrators may vary by operational,
compositional, and system variables, it is largely understood that HAP
emissions will scale with the concentration of HAP in the inlet stream
to the dehydrator.
The HAP emissions from dehydrators at major sources are regulated
in both NESHAP subpart HH and NESHAP subpart HHH. For both regulations,
dehydrators are separated into two subcategories: Large Dehydrators and
Small Dehydrators. In NESHAP subpart HH, the following definitions
apply.
Small glycol dehydration unit is defined as a glycol dehydration
unit, located at a major source, with an actual annual average natural
gas flowrate less than 85 thousand standard cubic meters per day or
actual annual average benzene emissions of less than 0.90 Mg/
yr.87 88
---------------------------------------------------------------------------

\87\ Determined using NESHAP subpart HH, 40 CFR 63.772(b).
\88\ 40 CFR 63.761
---------------------------------------------------------------------------

Large glycol dehydration unit is defined as a glycol dehydration
unit with an actual annual average natural gas flowrate equal to or
greater than 85 thousand standard cubic meters per day and actual
annual average benzene emissions equal to or greater than 0.90 Mg/
yr.\89\ A glycol dehydration unit complying with the 0.9 Mg/yr control
option under 40 CFR 63.765(b)(1)(ii) is considered to be a large
dehydrator.
---------------------------------------------------------------------------

\89\ Determined using NESHAP subpart HH, 40 CFR 63.772(b).
---------------------------------------------------------------------------

The definitions in NESHAP subpart HHH are similar to the
definitions in subpart HH, except the flowrate criteria are different.
Small glycol dehydration unit means a glycol dehydration unit,
located at a major source, with an actual annual average natural gas
flowrate less than 283.0 thousand standard cubic meters per day or
actual annual average benzene emissions less than 0.90 Mg/yr.\90\ Large
glycol dehydration unit means a glycol dehydration unit with an actual
annual average natural gas flowrate equal to or greater than 283.0
thousand standard cubic meters per day and actual annual average
benzene emissions equal to or greater than 0.90 Mg/yr.\91\ A glycol
dehydration unit complying with the 0.9 Mg/yr control option under 40
CFR 63.1275(b)(1)(ii) is considered to be a large dehydrator.
---------------------------------------------------------------------------

\90\ Determined using NESHAP subpart HHH, 40 CFR 63.1282(a).
\91\ Determined using NESHAP subpart HHH, 40 CFR 63.1282(a).
---------------------------------------------------------------------------

The EPA is not proposing any changes to the large dehydrator
provisions in either NESHAP subpart HH or NESHAP subpart HHH. However,
revisions are being proposed to the small dehydrator requirements in
both NESHAP subparts.
For small dehydrators both NESHAP subpart HH and NESHAP subpart HHH
include equations that calculate dehydrator-specific limits for the
combined emissions of BTEX. The equations in NESHAP subpart HH are as
follows.
For existing sources:

Equation 1
[GRAPHIC] [TIFF OMITTED] TP22AP26.010

Where:

EL<INF>BTEX</INF> = Unit-specific BTEX emission limit, megagrams per
year;
3.28 x 10-4 = BTEX emission limit, grams BTEX/standard
cubic meter-ppmv;
Throughput = Annual average daily natural gas throughput, standard
cubic meters per day; and

[[Page 21697]]

C<INF>i,BTEX</INF> = Annual average BTEX concentration of the
natural gas at the inlet to the glycol dehydration unit, ppmv.

For new sources:

Equation 2
[GRAPHIC] [TIFF OMITTED] TP22AP26.011

Where:

EL<INF>BTEX</INF> = Unit-specific BTEX emission limit, megagrams per
year;
4.66 x 10-6 = BTEX emission limit, grams BTEX/standard
cubic meter-ppmv;
Throughput = Annual average daily natural gas throughput, standard
cubic meters per day; and
C<INF>i,BTEX</INF> = Annual average BTEX concentration of the
natural gas at the inlet to the glycol dehydration unit, ppmv.

Similar equations are in NESHAP subpart HHH, as follows.
For existing sources:

Equation 1
[GRAPHIC] [TIFF OMITTED

[…truncated; see source link]

View on FederalRegister.gov →Plain-text source

Indexed from Federal Register on April 22, 2026.

This is legal information, not legal advice. Laws vary by jurisdiction and change frequently. Always verify current law with official sources and consult a licensed attorney in your jurisdiction for advice on your specific situation.