Final Report
of the
Small Business Advocacy Review Panel on
EPA's Planned Proposed Rule
Emission Standards for New, Reconstructed, and
Modified Sources in the Oil and Natural Gas Sector
September 2021
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Table of Contents
1 INTRODUCTION 3
2 BACKGROUND AND DESCRIPTION OF RULEMAKING 4
2.1 Regulatory History 4
2.2 Description of Rulemaking and its Scope 6
2.3 Overview of Revisions under Consideration 7
2.4 Related Federal Rules 7
3 APPLICABLE SMALL ENTITY DEFINITIONS 8
4 LIST OF SMALL ENTITY REPRESENTATIVES 11
5 SUMMARY OF SMALL ENTITY OUTREACH 12
5.1 PRE-PANEL OUTREACH MEETING 12
5.2 Panel outreach meetings 13
6 SUMMARY OF PRE-PANEL COMMENTS FROM POTENTIAL SMALL ENTITY REPRESENTATIVES 13
6.1 Number and Types of Entities Affected 13
6.2 Potential Reporting, Recordkeeping, and Compliance Requirements 14
6.3 Fugitive Emissions Requirements 15
6.4 Well Completion Requirements 19
6.5 Storage Vessel Requirements 19
6.6 Costs and Impacts Analysis 20
6.7 Need for Regulation 21
6.8 Other Comments 21
7 SUMMARY OF PANEL COMMENTS FROM SMALL ENTITY REPRESENTATIVES 22
7.1 Rulemaking Scope 22
7.2 Potential Reporting, Recordkeeping, and Compliance Requirements 23
7.3 Fugitive Emissions Requirements 24
7.4 Storage Vessel Requirements 27
7.5 Compressor Requirements 28
7.6 Pneumatic Controller Requirements 29
7.7 Liquids Unloading Requirements 29
7.8 Costs and Impacts Analysis 30
7.9 Other Comments 30
8 PANEL FINDINGS AND DISCUSSIONS 30
8.1 Number and Types of Entities Affected 30
8.2 Potential Reporting, Recordkeeping, and Compliance Requirements 31
8.3 Related Federal Rules 32
8.4 Regulatory Flexibility Alternatives 32
APPENDIX A: LIST OF MATERIALS EPA SHARED WITH SMALL ENTITY REPRESENTATIVES 39
APPENDIX B: WRITTEN COMMENTS SUBMITTED BY SMALL ENTITY REPRESENTATIVES 40
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1 INTRODUCTION
This report document is the findings of the Small Business Advocacy Review Panel (SBAR
Panel or Panel) convened to review the planned proposed rulemaking on the Emission Standards
for New, Reconstructed, and Modified Sources in the Oil and Natural Gas Sector. Under section
609(b) of the Regulatory Flexibility Act (RFA) as amended by the Small Business Regulatory
Enforcement Fairness Act of 1996 (SBREFA), a Panel is required to be convened prior to
publication of the initial regulatory flexibility analysis (IRFA) that an agency may be required to
prepare under the RFA. In addition to EPA's Small Business Advocacy Chairperson, the Panel
members are the Director of the Sector Policies & Programs Division within the EPA's Office of
Air and Radiation, the Acting Administrator of the Office of Information and Regulatory Affairs
within the Office of Management and Budget, and the Acting Chief Counsel for Advocacy of the
Small Business Administration.
Section 609(b) of the RFA directs the Panel to consult with and report on the comments of small
entity representatives (SERs) and make findings on issues related to elements of an IRFA under
section 603 of the RFA. Those elements of an IRFA are:
• A description of, and where feasible, an estimate of the number of small entities to which
the proposed rule will apply;
• A description of projected reporting, record keeping, and other compliance requirements
of the proposed rule, including an estimate of the classes of small entities which will be
subject to the requirement and the type of professional skills necessary for preparation of
the report or record;
• An identification, to the extent practicable, of all relevant Federal rules which may
duplicate, overlap, or conflict with the proposed rule; a description of any significant
alternatives to the proposed rule which accomplish the stated objectives of applicable
statutes and which minimize any significant economic impact of the proposed rule on
small entities. This analysis shall discuss any significant alternatives such as:
o the establishment of differing compliance or reporting requirements or timetables
that take into account the resources available to small entities;
o the clarification, consolidation, or simplification of compliance and reporting
requirements under the rule for such small entities;
o the use of performance rather than design standards; and
o an exemption from coverage of the rule, or any part thereof, for such small
entities.
In addition to the elements above, this report includes the following:
• Background information on the proposed rule being developed;
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• Information on the types of small entities that may be subject to the proposed rule;
• A description of efforts made to obtain the advice and recommendations of
representatives of those small entities; and
• A summary of the comments that have been received to date from those representatives.
Once completed, the Panel Report is provided to the agency issuing the proposed rule and is
included in the rulemaking record. The agency is to consider the Panel's findings when
completing the draft of the proposed rule. In light of the Panel Report, and where appropriate, the
agency is also to consider whether changes are needed to the IRFA for the proposed rule or the
decision on whether an IRFA is required.
The Panel's findings and discussion will be based on the information available at the time the
final Panel Report is drafted. EPA will continue to conduct analyses relevant to the proposed
rule, and additional information may be developed or obtained during the remainder of the rule
development process.
Any options identified by the Panel for reducing the rule's regulatory impact on small entities
may require further analysis and/or data collection to ensure that the options are practicable,
enforceable, environmentally sound, and consistent with the Clean Air Act and its amendments.
2 BACKGROUND AND DESCRIPTION OF RULEMAKING
2.1 Regulatory History
In 2012, the EPA published the final rule, "Standards of Performance for Crude Oil and Natural
Gas Production, Transmission and Distribution," 77 FR 49490 (40 CFR part 60, subpart OOOO)
("2012 NSPS OOOO"). This rule established VOC standards for several oil and natural gas-
related operations emission sources, including natural gas well completions, centrifugal and
reciprocating compressors, natural gas operated pneumatic controllers, and storage vessels. EPA
amended 2012 NSPS OOOO in 2013, 2014, and 2015.
In 2016, the EPA published a final rule, "Oil and Natural Gas Sector: Emission Standards for
New, Reconstructed, and Modified Sources; Final Rule," 81 FR 35824 (40 CFR part 60, subpart
OOOOa) ("2016 NSPS OOOOa"). The 2016 NSPS OOOOa rule established NSPS for sources
of GHG (in the form of limitations on methane emissions) and VOC emissions for certain
equipment, processes, and operations across the oil and natural gas industry. The 2016 NSPS
OOOOa addresses the following emission sources:
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• Sources that were unregulated under the 2012 NSPS OOOO (hydraulically fractured oil
well completions, pneumatic pumps, and fugitive emissions from well sites and
compressor stations);
• Sources that were regulated under the 2012 NSPS 0000 for VOC emissions, but not for
GHG emissions (hydraulically fractured gas well completions and equipment leaks at
natural gas processing plants); and
• Certain equipment that is used across the source category, for which the 2012 NSPS
0000 regulates emissions of VOC from only a subset of the equipment (pneumatic
controllers, centrifugal compressors, and reciprocating compressors, with the exception
of compressors located at well sites).
In 2018, the EPA finalized amendments of certain aspects of the 2016 NSPS 0000a
requirements for the collection of fugitive emission components at well sites and compressor
stations, specifically (1) the requirement that components on a delay of repair must conduct
repairs during unscheduled or emergency vent blowdowns, and (2) the monitoring survey
requirements for well sites located on the Alaska North Slope.
In 2020, the EPA published two final rules to amend the New Source Performance Standards.
Published on September 14, 2020, the first of the two rules is titled, "Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources Review." Commonly
referred to as the 2020 Policy Rule or Methane Recission Rule, it removed the transmission and
storage segment from regulation on the basis that this segment is not "sufficiently related" to
production and processing, and therefore cannot be part of the same source category. The 2020
Policy Rule also rescinded methane requirements for the industry's production and processing
segment on the basis that such standards are redundant to VOC standards for this segment.
Lastly, the rule interpreted CAA 111(b) to require, or at least authorize the Administrator to
require, a pollutant-specific "significant contribution finding" as a prerequisite to regulating a
new pollutant, that is supported by criteria or a threshold for determining "significance;"
rescinded methane requirements for the industry's production and processing segment on the
separate basis that EPA had failed to make that finding.
Published on September 15, 2020, the second of the two rules is titled, "Oil and Natural Gas
Sector: Emission Standards for New, Reconstructed, and Modified Sources Reconsideration."
Commonly referred to as the 2020 Technical Rule and finalized exempting low-production well
sites from fugitives monitoring (previously required semiannually), required semiannual
monitoring at gathering and boosting compressor stations (previously quarterly), streamlined
recordkeeping and reporting requirements, allowed compliance with equivalent state
requirements as an alternative to NSPS fugitive requirements, streamlined application to use new
technologies to monitor for fugitive emissions, addressed storage tank batteries for applicability
determination purposes and finalized several technical corrections. The 2020 Policy Rule
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amended 40 CFR part 60, subparts OOOO and OOOOa, as finalized in 2016. The Technical
Rule amended the 40 CFR part 60, subpart OOOOa, as amended by the Policy Rule.
On June 30, 2021, President Biden signed into law a joint resolution of Congress, adopted under
the Congressional Review Act (CRA), disapproving the 2020 Policy Rule. The CRA resolution
has the effect of reinstating the VOC and methane standards for the transmission and storage
segment, as well as the methane standards for the production and processing segments. The CRA
resolution did not address the 2020 Technical Rule; therefore, those amendments remain in
effect.
jscrlpi 11 making and Its Scope
On January 20, 2021, President Biden issued Executive Order (EO) 13990, "Protecting Public
Health and the Environment and Restoring Science to Tackle the Climate Crisis." EO 13990
describes the Administration's policy "to improve public health and protect our environment; to
ensure access to clean air and water; to limit exposure to dangerous chemicals and pesticides; to
hold polluters accountable, including those who disproportionately harm communities of color
and low-income communities; to reduce greenhouse gas emissions; to bolster resilience to the
impacts of climate change; to restore and expand our national treasures and monuments; and to
prioritize both environmental justice and the creation of the well-paying union jobs necessary to
deliver on these goals."
EO 13990 directs the EPA to consider proposing a rulemaking to reduce methane emissions in
the Oil and Natural Gas source category by suspending, revising, or rescinding previously issued
new source performance standards. It also instructs the EPA to consider proposing new
regulations to establish comprehensive standards of performance and emission guidelines for
methane and VOC emissions from existing operations in the oil and natural gas sector, including
the exploration and production, processing, transmission, and storage segments.
In response to EO 13990, the EPA is proposing an NSPS to include new or amended standards
for GHG and VOC emissions for certain new, modified, and reconstructed equipment, processes,
and activities across the oil and natural gas source category. The proposed NSPS OOOOb would
apply to sources which are new, reconstructed, and modified following the date of publication of
the proposed rule.
As part of this rulemaking, EPA will also discuss the impact of the CRA resolution of
disapproval of the 2020 Policy Rule, as well as identify and propose appropriate changes to
NSPS OOOOa to resolve any discrepancies in the regulatory text between the 2016 NSPS and
2020 Technical Rule. These revisions are specific to the discrepancies in NSPS OOOOa created
by the CRA resolution
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2.3 Overview of Revisions tinier Consideration
Through Agency review and stakeholder input, a broad range of program improvements have
been suggested. From these EPA identified those which could only be addressed through
regulation change, and further limited to those which would provide the most protective impact.
The following is a listing of regulatory revisions for NSPS OOOOb currently being considered
and evaluated by EPA and is not final at this time.
• Work practice standards for monitoring and repair of fugitive emissions from well sites,
compressor stations, and natural gas processing plants;
• Emission standards for centrifugal compressors;
• Work practices for reciprocating compressors;
• Emission standards for pneumatic controllers;
• Emission standards for pneumatic pumps;
• Emission standards for storage vessels;
• Work practices for completions of hydraulically fractured oil and gas wells; and
• Work practices for liquids unloading operations.
2.4 Related Federal Rules
There are two National Emission Standards for Hazardous Air Pollutants (NESHAP) rules that
apply to certain equipment and processes in the oil and natural gas sector. These rules, listed
below, address air toxics, primarily benzene, toluene, ethylbenzene, and xylenes (collectively
referred to as BTEX) and n-hexane. These two rules were promulgated under section 112 of the
Clean Air Act and are codified in 40 CFR Part 63 Subpart HH and Subpart HHH.
Aside from the EPA, several other Federal agencies have jurisdiction over the oil and natural gas
sector.
• The Bureau of Land Management (BLM) within the Department of the Interior regulates
the extraction of oil and gas from federal lands. BLM manages the Federal government's
onshore subsurface mineral estate, about 700 million acres. BLM also oversees oil and
gas operations on many Tribal leases and maintains an oil and gas leasing program. BLM
does not directly regulate emissions for the purposes of air quality, but does regulate
venting and flaring of natural gas for the purposes of preventing waste. An operator may
also be required to control/mitigate emissions as a condition of approval on a drilling
permit.
• The Bureau of Ocean Energy Management (BOEM) within the Department of the
Interior manages the development of America's offshore energy and mineral resources.
BOEM has air quality jurisdiction in the Gulf of Mexico and the North Slope Borough of
Alaska and in federal waters on the Outer Continental Shelf 3-9 miles offshore.
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• The Pipeline and Hazardous Materials Safety Administration (PHMSA) within the
Department of Transportation ensures safety in the design, construction, operation,
maintenance, and spill response planning of America's 2.8 million miles of natural gas
and hazardous liquid transportation pipelines. This includes data and risk analysis,
outreach, research and development, regulations and standards, training, inspections and
enforcement and accident investigations. Section 113 of the Protecting our Infrastructure
of Pipelines and Enhancing Safety Act of 2020 (PIPES Act of 2020) mandates that
PHMSA promulgate a final rule concerning gas pipeline leak detection and repair
programs no later than one year after the enactment of the law.
• The Federal Energy Regulatory Commission (FERC) within the Department of Energy
regulates natural gas pipeline, storage, and liquefied natural gas facility construction.
FERC also issues environmental assessments or draft and final environmental impact
statement for comment on most projects.
• The Internal Revenue Service (IRS), in the Internal Revenue Code (IRC), defines a
stripper well property as "a property where the average daily production of domestic
crude oil and gas produced from the wells on the property during a calendar year divided
by the number of such wells is 15 barrel equivalents or less". See IRC 613A(c)(6)(E).
3 Am uwm r smai I ek n rv nraxiTiONS
The Regulatory Flexibility Act (RFA) defines small entities as including "small businesses,"
"small governments," and "small organizations" (5 USC 601). The regulatory revisions being
considered by EPA for this rulemaking are expected to affect a variety of small businesses, but
would not affect any small governments or small organizations. The RFA references the
definition of "small business" found in the Small Business Act, which authorizes the Small
Business Administration to further define "small business" by regulation. The SBA definitions of
small business by size standards using the North American Industry Classification System
(NAICS) can be found at 13 CFR 121.201.
The detailed listing of SBA definitions of small business for affected industries or sectors, by
NAICS code, is included in Table 1, below. To estimate the number of small entities potentially
impacted by the rule, EPA developed a list of operators of oil and natural gas wells and natural
gas processing plants based on data from Enverus (wells) and the U.S. Energy Information
Administration (processing plants); data on operators of compressor stations was not available at
the time of the analysis. The list of well operators consists of all operators of wells completed in
2019, which serves as an approximation of the universe of operators that might be affected in
future years by updates to the NSPS. The list of processing plant operators consists of all
operators of natural gas processing plants in the EIA dataset for 2017 (the most recent year
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available).1 The dataset does not have information on construction dates of plants, so a
representative subset of operators of recently constructed plants could not be created as it was for
wells. In total, the operator dataset consists of 1,947 unique operator names.2
Using an approximate string matching algorithm, EPA merged the list of operators with business
information from D&B Hoovers to obtain information on NAICS codes (both own and ultimate
parent), number of employees, and annual revenues. The algorithm matched 1,267 (65%) of the
operators to NAICS codes with a valid SBA size classification threshold. Each matched operator
was coded as small business (1,096 operators), not small business (162), or unknown (9) by
comparing the estimated employee counts and annual revenues from Hoovers with the SBA size
classification thresholds; unknown entities were missing the applicable employee count or
annual revenue estimates. The results of the small business coding exercise are displayed by
NAICS code in Table 1.
1 https://www.eia.gov/naturalgas/ngqs/#?report=RP9&yearl=2017&year2=2017&company=Name
2 This does not necessarily mean that it represents 1,947 unique operators, however, as duplicates were only
removed for exact string matches. For example, Oil and Gas LLC and Oil & Gas LLC would be represented as two
unique entities.
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Table 1: Industry Sectors, Definitions & Estimated Percentage of Small Entities
Potentially Affected by EPA's Planned Action
Name of
Industry/Sector
'
2017
NAICS
Code
SK\ Size
Standard for
Small Business
Number of
Firms
Identified
Estimated
N umber of Small
Kntities
Estimated Percentage of
Small Kntities for
Identified Firms
Crude Petroleum
211120
1,250 employees
346
322
93%
Natural Gas Extraction
211130
1,250 employees
5
5
100%
Drilling Oil and Gas
Wells
213111
1,000 employees
60
58
97%
Support Activities for Oil
and Gas Operations
213112
$41.5 million in
receipts
373
326
87%
Pipeline Transportation
of Natural Gas
486210
$30.0 million in
receipts
33
11
33%
Other
Many
Varies
431
373
87%
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4 LIST OF SMALL ENTITY REPRESENTATIVES
EPA consulted with Advocacy to develop the list of small entity representatives (SERs) in Table
2. EPA issued a press release inviting self-nominations by affected small entities to serve as
potential SERs. The press release directed interested small entities to a web page where they
could indicate their interest in serving as a SER. EPA launched the website May 25, 2021 and
accepted self-nominations until June 4, 2021. In addition, EPA supplemented the self-
nominations by contacting the full list of SERs that participated in the 2015 SBAR Panel for this
sector and inviting them to participate in this Panel. We also reached out to small business
stakeholders during a training webinar on May 25, 2021 and invited them to participate in the
Panel. EPA sent Advocacy a Formal Notification with the suggested list of potential SERs on
July 2, 2021 and Advocacy responded on July 15, 2021. After the conclusion of EPA's Pre-Panel
Outreach meeting with potential SERs, and after clarification of the likely scope of EPA's
proposal, the Panel agreed that several small entities were not likely to be regulated and so were
not invited to consult with the Panel as SERs.
Table 2: List of Potential Small Entity Representatives
; Nil mi'
AfTilisil ion(s)
Arthur Stewart
Cameron Energy Company (PA)
Pennsylvania Grade Crude Oil Coalition (PGCC)
Douglas Jones
Catalyst Energy, Inc. (PA)
Charles E. Venditti
CountryMark Cooperative Holding Corp
Indiana Oil & Gas Association (IOGA)
Kentucky Oil & Gas Association (KOGA)
Rudy Vogt
Cumberland Valley Resources, LLC
J. Scott Huber
Fore Energy Partners, Inc (FEPI)
Michigan Oil & Gas Association (MOGA)
James D. Elliott
Gas and Oil Association of West Virginia (GO-WV)
Lee Fuller
Independent Petroleum Association of America (IPAA)
Howard R. Dieter and Chuck
Cornell
Jonah Energy, LLC
Edward Cross
Kansas Independent Oil & Gas Association (KIOGA)
Eric Johnson
Michigan Oil & Gas Association (MOGA)
Luke Miller
Miller Energy Company, LLC
Summit Petroleum Company, LLC
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Doug Mehan and Domenic
Tedesco
PennEnergy Resources, LLC
Angie Burckhalter
Petroleum Alliance of Oklahoma (PAO)
Jason Modglin
Texas Alliance of Energy Producers
Ed Longanecker
Texas Independent Producers and Royalty Owners
Association (TIPRO)
Dave Weinert
Wesco Operating, Inc
Tripp Parks
Western Energy Alliance (WEA)
5 SUMMARY OF SMALL ENTITY OUTREACH
EPA Office of Air Quality Planning and Standards (OAQPS) staff participates in monthly calls
with Small Business Environmental Assistance Program (SBEAP) representatives. In April
2021, OAQPS provided an update to SBEAP representatives on EO 13990 and its direction to
EPA to consider proposing a revised NSPS and standards for existing sources in the oil and
natural gas sector by September 2021. In May 2021, EPA provided three days of training
webinars for the public, with one of those days targeting small business stakeholders, to provide
an overview of the industry and share information to help stakeholders effectively engage in the
regulatory process. In June 2021, EPA held three days of public listening sessions where the
public had an opportunity to provide their views on the oil and natural gas industry and EPA's
upcoming proposed rule.
el outreach, meeting
EPA conducted a meeting/teleconference with potential SERs on June 29, 2021. To help SERs
prepare for the meeting/teleconference, on June 22, 2021, EPA sent materials to each of the
potential SERs via email. A list of the materials shared with the potential SERs during the pre-
Panel outreach meeting is contained in Appendix A. For the June 29, 2021 pre-Panel outreach
meeting with the potential SERs, EPA also invited representatives from the Office of Advocacy
of the Small Business Administration and the Office of Information and Regulatory Affairs
within the Office of Management and Budget. A total of 22 potential SERs participated in the
meeting. EPA presented an overview of the SBAR Panel process, an explanation of the planned
rulemaking, and technical background.
This outreach meeting was held to solicit feedback from the potential SERs on their suggestions
for the upcoming rulemaking. EPA asked the potential SERs to provide written comments by
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July 13, 2021. Comments raised during the June 29, 2021 outreach meeting and written
comments submitted by the potential SERS are summarized in section 6 of this document.
1 outreach, meetings
The Panel conducted an outreach meeting/teleconference with the SERs on July 29, 2021, with a
follow up on August 3, 2021. To help SERs prepare for these meetings, EPA sent materials to
each of the SERs via email. A list of the materials shared with the SERs during the Panel
outreach meeting is contained in Appendix A. A total of 14 SERs participated in the meeting.
These outreach meetings were held to solicit feedback from the SERs on their suggestions for the
upcoming rulemaking. EPA asked the SERs to provide written comments by August 12, 2021.
Comments raised during the July 29, 2021 and August 3, 2021 outreach meetings and written
comments submitted by the SERS are summarized in section 7 of this document.
8 SUMMARY OF PRP fWMEL COMMENTS FROM POTENTIAL
SMALL ENTF WES
At the conclusion of the Pre-Panel Outreach Meeting, potential SERs were asked to submit
written questions and comments to EPA. Nine entities submitted written materials to EPA. The
following subsections summarize these submissions.
6.1 Number and Types of Entitie cted
CountryMark, INOGA, and KOGA stated that the majority of wells in Indiana, Illinois, and
Kentucky are produced by small businesses. There are more than 58 small business oil and gas
operators represented by INOGA in Indiana and more than 98 small business oil and gas
operators represented by KOGA in Kentucky.
CountryMark, INOGA, and KOGA stated that CountryMark operates 363 tank facilities, with
less than 5 requiring combustion units. 24 are affected facilities under OOOOa.
Cumberland Valley Resources stated that from 2005 to 2010, they drilled approximately eight
new oil or gas wells per year. From 2011 to 2015, they drilled two or three oil wells per year.
They have not drilled a new oil well since 2015 and haven't drilled a new gas well since 2010. In
2018, they divested their oil producing properties, but continue to operate approximately 60 gas
wells.
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Cumberland Valley Resources estimated there are many thousands of small operators in the
Appalachian and Illinois Basins, over 1,000 in Kentucky.
KIOGA stated small businesses produce 92% of oil wells and 63% of gas wells in Kansas.
KIOGA stated that there are 750,000 low production wells in the United States, typically
operated by small businesses.
KIOGA estimates that 90 wells are drilled or modified each year by some operators.
PGCC and Cameron Energy Company stated that there are over 100,000 conventional oil and
gas wells in operation in Pennsylvania, almost all of which are low production wells. Most of
these wells were drilled over 15 years ago.
itentlal Reporting, Recordkeeping, and Compliance Requirements
6.2.1 Requirements
CountryMark, INOGA, and KOGA encouraged EPA to implement additional reductions to
recordkeeping and reporting requirements where data collected does not further support the
reduction in emissions.
KIOGA listed a number of existing reporting and recordkeeping requirements which they felt
were burdensome and added no value. These requirements included notification of hydraulic
fracturing, FLIR operator training, starting and ending time of monitoring surveys, maximum
wind speed, and survey deviations.
PAO stated EPA should maintain the recordkeeping and reporting provided in the 2020
Technical Rule. Where compliance with state programs is deemed equivalent, no further
recordkeeping or reporting should be required.
CountryMark, INOGA, and KOGA recommended one year compliance timeline for small
businesses.
6.2.2 Costs
Cumberland Valley Resources stated operators of low production wells cannot afford to hire
staff to fill out and keep the updated records that OOOOa requires.
KIOGA stated the OOOOa documentation burden grows as new wells and tank facilities are
added to the program each year. KIOGA questioned the need for some of the data that OOOOa
requires.
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KIOGA estimated the cost to develop a management and reporting system is $40,000 - $50,000,
with an ongoing annual cost of compliance of $20,000 - $100,000. KIOGA believes that one or
more full time positions may be required to meet all the annual reporting and data management
requirements, with annual salary and benefits of $50,000 - $60,000.
KIOGA estimated the burden of developing and maintaining a corporate-wide site specific
monitoring plan is 500 hours to solicit input, develop the written program, review with the
management team, and implement the program, with an associated cost of $30,000 - $50,000.
KIOGA estimates that storing digital photos and reports for 5 years will require the development
of a data management system, purchasing of additional data storage systems, and training of 600
- 800 hours, with an associated cost of $40,000 - $50,000.
6.2.3 Electronic Reporting
Cumberland Valley Resources stated the electronic reporting template is daunting to small
operators and very little of it is applicable to their operations.
PAO stated EPA should ensure the electronic reporting template does not call for additional
information that is not otherwise required, and that assistance with electronic reporting would be
beneficial to small businesses.
PAO stated EPA should consider the development of a fugitive emissions tracking software
program to aid small businesses with compliance. Currently available software is an additional
cost to small businesses.
6 igitive Emissions Requirements
6.3.1 Low production well sites
6.3.1.1 Applicability
Cumberland Valley Resources, CountryMark, INOGA, KOGA, PGCC and Cameron Energy
Company stated low production wells should continue to be exempt from OOOOa's fugitive
emissions requirements.
Cumberland Valley Resources stated low production wells should at least be considered a
separate subcategory to allow operators to use simple, common sense solutions to periodically
check for fugitive emissions in a manner that doesn't require additional personnel or equipment.
CountryMark, INOGA, and KOGA stated low production wells should be their own subcategory
in any future regulation because of their de-minimis emissions profile. Most low production
wells are operated by small businesses.
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PAO stated EPA should consider an offramp to reduce costs on small businesses. For example,
after two OGI surveys with no leaks, monitoring could decrease to annually or every 2 years.
EPA should also allow for exemptions or reduced inspections based on the API gravity of the
crude oil.
CountryMark, INOGA, and KOGA recommended retaining the low production well exemption,
updated to 12 month rolling average of production, rather than initial production.
6.3.1.2 Emissions Profile
KIOGA, Cumberland Valley Resources, CountryMark, INOGA, KOGA, PAO, and the Texas
Alliance of Energy Producers recommended a DOE study of emissions from low production
wells that should be completed in 2021. Preliminary results from the DOE third-party methane
emission study indicate no quantifiable or measurable emissions from wells or tank facilities.
EPA should use the emissions profile information developed in this study to design a low
production well program, and focus its program to address key sources.
PAO stated EPA must understand the emissions profile of low production wells to determine if
regulations are needed and to develop an appropriate regulatory program.
KIOGA stated that EPA does not have enough data to appropriately regulate low production
wells. KIOGA stated that EPA has relied on specious studies by environmentalists, outdated
studies that were never designed for regulation, and studies that assessed very few wells. KIOGA
stated that the studies EPA has relied upon were based on emissions data collected without an
understanding of the activities on the site. For example, without knowledge of whether the
emissions were fugitive emissions or rather a permitted release when a tank was being filled.
Sampling was generally ten minutes to an hour, but the studies extrapolated these values to daily
and annual rates. KIOGA further stated that these studies imply that most emissions from low
production well sites are from storage vessels, and managing storage vessel emissions does not
require a complex LDAR program.
Cumberland Valley Resources stated that gas gathering systems in Kentucky are constructed
using plastic pipeline less than 25 psi. Low production well wellheads include small numbers of
brass and steel fittings and valves threaded together (dozens of 2" components compared to
hundreds of larger components like used on high volume/high pressure wells). Threaded
connections in the low pressure piping, when doped and tightened properly, very seldom leak.
Any leaks at these connections can be detected using soap bubbles.
6.3.1.3 Requirements
Cumberland Valley Resources, CountryMark, INOGA, and KOGA stated requirements for low
production wells are not warranted or justified. Operators of these wells cannot bear the
additional cost of fugitive emissions monitoring, even at the annual frequency.
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Cumberland Valley Resources stated that once a well becomes a low production well, a less
expensive fugitive emissions program may extend the economic lifetime of a well.
KIOGA stated that the regulatory structure applied to low production wells is significant because
their viability depends on their cost of operation.
KIOGA and Cumberland Valley Resources stated the 2016 NSPS fugitive emissions program
was designed for large, high-production facilities and should not be applied to low production
well sites.
CountryMark, INOGA, and KOGA recommended annual OVA and soap bubble tests for leaks at
low production wells and associated tank facilities.
PAO stated EPA should allow alternative monitoring, for example functional testing of onsite
equipment or AVO.
KIOGA, CountryMark, INOGA, and KOGA asked EPA to change the requirements for all
facilities owned by small businesses to use OVA inspections or soap bubble tests to detect leaks.
Implementing this change will significantly reduce costs of compliance as well as documentation
and reporting costs for small business entities. They estimated that the inspection cost may be
reduced by as much as 50% by permitting OVA and soap bubble testing at tank facilities
associated with low production well sites. The cost savings will come through our trained
employees performing the inspections during already scheduled daily or weekly inspections of
the facilities. Independent contractors with expensive OGI equipment and certifications will not
need to be scheduled, paid for their travel time and time on location, managed as they are on our
work sites, and develop reports for our staff to review and address deficiencies. This compromise
in inspection technique will not result in a measurable increase in emissions because tank
emissions are already less than 6 tpy, indicating that the potential to emit is already low enough
to not be able to reliably support a combustion system.
6.3.2 Tank batteries
Cumberland Valley Resources, CountryMark, INOGA, and KOGA stated that tank batteries
under the 6 tpy threshold may fall into the fugitive emissions program. These tank batteries are
uncontrolled and a fugitive emissions program would be burdensome and have no environmental
benefit.
6.3.3 Leak Rate
CountryMark, INOGA, and KOGA stated that during CountryMark's 4 years of compliance with
OOOOa, they had the following leak rates:
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Year
tt of Leaks
Components Inspected
Failure Rate
2020
6
4,815
0.1%
2019
14
3,7m
0.4%
mm
9
2,325
0.3%
201?
9
1,195
0.8%
CountryMark, INOGA, and KOGA stated that leaks are generally challenging to detect with OGI
because of low production rates, low wellhead pressure, and low Gas to Oil ratio in the Illinois
Basin.
KIOGA stated that leak rates are between 1.1 - 1.65%, far lower than the EDF study's 2.3-60%.
KIOGA stated that the EDF had questionable methodology and poor data quality. The EDF
study relied on remote sensing of emissions and not the bottom-up onsite measurements
recommended by the National Academy of Sciences, meaning the study could not differentiate
between fugitive losses and permitted emissions.
6.3.4 Costs
CountryMark, INOGA, and KOGA estimated the annual cost to complete OGI monitoring of
well sites and tank batteries is $75,000. This cost includes amortizing an OGI camera, training an
employee and vehicle cost, insurance cost, and documentation and reporting costs.
MOGA stated the first year cost estimates would likely range from $4,000 - $10,000 for initial
implementation. Many small businesses in Michigan would likely need to hire a third-party
consultant to oversee implementation of these regulations. This cost estimate is based on the
need to gather, transfer, and educate personnel to facilitate the necessary in-depth understanding
of each of the 22 well sites in EPA's model plant. The variability of these costs can be allocated
to specific training, equipment and software purchases and functional knowledge and ability to
correctly implement proposed regulation requirements.
MOGA estimates the annual cost per well site to be between $3,000 and $6,000 because of the
need to hire third-party consultants, rather than in-house staff. In addition, the EPA did not
consider initial surveys for a single well that was new, modified, or reconstructed outside of
normally scheduled monitoring efforts. Single well monitoring using LDAR can range from
$2,500 to $3,500. The EPA further assumed fixed production and a constant number of wells,
when in reality, the number of producing wells can vary due to seasonal restrictions, formation
dynamics, operational agenda, oil and gas prices, and contracts.
MOGA estimates the annual repair cost for a single repair, including parts, for a small leak of
less than 1 scf/day would be between $500 - $1,500. In many cases, the repairs are conducted by
third party contractors.
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MOGA recommends that EPA provide cost considerations for both in-house and third-party
contractors.
6.3.5 Emerging Technology
PAO stated that the EPA should ensure that there is an avenue to allow for new and emerging
control and monitoring technologies. For example, multiple well inspections could be done each
day using drone / fixed wing technologies versus traditional OGI. These technologies must be
cost effective, reliable, easy to install and maintain.
6.4 Well Completion Requirements
6.4.1 Costs
KIOGA stated that certified combustion devices that will meet gas flow rate requirements and
gas quality will cost $12,000 - $22,000 to purchase and another $8,000 to install. A conventional
oil well may cost $300,000 - $600,000 to drill and complete. Installation of a combustion system
could be 5-10% to the total cost of the project. This does not include the cost to purchase and
install a separator, install piping, complete the required surveys, and recordkeeping and reporting
costs. These additional costs of compliance will eliminate projects from being implemented.
6.4.2 Definitions
KIOGA, CountryMark, INOGA, and KOGA recommended amending the definition of hydraulic
fracturing to explicitly exclude conventional wells. KIOGA believes that many wells in Kansas
don't meet this definition because their processes don't penetrate tight formations or require high
rate, extended flowback.
6.5 Storage Vessel Requirements
6.5.1 Requirements
MOGA provided an example of a small business in Michigan who had to purchase and install a
propane tank to keep the pilot light burning on its control device for storage vessel emissions due
to significant production decline from the well. This and other OOOOa compliance costs led the
producer to plug the well even though the well would likely produce at a marginal status for
many more years.
PAO stated many sites may not have electricity needed to power compressors for tank vapor
recovery, and low production wells may not produce enough gas to power the unit.
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PAO stated OOOOa control requirements for all tanks may result in higher emissions because of
the combustion processes as compared to allowing uncontrolled tank emissions.
6.5.2 Maximum Daily Throughput
PAO stated the method for calculating maximum daily throughput is unnecessarily burdensome,
especially for low production wells and facilities connected to pipelines with a mix of trucked
and pipeline shipped liquids. Compliance requires tank-specific metering or intensive daily
operating recordkeeping since tank gauging alone does not account for liquids sent through a
lease automatic custody transfer unit.
6.6 Costs and Impact Is
KIOGA stated that EPA often underestimates the cost of compliance and overestimates the
benefits provided by regulations.
KIOGA stated that small oil and gas compliances in Kansas have experienced the following
costs of compliance with OOOOa:
} Activity
I
Cost | frequency
1 VOC inspection of tank facility
$500 - $2,000
2* per yrar per facBtty/wtK
1
Documentation and record totpi*
$10,(WO • $100,000
Awnuafly
Green Completion (only for non-delineation w«tl&}
$10,000-$15,000
Every new exploration weft
Install sample fittings {fiats and labor) far gas samples
$500-51,000
fwerynewrxHity
laboratory analysis
$soi - $i,ooo
Cveiy new facility
Engineering evaluation of tab data analysis
$250 • $500
Every new facility
P£ Certification of combustion system
$2,500 ¦ $3,000
i'VWf WW filCtlitf
Installation of combustion system
$20,000-$40,000
Every new facility
Monthly inspection of combustion system
$250-5500
Monthly
MonlMy inspection after fernowl of combustion system
$2,500 - 4,000
K
Design of combustion system
$10,000-$15,000
One time coil
Develop record keeping system
$40.000-$50,000
One time cost
Develop site specific moratonng plans
$30,000 - $50,000
One time cost
Purchase f UR camera
$95,000 - $100,000
One tum- cosi
I FUR camera training
$3,000 - 55,000
One time coil
1 Put chase sample collection equipment
S2JW0. $5,000
One time cost
Table 2. Compliance Activities and Costs Required by NSPS OOOOa
Texas Alliance of Energy Producers stated that their actual costs may be higher than EPA's
estimates because the internal operations to adapt and conduct new regulatory requirements has
been limited due to the contraction of the industry in 2020.
MOGA and FEPI stated the overall cost of regulation may cause producers to plug and abandon
marginal wells in Michigan before the end of their lifetime because they are no longer
20
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economically productive. PGCC and Cameron Energy Company stated drilling conventional
wells in Pennsylvania is no longer economical.
The Petroleum Alliance of Oklahoma stated EPA should provide details on how the social cost
of greenhouse gas analysis will impact small businesses.
6,7 Neei for Regulat
6.7.1 Scope of methane emissions
KIOGA stated that Oil and Natural Gas systems account for about 1.2% of the US Green House
Gases Inventory (GHGI). Low production wells account for about 10-11% of U.S. production.
Their emissions would be in the 0.10-0.20% range of the GHGI.
6.7.2 Voluntary programs
KIOGA stated that a number of natural gas producers have voluntarily replaced, fixed, or
removed 31,000 high-bleed pneumatic controllers on their equipment.
;lier Comments
CountryMark, INOGA, and KOGA stated that OOOOa requires propane to maintain a pilot light
for combustion systems, and for low production well sites, more propane is consumed than gas is
burned at the flare. They recommended that for low production wells, the operator should
determine if propane is required to support flare systems based on safety requirements, rather
than one size fits all regulations. CountryMark, INOGA, and KOGA also stated that this
requirement has contributed to propane shortages through the United States.
PAO encouraged EPA to allow in-house engineers certify closed vent system design. These
calculations may be completed in-house with the same simulation software that a consulting firm
with a Professional Engineer would use.
The American Public Gas Association, City Of Las Cruces Utilities/Gas, Middle Tennessee
Natural Gas Utility District, Pensacola Energy, and Unitil Corporation stated that if EPA is not
considering any changes to the 2016 final rule exemption of natural gas utility intra-state
distribution, transmission pipeline, storage or LNG peak shaving operations inside and including
the local distribution utility custody transfer station, then our gas utility operations would not be
affected. If EPA is not considering changing the 2016 final rule's requirements for interstate
natural gas transmission pipelines, then Unitil's interstate natural gas transmission pipeline
operations would not be affected. However, if EPA does plan to consider any such changes, then
we will need an opportunity to provide information about how those proposals could impact our
small entity operations.
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7 \n TORMENTS FROM SMALL ENTITY
REPRESENTATIVES
At the conclusion of the Panel Outreach Meeting, SERs were asked to submit written questions
and comments to EPA. Nine entities submitted written materials to EPA. The following
subsections summarize these submissions.
llemaking Scope
Many SERs stated that conventional vertical wells should be exempt from NSPS OOOOa, even
if they have been hydraulically fractured.
Catalyst Energy stated that conventional wells in Pennsylvania and much of the Appalachian
Basin have largely been hydraulically fractured since the 1960s. A conventional oil well will
have a small footprint during drilling and hydraulically fracturing operations - typically 5,000
square feet, while an unconventional horizontal well will have a footprint over 20,000 square
feet. An unconventional well undergoing hydraulic fracturing will pump millions of gallons of
water and chemicals, while a conventional hydraulic fracturing operation will use 100,000 to
200,000 gallons of water with little to no chemicals, with much of the water being recycled.
Hydraulic fracturing at conventional wells has little flowback with nearly no natural gas released.
TIPRO, IPAA, and GO-WV stated that EPA's definition is not appropriate because both
conventional and unconventional wells engage in hydraulic fracturing. Conventional wells do not
penetrate and produce from tight formations, such as shale or coal formations, and do not require
high rate, extended flowback. Most conventional wells, being shorter, and having a shorter
profile in producing strata, produce methane at lower rates than horizontal, nonconventional
wells.
TIPRO, IPAA, and GO-WV stated that hydraulic fracturing of conventional wells involves
thousands of gallons of water, compared to millions of gallons used for unconventional wells,
and flowback is in hours, versus weeks or months. The permeability of the rock formations
where conventional wells are drilled is statistically different compared to unconventional wells.
PAO stated that conventional wells are typically vertical, and the completion of a vertical well is
much less involved than a horizontal well. Completion lasts less than a day, compared to many
days or weeks for a horizontal well. The clean-up and drill out is also much less involved, both
for completions and recompletions. Completing a vertical well generates less emissions
compared to horizontal wells.
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PGCC and Cameron Energy stated that a conventional wells should be treated differently than
unconventional wells. A conventional well has a 35 times smaller footprint than an
unconventional well. Wellhead pressures of conventional wells are only several hundred pounds
versus thousands of pounds. The substantially greater pressures and items of infrastructure
associated with unconventional wells means they have a greater potential for fugitive emissions.
Conventional wells also have a much lower equipment and fugitive component count than
unconventional wells. The typical conventional oil well site would not normally include glycol
dehydrators, amine gas sweetening units, line heater, heater treaters, reboilers, gas compressors,
pneumatic controllers, pneumatic pumps, or pipeline blowdowns.
PGCC and Cameron Energy stated that EPA could distinguish between large and small
hydrofractures based on fluid volume, pumping pressures, shut-in pressures, permeability of
fractured formations, and flowback rates and times.
Cumberland Valley Resources, LLC stated that they operate conventional, low volume, low
pressure wells, that have a different profile than unconventional wells based on scale, water
usage, and pressure, regardless of fracking status. No separator is needed during flowback for
these wells. Only after the majority of the frack fluid is removed will any significant amount of
gas or oil be present.
itentlal Reporting, Recordkeeping, and Compliance Requirements
WEA, TIPRO, IPAA, and GO-WV stated the streamlining of recordkeeping and reporting
requirements in the 2020 Technical Rule was successful and EPA should not abandon these
changes in a new rule.
TIPRO, IPAA, and GO-WV stated that if EPA deems a state program equivalent to OOOOa, no
additional recordkeeping or reporting beyond the state's requirements should be required.
MOGA and FEPI stated EPA should remove annual reporting requirements, and require small
businesses to retain records for 5 years, removing the exorbitant cost of annual reporting that
may never be reviewed.
CountryMark, INOGA, and KOGA requested that small entities have longer than 60 days to
comply with the regulation.
CountryMark, INOGA, and KOGA recommended removing well completion reporting
requirements. They recommend EPA only collect data to inform decision making, rather than
compliance assurance.
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Cumberland Valley Resources, LLC stated EPA needs to identify and adopt simplified and
cheaper methods of emissions reductions. Current compliance costs impact the economic
viability of legacy wells.
WEA stated that the CEDRI template was a success and the benefits of electronic reporting
should be brought forward into the 2021 proposal.
CountryMark, INOGA, and KOGA stated that EPA amend its electronic reporting template to
report for existing and new sources on separate sheets. Only the necessary information from
annual monitoring should be entered for wells that are newly affected facilities, reducing the
volume of data for operators to input each year.
igitive Emissions Requirements
7.3.1 Requirements
WEA supported the use of aerial, satellite, and other forms of monitoring for fugitive emissions
requirements beyond traditional LDAR, but only as an alternative and not as an additional
requirement. This technology can be quite costly depending on the range of operations, pipeline
right-of-way mileage, mobilization f71s for aircraft, and even terrain impacts. In addition, fixed-
wing flyovers often require follow up with a ground-based infrared camera in order to ground
truth any identified leaks or abnormal emissions to verify if the source is a persistent or a
transitory, short-lived event.
WEA stated that EPA should provide relief from monitoring requirements in exchange for
demonstrations that site-wide emissions are lower than a certain threshold. First, this would
encourage the adoption of new technology. Second, it could lower emissions associated with
traveling to facilities on increased monitoring frequencies, especially for those facilities that
could otherwise be demonstrated to be low emitting.
The Texas Alliance of Energy Producers stated that there was not sufficient workforce available
to complete fugitive surveys.
MOGA and FEPI stated that initial monitoring should be allowed within the first 60 days or
during the next applicable monitoring period. This allowance would reduce monitoring costs
while efficiently distributing monitoring costs across multiple well sites.
CountryMark, INOGA, and KOGA stated that identifying all fugitive emissions components and
developing a site map with an observation path is expensive and time consuming.
CountryMark, INOGA, and KOGA supported allowing the use of AVO and soap bubbles as a
leak detection method.
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CountryMark, INOGA, and KOGA stated EPA should allow emerging technologies such as
infrared cameras that attach to smart phones.
7.3.2 Low production well sites
MOGA, FEPI, and Cumberland Valley Resources, LLC stated that AVO surveys should be
allowed instead of traditional LDAR for low production well sites.
Catalyst Energy stated that new oil wells are often stripper wells from the onset. Most legacy
wells produce only a few gallons per day, and well head pressures are kept as low as possible to
maintain flow of oil. These wells have very little leakage of methane and VOC emissions.
CountryMark, INOGA, KOGA, TIPRO, IPAA, GO-WV, and Cumberland Valley Resources,
LLC stated that low production wells should be exempt from the NSPS. CountryMark, INOGA,
and KOGA stated that this should be based on a 12 month average production rate.
TIPRO, IPAA, and GO-WV stated that EPA has no data, or incorrect data on emissions from
low production wells. They stated that the studies from environmental non-governmental
organizations are flawed and should not be relied upon for regulatory purposes.
The Texas Alliance of Energy Producers, TIPRO, IPAA, GO-WV, MOGA, FEPI, CountryMark,
INOGA, KOGA, PAO, and PGCC and Cameron Energy stated that the Department of Energy
has initiated a study to quantify emissions from low production and marginal wells, and results
are due in 2021. They stated that the EPA should wait for the completion of this study before
issuing a proposal.
TIPRO, IPAA, and GO-WV stated that EPA should focus on super emitters / fat-tail emissions.
The DOE study indicates that the majority of emissions from low production wells is from
relatively few sources, for example, the top 10% of emission sources in the Appalachian Basin
contributed 72% of total measured emissions, and the top two emissions sources accounted for
40%. These sources harm the environment and threaten the economic viability of many small
businesses.
TIPRO, IPAA, and GO-WV stated that low production wells should be subcategorized because
they have a much lower potential to emit than other wells. They stated that emissions at low
production wells are dependent on volumetric flow, pressure, and component count.
MOGA and FEPI stated that low production wells should be subcategorized, and EPA should
update its definition to align with the IRS Tax Code.
MOGA, FEPI and PAO stated that EPA should create an offramp for low production and
marginal wells. These wells cannot adsorb the costs of maintaining an LDAR program, including
the costs of surveys, data capture and collection, reporting and repair.
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PGCC and Cameron Energy stated that EPA should use a threshold of 10 barrels per day for low
production wells.
7.3.3 Leak Rate
PGCC and Cameron Energy stated that a random study of wells in New York was conducted in
2021, and they found out of 150 conventional gas well sites, 22 leaking components were found,
or 0.11% of all components monitored using OGI.
7.3.4 Costs and Impacts
WEA stated that some aerial survey vendors charge on a per facility basis while others have a fee
based on the size of the actual basin. Companies have seen costs ranging from $50,000 to
$240,000 to complete a single fixed-wing methane survey of a primary asset area (typically
including all facilities in a given basin). Other cost estimates to cover an entire field are $125,00
for 1,000 square miles. On a per-facility basis, these costs would range from $110 and $176 for
an individual facility based on the frequency of aerial surveys.
WEA stated that multi-client campaigns where companies would share in mobilization costs
would be more efficient in fields where multiple operators are in the same basin. This would be
critical for smaller operators as funding an individual-operator aerial survey would be quite
costly and inefficient.
The Texas Alliance of Energy Producers stated that EPA' estimated cost of OGI monitoring is
low. They stated that they lacked the adequate staff and resources to meet this new requirements,
and could make some of their leases uneconomical. They stated that this would be cost
prohibitive for low volume wells.
MOGA and FEPI stated that a single day of OGI monitoring costs $2,500 to $3,500, with a
significant portion of the cost due to mobilization.
MOGA and FEPI stated that EPA's model plant over-estimates the average number of wells that
can share implementation and ongoing annual regulation costs.
MOGA and FEPI stated that the first year costs of the NSPS would likely range from $4,000 to
$10,000. This includes that cost of a third party consultant, and could vary based on specific
training, equipment, software purchases, and functional knowledge to implement the regulation.
MOGA and FEPI estimated that the ongoing annual cost per well site ranges from $3,000 to
$6,000. EPA did not consider initial surveys for stand alone well sites outside the normal
schedule, and LDAR monitoring can range from $2,500 to $3,500 per site. EPA also assumes
fixed production and a constant number of wells; MOGA and FEPI suggested EPPA base its
assumptions on actual production and operational dynamics, which vary based on season,
26
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formation dynamics, operational agendas, oil and gas prices, and landowner contracts. MOGA
and FEPI stated that a single repair would likely cost between $500 and $1,500.
MOGA and FEPI stated that EPA should provide cost estimates for both in-house and third party
contractors.
CountryMark, INOGA, and KOGA stated that developing a written compliance program is a one
time cost of $5,000 to $10,000. Creating site plans takes an estimated 4 hours per well site at
$125 per hour.
7.3.5 Exemptions
TIPRO, IPAA, and GO-WV stated that EPA should reevaluate the wellhead only exemption to
allow a drop-tank or separator at the well site. This is often necessary for safety and operational
considerations, and has minimal emissions.
PGCC and Cameron Energy stated that EPA could categorize wells by well bore direction, and
exempt vertical wells.
orage Vessel Requirements
7.4.1 Emissions
Catalyst Energy, Inc. stated that centralized tank batteries service 20-40 wells, and most have
separators to conserve and produce what little gas there is. Little gas is evolved from the oil in
those tanks. A pressurize hatch holding pressure on the tank should be sufficient since off
gassing is very low on older wells.
PGCC and Cameron Energy stated control of emissions at conventional tank batteries is affected
by tank composition, cost of oxygen monitoring, availability of gas sales pipeline, intermittent
gas generation, and difficulty of powering the control infrastructure.
7.4.2 Applicability
WEA stated applicability should continue to be based on VOC emissions. VOCs are a close
proxy for methane emissions, and changing the applicability would cause operators of facilities
dating back to 2011 to develop new applicability determinations, resulting in cost and waste with
no environmental benefits. This change may impact operators data management, recordkeeping,
and monitoring requirements.
WEA stated applicability should continue to be based on single storage vessels, rather than a
tank battery. Since this requirement has been in place since 2011, it would be prudent to keep the
current applicability.
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PGCC and Cameron Energy stated that operators may not drill new wells or may install a new
storage vessel or tank battery in order to stay below the 6 tpy threshold.
CountryMark, INOGA, and KOGA stated that EPA should allow operators to calculate
applicability based on volume of produced oil instead of other more rigorous methods.
7.4.3 Requirements
WEA stated that EPA should provide an off ramp or an alternative applicability options for tanks
that are part of a larger battery. They recommended a threshold at 24 tpy of VOC (for a typical
facility of 4 tanks, each at 6 tpy), and allow those facilities to not be affected facilities or set a
lower threshold as an off ramp for low producing facilities. This could avoid needing to calculate
or assign emissions to individual tanks without changing the current applicability threshold.
PAO stated that using a methane-based applicability would cause small operators to conduct
costly retrofits to install flares or control devices due to methane emissions. In some cases, there
may not be sufficient volumes of tank vapors to route to a control device.
CountryMark, INOGA, and KOGA stated that the EPA should provide an offramp to storage
vessels that fall below 6 tpy. No compliance activities should be associated with these vessels.
7.5 Compressor Requirements
WEA stated Colorado's definition of a centralized production facility would apply to a site that
only had a single wellhead and a compressor. As a result, this definition is essentially
meaningless, as it would apply to functionally all production facilities. The 2021 proposal should
maintain the same applicability currently delineated by OOOOa.
PAO stated that compressors at well sites are a very small emissions source, and most vendors
replace the rod packing every 36 months as part of their maintenance programs, so this would
result in minimal emissions reductions.
PAO stated the requirement to track records of replacement or tracking flow measurement may
be unnecessarily burdensome and costly. PAO stated basing rod packing changeout using
emissions monitoring rather than hours may be beneficial for large operators, but create
additional burden for smaller operators. PAO recommended that EPA include this as an option or
alternative to tracking hours.
PGCC and Cameron Energy stated that the NSPS incentivizes operators to run old or oversized
compressors in order to avoid triggering the NSPS requirements.
Cumberland Valley Resources, LLC stated that removing the wellsite exemption for compressor
requirements could prevent a small operator from developing new gas fields.
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Cumberland Valley Resources, LLC stated field or small central production facilities using less
than 250 horsepower should be exempt, or at least have simplified requirements and rod packing
requirements extended to 60 months.
leiiiiiallc Controller Requirements
PAO stated that zero emissions controllers would not be feasible at sites where electricity is
unavailable or insufficient. The installation of gas fired compressors at those sites to supply air
for instrument air systems may defeat the purpose by ultimately increasing emissions, and the
installation of electric service would be extremely expensive.
PAO provided a 2014 survey of emissions from pneumatic controllers from production sites in
Oklahoma, conducted by the Oklahoma Independent Petroleum Association. Existing emission
factors overestimate pneumatic controller emissions, and intermittent bleed pneumatics generate
minimal emissions. EPA should consider if expanding pneumatic controller requirements is
needed.
quids Unloading Requirements
Catalyst Energy, Inc. stated that liquids unloading takes many forms, from simply blowing a gas
well down to a tank bailing an open hole to swabbing a cased hole to various types of artificial
lift. These techniques depend on velocity up the casing or tubing to lift liquids effectively. Any
techniques that impede velocity to recover gas would reduce the effectiveness of the operation
and increase frequency of liquids unloading operations.
WEA stated that the EPA should employ a series of best management practices that align with
those used by members of the Environmental Partnership3, according to their protocol. The
methodology has minimized emissions from 44,000 liquids unloading events, and is achievable,
effective, and relatively inexpensive compared with other emission reduction techniques. Liquids
unloading can be performed similarly to reduced emissions completions when there is not
sufficient gas to operator a separator. The Environmental Partnership's protocol monitors the
manual unloading process on-site and closes all wellhead vents to the atmosphere as soon as
practicable. This minimizes emissions from the event without requiring the installation of use of
specialized equipment.
TIPRO, IPAA, and GO-WV stated that liquid unloading practices are site-specific, and a one
size fits all regulation is inappropriate. Releasing a certain amount of gas is inherent in the
process, and capturing this gas has a considerable cost, and may be technically infeasible in
3 https://theenvironmentalpartnership.org/
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certain cases. TIPRO, IPAA, and GO-WV stated that nothing has changed since 2016 when EPA
determined it did not have enough information to regulate this source.
PGCC and Cameron Energy stated that there is no technology currently in use in New York or
Pennsylvania which would capture emissions during liquids unloading. Emissions from these
events are low and might not warrant recovery or a flare. A vapor recovery system could work,
but would require more energy and generate more emission than it captures.
Cumberland Valley Resources, LLC stated that swabbing is done using a small truck mounted
rig that is moved over the wells when needed. Well construction often includes a string of tubing
run to the bottom of the well in order to remove fluid build up over time by pumping or
swabbing. Some wells have never been swabbed, and some need to be swabbed every couple of
years. This is done in a matter of hours and the fluid removed is trucked off location. It would be
almost impossible to flare and gas during this process due to the size and proximity to forested
lands. Plunger systems don't work because they don't have enough volume or pressure.
>sts and Impacl ¦ . lysis
CountryMark, INOGA, KOGA, MOGA, FEPI, and Cumberland Valley Resources, Inc. stated
that the additional cost of the NSPS may accelerate the plugging of wells. This will exacerbate
the need to drill additional wells to meet consumer demand.
;lier Comments
7.9.1 Professional Engineering Certification
MOGA and FEPI stated that the requirements for PE certification is insulting and can cost up to
$10,000 per facility. They stated that this certification can be done by anyone with a
mathematical, geological, or other related education combined with a fixed amount of experience
in the design, operation, construction and maintenance of oil and natural gas facilities.
0 PANEL FIN * v v \ \ * * vr vv ov
8.1 Number and Types of Entitie cted
EPA is currently working to determine small business concentrations for affected facilities in the
proposed rule. Table 3 illustrates small business concentrations in a recent year based on
operators of well sites and natural gas processing plants.
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Table 3. Small Business Concentrations at Well Sites and Natural Gas Processing Plants
Category
Total
firms
Small
Not
small
Unknown
Small business
percentage (of
identified firms)
Well Sites
1,753
1,010
107
636
90%
Natural Gas
Processing
Plants
205
93
58
54
62%
itentlal Reporting, Recordkeeping, and Compliance Requirements
The potential reporting, recordkeeping, and compliance requirements are still under
development. SERs identified challenges small operators have had with the electronic reporting
template and suggested additional efforts to ease compliance, particularly for small businesses.
The Panel recommends that EPA assess ways to simplify the electronic reporting template for
small businesses and offer small business consultation during the next update of the template.
The SERs also specifically wrote in favor of the recordkeeping and reporting streamlining in the
2020 Technical Rule. The Panel recommends the proposed rule not eliminate the streamlining
provisions of the 2020 Technical Rule and propose to continue these provisions in the new NSPS
OOOOb where appropriate.
SERs also recommended reviewing reporting requirements to ensure that the information
provided to regulatory authorities is being used to target enforcement resources and ensure
environmental benefits. SERs do not believe it necessary for regulatory authorities to gather
detailed operational information to ensure compliance. SERs also want to ensure that where state
compliance programs are considered equivalent to the NSPS, reporting and recordkeeping
requirements are limited to what is required by the state program. The Panel recommends that
reporting and recordkeeping requirements should be aligned to existing business practices to the
extent possible.
Advocacy recommends that EPA reduce reporting requirements to only information necessary to
target enforcement with the NSPS. EPA believes that reporting should include information to
assure compliance as well as target enforcement.
Advocacy recommends that EPA adopt the state equivalency provisions of the 2020 Technical
Rule for methane to the extent that existing state programs have the practical effect of regulating
methane emissions as part of VOC emission controls. EPA recommends that the proposed
revisions to NSPS OOOOa include state equivalency provisions for those states determined to be
equivalent in the 2020 Technical Rule that regulate both VOC and methane. EPA recommends
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extending this equivalency determination to NSPS OOOOb for states that regulate both VOC
and methane at a level equivalent to the new proposed NSPS.
8 iatei Federal Rules
SERs expressed concerns about potentially overlapping federal regulations that could apply to
this sector, particularly PHMSA's leak detection and repair rule, discussed in section 2.4. EPA
acknowledges the SERs' concerns and notes that EPA and PHMSA staff meet regularly to
discuss scope and boundaries of their respective rules. EPA understands that PHMSA regulations
cover the distribution segment, as well as natural gas transmission pipelines, both of which are
unregulated by the NSPS.
The Panel recommends that EPA continue consulting PHMSA to ensure that there are no
overlapping or contradictory requirements on these sources.
igiilatory Flexibility Alternatives
The Panel has reviewed the information provided by EPA to the SERs and the SERs' oral and
written comments from the pre-panel outreach and panel outreach. In response to this
consultation, the Panel identifies the following significant alternatives for consideration by the
Administrator of EPA which accomplish the stated objectives of the Clean Air Act and which
minimize any significant economic impact of the proposed rule on small entities.
8.4.1 Rule Scope
SERs stated that NSPS 0000a has unintentionally been applied to conventional and vertical
wells that engage in hydraulic fracturing. SERs contend that these wells have a very different
profile from unconventional and horizontal wells in terms of footprint, water usage, chemical
usage, equipment used, and flowback period. SERs recommend that EPA explicitly exempt
conventional and vertical wells from the proposal. EPA maintains that the original intend of the
NSPS was to regulate hydraulicly fractured wells, in both conventional and unconventional
reservoirs4, and both vertical and horizontal wells.5
NSPS 0000a defines hydraulic fracturing as "the process of directing pressurized fluids
containing any combination of water, proppant, and any added chemicals to penetrate tight
formations, such as shale or coal formations, that subsequently require high rate, extended
flowback to expel fracture fluids and solids during completions." The NSPS does not offer
numeric thresholds that define "pressurized fluids", "tight formations" or "high rate, extended
flowback". When developing the original NSPS 0000, EPA's analysis assumed hydraulic
4 EPA-HQ-OAR-2010-0505-0445, p.4-2 and EPA-HQ-OAR-2010-0505-4546, p. 30.
5 EPA-HQ-OAR-2010-0505-4546, p. 61.
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fracturing is performed in tight sand, shale, and coalbed methane formations to have an in situ
permeability (flow rate capability) to gas of less than 0.1 millidarcy.6 EPA also assumed the
flowback lasted between 3 and 10 days for the average gas well7, and 3 days for the average oil
well.8 However, in response to a public comment on the 2015 NSPS OOOOa proposal claiming
the definition of hydraulic fracturing was too broad, EPA clarified it intended to "include
operations that would increase the flow of hydrocarbons to the wellhead".9 Similarly, in response
to a public comment seeking an exemption for wells that have a flowback period of less than 24
hours, EPA acknowledged that there is a range of flowback periods, finding that the requested
exemption was not warranted.10
The Panel recommends that EPA solicit comment on appropriate definitions for 'tight formation'
and 'high rate, extended flowback' to clarify the proposal's applicability.
Advocacy notes that the EPA's intent at the time of NSPS OOOO and NSPS OOOOa is not
clearly stated to include conventional and unconventional reservoirs, particularly since the
definition of "hydraulic fracturing" explicitly includes reference to the geologic features
themselves, i.e. "tight formations," and to the operational activities that are absent in
conventional reservoirs, "high rate, extended flowback." This aligns with EPA's decision in the
NSPS 0000 RIA to only analyze hydraulic fracturing in such "tight formations." Nor is EPA's
response to a comment about "operations that would increase the flow of hydrocarbons to the
wellhead" 11 a clearly stated intent to cover geologic features other than those explicitly
described in the proposed definition. Advocacy therefore recommends that EPA propose
definitions with numerical standards that give meaning to the entire regulatory definition of
"hydraulic fracturing," based on the SERs' characterization of the distinction between geological
formations and operational characteristics likely to be the source of significant methane
emissions.
8.4.2 Fugitive Emissions Requirements
8.4.2.1 Monitoring Frequency
For NSPS OOOOa, EPA is evaluating revisions to resolve discrepancies between the 2020
Technical Rule and the 2016 NSPS OOOOa, unchanged by the 2020 Policy Rule. This includes
aligning VOC and methane monitoring frequencies. SERs recommend EPA adopt the VOC
monitoring and associated reporting and recordkeeping provisions from the 2020 Technical Rule
and apply those to methane. Advocacy recommends that EPA propose aligning the monitoring
6 EPA-HQ-OAR-2010-0505-0445, p.4-2.
7 EPA-HQ-OAR-2010-0505-0445, p.4-1.
8 EPA-HQ-OAR-2010-0505-5021, p.20.
9 EPA-HQ-OAR-2010-0505-7632, p.3-113.
10 EPA-HQ-OAR-2010-0505-7632, p.3-64.
11 EPA-HQ-OAR-2010-0505-7632, p.3-113.
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frequency in NSPS 0000a with the revised provisions for VOCs in the 2020 Technical Rule.
EPA recommends that it reanalyze the best system of emission reduction for both pollutants,
acknowledging that what was found to not be cost-effective for VOC in the 2020 Technical Rule
may change when accounting for emission reductions of both VOC and methane.
8.4.2,2 Low Production Well Sites
SERs provided a number of recommendations for low production well sites, ranging from
completely exempting these well sites, requiring a maximum of annual monitoring, or providing
an offramp as wells reach low production status. SERs contended that low production well sites
have little to no emissions, and EPA should delay proposing requirements until results of a DOE
study on emissions from these sites is available. SERs recommended that EPA focus its proposed
requirements on 'super emitters' or 'fat-tail' emissions. SERs also recommended that EPA revise
its definition of low production well sites to align with the IRS definition of a stripper well
property.
The Panel recommends EPA propose fugitive emission requirements that target sources with
large emissions or super emitters. EPA and Advocacy recommend that such a proposal impose
fewer requirements on sources that are less likely to emit methane and/or have demonstrated a
history of insignificant emissions. Advocacy and EPA recommend that, if EPA proposes annual
screening requirements, these requirements contain clear thresholds for follow-up monitoring,
including a de minimis level that warrants no further action. Advocacy further recommends that
EPA solicit comment on regulatory alternatives to minimize the number of well sites subject to
monitoring, particularly at well sites that emit insignificant amounts of methane. EPA
recommends that it solicit comment on regulatory alternatives that prioritize monitoring on well
sites that emit significant amounts of methane.
The Panel further recommends that EPA solicit comment on regulatory alternatives for low
production well sites. EPA and Advocacy note that such a solicitation should include a range of
options, including exempting these sites and providing an offramp for well sites that later
become low production well sites, such as EPA has proposed in the past. The Panel recommends
that EPA solicit comment on the factors that could make certain well sites less likely to emit
methane, including geologic features, equipment onsite, production levels, and any other factors
that could establish the basis for an exemption or off-ramp. The Panel further recommends that
EPA solicit comment for additional data, such as the DOE study, that assess the emissions from
low production well sites and subsequently use this data to evaluate how monitoring
requirements can be tailored to address sources mostly likely to be the sources of largest
emissions and, if warranted, subcategorize sources unlikely to emit significant amounts of
methane.
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Regarding the definition of low production well site, the EPA contends that aligning its NSPS
definition with the IRS definition is inappropriate. The IRS averages production over a calendar
year of production, while the EPA averages production over the first 30 days of production after
drilling or hydraulic fracturing. In the case where low production well sites have different
requirements from other well sites, the affected facility would need to determine which set of
requirements to follow, and waiting for a full year of production data would be infeasible.
Advocacy recommends that the EPA solicit comment on the use of the IRS definition of low
production well sites following the initial production period.
8.4.2.3 Exemptions
In addition, SERs supported maintaining the NSPS OOOOa wellhead only exemption from
fugitive emissions requirement, and include this same exemption in the NSPS 0000b proposal.
This provision in NSPS OOOOa excludes from fugitive emissions monitoring a well site that is
or later becomes a wellhead only well site, which the 2020 Technical Rule defines as "a well site
that contains one or more wellheads and no major production and processing equipment." EPA
and Advocacy agree that EPA should maintain the wellhead only exemption from fugitive
emissions requirements in NSPS OOOOa and propose a similar provision in the proposal for
NSPS 0000b.
8.4.2.4 Monitoring Technology
SERs recommended that EPA allow audio, visual, and olfactory (AVO) and soap bubble tests as
an option for finding fugitive emissions, particularly because they are lost cost and easy to
implement alternatives for detecting leaks. EPA clarified that soap bubble tests are a permissible
option as part of Method 21. The Panel recommends that EPA continue to allow Method 21 as an
option for fugitive emissions monitoring. The Panel recommends that EPA engage in additional
outreach to small entities to ensure that there is an adequate understanding of the requirements
and flexibilities that are already part of Method 21.
NSPS OOOOa allows AVO in limited and appropriate circumstances, including the inspection of
cover and closed vent systems, but EPA believes AVO is inappropriate as the primary method
for fugitive emissions inspections of well sites and compressor stations. EPA recommends
maintaining AVO inspections in these limited circumstances in NSPS 0000b. Advocacy
recommends EPA propose allowing AVO as an alternative in limited circumstances, such as part
of an off-ramp for facilities unlikely to emit more than insignificant methane or with a
demonstrated history of insignificant emissions.
8.4.2.5 Alternative Technology
SERs supported the use of aerial, satellite, and other forms of monitoring for fugitive emissions
requirements beyond traditional LDAR, but only as an alternative and not as an additional
requirement. The Panel recommends that EPA consider the cost and scope of alternative
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technologies and propose alternative screening technology. EPA and Advocacy support
proposing alternative screening technology as a compliance option rather than an additional
regulatory requirement. The Panel further recommends that EPA try to minimize significant
additional reporting and recordkeeping requirements. EPA and Advocacy recommend proposing
emissions thresholds for alternative screening technology that would allow small businesses to
adopt any alternative compliance options without significant additional reporting or
recordkeeping requirements and without needing to seek prior approval or changes to Clean Air
Act permits.
8.4.3 Pneumatic Controller Requirements
SERs stated that zero emission controllers are not feasible at wells sites or other locations
without reliable electricity, and installing gas-fired compressors to provide sufficient air for
instrument air systems may defeat the purpose by ultimately increasing emissions, and the
installation of electric service would be extremely expensive.
EPA and Advocacy recommend that the EPA only propose zero emission controllers at sites with
reliable and consistent onsite power available and clearly state that the intent is not require the
installation of electric services for this purpose.
8.4.4 Liquids Unloading Requirements
Some SERs questioned whether EPA could regulate liquids unloading because best practices are
very 'site-specific.' To the extent that EPA includes liquid unloading requirements in the
proposed NSPS OOOOb, SERs recommended that the EPA limit the requirements to best
management practices. SERs stated that liquids unloading can take many forms, from simply
blowing a gas well down to a tank bailing an open hole to swabbing a cased hole to various types
of artificial lift. A SER identified a source for an industry best practices to which EPA should
align its requirements.
Advocacy recommends that EPA not propose liquids unloading requirements. Advocacy is
concerned that a best management practice written into a regulation, particularly one that is very
'site-specific,' will not provide small entities clear instructions and lead to confusion and
significant risk of unwarranted enforcement actions. In addition, Advocacy is concerned that
EPA did not present the Panel or SERs more specific information about the need to regulate
liquids unloading or likely costs. Should EPA propose liquids unloading requirements, Advocacy
recommends that EPA only propose best management practices during liquids unloading
operations that align with industry best practices and give operators clear discretion to manage
on-site operations to minimize venting and ensure operational safety. Further, Advocacy
recommends that the proposal explicitly recognize the wide range of legitimate and allowable
practices during liquids unloading that may result in some emissions. Advocacy recommends
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EPA require only limited recordkeeping associated with any liquids unloading operation and not
require any reporting.
EPA recommends that the NSPS OOOOb proposal include a robust set of best management
practices during liquids unloading operations to minimize venting. The industry best practices
provided by a SER allow exemptions for multiple types of liquids unloading operations,
including swabbing and the use of plunger lifts, and suggest only monitoring the manual
unloading process and closing wellhead vents to the atmosphere as soon as practicable. EPA
believes that the industry best practices are not sufficient to minimize venting from liquids
unloading operations, and in particular, the number of exemptions would allow a significant
portion of this emissions source to go unregulated.
The Panel recommends that EPA solicit comments on exemptions for operations that may be
unlikely to result in emissions, such as wellheads that are not operating under positive pressure.
8.4.5 Storage Vessels
SERs discussed concerns with the current regulatory approach towards storage vessels. First,
SERs recommended establishing a regulatory off-ramp based on interconnected tanks that are
operated as a single unit but currently regulated as multiple sources. EPA and Advocacy
recommend that EPA propose that NSPS OOOOb applies to tank batteries rather than single
storage vessels. EPA and Advocacy agree that EPA propose an off-ramp for tank batteries with
emissions that later fall below a certain threshold of VOC and methane emissions.
Second, SERs raised concerns that situations exist where propane or other fossil fuel must be
used to maintain continuous pilot lights for flares that serve as control devices on storage tanks
that do not produce enough emissions. The Panel agrees that this issue deserves greater study,
including whether the GHG benefits of these control devices are negated by the need to burn
additional fossil fuels and whether additional factors exist that may cause variability in emissions
from storage tanks or could be used to more narrowly target these requirements to limit the
unnecessary operation of flares. The Panel recommends that EPA request comment on this issue.
One SER identified a conflict with a lease requirement for BLM leases in Michigan require
operators to open the tank hatches daily to check oil levels, for the purposes of royalty
calculation and loss prevention. This requirement however negates the emissions benefit of any
emissions limitation. Advocacy recommends EPA request more information about this situation
from BLM, including consultations with BLM. If this requirement exists in Federal, State or
tribal leases, then EPA should propose an exemption for affected storage tanks. EPA consulted
with BLM on this issue and found that BLM requires tank gauging monthly and this does not
require opening the thief hatch. The Panel recommends that EPA continue to consult with BLM
on its oil and gas regulations to ensure the regulations are harmonized, good government
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practice, and that owners and operators have clarity on compliance requirements if they are
subject to both BLM and EPA regulations.
8.4.6 Compressors
A SER expressed opposition to changing rod packing requirements from a fixed timeline to a
performance standard based on flow measurement. Advocacy notes that this consistent with
small business concerns that compliance with performance standards are often more expensive
because of the monitoring and recordkeeping. Small businesses frequently prefer design
standards that are explicit in their requirements and do not require additional monitoring.
Advocacy recommends that, if EPA proposes a rod packing requirement based on flow
measurement or other performance standard, EPA should propose an alternative compliance
strategy based on time in service or hours of operation. EPA believes that the flow measurement
is a straightforward and low cost compliance strategy. EPA recommends maintaining the
alternative compliance strategy of routing reciprocating compressor emissions to a process.
SERs expressed opposition to EPA's suggested definition of a 'centralized production facility' a
specific type of well site that operates with a larger number and size of equipment than
individual well sites. One SER stated that Colorado's definition of this type of facility was
inappropriate because it would inadvertently capture all well sites with a single well head and a
compressor.
EPA and Advocacy agree that, if EPA proposes to regulate compressors at centralized
production facilities, the definition of these facilities should clearly exclude single well head sites
with small compressors.
8.4.7 Requirements for Certification by Professional Engineers
SERs addressed aspects of NSPS OOOOa that require a professional engineer (PE) certification.
SERs argued that this requirement did not recognize the significant industry-specific experience
available in-house at many firms and thus unnecessarily raised costs for small businesses. They
recommended relaxing the requirement for to allow engineering certifications "to include those
with a mathematical, geological and other related educational disciplines combined with a fixed
amount of experience in the design, operations, construction and maintenance of oil and natural
gas facilities." In the 2020 Technical Rule, EPA expands the NSPS OOOOa requirements to
allow either a PE or an in-house engineer to complete these certifications. Advocacy and EPA
recommend that EPA maintain the flexibility for in-house engineers to complete these
certifications in NSPS OOOOa and include this same flexibility in NSPS 0000b.
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APPENDIXA; List of M n\\ liared with Small Entity
ntatives
Appendix Al. Materials EPA shared with potential SERs before the Pre-
Panel Outreach Meeting, June 29,2021
• Agenda for Pre-Panel Outreach Meeting, June 29, 2021
• Power Point Presentation: An Overview of the Small Business Advocacy Review Panel
Process
• Power Point Presentation: Oil and Natural Gas Sector New Source Performance
Standards - Small Entity Representative Pre-Panel Outreach
• Appendix - Fugitive Cost from 2020 TSD
Appendix A2. Materials EPA shared with SERs before the Panel Meeting
July 29, 2021
• Agenda for Panel Outreach Meeting, July 29, 2021
• Power Point Presentation: Oil and Gas SBAR Panel Presentation
• Power Point Presentation: Oil and Gas SBAR Panel Presentation - Supplemental
Materials
• Pre-Panel Comments from Potential SERs
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APPEK' Written Comments Submitted by Small Entity
ntatives
Appendix Bl. Written Comments from potential SERs following the June
29,2021 Pre-Panel Outreach Meeting
Appendix Bl is a compilation of documents containing all written comments received from SERs
following the pre-panel meeting.
• American Public Gas Association, City of Las Cruces Utilities/Gas, Middle Tennessee
Natural Gas Utility District, Pensacola Energy, and Unitil Corporation
• CountryMark, Indiana Oil and Gas Association (INOGA), and Kentucky Oil and Gas
Association (KOGA)
• Cumberland Valley Resources, LLC
• Fore Energy Partners, Inc (FEPI)
• Kansas Independent Oil & Gas Association (KIOGA)
• Michigan Oil and Gas Association (MOGA)
• Pennsylvania Grade Crude Oil Coalition (PGCC) and Cameron Energy Company
• The Petroleum Alliance of Oklahoma (PAO)
• Texas Alliance of Energy Producers
Appendix B2. Written Comments from SERs following the July 29,2021
Panel Outreach Meeting
Appendix B2 is a compilation of documents containing all written comments received from SERs
following the panel meeting.
• Catalyst Energy, Inc
• CountryMark, Indiana Oil and Gas Association (INOGA), and Kentucky Oil and Gas
Association (KOGA)
• Cumberland Valley Resources, LLC
• Michigan Oil and Gas Association and Fore Energy Partners, Inc. (MOGA and FEPI)
• Pennsylvania Grade Crude Oil Coalition (PGCC) and Cameron Energy Company
• The Petroleum Alliance of Oklahoma (PAO)
• Texas Alliance of Energy Producers
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• Texas Independent Producers and Royalty Owners Association (TIPRO), the
Independent Petroleum Association of America (IPAA), and the Gas and Oil Association
of WV, Inc (GO-WV)
• Western Energy Alliance (WEA)
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