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6560-50-P

ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2010-0505; FRL-9929-75-OAR]

RIN 2060-AS30

Oil and Natural Gas Sector: Emission Standards for New and 

Modified Sources

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule; notice of public hearing.

SUMMARY: This action proposes to amend the new source 

performance standards (NSPS) for the oil and natural gas source 

category by setting standards for both methane and volatile 

organic compounds (VOC) for certain equipment, processes and 

activities across this source category. The Environmental 

Protection Agency (EPA) is including requirements for methane 

emissions in this proposal because methane is a greenhouse gas 

(GHG), and the oil and natural gas category is currently one of 

the country's largest emitters of methane. In 2009, the EPA

found that by causing or contributing to climate change, GHGs 

endanger both the public health and the public welfare of 

current and future generations. The EPA is proposing to amend 
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the NSPS to include standards for reducing methane as well as 

VOC emissions across the oil and natural gas source category.

Specifically, we are proposing both methane and VOC standards 

for several emission sources not currently covered by the NSPS 

(i.e., hydraulically fractured oil well completions, fugitive 

emissions from well sites and compressor stations, and pneumatic 

pumps). In addition, we are proposing methane standards for 

certain emission sources that are currently regulated for VOC 

(i.e., hydraulically fractured gas well completions, equipment 

leaks at natural gas processing plants). With respect to certain 

equipment that are used across the source category, the current 

NSPS regulates only a subset of these equipment (pneumatic 

controllers, centrifugal compressors, reciprocating 

compressors). The proposed amendents would establish methane 

standards for these equipment across the source category and 

extend the current VOC standards to the remaining unregulated 

equipment. Lastly, amendments to the current NSPS are being 

proposed that improve implementation of several aspects of the

current standards. These improvements result from

reconsideration of certain issues raised in petitions for 

reconsideration that were received by the Administrator on the 

August 16, 2012, final NSPS for the oil and natural gas sector
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and related amendments. Except for the implementation 

improvements and the setting of standards for methane, these 

amendments do not change the requirements for operations already 

covered by the current standards.

DATES: Comments. Comments must be received on or before 

[insert date 60 days after date of publication in the federal 

register]. Under the Paperwork Reduction Act(PRA), comments on 

the information collection provisions are best assured of 

consideration if the Office of Management and Budget (OMB) 

receives a copy of your comments on or before [insert date 60 

days after date of publication in the federal register]. The EPA 

will hold public hearings on the proposal. Details will be 

announced in a separate notice.

ADDRESSES: Submit your comments, identified by Docket ID Number 

EPA-HQ-OAR-2010-0505, to the Federal eRulemaking Portal: 

http://www.regulations.gov. Follow the online instructions for 

submitting comments. Once submitted, comments cannot be edited 

or withdrawn. The EPA may publish any comment received to its 

public docket. Do not submit electronically any information you 

consider to be Confidential Business Information (CBI) or other 

information whose disclosure is restricted by statute. 

Multimedia submissions (audio, video, etc.) must be accompanied 
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by a written comment. The written comment is considered the 

official comment and should include discussion of all points you 

wish to make. The EPA will generally not consider comments or 

comment contents located outside of the primary submission (i.e. 

on the web, cloud, or other file sharing system). For additional

submission methods, the full EPA public comment policy, 

information about CBI or multimedia submissions, and general 

guidance on making effective comments, please visit 

http://www2.epa.gov/dockets/commenting-epa-dockets.

Instructions: All submissions must include agency name and 

respective docket number or Regulatory Information Number (RIN) 

for this rulemaking. Direct your comments to Docket ID Number 

EPA-HQ-OAR-2010-0505. The EPA's policy is that all comments 

received will be included in the public docket without change 

and may be made available online at www.regulations.gov, 

including any personal information provided, unless the comment 

includes information claimed to be confidential business 

information (CBI) or other information whose disclosure is 

restricted by statute. Do not submit information that you 

consider to be CBI or otherwise protected through 

www.regulations.gov or email. (See section III.B below for 

instructions on submitting information claimed as CBI.) The 
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www.regulations.gov Web site is an "anonymous access" system, 

which means the EPA will not know your identity or contact 

information unless you provide it in the body of your comment. 

If you submit an electronic comment through www.regulations.gov, 

the EPA recommends that you include your name and other contact 

information in the body of your comment and with any disk or CDROM you submit. If the EPA cannot read your comment due to 

technical difficulties and cannot contact you for clarification, 

the EPA may not be able to consider your comment. If you send an 

email comment directly to the EPA without going through 

www.regulations.gov, your email address will be automatically 

captured and included as part of the comment that is placed in 

the public docket and made available on the Internet. Electronic 

files should avoid the use of special characters, any form of 

encryption and be free of any defects or viruses. For additional 

information about the EPA’s public docket, visit the EPA Docket 

Center homepage at: www.epa.gov/epahome/dockets.htm.

Docket: The EPA has established a docket for this rulemaking 

under Docket ID Number EPA-HQ-OAR-2010-0505. All documents in 

the docket are listed in the www.regulations.gov index. Although 

listed in the index, some information is not publicly available,

e.g., CBI or other information whose disclosure is restricted by 
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statute. Certain other material, such as copyrighted material, 

is not placed on the Internet and will be publicly available 

only in hard copy. Publicly available docket materials are 

available either electronically in www.regulations.gov or in 

hard copy at the EPA Docket Center, EPA WJC West Building, Room 

Number 3334, 1301 Constitution Avenue, NW, Washington, D.C. The 

Public Reading Room is open from 8:30 a.m. to 4:30 p.m., Monday 

through Friday, excluding legal holidays. The telephone number 

for the Public Reading Room is (202) 566-1744, and the telephone 

number for the EPA Docket Center is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: For information concerning this 

action, or for other information concerning the EPA’s Oil and 

Natural Gas Sector regulatory program, contact Mr. Bruce Moore, 

Sector Policies and Programs Division (E143-05), Office of Air 

Quality Planning and Standards, Environmental Protection Agency, 

Research Triangle Park, North Carolina 27711, telephone number: 

(919) 541-5460; facsimile number: (919) 541-3470; email address: 

moore.bruce@epa.gov.

SUPPLEMENTARY INFORMATION: Outline. The information presented in 

this preamble is organized as follows: 

I. Preamble Acronyms and Abbreviations

II. Executive Summary

A. Purpose of the Regulatory Action
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B. Summary of the Major Provisions of the Regulatory Action

C. Costs and Benefits

III. General Information

A. Does this reconsideration notice apply to me?

B. What should I consider as I prepare my comments to the EPA?

C. How do I obtain a copy of this document and other related 

information?

IV. Background

A. Statutory Background

B. What are the regulatory history and litigation background 

regarding performance standards for the oil and natural gas 

source category?

C. Events Leading to This Action

V. Why is the EPA Proposing to Establish Methane Standards in 

the Oil and Natural Gas NSPS?

VI. The Oil and Natural Gas Source Category Listing Under Clean 

Air Act Section 111(b)(1)(A) 

A. Impacts of GHG, VOC, and SO2 Emissions on Public Health and 

Welfare

B. Stakeholder Input

VII. Summary of Proposed Standards

A. Control of Methane and VOC Emissions in the Oil and Natural 

Gas Source Category

B. Centrifugal Compressors

C. Reciprocating Compressors

D. Pneumatic Controllers

E. Pneumatic Pumps

F. Well Completions

G. Fugitive Emissions from Well Sites and Compressor Stations

H. Equipment Leaks at Natural Gas Processing Plants

I. Liquids Unloading Operations

J. Recordkeeping and Reporting

VIII. Rationale for Proposed Action for NSPS

A. How does EPA evaluate control costs in this action?

B. Proposed Standards for Centrifugal Compressors

C. Proposed Standards for Reciprocating Compressors

D. Proposed Standards for Pneumatic Controllers

E. Proposed Standards for Pneumatic Pumps

F. Proposed Standards for Well Completions 

G. Proposed Standards for Fugitive Emissions from Well Sites 

and Compressor Stations

H. Proposed Standards for Equipment Leaks at Natural Gas 

Processing Plants
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I. Liquids Unloading Operations

IX. Implementation Improvements

A. Storage Vessel Control Device Monitoring and Testing 

Provisions

B. Other Improvements

X. Next Generation Compliance and Rule Effectiveness

A. Independent Third-Party Verification

B. Fugitives Emissions Verification

C. Third-Party Information Reporting

D. Electronic Reporting and Transparency

XI. Impacts of This Proposed Rule

A. What are the air impacts?

B. What are the energy impacts?

C. What are the compliance costs?

D. What are the economic and employment impacts?

E. What are the benefits of the proposed standards?

XII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review 

B. Paperwork Reduction Act (PRA)

C. Regulatory Flexibility Act (RFA)

D. Unfunded Mandates Reform Act of 1995 (UMRA)

E. Executive Order 13132: Federalism

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks

H. Executive Order 13211: Actions Concerning Regulations that 

Significantly Affect Energy Supply, Distribution, or Use

I. National Technology Transfer and Advancement Act (NTTAA) 

and 1 CFR part 51

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and LowIncome Populations

I. Preamble Acronyms and Abbreviations

Several acronyms and terms are included in this preamble. 

While this may not be an exhaustive list, to ease the reading of 
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this preamble and for reference purposes, the following terms 

and acronyms are defined here:

ANGA America’s Natural Gas Alliance

API American Petroleum Institute

bbl Barrel

BID Background Information Document

BOE Barrels of Oil Equivalent

bpd Barrels Per Day

BSER Best System of Emissions Reduction

BTEX Benzene, Toluene, Ethylbenzene and Xylenes

CAA Clean Air Act

CFR Code of Federal Regulations

CPMS Continuous Parametric Monitoring Systems 

EIA Energy Information Administration

EPA Environmental Protection Agency

GOR Gas to Oil Ratio

HAP Hazardous Air Pollutants

HPDI HPDI, LLC

LDAR Leak Detection and Repair

Mcf Thousand Cubic Feet

NEI National Emissions Inventory

NEMS National Energy Modeling System

NESHAP National Emissions Standards for Hazardous Air 

Pollutants

NSPS New Source Performance Standards

NTTAA National Technology Transfer and Advancement Act of 

1995

OAQPS Office of Air Quality Planning and Standards

OGI Optical Gas Imaging

OMB Office of Management and Budget

OVA Olfactory, Visual and Auditory

PRA Paperwork Reduction Act

PTE Potential to Emit

REC Reduced Emissions Completion

RFA Regulatory Flexibility Act

RIA Regulatory Impact Analysis

scfh Standard Cubic Feet per Hour

scfm Standard Cubic Feet per Minute

SISNOSE Significant Economic Impact on a Substantial Number of 

Small Entities

tpy Tons per Year
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TSD Technical Support Document

TTN Technology Transfer Network

UMRA Unfunded Mandates Reform Act

VCS Voluntary Consensus Standards

VOC Volatile Organic Compounds

VRU Vapor Recovery Unit

II. Executive Summary 

A. Purpose of the Regulatory Action

The purpose of this action is to propose amendments to the 

NSPS for the oil and natural gas source category. To date the 

EPA has established standards for emissions of VOC and sulfur 

dioxide (SO2) for several operations in the source category. In 

this action, the EPA is proposing to amend the NSPS to include 

standards for reducing methane as well as VOC emissions across 

the oil and natural gas source category (i.e., production, 

processing, transmission and storage). The EPA is including 

requirements for methane emissions in this proposal because 

methane is a GHG and the oil and natural gas category is 

currently one of the country's largest emitters of methane. In 

2009, the EPA found that by causing or contributing to climate 

change, GHGs endanger both the public health and the public 

welfare of current and future generations.1 The proposed 

 

1 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 

66496 (Dec. 15, 2009) (“Endangerment Finding”).
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amendments would require reduction of methane as well as VOC 

across the source category. 

In addition, the proposed amendments include improvements 

to several aspects of the existing standards related to 

implementation. These improvements and the setting of standards 

for methane are a result of reconsideration of certain issues 

raised in petitions for reconsideration that were received by 

the Administrator on the August 16, 2012, NSPS (77 FR 49490) and 

on the September 13, 2013, amendments (78 FR 58416). Except for 

these implementation improvements, these proposed amendments do 

not change the requirements for operations and equipment already 

covered by the current standards.

B. Summary of the Major Provisions of the Regulatory Action 

The proposed amendments include standards for methane and 

VOC for certain new, modified and reconstructed equipment, 

processes and activities across the oil and natural gas source 

category. These emission sources include those that are 

currently unregulated under the current NSPS (hydraulically 

fractured oil well completions, pneumatic pumps and fugitive 

emissions from well sites and compressor stations); those that 

are currently regulated for VOC but not for methane 

(hydraulically fractured gas well completions, equipment leaks 
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at natural gas processing plants); and certain equipment that 

are used across the source category, but which the current NSPS 

regulates VOC emissions from only a subset of these equipment 

(pneumatic controllers, centrifugal compressors, reciprocating 

compressors), with the exception of compressors located at well 

sites.

Based on the EPA’s analysis (see section VIII), we believe 

it is important to regulate methane from the oil and gas sources 

already regulated for VOC emissions to provide more consistency 

across the category, and that the best system of emission 

reduction (BSER) for methane for all these sources is the same 

as the BSER for VOC. Accordingly, the current VOC standards also 

reflect the BSER for methane reduction for the same emission 

sources. In addition, with respect to equipment used categorywide of which only a subset of those equipment are covered under 

the NSPS VOC standards (i.e., pneumatic controllers, and

compressors located other than at well sites), EPA’s analysis 

shows that the BSER for reducing VOC from the remaining 

unregulated equipment to be the same as the BSER for those 

currently regulated. The EPA is therefore proposing to extend 

the current VOC standards for these equipment to the remaining 

unregulated equipment. 
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The additional sources for which we are proposing methane

and VOC standards were evaluated in the 2014 white papers (EPA 

Docket Number EPA-HQ-OAR-2014-0557). The papers summarized the 

EPA’s understanding of VOC and methane emissions from these 

sources and also presented the EPA’s understanding of mitigation 

techniques (practices and equipment) available to reduce these

emissions, including the efficacy and cost of the technologies 

and the prevalence of use in the industry. The EPA received 26 

submissions of peer review comments on these papers, and more 

than 43,000 comments from the public. The information gained 

through this process has improved the EPA’s understanding of the 

methane and VOC emissions from these sources and the mitigation 

techniques available to control them. The EPA has also received 

extensive and helpful input from state, local and tribal 

governments experienced in these operations, industry 

organizations, individual companies and others with data and 

experience. This information has been immensely helpful in 

determining appropriate standards for the various sources we are 

proposing to regulate. It has also helped the EPA design this 

proposal so as to complement, not complicate, existing state 

requirements. Following are brief summaries of these sources and 

the proposed standards.
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During development of these proposed requirements, we were 

mindful that some facilities that will be subject to the 

proposed EPA standards will also be subject to current or future 

requirements of the Department of Interior’s Bureau of Land 

Management (BLM) rules covering production of natural gas on 

Federal lands. We believe, to minimize confusion and unnecessary 

burden on the part of owners and operators, it is important that 

the EPA requirements not conflict with BLM requirements. As a 

result, EPA and BLM have maintained an ongoing dialogue during 

development of this action to identify opportunities for 

alignment and ways to minimize potential conflicting 

requirements and will continue to coordinate through the 

agencies’ respective proposals and final rulemakings. 

Compressors. The EPA is proposing a 95 percent reduction of

methane and VOC emissions from wet seal centrifugal compressors

across the source category (except for those located at well 

sites).2 For reciprocating compressors across the source category

(except for those located at well sites), the EPA is proposing 

 

2 During the development of the 2012 NSPS, our data indicated 

that there were no centrifugal compressors located at well 

sites. Since the 2012 NSPS, we have not received information 

that would change our understanding that there are no 

centrifugal compressors in use at well sites.
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to reduce methane and VOC emissions by requiring that owners 

and/or operators of these compressors replace the rod packing 

based on specified hours of operation or elapsed calendar months 

or route emissions from the rod packing to a process through a 

closed vent system under negative pressure. See sections VIII.B 

and C of this preamble for further discussion.

Pneumatic controllers. The EPA is proposing a natural gas 

bleed rate limit of 6 standard cubic feet per hour (scfh) to 

reduce methane and VOC emissions from individual, continuous 

bleed, natural gas-driven pneumatic controllers at locations 

across the source category other than natural gas processing 

plants. At natural gas processing plants, the proposed rule 

regulates methane and VOC emissions by requiring natural gasoperated pneumatic controllers to have a zero natural gas bleed 

rate, as in the current NSPS. See section VIII.D of this

preamble for further discussion.

Pneumatic pumps. The proposed standards for pneumatic pumps 

would apply to certain types of pneumatic pumps across the 

entire source category. At locations other than natural gas 

processing plants, we are proposing that the methane and VOC 

emissions from natural gas-driven chemical/methanol pumps and 

diaphragm pumps be reduced by 95 percent if a control device is 
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already available on site. At natural gas processing plants, the 

proposed standards would require the methane and VOC emissions 

from natural gas-driven chemical/methanol pumps and diaphragm 

pumps to be zero. See section VIII.E of this preamble for 

further discussion.

Hydraulically fractured oil well completions. For 

subcategory 1 wells (non-wildcat, non-delineation wells), we are 

proposing that for hydraulically fractured oil well completions,

owners and/or operators use reduced emissions completions, also 

known as ”RECs” or ”green completions,” to reduce methane and 

VOC emissions and maximize natural gas recovery from well 

completions. To achieve these reductions, owners and operators 

of hydraulically fractured oil wells must use RECs in 

combination with a completion combustion device. As is specified 

in the rule for hydraulically fractured gas well completions, 

the rule proposed here does not require RECs where their use is 

not feasible (e.g., if it technically infeasible for a separator 

to function). For subcategory 2 wells (wildcat and delineation 

wells), we are proposing that for hydraulically fractured oil 

well completions, owners and/or operators use a completion 

combustion device to reduce methane and VOC emissions. The 

proposed standards for hydraulically fractured oil well 
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completions are the same as the requirements finalized for 

hydraulically fractured gas well completions in the 2012 NSPS

and as amended in 2014 (see 79 FR 79018, December 31, 2014). See 

section VIII.F of this preamble for further discussion.

Fugitive emissions from well sites and compressor stations.

We are proposing that new and modified well sites and compressor 

stations conduct fugitive emissions surveys semiannually with 

optical gas imaging (OGI) technology and repair the sources of 

fugitive emissions within 15 days that are found during those 

surveys. We are also co-proposing OGI monitoring surveys on an 

annual basis for new and modified well sites, and requesting 

comment on OGI monitoring surveys on a quarterly basis for both 

well sites and compressor stations. Fugitive emissions can occur 

immediately on startup of a newly constructed facility as a 

result of improper makeup of connections and other installation 

issues. In addition, during ongoing operation and aging of the 

facility, fugitive emissions may occur. Under this proposal, the

required survey frequency would decrease from semiannually to 

annually for sites that find fugitive emissions from fewer than 

one percent of their fugitive emission components during a

survey, while the frequency would increase from semiannually to 

quarterly for sites that find fugitive emissions from five
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percent or more of their fugitive emission components during a

survey. In addition, we solicit comment on the whether new or 

modified well sites or compressor stations should not be 

affected facilities subject to the fugitive emission standards,

if the owner or operator is implementing a corporate-wide 

fugitive emissions monitoring and repair plan which is legally 

and practically enforceable. See section VIII.G of this preamble 

for further discussion.Building on the 2012 NSPS, the EPA 

intends to continue to encourage corporate-wide voluntary 

efforts to achieve emission reductions through responsible, 

transparent and verifiable actions that would obviate the need 

to meet obligations associated with NSPS applicability, as well 

as avoid creating disruption for operators following advanced 

responsible corporate practices. Based on this concept, we 

solicit comment on criteria we can use to determine whether and 

under what conditions well sites operating under corporate LDAR 

regimes can be deemed to be meeting the equivalent of the NSPS 

standards for well site fugitive emissions such that we can 

define those regimes as constituting alternative methods of 

compliance or otherwise provide appropriate regulatory 

streamlining. We also solicit comment on how to address 

enforceability of such alternative approaches (i.e., how to 
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assure that these well sites are achieving, and will continue to 

achieve, equal or better emission reduction than our proposed 

standards). 

Other reconsideration issues being addressed. The EPA is 

granting reconsideration of a number of issues raised in the 

administrative reconsideration petitions and, where appropriate, 

is proposing amendments to address such issues. These issues are 

as follows: storage vessel control device monitoring and testing 

provisions, initial compliance requirements in 

§60.5411(c)(3)(i)(A) for a bypass device that could divert an 

emission stream away from a control device, recordkeeping 

requirements of § 60.5420(c) for repair logs for control devices 

failing a visible emissions test, clarification of the due date 

for the initial annual report under the 2012 NSPS, flare design 

and operation standards, leak detection and repair (LDAR) for 

open-ended valves or lines, compliance period for LDAR for newly 

affected units, exemption to notification requirement for 

reconstruction, disposal of carbon from control devices, the 

definition of capital expenditure and initial compliance 

clarification. We are proposing to address these issues to 

clarify the rule, improve implementation and update procedures,

as fully detailed in section IX. 
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C. Costs and Benefits

The EPA has estimated emissions reductions, costs and 

benefits for two years of analysis: 2020 and 2025. Actions taken 

to comply with the proposed NSPS are anticipated to prevent 

significant new emissions, including 170,000 to 180,000 tons of 

methane, 120,000 tons of VOC and 310 to 400 tons of hazardous 

air pollutants (HAP) in 2020. The emission reductions are

340,000 to 400,000 tons of methane, 170,000 to 180,000 tons of 

VOC, and 1,900 to 2,500 tons of HAP in 2025. The methane-related 

monetized climate benefits are estimated to be $200 to $210

million in 2020 and $460 to $550 million in 2025 using a 3 

percent discount rate (model average).3

In addition to the benefits of methane reductions,

stakeholders and members of local communities across the country 

have reported to the EPA their significant concerns regarding 

potential adverse effects resulting from exposure to air toxics 

 

3 We estimate methane benefits associated with four different 

values of a one ton CH4 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). For the purposes of this summary, we present the 

benefits associated with the model average at 3 percent discount 

rate, however we emphasize the importance and value of 

considering the full range of social cost of methane values. We 

provide estimates based on additional discount rates in preamble 

section XI and in the RIA.
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emitted from oil and natural gas operations. Importantly, this 

includes disadvantaged populations. 

The measures proposed in this action achieve methane and 

VOC reductions through direct regulation. The hazardous air 

pollutant (HAP) reductions from these proposed standards will be 

meaningful in local communities. In addition, reduction of VOC 

emissions will be very beneficial in areas where ozone levels

approach or exceed the National Ambient Air Quality Standards 

for ozone. There have been measurements of increasing ozone 

levels in areas with concentrated oil and natural gas activity, 

including Wyoming and Utah. Several VOCs that commonly are 

emitted in the oil and natural gas source category are HAPs 

listed under Clean Air Act (CAA) section 112(b), including 

benzene, toluene, ethylbenzene and xylenes (this group is 

commonly referred to as “BTEX”) and n-hexane. These pollutants 

and any other HAP included in the VOC emissions controlled under 

the NSPS, including requirements for additional sources being 

proposed in this action, are controlled to the same degree. The 

co-benefit HAP reductions for the measures being proposed are 

discussed in the Regulatory Impact Analysis (RIA) and in the 

Background Technical Support Document (TSD) which are included 

in the public docket for this action.
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The EPA estimates the total capital cost of the proposed 

NSPS will be $160170 to $180 million in 2020 and $240280 to $330

million in 2025. The estimate of total annualized engineering 

costs of the proposed NSPS is $180 to $200 million in 2020 and 

$370 to $500 million in 2025 when using a 7 percent discount 

rate. When estimated revenues from additional natural gas are 

included, the annualized engineering costs of the proposed NSPS 

are estimated to be $150 to $170 million in 2020 and $320 to 

$420 million in 2025., assuming a wellhead natural gas price of 

$4/thousand cubic feet (Mcf). These compliance cost estimates 

include revenues from recovered natural gas as the EPA estimates 

that about 8.2 billion cubic feet in 2020 and 16 to 19 billion 

cubic feet in 2025 of natural gas will be recovered by 

implementing the NSPS.

Considering all the costs and benefits of this proposed 

rule, including the resources from recovered natural gas that 

would otherwise be vented, this rule results in a net benefit. 

The quantified net benefits (the difference between monetized 

benefits and compliance costs) are estimated to be $35 to $42 

million in 2020 using a 3 percent discount rate (model average)
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for climate benefits.4 The quantified net benefits are estimated 

to be $120 to $150 million in 2025 using a 3 percent discount 

rate (model average) for climate benefits. All dollar amounts 

are in 2012 dollars.

The EPA was unable to monetize all of the benefits 

anticipated to result from this proposal. The only benefits 

monetized for this rule are methane-related climate benefits. 

However, there would be additional benefits from reducing VOC 

and HAP emissions, as well as additional benefits from reducing 

methane emissions because methane is a precursor to global 

background concentrations of ozone. A detailed discussion of 

these unquantified benefits are discussed in section XI of this 

document as well as in the RIA available in the docket.

III. General Information

A. Does this reconsideration notice apply to me?

Categories and entities potentially affected by today’s 

notice include:

TABLE 1. INDUSTRIAL SOURCE CATEGORIES AFFECTED BY THIS ACTION

 

4Figures may not sum due to rounding. 
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Category NAICS 

code1 Examples of regulated entities

Industry . . . .

211111

Crude Petroleum and Natural Gas 

Extraction

211112 Natural Gas Liquid Extraction

221210 Natural Gas Distribution

486110

Pipeline Distribution of Crude 

Oil

486210

Pipeline Transportation of 

Natural Gas

Federal government . . . . Not affected

State/local/tribal 

government

. . . . Not affected

1 North American Industry Classification System.

This table is not intended to be exhaustive, but rather is 

meant to provide a guide for readers regarding entities likely 

to be affected by this action. If you have any questions 

regarding the applicability of this action to a particular 

entity, consult either the air permitting authority for the 

entity or your EPA regional representative as listed in 40 CFR 

60.4 or 40 CFR 63.13 (General Provisions).

B. What should I consider as I prepare my comments to the EPA?
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We seek comment only on the aspects of the new source 

performance standards for the oil and natural gas source 

category for the equipment, processes and activities

specifically identified in this document. We are not opening for 

reconsideration any other provisions of the new source 

performance standards at this time.

Do not submit information containing CBI to the EPA through 

www.regulations.gov or email. Send or deliver information 

identified as CBI only to the following address: OAQPS Document 

Control Officer (C404-02), Office of Air Quality Planning and 

Standards, U.S. Environmental Protection Agency, Research 

Triangle Park, North Carolina 27711, Attention: Docket ID Number 

EPA-HQ-OAR-2010-0505. Clearly mark the part or all of the 

information that you claim to be CBI. For CBI information in a 

disk or CD-ROM that you mail to the EPA, mark the outside of the 

disk or CD-ROM as CBI and then identify electronically within 

the disk or CD-ROM the specific information that is claimed as 

CBI. In addition to one complete version of the comment that 

includes information claimed as CBI, a copy of the comment that 

does not contain the information claimed as CBI must be 

submitted for inclusion in the public docket. Information so 
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marked will not be disclosed except in accordance with 

procedures set forth in 40 CFR part 2.

C. How do I obtain a copy of this document and other related 

information?

In addition to being available in the docket, electronic 

copies of these proposed rules will be available on the 

Worldwide Web through the Technology Transfer Network (TTN). 

Following signature, a copy of each proposed rule will be posted 

on the TTN's policy and guidance page for newly proposed or 

promulgated rules at the following address: 

http://www.epa.gov/ttn/oarpg/. The TTN provides information and 

technology exchange in various areas of air pollution control.

IV. Background

A. Statutory Background 

Section 111 of the CAA requires the EPA Administrator to 

list categories of stationary sources that, in his or her 

judgment, cause or contribute significantly to air pollution 

which may reasonably be anticipated to endanger public health or 

welfare. The EPA must then issue “standards of performance” for

new sources in such source categories. The EPA has the authority 

to define the source categories, determine the pollutants for 

which standards should be developed, and identify within each 
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source category the facilities for which standards of 

performance would be established.

CAA Section 111(a)(1) defines “a standard of performance” 

as “a standard for emissions of air pollutants which reflects 

the degree of emission limitation achievable through the

application of the best system of emission reduction which 

(taking into account the cost of achieving such reduction and 

any nonair quality health and environmental impact and energy 

requirement) the Administrator determines has been adequately

demonstrated.” This definition makes clear that the standard of 

performance must be based on controls that constitute "the best 

system of emission reduction... adequately demonstrated". The 

standard that the EPA develops, based on the BSER, is commonly a 

numerical emissions limit, expressed as a performance level 

(e.g., a rate-based standard). Generally, the EPA does not 

prescribe a particular technological system that must be used to 

comply with a standard of performance. Rather, sources generally 

can select any measure or combination of measures that will 

achieve the emissions level of the standard.

Standards of performance under section 111 are issued for

new, modified and reconstructed stationary sources. These 

standards are referred to as “new source performance standards.”
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The EPA has the authority to define the source categories, 

determine the pollutants for which standards should be 

developed, identify the facilities within each source category 

to be covered and set the emission level of the standards.

CAA section 111(b)(1)(B) requires the EPA to “at least 

every 8 years review and, if appropriate, revise” performance 

standards unless the “Administrator determines that such review 

is not appropriate in light of readily available information on 

the efficacy” of the standard. When conducting a review of an 

existing performance standard, the EPA has discretion to revise 

that standard to add emission limits for pollutants or emission 

sources not currently regulated for that source category.

B. What are the regulatory history and litigation background 

regarding performance standards for the oil and natural gas 

sector?

In 1979, the EPA published a list of source categories, 

including “crude oil and natural gas production,” for which the 

EPA would promulgate standards of performance under section 

111(b) of the CAA. See Priority List and Additions to the List 

of Categories of Stationary Sources, 44 FR 49222 (August 21, 

1979) (“1979 Priority List”). That list included, in the order 

of priority for promulgating standards, source categories that 
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the EPA Administrator had determined, pursuant to section 

111(b)(1)(A), contribute significantly to air pollution that may 

reasonably be anticipated to endanger public health or welfare. 

See 44 FR at 49223; see also, 49 FR 2636, 2637. In 1979, the EPA 

listed crude oil and natural gas production on its priority list 

of source categories for promulgation of NSPS (44 FR 49222,

August 21, 1979). 

On June 24, 1985 (50 FR 26122), the EPA promulgated an NSPS 

for the source category that addressed VOC emissions from 

leaking components at onshore natural gas processing plants (40 

CFR part 60, subpart KKK). On October 1, 1985 (50 FR 40158), a 

second NSPS was promulgated for the source category that

regulates sulfur dioxide (SO2) emissions from natural gas 

processing plants (40 CFR part 60, subpart LLL). In 2012, 

pursuant to its authority under section 111(b)(1)(B) to review 

and, if appropriate, revise NSPS, the EPA published the final 

rule, “Standards of Performance for Crude Oil and Natural Gas 

Production, Transmission and Distribution” (40 CFR part 60, 

subpart OOOO)(“2012 NSPS”). The 2012 NSPS updated the VOC 

standards for equipment leaks at onshore natural gas processing 

plants. In addition, it established VOC standards for several 

oil and natural gas-related operations not covered by subpart 
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KKK, including gas well completions, centrifugal and 

reciprocating compressors, natural gas-operated pneumatic 

controllers and storage vessels. In 2013 and 2014, the EPA made 

certain amendments to the 2012 NSPS in order to improve 

implementation of the standards (78 FR 58416 and 79 FR 79018).

The 2013 amendments focused on storage vessel implementation 

issues; the 2014 amendments provided clarification of well 

completion provisions which became fully effective on January 1, 

2015. The EPA received petitions for both judicial review and 

administrative reconsiderations for the 2012 NSPS as well as the 

subsequent amendments in 2013 and 2014. The litigations are 

stayed pending the EPA’s reconsideration process.

In this rulemaking, the EPA is granting reconsideration of 

a number of issues raised in the administrative reconsideration 

petitions and, where appropriate, is proposing amendments to 

address such issues. These issues, which mostly address 

implementation, are as follows: storage vessel control device 

monitoring and testing provisions, initial compliance 

requirements in §60.5411(c)(3)(i)(A) for a bypass device that 

could divert an emission stream away from a control device, 

recordkeeping requirements of §60.5420(c) for repair logs for 

control devices failing a visible emissions test, clarification 
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of the due date for the initial annual report under the 2012 

NSPS, emergency flare exemption from routine compliance tests, 

LDAR for open-ended valves or lines, compliance period for LDAR 

for newly affected process units, exemption to notification 

requirement for reconstruction of most types of facilities, and 

disposal of carbon from control devices.

C. Events Leading to Today’s Action

Several factors have led to today’s proposed action. First, 

the EPA in 2009 found that six well-mixed GHGs - carbon dioxide, 

methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, 

and sulfur hexafluoride - endanger both the public health and 

the public welfare of current and future generations by causing 

or contributing to climate change. Oil and gas operations are 

significant emitters of methane. According to Greenhouse Gas 

Reporting Program (GHGRP) data, oil and gas operations are the 

second largest emitter of GHGs in the U.S. (when considering 

both methane emissions and combustion-related GHG emissions at 

oil and gas facilities), second only than fossil-fueled 

electricity generation. This endangerment finding is described 

in more detail in section VI.

Second, on August 16, 2012, the EPA published the 2012 NSPS 

(77 FR 49490). The 2012 NSPS included VOC standards for a number 
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of emission sources in the oil and natural gas source category. 

Based on information available at the time, the EPA also 

evaluated methane emissions and reductions during the 2012 NSPS 

rulemaking as a potential co-benefit from regulating VOC. 

Although information at the time indicated that methane 

emissions could be significant, the EPA did not take final 

action in the 2012 NSPS with respect to the regulation of 

methane; the EPA noted the impending collection of a large

amount of GHG data for this industry through the GHGRP (40 CFR 

part 98) and expressed its intent to continue its evaluation of 

methane. As stated previously, the 2012 NSPS is the subject of a 

number of petitions for judicial review and administrative 

reconsideration. The litigation is currently stayed pending the 

EPA’s reconsideration process. Regulation of methane is an issue 

raised in several of the administrative petitions for the EPA’s 

reconsideration. 

Third, in June 2013, President Obama issued his Climate 

Action Plan which, among other actions, directed the EPA and 

five other federal agencies to develop a comprehensive 

interagency strategy to reduce methane emissions. The plan 

recognized that methane emissions constitute a significant 

percentage of domestic GHG emissions, highlighted reductions in 
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methane emissions since 1990, and outlined specific actions that 

could be taken to achieve additional progress. Specifically, the 

federal agencies were instructed to focus on “assessing current 

emissions data, addressing data gaps, identifying technologies 

and best practices for reducing emissions and identifying 

existing authorities and incentive-based opportunities to reduce 

methane emissions.”

Forth, as a follow-up to the 2013 Climate Action Plan, the 

Climate Action Plan: Strategy to Reduce Methane Emissions (the 

Methane Strategy) was released in March 2014. The focus on 

reducing methane emissions reflects the fact that methane is a 

potent GHG with a 100-year global warming potential (GWP) that 

is 28-36 times greater than that of carbon dioxide.5 Methane has 

an atmospheric life of about 12 years, and because of its 

potency as a GHG and its atmospheric life, reducing methane 

emissions is an important step that can be taken to achieve a 

near-term beneficial impact in mitigating global climate change. 

 

5 IPCC, 2013: Climate Change 2013: The Physical Science Basis. 

Contribution of Working Group I to the Fifth Assessment Report 

of the Intergovernmental Panel on Climate Change [Stocker, T.F., 

D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. 

Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge 

University Press, Cambridge, United Kingdom and New York, NY, 

USA, 1535 pp. Note that for purposes of inventories and 

reporting, GWP values from the 4th Assessment Report may be used.
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The Methane Strategy instructed the EPA to release a series of 

white papers on several potentially significant sources of 

methane in the oil and natural gas sector and to solicit input 

from independent experts. The papers were released in April 

2014. They focused on technical issues, covering emissions and

control technologies that reduce both VOC and methane, with 

particular focus on completions of hydraulically fractured oil 

wells, liquids unloading, leaks, pneumatic devices and 

compressors. The peer review process was completed on June 16, 

2014. The EPA received 26 submissions of peer review comments on 

these papers, and more than 43,000 comments from the public. The 

comments received from the peer reviewers are available on EPA’s 

oil and natural gas white paper Web site

(http://www.epa.gov/airquality/oilandgas/methane.html). Public 

comments on the white papers are available in EPA’s 

nonregulatory docket at www.regulations.gov, docket ID # EPA-HQOAR-2014-0557. The Methane Strategy also instructed the EPA to 

complete any new oil and natural gas regulations pertaining to 

the sources addressed in the white papers by the end of 2016.

Finally, following the Climate Action Plan and Methane 

Strategy, in January 2015, the Administration announced a new 

goal to cut methane emissions from the oil and gas sector (by 40 
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– 45 percent from 2012 levels by 2025) and steps to put the U.S. 

on a path to achieve this ambitious goal. These actions 

encompass both commonsense standards and cooperative engagement 

with states, tribes and industry. Building on prior actions by 

the Administration, and leadership in states and industry, the 

announcement laid out a plan for EPA to address, and if 

appropriate, propose and set commonsense standards for methane 

and ozone forming emissions from new and modified sources and 

issue Control Technique Guidelines (CTGs) to assist states in 

reducing ozone-forming pollutants from existing oil and gas 

systems in areas that do not meet the health-based standard for 

ozone.

Building on the 2012 NSPS, the EPA intends to encourage 

corporate-wide efforts to achieve emission reductions through 

transparent and verifiable voluntary action that would obviate 

the burden associated with NSPS applicability. Throughout this 

proposal, we solicit comment on specific approaches that could 

provide incentive for owners and operators to design and 

implement programs to reduce fugitive emissions at their 

facilities. 

V. Why is the EPA Proposing to Establish Methane Standards in 

the Oil and Natural Gas NSPS?
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In a petition for reconsideration of the 2012 NSPS, the 

petitioners urged that “EPA must reconsider its failure adopt 

standards for the methane pollution released by the oil and gas 

sector.”6 Upon reconsidering the issue, and on the basis of the 

wealth of additional information now available to us, the EPA is

proposing to establish methane standards for facilities

throughout the oil and natural gas source category. 

The EPA has discretion under CAA section 111(b) to 

determine which pollutants emitted from a listed source category 

warrant regulation. 7 In making such determination, we have

generally considered a number of factors to help inform our 

decision (We discuss considerations specific to individual 

emission source types in section VIII as part of the BSER 

analyses and rationale for regulating the sources). These 

factors include the amount such pollutant is being emitted from 

the source category, the avaibilty of technically feasible 

control options and the costs of such control options. As we 

 

6 Sierra Club et al., Petition for Reconsideration, In the Matter 

of: Final Rule Published at 77 Fed. Reg. 49490 (Aug. 16, 2012), 

titled “Oil and Gas Sector: New Source Performance Standards and 

National Emission Standards for Hazardous Air Pollutants 

Reviews; Final Rule,” Docket No. EPA-HQ-OAR-2010-0505, RIN 2060-

AP76 (2012). 7 See 42 U.S.C. § 7411(b)
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previously explained, “we have historically declined to propose 

standards for a pollutant where it is emitting (sic) in low 

amounts or where we determined that a [control analysis] would 

result in no control” device being used. 75 Fed. Reg. 54970, 

54997 (Sep. 9, 2010). Our consideration of these factors are 

provided below and in more detail in sections VI and VIII. 

The oil and natural gas industry is one of the largest 

emitters of methane, a GHG with a global warming potential more 

than 25 times greater than that of carbon dioxide. During the 

2012 oil and natural gas NSPS rulemaking, while we had 

considerable amount of data and understanding on VOC emissions 

from the oil and natural gas industry and the available control 

options, data on methane emissions were just emerging. In light 

of the rapid expansion of this industry and the growing concern 

with the associated emissions, the EPA proceeded to establish a 

number of VOC standards in the 2012 NSPS but indicated in that 

rulemaking an intent to revisit methane at a later date when 

additional information was available from the GHGRP. We have 

since received and evaluated such data, which confirm that the 

oil and natural gas industry is one of the largest emitters of 

methane. As discussed in section VI, the current methane 

emissions from this industry contribute substantially to 
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nationwide GHG emissions. These emissions are expected to 

increase as a result of the rapid growth of this industry. While 

the VOC standards in the 2012 NSPS also reduce methane 

emissions, in light of the current and projected future methane 

emissions from the oil and natural gas industry, reducing 

methane emissions from this source category cannot be treated 

simply as an incidental benefit to VOC reduction; rather, it is 

something that should be directly addressed through standards 

for methane under section 111(b) based on direct evaluation of 

the extent and impact of methane emissions from this source 

category and the best system for their reduction. Such 

standards, which would be reviewed and, if appropriate, revised 

at least every eight years, would achieve meaningful methane 

reductions and, as such, would be an important step towards 

mitigating the impact of GHG emissions on climate change. In 

addition, while many of the currently regulated emission sources 

are equipment used throughout the oil and natural gas industry

(e.g., pneumatic controllers, compressors) and emit both VOC and 

methane, the current VOC standards apply only to a subset of 

these equipment based on VOC-only evaluation. However, as shown 

in section VIII, there are cost-effective controls that can 

simulatenously reduce both methane and VOC emsisions from these 
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equipment across the industry, which in some instances would not 

occur were we to focus solely on VOC reductions. Revising the 

NSPS to establish both methane and VOC standards for all such 

equipment across the industry would also promote consistency by 

providing the same regulatory regime for these equipment 

throughout the oil and natural gas source category, thereby 

facilitating implementation and enforcement.8 

As mentioned above, we also we consider whether there are 

technically feasiable control options that can be applied 

nationally to sources to mitigate emissions of a pollutant and 

whether the costs of such controls are reasonable. As discussed 

in detail in section VIII, we have identified technically 

feasible controls that can be applied nationally to reduce 

methane emissions and thus GHG emissions from the oil and 

natural gas source category. We consider whether the costs 

 

8 The EPA often revises standards even where the revision will 

not lead to any additional reductions of a pollutant because 

another standard regulates a different pollutant using the same 

control equipment. For example, in 2014, the EPA revised the 

Kraft Pulp Mill NSPS in Part 60 Subpart BB (published at 70 FR 

18952 (April 4, 2014) to align the NSPS standards with the 

NESHAP standards for those sources in Part 63 Subpart S.

Although no previously unregulated sources were added to the 

Kraft Pulp Mill NSPS, several emission limits were adjusted 

downward. The revised NSPS did not achieve additional reductions

beyond those achieved by the NESHAP, but eased compliance burden 

for the sources. 
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(e.g., capital costs, operating costs) are reasonable 

considering the emission reductions achieved through application 

of the controls that would be required by the proposed rule. As 

discussed in detail in section VIII, for the oil and natural gas 

source category, the available controls for reducing methane 

emissions simultaneously control VOC emissions and vice versa. 

Accordingly, the available controls are the same for reducing 

methane and VOC from the individual oil and natural gas emission 

sources. For a detailed discussion on how we evaluated control 

costs and our cost analysis for individual emission sources, 

please see section VIII. As shown in that section, there are 

cost-effective controls for reducing metane emissions from the 

oil and natural gas source category. 

Based on our consideration of the three factors, the EPA is 

proposing to revise the NSPS to regulate directly GHG emissions 

in addition to VOC emissions across the oil and natural gas 

source category. The proposed standards include adding methane 

standards to certain sources currently regulated for VOC, as 

well as methane and VOC standards for additional emission 

sources. Specifically, 

• Well completions: we are proposing to revise the current 

NSPS to regulate both methane and VOC emissions from well 
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completions of all hydraulically fractured wells (i.e., gas 

wells and oil wells);

• Fugitive emissions: we are proposing standards to reduce 

methane and VOC emissions from fugitive emission components 

at well sites and compressor stations;

• Pneumatic pumps: we are proposing methane and VOC 

standards;

• Pneumatic controllers, centrifugal compressors, and 

reciprocating compressors (industry-wide, except for well 

site compressors, of which only a subset of those equipment 

are regulated currently): we are proposing to establish 

methane and VOC standards across the industry by adding 

methane standards to those currently subject to VOC 

standard and VOC and methane standards for all the others.

• Equipment leaks at natural gas processing plants: we are 

proposing to add methane standards.

For a detailed description of the proposed standards, please see 

section VII. For the BSER analyses that serve as the bases for 

the proposed standards, please see section VIII. 

VI. The Oil and Natural Gas Source Category Listing Under CAA 

Section 111(b)(1)(A) 
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Section 111(b)(1)(A) of the CAA, which Congress enacted as 

part of the 1970 CAA Amendments, requires the EPA to promulgate 

a list of categories of stationary sources that the 

Administrator, in his or her judgment, finds “causes, or 

contributes significantly to, air pollution which may reasonably 

be anticipated to endanger public health or welfare.” In 1979, 

the EPA published a list of source categories, including “crude 

oil and natural gas production,” for which the EPA would 

promulgate standards of performance under section 111(b) of the 

CAA. Priority List and Additions to the List of Categories of 

Stationary Sources, 44 FR 49222 (August 21, 1979) (“1979 

Priority List”). That list included, in the order of priority 

for promulgating standards, source categories that the EPA 

Administrator had determined, pursuant to section 111(b)(1)(A), 

to contribute significantly to air pollution that may reasonably 

be anticipated to endanger public health or welfare. See 44 FR 

49222; see also, 49 FR 2636, 2637. 

As mentioned above, one of the source categories listed in 

that 1979 rulemaking related to the oil and natural gas

industry. The EPA interprets the listing that resulted from that 

rulemaking as generally covering the oil and natural gas

industry. Specifically, with respect to the natural gas 
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industry, it includes production, processing, transmission, and 

storage. The EPA believes that the intent of the 1979 listing 

was to broadly cover the natural gas industry.9 This intent was 

evident in the EPA’s analysis at the time of listing.10 For 

example, the priority list analysis indicated that the EPA 

evaluated emissions beyond the natural gas production segment to 

include emissions from natural gas processing plants. The 

analysis also showed that the EPA evaluated equipment, such as 

stationary pipeline compressor engines, that are used in various 

segments of the natural gas industry. The EPA’s interpretation 

of the 1979 listing is further supported by the Agency’s 

pronouncements during the NSPS rulemaking that followed the 

listing. Specifically, in its description of this listed source 

category in the 1984 preamble to the proposed NSPS for equipment 

leaks at natural gas processing plants, the EPA described the 

major emission points of this source category to include 

 

9 The process of producing natural gas for distribution involves 

operations in the various segments of the natural gas industry 

described above. In contrast, oil production involves 

drilling/extracting oil, which is immediately followed by 

distribution offsite to be made into different products. 10 See Standards of Performance for New Stationary Sources, 43 FR

38872, August 31, 1978, and Priority List and Additions to the 

List of Categories of Stationary Sources, 44 FR 49222, August 

21, 1979.
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process, storage and equipment leaks; these emissions can be 

found throughout the various segments of the natural gas 

industry. 49 FR at 2637. There are also good reasons for 

treating various segments of the natural gas industry as one 

source category. Operations at production, processing, 

transmission and storage facilities are a sequence of functions 

that are interrelated and necessary for getting the recovered 

gas ready for distribution.11 Because they are interrelated, 

segments that follow others are faced with increases in 

throughput caused by growth in throughput of the segments 

preceding (i.e., feeding) them. For example, the relatively 

recent substantial increases in natural gas production brought 

about by hydraulic fracturing and horizontal drilling result in 

increases in the amount of natural gas needing to be processed 

and moved to market or stored. These increases in production and 

throughput can cause increases in emissions across the entire

natural gas industry. We also note that some equipment (e.g., 

 

11 The crude oil production segment of the source category, which 

includes the well and extends to the point of custody transfer 

to the crude oil transmission pipeline, is more limited in scope 

than the segments of the natural gas value chain included in the 

source category. However, increases in production at the well 

and/or increases in the number of wells coming on line, in turn 

increase throughput and resultant emissions, similarly to the 

natural gas segments in the source category.
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storage vessels, compressors) are used across the oil and 

natural gas industry, which further supports considering the 

industry as one source category. For the reasons stated above, 

the EPA interprets the 1979 listing broadly to include the 

various segments of the natural gas industry (production, 

processing, transmission, and storage).

Since the 1979 listing, EPA has promulgated performance 

standards to regulate SO2 emissions from natural gas processing 

and VOC emissions from the oil and natural gas industry. In this 

action, the EPA is proposing to further regulate VOC emissions 

as well as proposing performance standards for methane emissions 

from this industry. With respect to the latter, the EPA 

identifies the air pollutant that it proposes to regulate as the 

pollutant GHGs (which consist of the six well-mixed gases, 

consistent with other actions the EPA has taken under the CAA),

although only methane will be reduced directly by the proposed 

standards. 

As mentioned above, in the 1979 category listing, section 

111(b)(1)(A) does not require another determination as a 

prerequisite for regulating a particular pollutant. Rather, once 

the EPA has determined that the source category causes, or 

contributes significantly to, air pollution that may reasonably 
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be anticipated to endanger public health or welfare, and has 

listed the source category on that basis, the EPA interprets 

section 111(b)(1)(A) to provide authority to establish a 

standard for performance for any pollutant emitted by that 

source category as long as the EPA has a rational basis for 

setting a standard for the pollutant.12 The EPA believes that the 

information included below in this section provides a rational 

basis for the methane standards it is proposing in this action. 

First, because the EPA is not listing a new source category 

in this rule, the EPA is not required to make a new endangerment 

finding with regard to oil and natural gas source category in 

order to establish standards of performance for the methane from 

those sources. Under the plain language of CAA section 

111(b)(1)(A), an endangerment finding is required only to list a 

source category. Further, though the endangerment finding is 

based on determinations as to the health or welfare impacts of 

the pollution to which the source category’s pollutants 

contribute, and as to the significance of the amount of such 

contribution, the statute is clear that the endangerment finding 

is made with respect to the source category; section 

 

12 See additional discussion at 79 FR 1430, 1452 (Jan 8, 2014).
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111(b)(1)(A) does not provide that an endangerment finding is 

made as to specific pollutants. This contrasts with other CAA 

provisions that do require the EPA to make endangerment findings 

for each particular pollutant that the EPA regulates under those 

provisions. E.g., CAA sections 202(a)(1), 211(c)(1), 

231(a)(2)(A). See American Electric Power v. Connecticut, 131 S. 

Ct. 2527, 2539 (2011) (“the Clean Air Act directs EPA to 

establish emissions standards for categories of stationary 

sources that, ‘in [the Administrator's] judgment,’ ‘caus[e], or 

contribut[e] significantly to, air pollution which may 

reasonably be anticipated to endanger public health or welfare.’ 

§ 7411(b)(1)(A).”) (emphasis added).

Second, once a source category is listed, the CAA does not 

specify what pollutants should be the subject of standards from 

that source category. The statute, in section 111(b)(1)(B), 

simply directs the EPA to propose and then promulgate 

regulations “establishing Federal standards of performance for 

new sources within such category.” In the absence of specific 

direction or enumerated criteria in the statute concerning what 

pollutants from a given source category should be the subject of 

standard, it is appropriate for EPA to exercise its authority to 
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adopt a reasonable interpretation of this provision. Chevron 

U.S.A. Inc. v. NRDC, 467 U.S. 837, 843-44 (1984).

The EPA has previously interpreted this provision as 

granting it the discretion to determine which pollutants should 

be regulated. See Standards of Performance for Petroleum 

Refineries, 73 Fed. Reg. 35838, 35858 (col. 3)(June 24, 

2008)(concluding the statute provides “the Administrator with 

significant flexibility in determining which pollutants are 

appropriate for regulation under section 111(b)(1)(B)” and 

citing cases). Further, in directing the Administrator to 

propose and promulgate regulations under section 111(b)(1)(B), 

Congress provided that the Administrator should take comment and 

then finalize the standards with such modifications “as he deems 

appropriate.” The D.C. Circuit has considered similar statutory 

phrasing from CAA section 231(a)(3) and concluded that “[t]his 

delegation of authority is both explicit and extraordinarily 

broad.” National Assoc. of Clean Air Agencies v. EPA, 489 F.3d 

1221, 1229 (D.C. Cir. 2007).

In exercising its discretion with respect to which 

pollutants are appropriate for regulation under section 

111(b)(1)(B), the EPA has in the past provided a rational basis 

for its decisions. See National Lime Assoc. v. EPA, 627 F.2d 
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416, 426 & n.27 (D.C. Cir. 1980) (court discussed, but did not 

review, the EPA’s reasons for not promulgating standards for NOX, 

SO2 and CO from lime plants”); Standards of Performance for 

Petroleum Refineries, 73 Fed. Reg. at 35859-60 (June 24, 2008) 

(providing reasons why the EPA was not promulgating GHG 

standards for petroleum refineries as part of that rule). Though 

these previous examples involved the EPA providing a rational 

basis for not setting standards for a given pollutant, a similar 

approach is appropriate where the EPA determines that it should 

set a standard for an additional pollutant for a source category 

that was previously listed and regulated for other pollutants.

While the EPA believes that the 1979 listing of this source 

category provides sufficient authority for this action, to the 

extent that there is any ambiguity in the prior listing, the 

information provided here should be considered to constitute the 

requisite conclusions related to the category listing. Were EPA 

to formally seek to revise the category listing to broadly 

include the oil and natural gas industry (i.e., production, 

processing, transmission, and storage)13 , we believe this 

information discussed here fully suffices to support it as a 

 

13 For the oil industry, the listing includes production, as 

explained above in footnote 10. 
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source category that, in the Administrator’s judgment, 

contributes significantly to air pollution which may reasonably 

be anticipated to endanger public health or welfare.

Furthermore, for the reason stated below, EPA’s previous 

determination under section 111(b)(1)(A) is sufficient to 

support the proposed revision to the category listing as well as 

the proposed standards in this action. During the 1979 listing, 

EPA had determined that, at least a part of the oil and natural 

gas industry contributes significantly to air pollution which 

may reasonably be anticipated to endanger public health or 

welfare. Such health and welfare impacts could only increase 

when considering the broader industry (assuming it had not 

already been considered in the 1979 listing). To further support 

the conclusion related to this category listing, EPA has 

included below in this section information and analyses 

regarding the public health and welfare impacts from GHG, VOC 

and SO2 emissions, three of the primary pollutants emitted from 

the oil and natural gas industry, and the estimated emissions of 

these pollutants from the oil and natural gas source category. 

It is evident from this information and analyses that the oil 

and natural gas source category contributes significantly to air 
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pollution which may reasonably be anticipated to endanger public 

health or welfare. 

Provided below are the supporting information and analyses.

Specifically, section VI.A describes the public health and 

welfare impacts from GHG, VOC and SO2. Section VI.B analyzes the 

emission contribution of these three pollutants by the oil and 

natural gas industry. 

A. Impacts of GHG, VOC and SO2 Emissions on Public Health and 

Welfare 

The oil and natural gas industry emits a wide range of 

pollutants, including GHGs (such as methane and CO2), VOC, SO2, 

NOx, H2S, CS2 and COS. See 49 FR 2636, at 2637 (Jan 20, 1984). 

Although all of these pollutants have significant impacts on 

public health and welfare, an analysis of every one of these 

pollutants is not necessary for the Administrator to make a 

determination under section 111(b)(1)(A); as shown below, the 

EPA’s analysis of GHG, VOC, and SO2, three of the primary 

emissions from the oil and natural gas source category, alone 

are sufficient for the Administrator to determine under section 

111(b)(1)(A) that the oil and natural gas source category 
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contributes significantly to air pollution which may reasonably 

be anticipated to endanger public health and welfare.14 

1. Climate Change Impacts from GHG Emissions

In 2009, based on a large body of robust and compelling 

scientific evidence, the EPA Administrator issued the

Endangerment Finding under CAA section 202(a)(1).15 In the 

Endangerment Finding, the Administrator found that the current, 

elevated concentrations of GHGs in the atmosphere—already at 

levels unprecedented in human history—may reasonably be 

anticipated to endanger public health and welfare of current and 

future generations in the United States. We summarize these 

adverse effects on public health and welfare briefly here. 

a. Public health impacts detailed in the 2009 Endangerment 

Finding

Climate change caused by human emissions of GHGs threatens 

the health of Americans in multiple ways. By raising average 

temperatures, climate change increases the likelihood of heat 

 

14 We note that EPA’s focus on GHG (in particular methane), VOC 

and SO2 in these analyses, does not in any way limit the EPA’s 

authority to promulgate standards that would apply to other 

pollutants emitted from the oil and natural gas source category, 

if the EPA determines that such action is appropriate. 

15 “Endangerment and Cause or Contribute Findings for Greenhouse 

Gases Under Section 202(a) of the Clean Air Act,” 74 Fed. Reg. 

66496 (Dec. 15, 2009) (“Endangerment Finding”).
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waves, which are associated with increased deaths and illnesses. 

While climate change also increases the likelihood of reductions 

in cold-related mortality, evidence indicates that the increases 

in heat mortality will be larger than the decreases in cold 

mortality in the United States. Compared to a future without 

climate change, climate change is expected to increase ozone 

pollution over broad areas of the U.S., especially on the 

highest ozone days and in the largest metropolitan areas with 

the worst ozone problems, and thereby increase the risk of 

morbidity and mortality. Climate change is also expected to 

cause more intense hurricanes and more frequent and intense 

storms and heavy precipitation, with impacts on other areas of 

public health, such as the potential for increased deaths, 

injuries, infectious and waterborne diseases, and stress-related 

disorders. Children, the elderly, and the poor are among the 

most vulnerable to these climate-related health effects.

b. Public welfare impacts detailed in the 2009 Endangerment 

Finding

Climate change impacts touch nearly every aspect of public 

welfare. Among the multiple threats caused by human emissions of 

GHGs, climate changes are expected to place large areas of the 

country at serious risk of reduced water supplies, increased 
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water pollution, and increased occurrence of extreme events such 

as floods and droughts. Coastal areas are expected to face a 

multitude of increased risks, particularly from rising sea level 

and increases in the severity of storms. These communities face 

storm and flooding damage to property, or even loss of land due 

to inundation, erosion, wetland submergence and habitat loss. 

Impacts of climate change on public welfare also include 

threats to social and ecosystem services. Climate change is 

expected to result in an increase in peak electricity demand, 

Extreme weather from climate change threatens energy, 

transportation, and water resource infrastructure. Climate 

change may also exacerbate ongoing environmental pressures in 

certain settlements, particularly in Alaskan indigenous 

communities, and is very likely to fundamentally rearrange U.S. 

ecosystems over the 21st century. Though some benefits may 

balance adverse effects on agriculture and forestry in the next 

few decades, the body of evidence points towards increasing 

risks of net adverse impacts on U.S. food production, 

agriculture and forest productivity as temperature continues to 

rise. These impacts are global and may exacerbate problems 

outside the U.S. that raise humanitarian, trade, and national 

security issues for the U.S.
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c. New scientific assessments and observations

Since the administrative record concerning the Endangerment 

Finding closed following the EPA’s 2010 Reconsideration Denial, 

the climate has continued to change, with new records being set 

for a number of climate indicators such as global average 

surface temperatures, Arctic sea ice retreat, CO2 concentrations, 

and sea level rise. Additionally, a number of major scientific 

assessments have been released that improve understanding of the 

climate system and strengthen the case that GHGs endanger public 

health and welfare both for current and future generations. 

These assessments, from the Intergovernmental Panel on Climate 

Change (IPCC), the U.S. Global Change Research Program (USGCRP), 

and the National Research Council of the National Academies 

(NRC), include: IPCC’s 2012 Special Report on Managing the Risks 

of Extreme Events and Disasters to Advance Climate Change 

Adaptation (SREX) and the 2013-2014 Fifth Assessment Report 

(AR5), USGCRP’s 2014 National Climate Assessment, Climate Change 

Impacts in the United States (NCA3), and the NRC’s 2010 Ocean 

Acidification: A National Strategy to Meet the Challenges of a 

Changing Ocean (Ocean Acidification), 2011 Report on Climate 

Stabilization Targets: Emissions, Concentrations, and Impacts 

over Decades to Millennia (Climate Stabilization Targets), 2011 
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National Security Implications for U.S. Naval Forces (National 

Security Implications), 2011 Understanding Earth’s Deep Past: 

Lessons for Our Climate Future (Understanding Earth’s Deep 

Past), 2012 Sea Level Rise for the Coasts of California, Oregon, 

and Washington: Past, Present, and Future, 2012 Climate and 

Social Stress: Implications for Security Analysis (Climate and 

Social Stress), and 2013 Abrupt Impacts of Climate Change

(Abrupt Impacts) assessments. 

The EPA has carefully reviewed these recent assessments in 

keeping with the same approach outlined in Section VIII.A. of 

the 2009 Endangerment Finding, which was to rely primarily upon 

the major assessments by the USGCRP, IPCC, and the NRC to 

provide the technical and scientific information to inform the 

Administrator’s judgment regarding the question of whether GHGs 

endanger public health and welfare. These assessments addressed 

the scientific issues that the EPA was required to examine were 

comprehensive in their coverage of the GHG and climate change 

issues, and underwent rigorous and exacting peer review by the 

expert community, as well as rigorous levels of U.S. government 

review. 

The findings of the recent scientific assessments confirm 

and strengthen the conclusion that GHGs endanger public health, 
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now and in the future. The NCA3 indicates that human health in

the United States will be impacted by “increased extreme weather 

events, wildfire, decreased air quality, threats to mental 

health, and illnesses transmitted by food, water, and diseasecarriers such as mosquitoes and ticks.” The most recent 

assessments now have greater confidence that climate change will 

influence production of pollen that exacerbates asthma and other 

allergic respiratory diseases such as allergic rhinitis, as well 

as effects on conjunctivitis and dermatitis. Both the NCA3 and 

the IPCC AR5 found that increasing temperature has lengthened 

the allergenic pollen season for ragweed, and that increased CO2

by itself can elevate production of plant-based allergens. 

The NCA3 also finds that climate change, in addition to 

chronic stresses such as extreme poverty, is negatively 

affecting indigenous peoples’ health in the United States 

through impacts such as reduced access to traditional foods, 

decreased water quality, and increasing exposure to health and 

safety hazards. The IPCC AR5 finds that climate change-induced 

warming in the Arctic and resultant changes in environment 

(e.g., permafrost thaw, effects on traditional food sources) 

have significant impacts, observed now and projected, on the 

health and well-being of Arctic residents, especially indigenous 
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peoples. Small, remote, predominantly-indigenous communities are 

especially vulnerable given their “strong dependence on the 

environment for food, culture, and way of life; their political 

and economic marginalization; existing social, health, and 

poverty disparities; as well as their frequent close proximity 

to exposed locations along ocean, lake, or river shorelines.”16 

In addition, increasing temperatures and loss of Arctic sea ice 

increases the risk of drowning for those engaged in traditional 

hunting and fishing.

The NCA3 concludes that children’s unique physiology and 

developing bodies contribute to making them particularly 

vulnerable to climate change. Impacts on children are expected 

from heat waves, air pollution, infectious and waterborne 

illnesses, and mental health effects resulting from extreme 

weather events. The IPCC AR5 indicates that children are among 

those especially susceptible to most allergic diseases, as well 

as health effects associated with heat waves, storms, and 

 

16 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part B: Regional Aspects. Contribution of Working 

Group II to the Fifth Assessment Report of the Intergovernmental 

Panel on Climate Change [Barros, V.R., C.B. Field, D.J. Dokken, 

M.D. Mastrandrea, K.J. Mach, T.E. Bilir, M. Chatterjee, K.L. 

Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. Kissel, A.N. 

Levy, S. MacCracken, P.R. Mastrandrea, and L.L. White (eds.)]. 

Cambridge University Press, Cambridge, p. 1581.
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floods. The IPCC finds that additional health concerns may arise 

in low income households, especially those with children, if 

climate change reduces food availability and increases prices, 

leading to food insecurity within households.

Both the NCA3 and IPCC AR5 conclude that climate change 

will increase health risks facing the elderly. Older people are 

at much higher risk of mortality during extreme heat events.

Pre-existing health conditions also make older adults 

susceptible to cardiac and respiratory impacts of air pollution 

and to more severe consequences from infectious and waterborne 

diseases. Limited mobility among older adults can also increase 

health risks associated with extreme weather and floods.

The new assessments also confirm and strengthen the 

conclusion that GHGs endanger public welfare, and emphasize the 

urgency of reducing GHG emissions due to their projections that 

show GHG concentrations climbing to ever-increasing levels in 

the absence of mitigation. The NRC assessment Understanding 

Earth’s Deep Past projected that, without a reduction in 

emissions, CO2 concentrations by the end of the century would 

increase to levels that the Earth has not experienced for more 
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than 30 million years.17 In fact, that assessment stated that 

“the magnitude and rate of the present GHG increase place the 

climate system in what could be one of the most severe increases 

in radiative forcing of the global climate system in Earth 

history.”18 Because of these unprecedented changes, several 

assessments state that we may be approaching critical, poorly 

understood thresholds: as stated in the NRC assessment 

Understanding Earth’s Deep Past, “As Earth continues to warm, it 

may be approaching a critical climate threshold beyond which 

rapid and potentially permanent—at least on a human timescale—

changes not anticipated by climate models tuned to modern 

conditions may occur.” The NRC Abrupt Impacts report analyzed 

abrupt climate change in the physical climate system and abrupt 

impacts of ongoing changes that, when thresholds are crossed, 

can cause abrupt impacts for society and ecosystems. The report 

considered destabilization of the West Antarctic Ice Sheet 

(which could cause 3-4 m of potential sea level rise) as an 

abrupt climate impact with unknown but probably low probability 

of occurring this century. The report categorized a decrease in 

 

17 National Research Council, Understanding Earth’s Deep Past, p. 

1.

18 Id., p.138.
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ocean oxygen content (with attendant threats to aerobic marine 

life); increase in intensity, frequency, and duration of heat 

waves; and increase in frequency and intensity of extreme 

precipitation events (droughts, floods, hurricanes, and major 

storms) as climate impacts with moderate risk of an abrupt 

change within this century. The NRC Abrupt Impacts report also 

analyzed the threat of rapid state changes in ecosystems and 

species extinctions as examples of an irreversible impact that 

is expected to be exacerbated by climate change. Species at most 

risk include those whose migration potential is limited, whether 

because they live on mountaintops or fragmented habitats with 

barriers to movement, or because climatic conditions are 

changing more rapidly than the species can move or adapt. While 

the NRC determined that it is not presently possible to place 

exact probabilities on the added contribution of climate change 

to extinction, they did find that there was substantial risk 

that impacts from climate change could, within a few decades, 

drop the populations in many species below sustainable levels 

thereby committing the species to extinction. Species within 

tropical and subtropical rainforests such as the Amazon and 

species living in coral reef ecosystems were identified by the 

NRC as being particularly vulnerable to extinction over the next 
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30 to 80 years, as were species in high latitude and high 

elevation regions. Moreover, due to the time lags inherent in 

the Earth’s climate, the NRC Climate Stabilization Targets 

assessment notes that the full warming from increased GHG

concentrations will not be fully realized for several centuries, 

underscoring that emission activities today carry with them 

climate commitments far into the future. 

Future temperature changes will depend on what emission 

path the world follows. In its high emission scenario, the IPCC 

AR5 projects that global temperatures by the end of the century 

will likely be 2.6 °C to 4.8 °C (4.7 to 8.6 °F) warmer than 

today. Temperatures on land and in northern latitudes will 

likely warm even faster than the global average. However, 

according to the NCA3, significant reductions in emissions would 

lead to noticeably less future warming beyond mid-century, and 

therefore less impact to public health and welfare. 

While rainfall may only see small globally and annually 

averaged changes, there are expected to be substantial shifts in 

where and when that precipitation falls. According to the NCA3, 

regions closer to the poles will see more precipitation, while 

the dry subtropics are expected to expand (colloquially, this 

has been summarized as wet areas getting wetter and dry regions 
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getting drier). In particular, the NCA3 notes that the western 

U.S., and especially the Southwest, is expected to become drier. 

This projection is consistent with the recent observed drought 

trend in the West. At the time of publication of the NCA, even 

before the last 2 years of extreme drought in California, tree 

ring data were already indicating that the region might be 

experiencing its driest period in 800 years. Similarly, the NCA3 

projects that heavy downpours are expected to increase in many 

regions, with precipitation events in general becoming less 

frequent but more intense. This trend has already been observed 

in regions such as the Midwest, Northeast, and upper Great 

Plains. Meanwhile, the NRC Climate Stabilization Targets 

assessment found that the area burned by wildfire is expected to 

grow by 2 to 4 times for 1 °C (1.8 °F) of warming. For 3 °C of 

warming, the assessment found that 9 out of 10 summers would be 

warmer than all but the 5 percent of warmest summers today, 

leading to increased frequency, duration, and intensity of heat 

waves. Extrapolations by the NCA also indicate that Arctic sea 

ice in summer may essentially disappear by mid-century. 

Retreating snow and ice, and emissions of carbon dioxide and 

methane released from thawing permafrost, will also amplify 

future warming. 
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Since the 2009 Endangerment Finding, the USGCRP NCA3, and 

multiple NRC assessments have projected future rates of sea 

level rise that are 40 percent larger to more than twice as 

large as the previous estimates from the 2007 IPCC 4th Assessment 

Report due in part to improved understanding of the future rate 

of melt of the Antarctic and Greenland ice sheets. The NRC Sea 

Level Rise assessment projects a global sea level rise of 0.5 to 

1.4 meters (1.6 to 4.6 feet) by 2100, the NRC National Security 

Implications assessment suggests that “the Department of the 

Navy should expect roughly 0.4 to 2 meters (1.3 to 6.6 feet)

global average sea-level rise by 2100,”19 and the NRC Climate 

Stabilization Targets assessment states that an increase of 3°C 

will lead to a sea level rise of 0.5 to 1 meter (1.6 to 3.3 

feet) by 2100. These assessments continue to recognize that 

there is uncertainty inherent in accounting for ice sheet 

processes. Additionally, local sea level rise can differ from 

the global total depending on various factors: the east coast of 

the U.S. in particular is expected to see higher rates of sea 

level rise than the global average. For comparison, the NCA3 

states that “five million Americans and hundreds of billions of 

 

19 NRC, 2011: National Security Implications of Climate Change 

for U.S. Naval Forces. The National Academies Press, p. 28.
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dollars of property are located in areas that are less than four 

feet above the local high-tide level,” and the NCA3 finds that 

“[c]oastal infrastructure, including roads, rail lines, energy 

infrastructure, airports, port facilities, and military bases, 

are increasingly at risk from sea level rise and damaging storm 

surges.”20 Also, because of the inertia of the oceans, sea level 

rise will continue for centuries after GHG concentrations have 

stabilized (though more slowly than it would have otherwise). 

Additionally, there is a threshold temperature above which the 

Greenland ice sheet will be committed to inevitable melting: 

according to the NCA, some recent research has suggested that 

even present day carbon dioxide levels could be sufficient to 

exceed that threshold.

In general, climate change impacts are expected to be 

unevenly distributed across different regions of the United 

States and have a greater impact on certain populations, such as 

indigenous peoples and the poor. The NCA3 finds climate change 

impacts such as the rapid pace of temperature rise, coastal 

erosion and inundation related to sea level rise and storms, ice 

 

20 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, p. 9.
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and snow melt, and permafrost thaw are affecting indigenous 

people in the United States. Particularly in Alaska, critical 

infrastructure and traditional livelihoods are threatened by 

climate change and, “[i]n parts of Alaska, Louisiana, the 

Pacific Islands, and other coastal locations, climate change 

impacts (through erosion and inundation) are so severe that some 

communities are already relocating from historical homelands to 

which their traditions and cultural identities are tied.”21 The 

IPCC AR5 notes, “Climate-related hazards exacerbate other 

stressors, often with negative outcomes for livelihoods, 

especially for people living in poverty (high confidence).

Climate-related hazards affect poor people’s lives directly 

through impacts on livelihoods, reductions in crop yields, or 

destruction of homes and indirectly through, for example, 

increased food prices and food insecurity.”22 

 

21 Melillo, Jerry M., Terese (T.C.) Richmond, and Gary W. Yohe, 

Eds., 2014: Climate Change Impacts in the United States: The 

Third National Climate Assessment. U.S. Global Change Research 

Program, p. 17.

22 IPCC, 2014: Climate Change 2014: Impacts, Adaptation, and 

Vulnerability. Part A: Global and Sectoral Aspects. Contribution 

of Working Group II to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Field, C.B., V.R. 

Barros, D.J. Dokken, K.J. Mach, M.D. Mastrandrea, T.E. Bilir, M. 

Chatterjee, K.L. Ebi, Y.O. Estrada, R.C. Genova, B. Girma, E.S. 

Kissel, A.N. Levy, S. MacCracken, P.R. Mastrandrea, and L.L. 

White (eds.)]. Cambridge University Press, p. 796.
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Events outside the United States, as also pointed out in 

the 2009 Endangerment Finding, will also have relevant 

consequences. The NRC Climate and Social Stress assessment 

concluded that it is prudent to expect that some climate events 

“will produce consequences that exceed the capacity of the 

affected societies or global systems to manage and that have 

global security implications serious enough to compel 

international response.” The NRC National Security Implications 

assessment recommends preparing for increased needs for 

humanitarian aid; responding to the effects of climate change in 

geopolitical hotspots, including possible mass migrations; and 

addressing changing security needs in the Arctic as sea ice 

retreats.

In addition to future impacts, the NCA3 emphasizes that 

climate change driven by human emissions of GHGs is already 

happening now and it is happening in the United States. 

According to the IPCC AR5 and the NCA3, there are a number of 

climate-related changes that have been observed recently, and 

these changes are projected to accelerate in the future. The 

planet warmed about 0.85 °C (1.5 °F) from 1880 to 2012. It is 

extremely likely (>95% probability) that human influence was the 

dominant cause of the observed warming since the mid-20th
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century, and likely (>66% probability) that human influence has 

more than doubled the probability of occurrence of heat waves in 

some locations. In the Northern Hemisphere, the last 30 years 

were likely the warmest 30 year period of the last 1400 years. 

U.S. average temperatures have similarly increased by 1.3 to 1.9 

degrees F since 1895, with most of that increase occurring since 

1970. Global sea levels rose 0.19 m (7.5 inches) from 1901 to 

2010. Contributing to this rise was the warming of the oceans 

and melting of land ice. It is likely that 275 gigatons per year 

of ice melted from land glaciers (not including ice sheets) 

since 1993, and that the rate of loss of ice from the Greenland 

and Antarctic ice sheets increased substantially in recent 

years, to 215 gigatons per year and 147 gigatons per year 

respectively since 2002. For context, 360 gigatons of ice melt 

is sufficient to cause global sea levels to rise 1 millimeter 

(mm). Annual mean Arctic sea ice has been declining at 3.5 to 

4.1 percent per decade, and Northern Hemisphere snow cover 

extent has decreased at about 1.6 percent per decade for March 

and 11.7 percent per decade for June. Permafrost temperatures 

have increased in most regions since the 1980s, by up to 3 °C 

(5.4 °F) in parts of Northern Alaska. Winter storm frequency and 

intensity have both increased in the Northern Hemisphere. The 
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NCA3 states that the increases in the severity or frequency of 

some types of extreme weather and climate events in recent 

decades can affect energy production and delivery, causing 

supply disruptions, and compromise other essential 

infrastructure such as water and transportation systems.

In addition to the changes documented in the assessment 

literature, there have been other climate milestones of note. 

According to the IPCC, methane concentrations in 2011 were about 

1803 parts per billion, 150 percent higher than concentrations 

were in 1750. After a few years of nearly stable concentrations 

from 1999 to 2006, methane concentrations have resumed 

increasing at about 5 parts per billion per year. Concentrations 

today are likely higher than they have been for at least the 

past 800,000 years. Arctic sea ice has continued to decline, 

with September of 2012 marking a new record low in terms of 

Arctic sea ice extent, 40 percent below the 1979-2000 median. 

Sea level has continued to rise at a rate of 3.2 mm per year 

(1.3 inches/decade) since satellite observations started in 

1993, more than twice the average rate of rise in the 20th

century prior to 1993.23 And 2014 was the warmest year globally 

 

23 Blunden, J., and D. S. Arndt, Eds., 2014: State of the Climate 

in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.
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in the modern global surface temperature record, going back to 

1880; this now means 19 of the 20 warmest years have occurred in 

the past 20 years, and except for 1998, the ten warmest years on 

record have occurred since 2002.24 The first months of 2015 have 

also been some of the warmest on record. 

These assessments and observed changes make it clear that 

reducing emissions of GHGs across the globe is necessary in 

order to avoid the worst impacts of climate change, and

underscore the urgency of reducing emissions now. The NRC 

Committee on America’s Climate Choices listed a number of 

reasons “why it is imprudent to delay actions that at least 

begin the process of substantially reducing emissions.”25 For 

example:

• The faster emissions are reduced, the lower the risks 

posed by climate change. Delays in reducing emissions 

could commit the planet to a wide range of adverse 

impacts, especially if the sensitivity of the climate 

to GHGs is on the higher end of the estimated range.

 

24 http://www.ncdc.noaa.gov/sotc/global/2014/13. 25 NRC, 2011: America’s Climate Choices, The National Academies 

Press.
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• Waiting for unacceptable impacts to occur before 

taking action is imprudent because the effects of GHG

emissions do not fully manifest themselves for decades 

and, once manifest, many of these changes will persist 

for hundreds or even thousands of years.

• In the committee’s judgment, the risks associated with 

doing business as usual are a much greater concern 

than the risks associated with engaging in strong 

response efforts.

Methane is also a precursor to ground-level ozone, a 

health-harmful air pollutant. Additionally, ozone is a shortlived climate forcer that contributes to global warming. In 

remote areas, methane is a dominant precursor to tropospheric 

ozone formation.26 Approximately 50 percent of the global annual 

mean ozone increase since preindustrial times is believed to be 

due to anthropogenic methane.27 Projections of future emissions 

 

26 U.S. EPA. 2013. “Integrated Science Assessment for Ozone and 

Related Photochemical Oxidants (Final Report).” EPA-600-R-10-

076F. National Center for Environmental Assessment—RTP Division. 

Available at http://www.epa.gov/ncea/isa/. 27 Myhre, G., D. Shindell, F.-M. Bréon, W. Collins, J. 

Fuglestvedt, J. Huang, D. Koch, J.-F. Lamarque, D. Lee, B. 

Mendoza, T. Nakajima, A. Robock, G. Stephens, T. Takemura and H. 

Zhang, 2013: Anthropogenic and Natural Radiative Forcing. In: 

Climate Change 2013: The Physical Science Basis. Contribution of 
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also indicate that methane is likely to be a key contributor to 

ozone concentrations in the future.28 Unlike nitrogen oxide (NOX) 

and VOC, which affect ozone concentrations regionally and at 

hourly time scales, methane emissions affect ozone 

concentrations globally and on decadal time scales given 

methane’s relatively long atmospheric lifetime compared to these 

other ozone precursors.29 Reducing methane emissions, therefore, 

may contribute to efforts to reduce global background ozone 

concentrations that contribute to the incidence of ozone-related 

health effects.30,31 These benefits are global and occur in both 

urban and rural areas.

2. VOC

Tropospheric, or ground-level, ozone is formed through 

reactions of VOC and NOx in the presence of sunlight. Ozone 

 

Working Group I to the Fifth Assessment Report of the 

Intergovernmental Panel on Climate Change [Stocker, T.F., D. 

Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. 

Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge 

University Press, Cambridge, United Kingdom and New York, NY, 

USA. Pg. 680.

28 Ibid. 29 Ibid. 30 West, J.J., Fiore, A.M. 2005. “Management of tropospheric 

ozone by reducing methane emissions.” Environ. Sci. Technol.

39:4685-4691. 31 Anenberg, S.C., et al. 2009. “Intercontinental impacts of 

ozone pollution on human mortality,” Environ. Sci. & Technol.

43: 6482-6487.
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formation can be controlled to some extent through reductions in 

emissions of ozone precursor VOC and NOx. A significantly 

expanded body of scientific evidence shows that ozone can cause 

a number of harmful effects on health and the environment. 

Exposure to ozone can cause respiratory system effects such as 

difficulty breathing and airway inflammation. For people with 

lung diseases such as asthma and chronic obstructive pulmonary 

disease (COPD), these effects can lead to emergency room visits 

and hospital admissions. Studies have also found that ozone 

exposure is likely to cause premature death from lung or heart 

diseases. In addition, evidence indicates that long-term 

exposure to ozone is likely to result in harmful respiratory 

effects, including respiratory symptoms and the development of 

asthma. People most at risk from breathing air containing ozone 

include: children; people with asthma and other respiratory 

diseases; older adults; and people who are active outdoors, 

especially outdoor workers. An estimated 25.9 million people 

have asthma in the U.S., including almost 7.1 million children. 

Asthma disproportionately affects children, families with lower 
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incomes, and minorities, including Puerto Ricans, Native 

Americans/Alaska Natives and African-Americans.32

Scientific evidence also shows that repeated exposure to 

ozone reduces growth and has other harmful effects on plants and 

trees. These types of effects have the potential to impact 

ecosystems and the benefits they provide.

3. SO2

Current scientific evidence links short-term exposures to 

SO2, ranging from 5 minutes to 24 hours, with an array of adverse 

respiratory effects including bronchoconstriction and increased 

asthma symptoms. These effects are particularly important for 

asthmatics at elevated ventilation rates (e.g., while exercising 

or playing). 

Studies also show an association between short-term 

exposure and increased visits to emergency departments and 

hospital admissions for respiratory illnesses, particularly in 

at-risk populations including children, the elderly, and 

asthmatics.

SO2 in the air can also damage the leaves of plants, 

decrease their ability to produce food – photosynthesis – and 

 

32 National Health Interview Survey (NHIS) Data, 2011 

http://www.cdc.gov/asthma/nhis/2011/data.htm
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decrease their growth. In addition to directly affecting plants, 

SO2 when deposited on land and in estuaries, lakes and streams, 

can acidify sensitive ecosystems resulting in a range of harmful 

indirect effects on plants, soils, water quality, and fish and 

wildlife (e.g., changes in biodiversity and loss of habitat, 

reduced tree growth, loss of fish species). Sulfur deposition to 

waterways also plays a causal role in the methylation of 

mercury.33

4. Emission Estimates 

Section VI.A above explains how GHGs, VOC, and SO2 emissions 

are “air pollution” that may reasonably be anticipated to 

endanger public health and welfare. This section provides 

estimated emissions that the oil and natural gas source category 

contributes to this air pollution. As shown below, the 

contribution from this industry is quite significant. 

a. GHG Emissions

 

33 U.S. EPA. Integrated Science Assessment (ISA) for Oxides of 

Nitrogen and Sulfur Ecological Criteria (2008 Final Report). 

U.S. Environmental Protection Agency, Washington, DC, EPA/600/R08/082F, 2008.
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Atmospheric concentrations of GHGs are now at essentially 

unprecedented levels compared to the distant and recent past.34

This is the unambiguous result of emissions of these gases from 

human activities. Global emissions of well-mixed GHGs have been 

increasing, and are projected to continue increasing for the 

foreseeable future. According to IPCC AR5, total global 

emissions of GHGs in 2010 were about 49,000 million metric tons35

of CO2 equivalent (MMT CO2eq).36 This represents an increase in 

global GHG emissions of about 29 percent since 1990 and 23 

percent since 2000. In 2010, total U.S. GHG emissions were 

responsible for about 14 percent of global GHG emissions (and 

about 12 percent when factoring in the effect of carbon sinks 

from U.S. land use and forestry). 

 

34 IPCC, 2013: Summary for Policymakers. In: Climate Change 2013: 

The Physical Science Basis. Contribution of Working Group I to 

the Fifth Assessment Report of the Intergovernmental Panel on 

Climate Change [Stocker, T.F., D. Qin, G.-K. Plattner, M. 

Tignor, S.K. Allen, J. Boschung, A. Nauels, Y. Xia, V. Bex and 

P.M. Midgley (eds.)]. Cambridge University Press, p. 11.

35 One MMT = 1 million metric tons = 1 megatonne (Mt). 1 metric 

ton = 1,000 kg = 1.102 short tons = 2,205 lbs. 

36 IPCC, 2014: Climate Change 2014: Mitigation of Climate Change. 

Contribution of Working Group III to the Fifth Assessment Report 

of the Intergovernmental Panel on Climate Change [Edenhofer, O., 

R. Pichs-Madruga, Y. Sokona, E. Farahani, S. Kadner, K. Seyboth, 

A. Adler, I. Baum, S. Brunner, P. Eickemeier, B. Kriemann, J. 

Savolainen, S. Schlömer, C. von Stechow, T. Zwickel and J.C. 

Minx (eds.)]. Cambridge University Press, 1435 pp. 
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Based on the Inventory of U.S. Greenhouse Gas Emissions and 

Sinks Report37 (hereinafter “U.S. GHG Inventory”), in 2013 total 

U.S. GHG emissions increased by 5.9 percent from 1990 (or by 

about 4.8 percent when including the effects of carbon sinks), 

and increased from 2012 to 2013 by 2.0 percent. This increase 

was attributable to multiple factors including increased carbon 

intensity of fuels consumed to generate electricity, a 

relatively cool winter leading to an increase in heating 

requirements, an increase in industrial production across 

multiple sectors and a small increase in vehicle miles traveled 

(VMT) and fuel use across on-road transportation modes.

Because 2010 is the most recent year for which IPCC 

emissions data are available, we provide 2011 estimates from the 

World Resources Institute’s (WRI) Climate Analysis Indicators 

Tool (CAIT)38 for comparison. According to WRI/CAIT, the total 

global GHG emissions in 2011 were 43,816 MMT of CO2 Eq., 

representing an increase in global GHG emissions of about 42 

 

37 U.S. EPA, 2014: Inventory of U.S. Greenhouse Gas Emissions and 

Sinks: 1990–2012. Available at 

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.

html#fullreport (Last accessed January 29, 2015). 38 World Resources Institute (WRI) Climate Analysis Indicators

Tool (CAIT) Data Explorer (Version 2.0). Available at 

http://cait.wri.org. (Last accessed October 31, 2014.) 
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percent since 1990 and 30 percent since 2000 (excluding land 

use, land use change and forestry). These estimates are 

generally consistent with those of IPCC. In 2011, WRI/CAIT data 

indicate that total U.S. GHG emissions were responsible for 

almost 15.5 percent of global emissions, which is also generally 

in line with the percentages using IPCC’s 2010 estimate 

described above. According to WRI/CAIT, current U.S. GHG 

emissions rank only behind China’s, which was responsible for 24 

percent of total global GHG emissions. 

i. Methane Emissions in the United States and from the Oil and 

Natural Gas Industry

The GHGs addressed by the 2009 Endangerment Finding 

consist of six well-mixed gases, including methane. Methane is a 

potent GHG with a 100 year GWP that is 28-36 times greater than 

that of carbon dioxide.39 Methane has an atmospheric life of 

about 12 years. Official U.S. estimates of national level GHG 

emissions and sinks are developed by the EPA for the U.S. GHG 

 

39 IPCC, 2013: Climate Change 2013: The Physical Science Basis. 

Contribution of Working Group I to the Fifth Assessment Report 

of the Intergovernmental Panel on Climate Change [Stocker, T.F., 

D. Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. 

Nauels, Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge 

University Press, Cambridge, United Kingdom and New York, NY, 

USA, 1535 pp. Note that for purposes of inventories and 

reporting, GWP values from the 4th Assessment Report may be 

used.
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Inventory to comply with commitments under the United Nations 

Framework Convention on Climate Change (UNFCCC). The U.S.

inventory, which includes recent trends, is organized by 

industrial sectors. Natural gas and petroleum systems are the 

largest emitters of methane in the U.S. These systems emit 29

percent of U.S. anthropogenic methane. 

Table 2 below presents total U.S. anthropogenic methane 

emissions for the years 1990, 2005 and 2013. 

Table 2—U.S. METHANE EMISSIONS BY SECTOR (MILLION METRIC TON 

CARBON DIOXIDE EQUIVALENT (MMT CO2 Eq.))

Sector 1990 2005 2013

Oil and 

Natural Gas 

Production, 

and Natural 

Gas Processing 

and 

Transmission

170.0 163.5 148.3

Enteric 

Fermentation

164.2 168.9 164.5

Landfills 186.2 165.5 114.6

Coal Mining 96.5 64.1 64.6

Manure 

Management

37.2 56.3 61.4

Other Methane 

Sources40

91.4 89.5 82.9

 

40 Other sources include remaining natural gas distribution, 

petroleum transport and petroleum refineries, forest land, 

wastewater treatment, rice cultivation, stationary combustion, 

abandoned coal mines, petrochemical production, mobile 
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Total Methane 

Emissions

745.5 707.8 636.3

Emissions from the U.S. GHG Inventory, calculated using GWP of 25.

Oil and natural gas production and natural gas processing 

and transmission systems encompass wells, natural gas gathering 

and processing facilities, storage, and transmission pipelines. 

These components are all important aspects of the natural gas 

cycle—the process of getting natural gas out of the ground and 

to the end user. In the oil industry, some underground crude oil 

contains natural gas that is entrained in the oil at high 

reservoir pressures. When oil is removed from the reservoir, 

associated natural gas is produced.

Methane emissions occur throughout the natural gas 

industry. They primarily result from normal operations, routine 

maintenance, fugitive leaks and system upsets. As gas moves 

through the system, emissions occur through intentional venting 

and unintentional leaks. Venting can occur through equipment

design or operational practices, such as the continuous bleed of 

gas from pneumatic controllers (that control gas flows, levels, 

temperatures, and pressures in the equipment), or venting from 

well completions during production. In addition to vented 

 

combustion, composting, and several sources emitting less than 1 

MMT CO2-e in 2013.
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emissions, methane losses can occur from leaks (also referred to 

as fugitive emissions) in all parts of the infrastructure, from 

connections between pipes and vessels, to valves and equipment.

In petroleum systems, methane emissions result primarily 

from field production operations, such as venting of associated 

gas from oil wells, oil storage tanks, and production-related 

equipment such as gas dehydrators, pig traps, and pneumatic 

devices.

Table 3 (a and b) below present total methane emissions 

from natural gas and petroleum systems, and the associated 

segments of the sector, for years 1990, 2005 and 2013, in 

million metric tons of carbon dioxide equivalent (Table 3(a)) 

and kilotons (or thousand metric tons) of methane (Table 3(b)). 

TABLE 3(a)—U.S. METHANE EMISSIONS FROM NATURAL GAS AND PETROLEUM 

SYSTEMS (MMT CO2 Eq.)

Sector 1990 2005 2013

Oil and 

Natural Gas 

Production and 

Natural Gas 

Processing and 

Transmission

(Total)

170 163 148

Natural Gas 

Production

59 75 47

Natural Gas 

Processing

21 16 23
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Natural Gas 

Transmission 

and Storage

59 49 54

Petroleum 

Production

31 23 24

Emissions from the 2015 U.S. GHG Inventory, calculated using GWP of 25.

TABLE 3(b)—U.S. METHANE EMISSIONS FROM NATURAL GAS AND PETROLEUM 

SYSTEMS (kt CH4)

Sector 1990 2005 2013

Oil and 

Natural Gas 

Production and 

Natural Gas 

Processing and 

Transmission

(Total)

 6,802 6,539 5,930 

Natural Gas 

Production 2,380 3,018 1,879 

Natural Gas 

Processing 852 655 906 

Natural Gas 

Transmission 

and Storage

 2,343 1,963 2,176 

Petroleum 

Production 1,227 903 969 

Emissions from the 2015 U.S. GHG Inventory, in kt (1,000 tons) of CH4.

ii. U.S. Oil and Natural Gas Production and Natural Gas 

Processing and Transmission GHG Emissions Relative to Total U.S. 

GHG Emissions

Relying on data from the U.S. GHG Inventory, we compared

U.S. oil and natural gas production and natural gas processing 

and transmission GHG emissions to total U.S. GHG emissions as an 
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indication of the role this source plays in the total domestic 

contribution to the air pollution that is causing climate 

change. In 2013, total U.S. GHG emissions from all sources were 

6,673 MMT CO2 Eq. 

For purposes of the proposed revision to the category 

listing, the EPA is including oil and natural gas production 

sources, and natural gas processing transmission sources. In 

2013, emissions from oil and natural gas production sources and 

natural gas processing and transmission sources accounted for 

148 MMT CO2eq methane emissions and oil completions for another 3 

MMT CO2eq (using a GWP of 25 for methane). The sector also 

emitted 44 MMT of CO2, mainly from acid gas removal during 

natural gas processing (22 MMT) and flaring in oil and natural 

gas production (16 MMT). In total, these emissions account for

3.0 percent of total U.S. domestic emissions. 

In regard to the six well-mixed GHGs (CO2, methane, nitrous 

oxide, hydrofluorocarbons, perfluorocarbons, and sulfur 

hexafluoride), only two of these gases - CO2 and methane – are 

reported as non-zero emissions for the oil and natural gas

production sources and natural gas processing and transmission 

sources that are being addressed within this rule. 
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TABLE 4-COMPARISONS OF U.S. OIL AND NATURAL GAS PRODUCTION AND 

NATURAL GAS PROCESSING AND TRANSMISSION GHG EMISSIONS TO TOTAL 

U.S. GHG EMISSIONS 

2010 2011 2012 2013

Total U.S. 

Oil & Gas 

Production 

and Natural 

Gas 

Processing & 

Transmission 

GHG 

Emissions 

(MMT CO2 Eq)

147 147 146 148

Share of 

Total U.S. 

GHG 

Inventory

2.13% 2.18% 2.23% 2.22%

Total U.S. 

GHG 

Emissions 

(MMT CO2 Eq)

6,899 6,777 6,545 6,673

iii. U.S. Oil and Natural Gas Production and Natural Gas 

Processing and Transmission GHG Emissions Relative to Total 

Global GHG Emissions 

TABLE 5-COMPARISONS OF U.S. OIL AND NATURAL GAS PRODUCTION AND 

NATURAL GAS PROCESSING AND TRANSMISSION GHG EMISSIONS TO TOTAL 

GLOBAL GREENHOUSE GAS EMISSIONS IN 2010

2010

(MMT CO2 

eq)

Total U.S. Oil and Natural 

Gas Production and Natural 

Gas Processing and 

Transmission 

Share (%)
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Total Global 

GHG 

Emissions

49,000 0.3%

For additional background information and context, we used 

2011 WRI/CAIT and IEA data to make comparisons between U.S. oil 

and natural gas production and natural gas processing and 

transmission emissions and the emissions inventories of entire 

countries and regions. Ranking U.S. emissions of GHGs from oil 

and natural gas production and natural gas processing and 

transmission against total GHG emissions for entire countries, 

show that these emissions would be more than the national-level 

emissions totals for all anthropogenic sources for Greece, the 

Czech Republic, Chile, Belgium, and about 140 other countries. 

As illustrated by the data summarized above, the collective 

GHG emissions from oil and natural gas production and natural 

gas processing and transmission sources are significant, whether 

the comparison is domestic (3.0 percent of total U.S. emissions) 

or global (0.3 percent of all global GHG emissions). The EPA

believes that consideration of the global context is important. 

GHG emissions from U.S. oil and natural gas production and 

natural gas processing and transmission will become globally 

well-mixed in the atmosphere, and thus will have an effect on 
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the U.S. regional climate, as well as the global climate as a 

whole for years and indeed many decades to come. Based on the 

data above, GHG emissions from the oil and natural gas source 

category is significiant whether only the domestic context is 

considered, only the global context is considered, or both the 

domestic and global GHG emissions comparisons are viewed in 

combination. 

As was the case in 2009, no single GHG source category 

dominates on the global scale, and many (if not all) individual 

GHG source categories could appear small in comparison to the 

total, when, in fact, they could be very important contributors 

in terms of both absolute emissions or in comparison to other 

source categories, globally or within the U.S. Contributions of 

GHG to the global problem should not be compared to 

contributions associated with local air pollution problems. The 

EPA continues to believe that these unique, global aspects of 

the climate change problem — including that from a percentage 

perspective there are no dominating sources emitting GHGs and 

fewer sources that would even be considered to be close to 

dominating — tend to support consideration of contribution to 

the air pollution at lower percentage levels than the EPA

typically encounters when analyzing contribution towards a more 
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localized air pollution problem. Thus, the EPA, similar to the 

approach taken in the 2009 Finding, is placing significant 

weight on the fact that oil and natural gas production and 

natural gas processing and transmission sources contribute 3

percent of total U.S. GHG emissions for the contribution 

finding. 

b. VOC Emissions

The EPA National Emissions Inventory (NEI) estimated total 

VOC emissions from the oil and natural gas sector to be 

2,782,000 tons in 2011. This ranks second of all the sectors 

estimated by the NEI and first of all the anthropogenic sectors 

in the NEI.

c. SO2 Emissions

The NEI estimated total SO2 emissions from the oil and 

natural gas sector to be 74,000 tons in 2011. This ranks 13th of 

the sectors estimated by the NEI.

5. Conclusion 

In summary, EPA interprets the 1979 category listing to 

broadly cover the oil and natural gas industry, including all 

segments of the natural gas industry (production, processing, 

transmission, and storage). To the extent there is ambiguity to 
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the prior listing, EPA is proposing to revise the category 

listing to include the various segments of the natural gas 

industry. In support, EPA notes its previous determination under 

section 111(b)(1)(A) for the oil and natural gas source 

category. In addition, EPA provides in this section information 

and analyses detailing the public health and welfare impacts of 

GHG, VOC and SO2 emissions and the amount of these emission from 

the oil and natural gas source category (in particular from the 

various segments of the natural gas industry). Although EPA does 

not believe the proposed revision to the category listing is 

required for the standards we are proposing in this action, even 

assuming it is, the proposal is well justified.

B. Stakeholder Input

1. White papers

As a follow up to the 2013 Climate Action Plan, the Climate 

Action Plan: Strategy to Reduce Methane Emissions (the Methane 

Strategy) was released in March 2014. The Methane Strategy 

instructed the EPA to release a series of white papers on 

several potentially significant sources of methane in the oil 

and natural gas sector and solicit input from independent 

experts. The papers were released in April 2014, and focused on 

technical issues, covering emissions and control technologies 
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that target both VOC and methane with particular focus on 

completions of hydraulically fractured oil wells, liquids 

unloading, leaks, pneumatic devices and compressors. The peer 

review process was completed on June 16, 2014.

The peer review and public comments on the white papers 

included additional technical information that provided further 

clarification of our understanding of the emission sources and 

emission control options. The comments also provided additional 

data on emissions and number of sources, and pointed out newly 

published studies that further informed our emission rate 

estimates. Where appropriate, we used the information and data 

provided to adjust the control options considered and the 

impacts estimates presented in the 2015 TSD.

The EPA used an ad hoc external peer review process, as 

outlined in the EPA’s Peer Review Handbook, 3rd Edition. Under 

that process, the Agency submitted names recommended by industry 

and environmental groups, along with state, tribal, and academic 

organizations to an outside contractor. To avoid any conflict of 

interest, the contractor did not work on the white papers and is 

not working on the EPA’s oil and natural gas regulations or 

voluntary programs. The contractor built a list of qualified 

reviewers from these names and their own research, reviewed 
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appropriate credentials and selected reviewers from the list. A

different set of reviewers was selected for each white paper, 

based on the reviewers’ expertise. A total of 26 sets of 

comments from peer reviewers were submitted to the EPA. 

Additionally, the EPA solicited technical information and data 

from the public. The EPA received over 43,000 submissions from

the public. The comments received from the peer reviewers are 

available on EPA’s oil and natural gas white paper Web site

(http://www.epa.gov/airquality/oilandgas/methane.html). Public 

comments on the white papers are available in EPA’s 

nonregulatory docket at www.regulations.gov, docket ID # EPA-HQOAR-2014-0557.

2. Outreach to state, local and tribal governments

The EPA spoke with state, local and tribal governments to hear 

how they have managed issues, and to get feedback that would 

help us as we develop the rule. In February 2015, the EPA 

asked states and tribes to nominate themselves to participate 

in discussions. Twelve states, three tribes and several local 

air districts participated. We conducted several 

teleconferences in March and April 2015 to discuss such 

questions as:
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• Whether these governments are, or have considered, 

regulating the sources identified in the white papers

• Factors considered in determining whether to regulate 

them 

• Use of innovative compliance options 

• Experiences implementing control techniques guidelines 

(CTGs)41

• Information and features that would be helpful to include 

in a CTG

• Whether any sources of emissions are particularly 

suitable to voluntary rather than regulatory action

In addition to the outreach described above, the EPA 

consulted with tribal officials under the “EPA Policy on 

Consultation and Coordination with Indian Tribes” early in the 

process of developing this regulation to provide them with the 

opportunity to have meaningful and timely input into its 

development. Additionally, the EPA has conducted meaningful 

involvement with tribal stakeholders throughout the rulemaking 

process and provided an update on the methane strategy to the

National Tribal Air Association. Consistent with previous 

 

41 Control techniques guidelines are not part of this action.
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actions affecting the oil and natural gas sector, there is 

significant tribal interest because of the growth of the oil and 

natural gas production in Indian country. The EPA specifically 

solicits additional comment on this proposed action from tribal 

officials.

VII. Summary of Proposed Standards

A. Control of Methane and VOC Emissions in the Oil and Natural 

Gas Source Category

In this action, we propose to set emission standards for

methane and VOC for certain new, modified and reconstructed 

emission sources across the oil and natural gas source category. 

For some of these sources, there are VOC requirements currently 

in place that were established in the 2012 NSPS. For others, for 

which there are no current requirements, we are proposing 

methane and VOC standards. We are also proposing improvements to 

enhance implementation of the current standards. The EPA is 

soliciting comment on whether it is appropriate to establish 

standards by emission source for each pollutant within each 

segment of the oil and gas category. For example, this approach 

could result in a standard for pneumatic controllers predicated 

on VOC emissions in the production segment, while establishing a 
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standard predicated on methane emissions in the transmission and 

storage segment. 

For the reasons explained in section V, EPA believes that 

the proposed methane standards are warranted, even for those 

already subject to VOC standards under the 2012 NSPS. Further, 

as shown in the analyses in section VIII, there are cost 

effective controls that achieve simultaneous reductions of 

methane and VOC emission. That said, EPA acknowledges that there 

is no additional methane reductions from the proposed methane 

standards for those already subject to VOC standards. EPA is 

also aware that, depending on the segment of the industry, the 

VOC emissions may be high while methane emissions are low and 

vice versa. In light of the above, The EPA is soliciting comment 

on whether it is appropriate to evaluate the emissions of the 

two pollutants separately for each emission source within each 

segment of the oil and gas category. For example, based on 

methane and VOC emissions from pneumatic controllers, this 

approach could result in just a VOC standard for pneumatic 

controllers in the production segment and a methane standard in 

the transmission and storage segment.

Pursuant to CAA section 111(b), we are proposing to amend

subpart OOOO and to create a new subpart OOOOa which will 
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include the standards and requirements summarized in this 

section. Subpart OOOO would be amended to apply to facilities 

constructed, modified or reconstructed after August 23, 2011, 

(i.e., the original proposal date of subpart OOOO) and before 

[date of publication in the Federal Register] (i.e., the 

proposal date of the new subpart OOOOa) and would be amended 

only to include the revisions reflecting implementation 

improvements in response to issues raised in petitions for 

reconsideration. Subpart OOOOa would apply to facilities 

constructed, modified or reconstructed after [date of 

publication in the Federal Register] and would include current 

VOC requirements already provided in subpart OOOO as well as new 

provisions for methane and VOC across the oil and natural gas 

source category as highlighted below in this section. More 

details of the rationale for these proposed standards and 

requirements are provided in section VIII of this preamble. 

We note that the terms “emission source,” “source type” and 

“source,” as used in this preamble, refer to equipment, 

processes and activities that emit VOC and/or methane. This term 

does not refer to specific facilities, in contrast to usage of 

the term “source” in the contexts of permitting and section 112 

actions. As summarized below and discussed in more detail in 
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section VIII, the BSER for methane is the same as that for VOC

for all emission sources, including those currently subject to 

VOC standards and for which we are proposing to establish 

methane standards in this action. Accordingly, the current 

requirements reflect the BSER for both VOC and methane for these 

sources. We are, therefore, not proposing any change to the 

current requirements for emission sources addressed under the 

2012 NSPS.

Both VOC and methane are hydrocarbon compounds and behave 

essentially the same when emitted together or separately. 

Accordingly, the available controls for methane are the same as 

those for VOC and achieve the same levels of reduction for both 

VOC and methane. For example, combustion-based control 

technologies (e.g., flares and enclosed combustors) that reduce 

VOC emissions by 95 percent can be expected to also reduce 

methane emissions by 95 percent. Similarly, work practice and 

operational standards (e.g., leak detection and reduced emission 

completion of wells) that reduce emissions of VOC can be 

expected to have the same effect on methane emissions. Because 

VOC control technologies perform the same when used to control 

methane emissions, the BSER for methane is the same as the BSER 

for VOC. Therefore, we are proposing performance and operational 
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standards to control methane and VOC emissions for certain 

emission sources across the source category. These proposed 

methane standards would require no change to the requirements 

for currently regulated affected facilities.

Please note that there are minor differences in some values 

presented in various documents supporting this action. This is 

because some calculations have been performed independently 

(e.g., TSD calculations focused on unit-level cost-effectiveness 

and RIA calculations focused on national impacts) and include 

slightly different rounding of intermediate values.

B. Centrifugal Compressors

We are proposing standards to reduce methane and VOC 

emissions from new, modified or reconstructed centrifugal 

compressors located across the oil and natural gas source 

category, except those located at well sites. As discussed in 

detail in section VIII.B, the proposed standards are the same as 

those currently required to control VOC from centrifugal 

compressors in the production segment. Specifically, we are 

proposing to require 95 percent reduction of the emissions from 

each wet seal centrifugal compressor affected facility. The 

standard can be achieved by capturing and routing the emissions 

utilizing a cover and closed vent system to a control device 
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that achieves an emission reduction of 95 percent, or routing 

the captured emissions to a process. Consistent with the current

VOC provisions for centrifugal compressors in the production 

segment, dry seal centrifugal compressors are inherently lowemitting and would not be affected facilities. These proposed 

standards are the same as for centrifugal compressors regulated 

in the 2012 final rule.

C. Reciprocating Compressors

For the reasons discussed in section VIII.C, we are 

proposing an operational standard for affected reciprocating 

compressors across the oil and natural gas source category, 

except those located at well sites, that requires either 

replacement of the rod packing based on usage or routing of rod 

packing emissions to a process via a closed vent system under 

negative pressure. The owner or operator of a reciprocating 

compressor affected facility would be required to monitor the 

duration (in hours) that the compressor is operated, beginning 

on the date of initial startup of the reciprocating compressor 

affected facility. When the hours of operation reach 26,000 

hours, the owner or operator would be required to immediately 

change the rod packing. Owners or operators can elect to change 

the rod packing every 36 months in lieu of monitoring compressor 
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operating hours. As an alternative to rod packing replacement, 

owners and operators may route the rod packing emissions to a 

process via a closed vent system operated at negative pressure.

These proposed standards are the same as for reciprocating 

compressors regulated in the 2012 rule.

D. Pneumatic Controllers

For the reasons presented in section VIII.D, consistent 

with VOC standards in the 2012 NSPS for pneumatic controllers in 

the production segment, we are proposing to control methane and 

VOC emissions by requiring use of low-bleed controllers in place 

of high-bleed controllers (i.e., natural gas bleed rate not to 

exceed 6 scfh)42 at locations within the source category except 

for natural gas processing plants. For natural gas processing 

plants, consistent with the VOC emission standards in the 2012 

NSPS, we are proposing to control methane and VOC emissions by 

requiring that pneumatic controllers have zero natural gas bleed 

rate (i.e., they are operated by means other than natural gas, 

such as being driven by compressed instrument air). We are 

proposing that these standards apply to each newly installed, 

modified or reconstructed pneumatic controller (including 

 

42 Bleed rate can be documented through information provided by 

the controller manufacturer.
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replacement of an existing controller). Consistent with the 

current requirements under the 2012 NSPS for control of VOC 

emissions from pneumatic controllers in the production segment

and at natural gas processing plants, the proposed standards 

provide exemptions for certain critical applications based on 

functional considerations. These proposed standards are the same 

as for pneumatic controllers regulated in the 2012 rule.

E. Pneumatic Pumps

For the reasons detailed in section VIII.E, we are 

proposing standards for natural gas-driven chemical/methanol 

pumps and diaphragm pumps. The proposed standards would require 

the methane and VOC emissions from new, modified and 

reconstructed natural gas-driven chemical/methanol pumps and 

diaphragm pumps located at any location (except for natural gas 

processing plants) throughout the source category to be reduced 

by 95 percent if a control device is already available on site. 

For pneumatic pumps located at a natural gas processing plant, 

the proposed standards would require the methane and VOC 

emissions from natural gas-driven chemical/methanol pumps and 

diaphragm pumps to be zero.

F. Well Completions
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We are proposing operational standards for well completions 

at hydraulically fractured (or refractured) wells, including oil 

wells. The 2012 NSPS regulated well completions to control VOC 

emissions from hydraulically fractured or refractured gas wells.

These proposed standards are the same as for natural gas wells 

regulated in the 2012 rule. We identified two subcategories of 

hydraulically fractured wells for which well completions are 

conducted: (1) non-wildcat and non-delineation wells; and (2) 

wildcat and delineation wells. A wildcat well, also referred to 

as an exploratory well, is a well drilled outside known fields 

or are the first well drilled in an oil or gas field where no 

other oil and gas production exists. A delineation well is a 

well drilled to determine the boundary of a field or producing 

reservoir.

As discussed in detail in section VIII.F, we are proposing 

operational standards for subcategory 1 (non-wildcat, nondelineation wells) requiring a combination of REC and 

combustion. Compared to combustion alone, we believe that the 

combination of REC and combustion will maximize gas recovery and 

minimize venting to the atmosphere. Furthermore, the use of 

traditional combustion control devices (i.e., flares and 

enclosed combustion control devices), present local emissions 
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impacts. The proposed standards for subcategory 2 wells (wildcat 

and delineation wells) require only combustion. For subcategory 

1 wells, we are proposing to define the flowback period of an 

oil well completion as consisting of two distinct stages, the 

“initial flowback stage” and the “separation flowback stage.”

The initial flowback stage begins with the onset of flowback and 

ends when the flow is routed to a separator. During the initial 

flowback stage, any gas in the flowback is not subject to

control. However, the operator must route the flowback to a 

separator unless it is technically infeasible for a separator to 

function. The point at which the separator can function marks 

the beginning of the separation flowback stage. During this 

stage, the operator must route all salable quality gas from the 

separator to a flow line or collection system, re-inject the gas 

into the well or another well, use the gas as an on-site fuel 

source or use the gas for another useful purpose. If it is 

technically infeasible to route the gas as described above, or 

if the gas is not of salable quality, the operator must combust 

the gas unless combustion creates a fire or safety hazard or can 

damage tundra, permafrost or waterways. No direct venting of gas 

is allowed during the separation flowback stage. The separation 

flowback stage ends either when the well is shut in and the
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flowback equipment is permanently disconnected from the well, or 

on startup of production. This also marks the end of the 

flowback period. The operator has a general duty to safely

maximize resource recovery safely and minimize releases to the 

atmosphere over the duration of the flowback period. The 

operator is also required to document the stages of the 

completion operation by maintaining records of (1) the date and 

time of the onset of flowback; (2) the date and time of each

attempt to route flowback to the separator; (3) the date and 

time of each occurrence in which the operator reverted to the 

initial flowback stage; (4) the date and time of well shut in; 

and (5) date and time that temporary flowback equipment is 

disconnected. In addition, the operator must document the total 

duration of venting, combustion and flaring over the flowback 

period. All flowback liquids during the initial flowback period 

and the separation flowback period must be routed to a well 

completion vessel, a storage vessel or a collection system. 

For subcategory 2 wells, we are proposing an operational 

standard that requires routing of the flowback into well 

completion vessels and commencing operation of a separator 

unless it is technically infeasible for the separator to 

function. Once the separator can function, recovered gas must be 
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captured and directed to a completion combustion device unless 

combustion creates a fire or safety hazard or can damage tundra, 

permafrost or waterways. Operators would be required to maintain 

the same records described above for category 1 wells.

Consistent with the current VOC standards for hydraulically 

fractured gas wells, we are proposing that “low pressure” wells

would remain affected facilities and would have the same 

requirements as subcategory 2 wells (wildcat and delineation 

wells). The term “low pressure gas well” is unchanged from the 

currently codified definition in the NSPS; however, we solicit 

comment on whether this definition appropriately indicates 

hydraulically fractured oil wells for which conducting an REC 

would be technologically infeasible and whether the term should 

be revised to address all wells rather than just gas wells. 

We are also retaining the provision from the 2012 NSPS, now

at §60.5365a(a)(1), that a well that is refractured, and for 

which the well completion operation is conducted according to 

the requirements of §60.5375a(a)(1) through(4), is not 

considered a modified well and therefore does not become an 

affected facility under the NSPS. We point out that such an 

exclusion of a “well” from applicability under the NSPS has no 

effect on the affected facility status of the “well site” for 
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purposes of the proposed fugitive emissions standards at 

§60.5397a. 

Further, we are proposing that wells with a gas-to-oil 

ratio (GOR) of less than 300 scf of gas per barrel of oil

produced would not be affected facilities subject to the well 

completion provisions of the NSPS. We solicit comment on whether 

a GOR of 300 is the appropriate applicability threshold. 

Rationale for this threshold is discussed in detail in section 

VIII.F. 

G. Fugitive Emissions from Well Sites and Compressor Stations

1. Fugitive Emissions from Oil and Natural Gas Production Well 

Sites

We are proposing standards to reduce fugitive methane and 

VOC emissions from new and modified oil and natural gas 

production well sites. The proposed standards would require 

locating and repairing sources of fugitive emissions (e.g., 

visible emissions from fugitive emissions component observed 

using OGI) at well sites. Under the proposed standards, the 

affected facility would be “the collection of fugitive emissions 

components at a well site”; where “well site” is defined in 

subpart OOOO as “one or more areas that are directly disturbed 

during the drilling and subsequent operation of, or affected by, 
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production facilities directly associated with any oil well, gas 

well, or injection well and its associated well pad.” This 

definition is intended to include all ancillary equipment in the 

immediate vicinity of the well that are necessary for or used in

production, and may include such items as separators, storage 

vessels, heaters, dehydrators, or other equipment at the site.

Some well sites, especially in areas with very dry gas or 

where centralized gathering facilities are used, consist only of

one or more wellheads, or “Christmas trees,” and have no

ancillary equipment such as storage vessels, closed vent 

systems, control devices, compressors, separators and pneumatic 

controllers. Because the magnitude of fugitive emissions depends 

on how many of each type of component (e.g., valves, connectors 

and pumps) are present, fugitive emissions from these well sites 

are extremely low. For that reason, we are proposing to exclude

from the fugitive emissions requirements those well sites that 

contain only wellheads. Therefore, we are proposing to add the 

following sentence to the definition of “well site” above: “For 

the purposes of the fugitive emissions standards at §60.5397a, a 

well site that only contains one or more wellheads is not 

subject to these standards.”
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Also, we are proposing to exclude low production well sites

(i.e., a low production site is defined by the average combined 

oil and natural gas production for the wells at the site being 

less than 15 barrels of oil equivalent (boe) per day averaged

over the first 30 days of production) from the standards for 

fugitives emissions from well sites. Please refer to section 

VIII.G. for further discussion. 

We are proposing that owners or operators of well siteaffected facilities conduct an initial survey of “fugitive 

emissions components,” which we are proposing to define in 

§60.5430a to include, among other things, valves, connectors, 

open-ended lines, pressure relief devices, closed vent systems 

and thief hatches on tanks using either OGI technology. For new 

well sites, the initial survey would have to be conducted within 

30 days of the end of the first well completion or upon the date 

the site begins production, whichever is later. For modified 

well sites, the initial survey would be required to be conducted 

within 30 days of the site modification. We solicit comment on 

whether 30 days is an appropriate period for the first survey 

following startup or modification. For the purposes of these 

fugitive emissions standards, a modification would occur when a 

new well is added to a well site (regardless of whether the well 
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is fractured) or an existing well on a well site is fractured or 

refractured. See section VII.G.3 below for a discussion of 

modifications in the context of fugitive emission requirements 

for well sites and compressor stations. After the initial 

monitoring survey, monitoring surveys would be required to be 

conducted semiannually for all new and modified well sites. We 

are also co-proposing monitoring surveys on an annual basis for 

new and modified well sites. 

The proposed standards would require replacement or repair 

of components if evidence of fugitive emissions is detected 

during the monitoring survey through visible confirmation from 

OGI. As discussed in section VIII.G, we solicit comment on 

whether to allow EPA Method 21 as an alternative to OGI for 

monitoring, including the appropriate EPA Method 21 level repair 

threshold.

We are proposing that the source of emissions be repaired 

or replaced, and resurveyed, as soon as practicable, but no 

later than 15 calendar days after detection of the fugitive 

emissions. We expect that the majority of the repairs can be 

made at the time the initial monitoring survey is conducted. 

However, we understand that more time may be necessary to repair 

more complex components. We have historically allowed 15 days 
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for repair/resurvey in the LDAR program, which has appeared to 

be sufficient time. We are proposing to allow the use of either 

Method 21 or OGI for resurveys that cannot be performed during 

the initial monitoring survey and repair. As explained above, 

there may be some components that cannot not be repaired right 

away and in some instances not until after the initial OGI 

personnel are no longer on site. In that event, resurvey with 

OGI would require rehiring OGI personnel, which would make the 

resurvey not cost effective. For those components that have been 

repaired, we believe that the no fugitive emissions would be 

detected above 500 ppm above background using Method 21. This 

has been historically used to ensure that there are no emissions 

from components that are required to operate with no detectable

emissions. We solicit comments on whether either optical gas 

imaging or Method 21 should be allowed for the resurvey of the 

repaired components when fugitive emissions are detected with 

OGI. We estimate that the majority of operators will need to 

hire a contractor to come back to conduct the optical gas 

imaging resurvey. While there will also be costs associated with 

resurveying using Method 21, we estimate that many companies own 

Method 21 instruments (e.g., OVA/TVA) and would be able to 

perform the resurvey at a minimal cost. To verify that the 
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repair has been made using OGI, no evidence of visible emissions 

must be seen during the survey. For Method 21, we are proposing 

that the instrument show a reading of less than 500 ppm above 

background from any of the repaired components. We solicit 

comment whether 500 ppm above background is the appropriate 

repair resurvey threshold when Method 21 instruments are used or 

if not, what the appropriate repair resurvey threshold is for 

Method 21.

If the repair or replacement is technically infeasible or 

unsafe during unit operations, the repair or replacement must be 

completed during the next scheduled shutdown or within six

months, whichever is earlier. Equipment is unsafe to repair or 

replace if personnel would be exposed to an immediate danger in 

conducting the repair or replacement. All sources of fugitive 

emissions that are repaired must be resurveyed within 15 days of 

repair completion to ensure the repair has been successful

(i.e., no fugitive emissions are imaged using OGI or less than 

500 ppm above background when using Method 21).

The EPA is proposing that these fugitive emission 

requirements be carried out through the development and 

implementation of a monitoring plan, which would specify the 

measures for locating sources of fugitive emissions and the 
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detection technology to be used. A company would be able to 

develop a corporate-wide monitoring plan, although there may be 

specific information needed that pertains to a single site, such 

as number and identification of fugitive emission components. 

The monitoring plan must also include a description of how the 

OGI survey will be conducted that ensures that fugitive 

emissions can be imaged effectively. In addition, we solicit 

comment on whether other techniques could be required elements 

of the monitoring plan in conjunction with OGI, such as visual 

inspections, to help identify signs such as staining of storage 

vessels or other indicators of potential leaks or improper 

operation.

If fugitive emissions are detected at less than one percent 

of the fugitive emission components at a well site during two

consecutive semiannual monitoring surveys, then the monitoring 

survey frequency for that well site may be reduced to annually. 

If, during a subsequent monitoring survey, fugitive emissions 

are detected at between one percent and five percent of the 

fugitive emission components, then the monitoring survey 

frequency for that well site must be increased to semiannually.

If fugitive emissions are detected from five percent or 

more of the fugitive emission components at a well site during
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two consecutive semiannual monitoring, then the monitoring 

survey frequency for that well site must be increased to 

quarterly. If, during a subsequent monitoring survey, fugitive 

emissions are detected from one to five percent of the fugitive 

emission components, then the monitoring survey frequency for 

that well site may be reduced to semiannually. If fugitive 

emissions are detected from less than one percent of the 

fugitive emission components, then the monitoring survey 

frequency for that well site may be reduced to annually. We 

solicit comment on the proposed metrics of one percent and five 

percent and whether these thresholds should be specific numbers

of components rather than percentages of components for 

triggering change in survey frequency discussed in this action.

We also solicit comment on whether a performance-based frequency 

or a fixed frequency is more appropriate.

As discussed in more detail in section VIII.G below and the 

TSD for this action available in the docket, we have identified 

OGI technology with semiannual survey monitoring as the BSER for 

detecting fugitive emissions from new and modified well sites. 

The proposed standards would apply to new well sites and to 

modified well sites. As explained in more detail in section 

VIII.B below, for purposes of this proposed standard, a well 
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site is modified when a new well is completed (regardless of 

whether it is fractured) or an existing well is fractured or 

refractured after [effective date of final rule]. The standards 

would not apply to existing well sites where additional drilling 

activities were conducted on an existing well but those 

activities did not include fracturing or refracturing (e.g., 

well workovers that do not include fracturing or refracturing).

2. Fugitive Emissions from Compressor Stations

We are proposing standards to reduce fugitive methane and 

VOC emissions from new and modified natural gas compressor 

stations throughout the oil and natural gas source category. The 

proposed standards would require affected facilities to locate 

sources of fugitive emissions and to repair those sources. We 

are proposing that owners or operators of the affected 

facilities conduct an initial survey of the collection of 

fugitive emissions components (e.g., valves, connectors, openended lines, pressure relief devices, closed vent systems and 

thief hatches on tanks) using OGI technology. For new compressor 

stations, the initial survey would have to be conducted within 

30 days of site startup. For modified compressor stations, the 

initial survey would be required within 30 days of the site 

modification. After the initial survey, surveys would be 
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required semiannually. We solicit comment on whether 30 days is 

an appropriate period for the first survey following startup.

The proposed standards would require replacement or repair

of any fugitive emissions component that has evidence of 

fugitive emissions detected during the survey through visible

confirmation from OGI. As discussed in section VIII.G, we 

solicit comment on whether to allow EPA Method 21 as an 

alternative to OGI for monitoring, including the appropriate EPA 

Method 21 level repair threshold.

We are proposing that the source of emissions be repaired 

or replaced, and resurveyed, as soon as practicable, but no 

later than 15 calendar days after detection of the fugitive 

emissions. We expect that the majority of the repairs can be 

made at the time the initial monitoring survey is conducted. 

However, we understand that more time may be necessary to repair 

more complex components. We have historically allowed 15 days 

for repair/resurvey in the LDAR program, which has appeared to 

be sufficient time. We are proposing to allow the use of either 

Method 21 or OGI for resurveys that cannot be performed during 

the initial monitoring survey and repair. As explained above, 

there may be some components that cannot not be repaired right 

away and in some instances not until after the initial OGI 
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personnel are no longer on site. In that event, resurvey with 

OGI would require rehiring OGI personnel, which would make the 

resurvey not cost effective. For those components that have been 

repaired, we believe that the no fugitive emissions would be 

detected above 500 ppm above background using Method 21. This 

has been historically used to ensure that there are no emissions 

from components that are required to operate with no detectable 

emissions. We solicit comments on whether either optical gas 

imaging or Method 21 should be allowed for the resurvey of the 

repaired components when fugitive emissions are detected with 

OGI. We estimate that the majority of operators will need to 

hire a contractor to come back to conduct the optical gas 

imaging resurvey. While there will also be costs associated with 

resurveying using Method 21, we estimate that many companies own 

Method 21 instruments (e.g., OVA/TVA) and would be able to 

perform the resurvey at a minimal cost. To verify that the 

repair has been made using OGI, no evidence of visible emissions 

must be seen during the survey. For Method 21, we are proposing 

that the instrument show a reading of less than 500 ppm above 

background from any of the repaired components. We solicit 

comment whether 500 ppm above background is the appropriate 

repair resurvey threshold when Method 21 instruments are used or 
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if not, what the appropriate repair resurvey threshold is for 

Method 21.

The source of emissions must be repaired or replaced as 

soon as practicable, but no later than 15 calendar days after 

detection of the fugitive emissions. If the repair or 

replacement is technically infeasible or unsafe during unit 

operations, the repair or replacement must be completed during 

the next scheduled shutdown or within six months, whichever is 

earlier. Equipment is unsafe to repair or replace if personnel 

would be exposed to an immediate danger in conducting

monitoring. All sources of fugitive emissions that are repaired 

must be resurveyed to ensure the repair has been successful 

(i.e., no fugitive emissions are imaged using OGI or less than 

500 ppm above background when using Method 21).

The EPA is proposing that these fugitive emission 

requirements be carried out through the development and 

implementation of a monitoring plan, which would specify the 

measures for locating sources of fugitive emissions and the 

detection technology to be used. The monitoring plan must also 

include a description of how the OGI survey will be conducted 

that ensures that fugitive emissions can be imaged effectively.

In addition, we solicit comment on whether other techniques 
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could be required elements of the monitoring plan in conjunction 

with OGI, such as visual inspections, to help identify signs 

such as staining of storage vessels or other indicators of 

potential leaks or improper operation.

If fugitive emissions are detected during two consecutive 

semi-annual monitoring surveys at less than one percent of the 

fugitive emission components, then the monitoring survey 

frequency for that compressor station may be reduced to 

annually. If, during a subsequent monitoring survey, visible 

fugitive emissions are detected using OGI from one to five

percent of the fugitive emission components, then the monitoring 

survey frequency for that compressor station must be increased 

to semiannually.

If fugitive emissions are detected from five percent or 

more of the fugitive emission components during two consecutive 

semiannual monitoring surveys with OGI technology, then the 

monitoring survey frequency for that compressor station must be 

increased to quarterly. If, during a subsequent monitoring 

survey, fugitive emissions are detected from one to five percent

of the fugitive emission components using OGI technology, then 

the monitoring survey frequency for that compressor station may 

be reduced to semiannually. If fugitive emissions are detected 
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from less than one percent of the fugitive emission components, 

then the monitoring survey frequency for that well site may be 

reduced to annually. We solicit comment on the proposed metrics

of one percent and five percent and whether these thresholds

should be specific numbers of components rather than percentages 

of components for triggering change in survey frequency 

discussed in this action. We also solicit comment on whether a

performance-based frequency or a fixed frequency is more 

appropriate.

As discussed in more detail in section VIII.G below and the 

TSD for this action available in the docket, we have identified 

OGI technology as the BSER for detecting fugitive emissions from 

new and modified compressor stations.

The proposed standards apply to new and modified compressor

stations throughout the oil and natural gas source category. As 

explained in section VII.G.3 below, compressor stations are 

considered modified for the purposes of these fugitive emission 

standards when one or more compressors is added to the station

after [effective date of final rule].

3. Modification of the Collection of Fugitive Emissions 

Components at Well Sites and Compressor Stations
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For the purposes of the fugitive emission standards at well 

sites and compressor stations, we are proposing definitions of 

“modification” for those facilities that are specific to these 

provisions and for this purpose only. As provided in section 

60.14(f), such provisions in the specific subparts would 

supersede any conflicting provisions in §60.14 of the General 

Provisions. This definition does not affect other standards 

under this subpart for wells, other equipment at well sites or 

compressors.

For purposes of the proposed fugitive emissions standards 

at well sites, we propose that a modification to a well site 

occurs only when a new well is added to a well site (regardless 

of whether the well is fractured) or an existing well on a well 

site is fractured or refractured. When a new well is added or a 

well is fractured or refractured, there is an increase in 

emissions to the fugitive emissions components because of the 

addition of piping and ancillary equipment to support the well, 

along with potentially greater pressures and increased 

production brought about by the new or fractured well. Other 

than these events, we are not aware of any other physical change 

to a well site that would result in an increase in emissions 

from the collection of fugitive components at such well site. To 
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clarify and ease implementation, we propose to define 

“modification” to include only these two events for purposes of 

the fugitive emissions provisions at well sites. We note that 

under §60.5365a(a)(1) a well that is refractured, and for which 

the well completion operation is conducted according to the 

requirements of §60.5375a(a)(1) through(4), is not considered a

modified well and therefore does not become an affected facility

under the NSPS. We would like to clarify that such an exclusion 

of a “well” from applicability under the NSPS would have no 

effect on the affected facility status of the “well site” for 

purposes of the proposed fugitive emissions standards.

Accordingly, a well at an existing well site that is refractured 

constitutes a modification of the well site, which then would be 

an affected facility for purposes of the fugitive emission 

standards at §60.5397a, regardless of whether the well itself is 

an affected facility. We solicit comment on the whether such

modified well sites should not be affected facilities subject to 

the NSPS, if the owner or operator is implementing a corporatewide fugitive emissions monitoring and repair plan which is 

legally and practically enforceable.

In the 2012 NSPS, we provided that completion requirements 

do not apply to refracturing of an existing well that is 
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completed responsibly (i.e. green completions). Building on the 

2012 NSPS, the EPA intends to continue to encourage corporatewide voluntary efforts to achieve emission reductions through 

responsible, transparent and verifiable actions that would 

obviate the need to meet obligations associated with NSPS 

applicability, as well as avoid creating disruption for 

operators following advanced responsible corporate practices. 

To encourage companies to continue such good corporate policies 

and encourage advancement in the technology and practices, we 

solicit comment on criteria we can use to determine whether and 

under what conditions well sites operating under corporate LDAR 

regimes can be deemed to be meeting the equivalent of the NSPS 

standards for well site fugitive emissions such that we can 

define those regimes as constituting alternative methods of 

compliance or otherwise provide appropriate regulatory 

streamlining. We also solicit comment on how to address 

enforceability of such alternative approaches (i.e., how to 

assure that these well sites are achieving, and will continue to 

achieve, equal or better emission reduction than our proposed 

standards).

For purposes of the proposed standards for fugitive 

emission at compressor stations, we propose that a modification 
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occurs only when a compressor is added to the compressor station

or when physical change is made to an existing compressor at a 

compressor station that increases the compression capacity of 

the compressor station. Since fugitive emissions at compressor 

stations are from compressors and their associated piping, 

connections and other ancillary equipment, expansion of 

compression capacity at a compressor station, either through 

addition of a compressor or physical change to the an existing 

compressor, would result in an increase in emissions to the 

fugitive emissions components. Other than these events, we are 

not aware of any other physical change to a compressor station 

that would result in an increase in emissions from the

collection of fugitive components at such compressor station. To 

clarify and ease implementation, we define “modification” as the 

addition of a compressor for purposes of the fugitive emissions 

provisions at compressor stations.

H. Equipment Leaks at Natural Gas Processing Plants

We are proposing standards to control methane and VOC 

emissions from equipment leaks at natural gas processing plants. 

These requirements are the same as the VOC equipment leak 

requirements in the 2012 NSPS and would require NSPS part 60, 

subpart VVa level of control, including a detection level of 500 
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ppm as in the 2012 NSPS. As discussed further in section VIII.H, 

we propose that the subpart VVa level of control applied plantwide is the BSER for controlling methane emissions from 

equipment leaks at onshore natural gas processing plants. We 

believe it provides the greatest emission reductions of the 

options we considered in our analysis in Section VIII.H, and 

that the costs are reasonable. 

I. Liquids Unloading Operations

For the reasons discussed in section VIII.I, at this time 

the EPA does not have sufficient information to propose a 

standard for liquids unloading. However, we are requesting 

comment on nationally applicable technologies and techniques 

that reduce methane and VOC emissions from these events. 

Specifically, we request comment on technologies and techniques 

that can be applied to new gas wells that can reduce emissions 

from liquids unloading in the future.

J. Recordkeeping and Reporting 

We are proposing recordkeeping and reporting requirements 

that are consistent with those required in the current NSPS for 

natural gas well completions, compressors and pneumatic 

controllers. Owners or operators would be required to submit 

initial notifications (except for wells, pneumatic controllers, 
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pneumatic pumps and compressors, as provided in §60.5420(a)(1)) 

and annual reports, and to retain records to assist in 

documenting that they are complying with the provisions of the 

NSPS. 

For new, modified or reconstructed pneumatic controllers, 

owners and operators would not be required to submit an initial 

notification; they would simply need to report the installation 

of these affected facilities in their facility’s first annual 

report following the compliance period during which they were 

installed. Owners or operators of well-affected facilities

(consistent with current requirements for gas well affected 

facilities) would be required to submit an initial notification 

no later than two days prior to the commencement of each well 

completion operation. This notification would include contact 

information for the owner or operator, the American Petroleum 

Institute (API) well number, the latitude and longitude 

coordinates for each well, and the planned date of the beginning 

of flowback. 

In addition, an initial annual report would be due no later 

than 90 days after the end of the initial compliance period,

which is established in the rule. Subsequent annual reports 

would be due no later than the same date each year as the 
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initial annual report. The annual reports would include 

information on all affected facilities owned or operated of 

sources that were constructed, modified or reconstructed during 

the reporting period. A single report may be submitted covering 

multiple affected facilities, provided that the report contains 

all the information required by 40 CFR 60.5420(b). This 

information would include general information on the facility 

(i.e., company name and address, etc.), as well as information 

specific to individual affected facilities. 

For well affected facilities, the information required in 

the annual report would include the location of the well, the 

API well number, the date and time of the onset of flowback 

following hydraulic fracturing or refracturing, the date and 

time of each attempt to direct flowback to a separator, the date 

and time of each occurrence of returning to the initial flowback 

stage, and the date and time that the well was shut in and the 

flowback equipment was permanently disconnected or the startup 

of production, the duration of flowback, the duration of 

recovery to the flow line, duration of combustion, duration of 

venting, and specific reasons for venting in lieu of capture or 

combustion. For each oil well for which an exemption is claimed

for conditions in which combustion may result in a fire hazard 
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or explosion or where high heat emissions from a completion 

combustion device may negatively impact tundra, permafrost or 

waterways, the report would include the location of the well,

the API well number, the specific exception claimed, the 

starting date and ending date for the period the well operated 

under the exception, and an explanation of why the well meets 

the claimed exception. The annual report would also include 

records of deviations where well completions were not conducted 

according to the applicable standards.

For centrifugal compressor affected facilities, information 

in the annual report would include an identification of each 

centrifugal compressor using a wet seal system constructed, 

modified or reconstructed during the reporting period, as well 

as records of deviations in cases where the centrifugal 

compressor was not operated in compliance with the applicable 

standards. 

For reciprocating compressors, information in the annual 

report would include the cumulative number of hours of operation

or the number of months since initial startup or the previous 

reciprocating compressor rod packing replacement, whichever is 

later, or a statement that emissions from the rod packing are 
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being routed to a process through a closed vent system under 

negative pressure.

Information in the annual report for pneumatic controller

affected facilities would include location and documentation of 

manufacturer specifications of the natural gas bleed rate of 

each pneumatic controller installed during the compliance 

period. For pneumatic controllers for which the owner is 

claiming an exemption to the standards, the annual report would 

include documentation that the use of a pneumatic controller 

with a natural gas bleed rate greater than 6 scfh is required 

and the reasons why. The annual report would also include 

records of deviations from the applicable standards.

For pneumatic pump affected facilities, information in the 

annual report would include an identification of each pneumatic 

pump constructed, modified or reconstructed during the 

compliance period, as well as records of deviations in cases 

where the pneumatic pump was not operated in compliance with the 

applicable standards. 

The proposed rule includes new requirements for monitoring 

and repairing sources of fugitive emissions at well sites and 

compressor stations. The owner or operator would be required to 

keep one or more digital photographs of each affected well site 
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or compressor station. A photograph of every component that is 

surveyed during the monitoring survey is not required. The 

photograph must include the date the photograph was taken and 

the latitude and longitude of the well site imbedded within or 

stored with the digital file and must identify the affected 

facility. This could include a “still” image taken using OGI 

technology or a digital photograph taken of the survey being 

performed. As an alternative to imbedded latitude and longitude 

within the digital photograph, the digital photograph may 

consist of a photograph of the affected facility with a 

photograph of a separately operating Geographic Information 

Systems (GIS) device within the same digital picture, provided 

the latitude and longitude output of the GIS unit can be clearly 

read in the digital photograph. The owner or operator would also 

be required to keep a log for each affected facility. The log 

must include the date monitoring surveys were performed, the 

technology used to perform the survey, the monitoring frequency 

required at the time of the survey, the number and types of 

equipment found to have fugitive emissions, the date or dates of 

first attempt to repair the source of fugitive emissions, the

final repair of each source of fugitive emissions, any source of 

fugitive emissions found to be technically infeasible or unsafe 
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to repair during unit operation and the date that source is

scheduled to be repaired. These digital photographs and logs 

must be available at the affected facility or the field office. 

We solicit comment on whether these records also should be sent 

directly to the permitting agency electronically to facilitate 

review remotely. The owner or operator would also be required to 

develop and maintain a corporate-wide and site specific 

monitoring plan enabling the fugitive emissions monitoring 

program. 

Annual reports for each fugitive emissions affected 

facility would have to be submitted that include the date 

monitoring surveys were performed, the technology used to 

perform the survey, the monitoring frequency required at the 

time of the survey, the number and types of component found to 

have fugitive emissions, the date of first attempt to repair the 

source of fugitive emissions, the date of final repair of each 

source of fugitive emissions, any source of fugitive emissions 

found to be technically infeasible or unsafe to repair during 

unit operation and the date that source is scheduled to be 

repaired. 

Consistent with the current requirements of subpart OOOO, 

records must be retained for 5 years and generally consist of 
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the same information required in the initial notification and 

annual reports. The records may be maintained either onsite or 

at the nearest field office. We solicit comment on whether these 

records also should be sent directly to the permitting agency 

electronically to facilitate review remotely.

Lastly, the EPA realizes that duplicative recordkeeping and 

reporting requirements may exist between the NSPS, Subpart W, 

and other state and local rules, and is trying to minimize 

overlapping requirements on operators. We solicit comment on 

ways to minimize recordkeeping and reporting burden. 

VIII. Rationale for Proposed Action for NSPS

The following sections provide our BSER analyses and the

resulting proposed new source performance standards to reduce

methane and VOC emissions from across the oil and natural gas 

source category. Our general process for evaluating BSER for the 

emission sources discussed below included: (1) identification of 

available control measures; (2) evaluation of these measures to 

determine emission reductions achieved, associated costs, nonair 

environmental impacts, energy impacts and any limitations to 

their application; and (3) selection of the control techniques 

that represent BSER.
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As mentioned previously and discussed in more detail below, 

the control technologies available for reducing methane and VOC 

emissions are the same for the emissions sources in this source 

category. This observation was made in the 2014 white papers and 

confirmed by the comments received on the 2014 white papers, as 

well as state regulations, including those of Colorado, that 

require methane and VOC mitigation measures from these sources 

of emissions.

CAA Section 111 also requires that EPA considers cost in 

determining BSER. Section VIII.A below describes how EPA 

evaluates the cost of control for purposes of this rulemaking.

Sections VIII.B through VIII.I provide the BSER analysis and the 

resulting proposed standards for individual emission sources 

contemplated in this action.

Please note that there are minor differences in some values 

presented in various documents supporting this action. This is 

because some calculations have been performed independently 

(e.g., TSD calculations focused on unit-level cost-effectiveness 

and RIA calculations focused on national impacts) and include 

slightly different rounding of intermediate values.

A. How does EPA evaluate control costs in this action? 
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Section 111 requires that EPA consider a number of factors, 

including cost, in determining “the best system of emission 

reduction ... adequately demonstrated.” While section 111 requires 

that EPA consider cost in determining such system (i.e., 

“BSER”), it does not prescribe any criteria for such 

consideration. However, in several cases, the D.C. Circuit has 

shed light on how EPA is to consider cost under CAA section 

111(a)(1). For example, in Essex Chemical Corp. v. Ruckelshaus,

486 F.2d 427, 433 (D.C. Cir. 1973), the D.C. Circuit stated that

to be "adequately demonstrated," the system must be "reasonably 

reliable, reasonably efficient, and . . . reasonably expected to 

serve the interests of pollution control without becoming 

exorbitantly costly in an economic or environmental way." The 

Court has reiterated this limit in subsequent case law, 

including Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. 

Cir. 1999), in which it stated: "EPA's choice will be sustained 

unless the environmental or economic costs of using the 

technology are exorbitant." In Portland Cement Ass'n v. EPA, 513 

F.2d 506, 508 (D.C. Cir. 1975), the Court elaborated by 

explaining that the inquiry is whether the costs of the standard 
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are "greater than the industry could bear and survive."43 In 

Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981), the 

Court provided a substantially similar formulation of the cost 

standard when it held: "EPA concluded that the Electric 

Utilities' forecasted cost was not excessive and did not make 

the cost of compliance with the standard unreasonable. This is a 

judgment call with which we are not inclined to quarrel." We 

believe that these various formulations of the cost standard--

"exorbitant," "greater than the industry could bear and 

survive," "excessive," and "unreasonable"--are synonymous; the 

D.C. Circuit has made no attempt to distinguish among them. For 

convenience, in this rulemaking, we will use reasonableness as 

the standard, so that a control technology may be considered the 

 

43 The 1977 House Committee Report noted:

In the [1970] Congress [sic: Congress's] view, it was only right 

that the costs of applying best practicable control technology 

be considered by the owner of a large new source of pollution as 

a normal and proper expense of doing business.

1977 House Committee Report at 184. Similarly, the 1970 Senate 

Committee Report stated:

The implicit consideration of economic factors in determining 

whether technology is "available" should not affect the 

usefulness of this section. The overriding purpose of this 

section would be to prevent new air pollution problems, and 

toward that end, maximum feasible control of new sources at the 

time of their construction is seen by the committee as the most 

effective and, in the long run, the least expensive approach.

S. Comm. Rep. No. 91-1196 at 16.
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"best system of emission reduction . . . adequately 

demonstrated" if its costs are reasonable, but cannot be 

considered the best system if its costs are unreasonable.

In evaluting whether the cost of a control is reasonable, 

EPA considers various costs associated with such control, 

including capital costs and operating costs, and the emission 

reductions that the control can achieve. A cost-effectiveness 

analysis is one means of evaluting whether a given control 

achieves emission reduction at a reasonable cost. Costeffectiveness analysis also allows comparisons of relative costs 

and outcomes (effects) of two or more options. In general, costeffectiveness is a measure of the benefit produced by resources 

spent. In the context of air pollution control options, costeffectiveness typically refers to the annualized cost of 

implementing an air pollution control option divided by the 

amount of pollutant reductions realized annually. A costeffectiveness analysis is not intended to constitute or 

approximate a cost-benefits analysis but rather provides a 

metric of the relative cost to reduction ratios of various 

control options.

The estimation and interpretation of cost-effectiveness 

values is relatively straightforward when an abatement measure 
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controls a single pollutant. Increasingly, however, air 

pollution reduction programs require reductions in emissions of 

multiple pollutants, and in such programs multipollutant 

controls may be employed. Consequently, there is a need for 

determining cost-effectiveness for a control option across 

multiple pollutants (or classes of multiple pollutants). This is 

the case for this proposal where, for the reasons explained in 

section V, we are proposing to directly regulate both methane 

and VOC. Further, as discussed in more detail below, both 

methane and VOC are simultaneously and equi-proportionally 

reduced when controlled.

We have evaluated a number of approaches for considering 

the costs of the available multipollutant controls for reducing

both methane and VOC emissions. One approach is to assign the 

entire annualized cost to the reduction in emissions of a single 

pollutant reduced by the multipollutant control option and treat 

the simultaneous reductions of the other pollutants as 

incidental or co-benefits. This was the approach we took in the 

2012 NSPS but no longer believe to be appropriate for the 

reasons explained in section V. Under the current proposal, 

methane and VOCs are both directly regulated; therefore,

reductions of each pollutant must be properly considered 
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benefits, not co-benefits, and consideration of only one of the 

regulated pollutants is not appropriate.

Alternatively, all annualized costs can be allocated to 

each of the pollutant emission reductions addressed by the 

multipollutant control option. Unlike the approach above, no

emission reduction is treated as co-benefit; each emission 

reduction is assessed based on the full cost of the control.

However, this approach, which is often used for assessing single

pollutant controls, evaluates emission reduction of each 

pollutant separately, assuming that each bears the entire cost, 

and thus inflates the control cost in the multiple of the number 

of additional pollutants being reduced. This type of approach 

therefore over-estimates the cost of obtaining emissions 

reductions with a multipollutant control as it does not 

recognize the simultaneity of the reductions achieved by the 

application of the control option. 

Another type of approach allocates the annualized cost to 

the sum of the individual pollutant emission reductions 

addressed by the multipollutant control option. The 

multipollutant cost-effectiveness approach may be appropriate 

when each of the pollutant reductions is similar in value or 
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impact. However, methane and VOC have quite different health and 

environmental impacts. Summing the pollutants to derive the 

denominator of the cost-effectiveness equation is inappropriate 

for this reason. Similarly, if the multiple pollutants could be 

combined with like units — for example, via economic valuation —

the pollutants could be summed. We also think that this approach 

would be inappropriate here.

For purposes of this proposal, we have identified and are 

proposing to use two types of approaches for considering the 

cost of reducing emissions from multiple pollutants using one 

control. One approach assigns all costs to the emission 

reduction of one pollutant and zero to all other concurrent 

reductions; if the cost is reasonable for reducing any of the 

targeted emissions alone, the cost of such control is clearly

reasonable for the concurrent emission reduction of all the 

other pollutants because they are being reduced at no additional 

cost. This approach acknowledges the reductions as intended as 

opposed to incidental or co-benefits. It also reflects the 

actual overall cost of the control. While this approach assigns 

all costs to only a portion of the emission reduction and thus 

may overstate the cost for that assigned portion, it does not 

overstate the overall cost. It also does not require evaluating 
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in aggregate the benefits of methane and VOC emission reduction, 

which is not appropriate as discussed in the option immediately 

above. In addition, this approach is simple and straightforward 

in application. If the multipollutant control is cost-effective 

for reducing emissions of either of the targeted pollutant, it 

is clearly cost-effective for reducing all other targeted 

emissions that are being achieved simultaneously. 

A second approach, which we term for the purpose of this 

rulemaking a “multipollutant cost-effectiveness” approach, 

apportions the annualized cost across the pollutant reductions 

addressed by the control option in proportion to the relative 

percentage reduction of each pollutant controlled. For example, 

in this proposal both methane and VOC emissions are reduced in 

equal proportion by the multipollutant control option. As a 

result, half of the control costs are allocated to methane, the 

other half to VOC. This approach similarly does not inflate the

control cost nor requires evaluating in aggregate the benefits 

of methane and VOC emission reduction. 

We believe that both approaches discussed above are 

appropriate for assessing the reasonableness of the 

multipollutant controls considered in this action. As such, in 
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our analyses below, if a device is cost-effective under either 

of these two approaches, we find it to be cost-effective. EPA 

has considered similar approaches in the past when considering 

multiple pollutants that are controlled by a given control 

option.44 The EPA recognizes, however, not all situations where 

multipollutant controls are applied are the same, and that other 

types of approaches, including those described above as 

inappropriate for this action, might be appropriate in other 

instances. The EPA solicits comments on the approaches to 

estimate cost-effectiveness for emissions reductions using 

multipollutant controls assessed in this action.

In considering control costs, the EPA takes into account 

any expected revenues from the sale of natural gas product that 

would be realized as a result of avoided emissions. Although no 

D.C. Circuit case addresses how to account for revenue generated 

from the byproducts of pollution control, or product saved as a 

result of control, it is logical and a reasonable interpretation 

of the statute that any expected revenues from the sale of 

recovered product may be considered when determining the overall 

 

44 See e.g. 73 FR 64079-64083 and EPA Document I.D. EPA-HQ-OAR2004-0022-0622, EPA-HQ-OAR-2004-0022-0447, EPA-HQ-OAR-2004-0022-

0448. 
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costs of implementation of the control technology. Clearly, such 

a sale would offset regulatory costs and so must be included to 

accurately assess the costs of the standard. In our analysis we 

consider any natural gas that is either recovered or that is not 

emitted as a result of a control option as being "saved." We 

estimate that one thousand standard cubic feet (Mcf) of natural 

gas is valued at $4.00.45 Our cost analysis then applies the 

monetary value of the saved natural gas as an offset to the

control cost. This offset applies where, in our estimation, the 

monetary savings of the natural gas saved can be realized by the 

affected facility owner or operator and not where the owner or 

operator does not own the gas and would not likely realize the 

monetary value of the natural gas saved (e.g., transmission 

stations and storage facilities). Detailed discussions of these 

assumptions are presented in Chapter 3 of the RIA associated 

with this action, which is in the Docket.

 

45 The Energy Information Administration’s 2014 Annual Energy 

Outlook forecasted wellhead prices paid to lower 48 state 

producers to be $4.46/Mcf in 2020 and $5.06/Mcf in 2025. The 

$4/Mcf price assumed in the RIA is intended to reflect the AEO 

estimate but simultaneously be conservatively low.
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We also completed two additional analyses to further inform 

our determination of whether the cost of control is reasonable., 

similar to compliance cost analyses we have completed for other 

NSPS46. First, we compared the capitals costs that would be 

incurred to comply with the proposed standards to the industry’s 

estimated new annual capital expenditures. This analysis allowed 

us to compare the capital costs that would be incurred to comply 

with the proposed standards to the level of new capital 

expenditures that the industry is incurring in the absence of 

the proposed standards. We then determined whether the capital 

costs appear reasonable in comparison to the industry’s current 

level of capital spending. Second, we compared the annualized 

costs that would be incurred to comply with the standards to the 

industry’s estimated annual revenues. This analysis allowed us 

determine whetherto evaluate the annualized costs appears 

reasonable as a percentage of the revenues being generated by 

the industry.

 

46 For example, see our compliance cost analysis in “Regulatory 

Impact Analysis (RIA) for Residential Wood Heaters NSPS 

Revision. Final Report.” U.S. Environmental Protection Agency, 

Office of Air Quality Planning and Standards. EPA-452/R-15-001, 

February 2015.
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EPA evaluated incremental capital cost in prior new source 

performance standards, and its determinations that the costs 

were reasonable were upheld by the courts. For example, the EPA 

estimated that the costs for the 1971 NSPS for coal-fired 

electric utility generating units were $19 million for a 600 MW 

plant, consisting of $3.6 million for particulate matter 

controls, $14.4 million for sulfur dioxide controls, and $1

million for nitrogen oxides controls, representing a 15.8 

percent increase in capital costs above the $120 million cost of 

the plant. See 1972 Supplemental Statement, 37 FR 5767, 5769 

(March 21, 1972). The D.C. Circuit upheld the EPA’s 

determination that the costs associated with the final 1971 

standard were reasonable, concluding that the EPA had properly 

taken costs into consideration. Essex Cement v. EPA, 486 F. 2d 

at 440. Similarly, in Portland Cement Association, the D.C.

Circuit upheld the EPA’s consideration of costs for a standard

of performance that would increase capital costs by about 12

percent, although the rule was remanded due to an unrelated

procedural issue. 486 F.2d at 387-88. Reviewing the EPA’s final

rule after remand, the court again upheld the standards and the

EPA’s consideration of costs, noting that “[t]he industry has

not shown inability to adjust itself in a healthy economic
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fashion to the end sought by the Act as represented by the

standards prescribed.” Portland Cement v. Ruckelshaus, 513 F. 2d

506, 508 (D.C. Cir. 1975). As shown below in the BSER analysis 

for each of the proposed standards, the associated increase in 

capital cost is well below the percentage increase previously 

upheld by the Court, and the annualized cost is but less than 1 

percent of the annual revenue. 

Capital expenditure data for relevant NAICS codes were 

obtained from the U.S. Census 2013 Annual Capital Expenditures 

Survey47. Annual revenue data for relevant NAICS codes were 

obtained from the U.S. Census 2012 County Business Patterns and 

2012 Economic Census48. For both the capital expenditures and 

annual revenues, we obtained the Census data and performed the 

analyses on an affected facility basis rather than an industrywide basis. We did this to better reflect the fact that 

different owners or operators are generally involved in the 

different industry segments. Thus, an industry-wide analysis 

would likely not be representative of the cost impacts on owners 

 

47 http://www.census.gov/econ/aces/xls/2013/full_report.html 48 For information on confidentiality protection, sampling error,

and nonsampling error, see 

http://www.census.gov/econ/susb/methodology.html. For 

definitions of estimated receipts and other definitions, see 

http://www.census.gov/econ/susb/definitions.html.
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and operators within each segment. Although there is not a oneto-one correspondence between NAICS codes and the industry 

segments we used in the development of the cost impacts, we 

believe there is enough similarity to draw accurate conclusions 

from our analysis.

For the capital expenditures analysis, we determined the 

estimated nationwide capital costs incurred by each type of 

affected facility to comply with the proposed standards, then 

divided the nationwide capital costs by the new capital 

expenditures (Census data) for the appropriate NAICS code(s) to 

determine the percentage that the nationwide capital costs 

represent of the capital expenditures. Similarly, for the annual 

revenues analysis, we determined the estimated nationwide 

annualize costs incurred by each type of affected facility to 

comply with the proposed standards, then divided the nationwide 

annualized costs by the annual revenues (Census data) for the 

appropriate NAICS code(s) to determine the percentage that the 

nationwide annualized costs represent of annual revenues. These 

percentages are presented below in this section for each 

affected facility.

B. Proposed Standards for Centrifugal Compressors
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In the 2012 NSPS, we established VOC standards for wet seal 

centrifugal compressors in the production segment of the oil and 

natural gas source category. Specifically, the standards apply 

to centrifugal compressors located after the well site and 

before transmission and storage segments because our data 

indicate that there are no centrifugal compressors in use at 

well sites49. In this action, we are proposing to extend these 

VOC standards to the remaining wet seal centrifugal compressors 

in the source category. We are also proposing methane standards 

for all wet seal centrifugal compressors in the oil and natural 

gas source category. Based on the analysis below, the proposed 

VOC and methane standards described above are the same as the 

wet seal centrifugal compressor standards currently in the NSPS. 

Centrifugal compressors are used throughout the natural gas

industry50 to move natural gas along the pipeline. They are a 

source of methane and VOC emissions. These compressors are 

powered by turbines. They use a small portion of the natural gas

 

49 Since the 2012 NSPS, we have not received information that 

would change our understanding that there are no centrifugal 

compressors in use at well sites. 50 See previous footnote regarding centrifugal compressors at 

well sites.
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that they compress to fuel the turbine. Sometimes an electric 

motor is used to turn a centrifugal compressor. 

Centrifugal compressors require seals around the rotating 

shaft to minimize gas leakage from the point at which the shaft 

exits the compressor casing. There are two types of seal 

systems: wet seal systems and mechanical dry seal systems. 

Wet seal systems use oil, which is circulated under high 

pressure between three or more rings around the compressor 

shaft, forming a barrier to minimize compressed gas leakage. 

Very little gas escapes through the oil barrier, but 

considerable gas is absorbed by the oil. The amount of gas 

absorbed and entrained by the oil barrier is affected by the 

operating pressure of the gas being handled; higher operating 

pressures result in higher absorption of gas into the oil. Seal 

oil is purged of the absorbed and entrained gas (using heaters, 

flash tanks and degassing techniques) and recirculated to the 

seal area for reuse. Gas that is purged from the seal oil is 

commonly vented to the atmosphere. Degassing of the seal oil 

emits an average of 47.7 standard cubic feet per minute (scfm) 
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of methane51, depending on the operating pressure of the 

compressor. Based on the average gas composition, which varies

among segments of the natural gas industry, we estimate methane 

emission during the venting process of an uncontrolled wet seal 

system to be, on average, 228 tpy in the production segment, 157 

tpy in the transmission segment and 117 tpy in the storage 

segment. We estimate the VOC emissions to be, on average, 

approximately 4.34 tpy VOC in the transmission segment and 3.24 

tpy of VOC in the storage segment.52

Dry seal systems do not use any circulating seal oil. Dry 

seals operate mechanically under the opposing force created by 

hydrodynamic grooves and springs. Fugitive emissions occur from

dry seals around the compressor shaft. Based on manufacturer 

studies and engineering design estimates, fugitive emissions 

from dry seal systems are approximately 6 scfm of gas, much 

lower than wet seal systems. A dry seal system can have fugitive 

 

51 Factors came from U.S Environmental Protection Agency. 

Methodology for Estimating CH4 and CO2 Emissions from Natural Gas 

Systems. Greenhouse Gas Inventory: Emission and Sinks 1990-2012. 

Washington, DC. Annex 3.5. Table A-129. 52 Estimated uncontrolled VOC emissions from a wet seal 

compressor in the processing segment is not included here 

because these emissions are already subject to subpart OOOO and 

are not included in this proposed rule.
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methane emissions of, on average, approximately 28.6 tpy in the 

processing segment, and 19.7 tpy in the transmission segment and 

14.7 tpy in the storage segment. Likewise, VOC emissions are 

estimated to be 0.5 tpy in the transmission segment and 0.4 tpy 

in the storage segment.53 In the 2012 NSPS, we did not regulate 

fugitive VOC emissions from dry seal compressors because we did 

not identify any control device suitable to capture and control 

such emissions. For the same reasons we explained in the 2012 

NSPS, we are not proposing methane standards for dry seal 

compressors. 

The available control techniques for reducing methane and 

VOC emissions from degassing of wet seal systems are the same. 

These include routing the gas to a process and routing the gas 

to a combustion device. We also consider replacing wet seal 

system with a dry seal system due to its inherent low emissions. 

These are the same options we previously identified for 

controlling fugitive VOC emissions from degassing of wet seal 

compressors. We did not find other available control options 

from our white paper process or information review. 

 

53 IBID.
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During the rulemakings for the 2012 NSPS and subsequent 

amendments, we found that the dry seal system had inherently low 

VOC emissions and the option of routing to a process had at 

least 95 percent control efficiency. However, the integration of 

a centrifugal compressor into an operation may require a certain 

compressor size or design that is not available in a dry seal 

model, or in the case of capture of emissions with routing to a 

process, there may not be down-stream equipment capable of 

handling a low pressure fuel source. As such, these two options

not technically feasible in all instances and, therefore, 

neither was the BSER for reducing fugitive VOC emissions from 

wet seal centrifugal compressors. Available information since 

then continues to show that that these two options cannot be 

used in all circumstances. For the same reasons, these options 

do not qualify as BSER for reducing methane emissions from wet 

seal centrifugal compressors.

In the 2012 NSPS rulemaking, we found that a capture and 

combustion device (option 3) had a 95 percent VOC emission 

reduction efficiency. Available information since then continues 

to support that such device can achieve 95 percent control 

efficiency and for both methane and VOC emissions. Based on the 

average uncontrolled emissions of wet seal systems discussed 
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above and a capture and combustion device system efficiency of 

95 percent, we determined that methane emissions from a wet seal 

system in the processing segment would be reduced by 217 tpy, by 

149 tpy in the transmission segment and by 111 tpy in the 

storage segment. The VOC emissions would be reduced by 4.12 tpy 

in the transmission segment and by 3 tpy in the storage 

segment.54 

For purposes of this action, we have identified in section 

VIII.A two approaches for evaluating whether the cost of a 

multipollutant control, such as option 3 (routing to a 

combustion device), is reasonable. As explained in that section, 

we believe that both approaches are appropriate for assessing 

the reasonableness of the multipollutant controls considered in 

this action. Therefore, we propose to find the cost of control 

to be reasonable as long as it is such under either of these two 

approaches. 

Under the single pollutant approach, we assign all costs to 

the reduction of one pollutant and zero to all other pollutants 

 

54 Estimated VOC emissions reductions from a wet seal compressor 

in the processing segment is not included here because these 

emissions are already subject to the NSPS are not included in 

this proposed rule.
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simultaneously reduced. For this approach, we would find the 

cost of control reasonable if it is reasonable for reducing one 

pollutant alone. As shown in the evaluation below, which assigns 

all the costs to methane reduction alone, and based on an 

annualized cost per compressor of $114,146 to install and 

operate a new combustion device for the processing, transmission 

and storage segments, we estimate the cost of control for 

reducing methane emissions from a wet seal centrifugal 

compressor to be $478 per ton for the processing segment, $767 

per ton in the transmission segment and $1,028 per ton in the 

storage segment. The cost of the simultaneous VOC reduction is 

zero because all the costs have been attributed to methane 

reduction.55 It is important to note that these costs are likely 

over-estimates for most because they assume that each compressor 

requires a new, individual control device, which is not the case 

in most instances. It is our general understanding that multiple 

compressors can and do get routed to one common control. The 

estimates also do not reflect situations where installation of a 

 

55 In 2012, we already found that the cost of this control to be 

reasonable for reducing VOC emissions from wet seal centrifugal 

compressors in the production segment. We are not reopening 

that decision in this action. Therefore, this cost finding is 

relevant only to VOC reduction from wet seal centrifugal 

compressors in the transmission and storage segments.
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control is not required because one is already available for use 

on site. 

For the reasons stated above, we believe that these 

estimates represent a conservative scenario and that the cost of 

this control (routing to a combustion control device) is lower 

in most instances.

We also evaluate the cost of methane reduction by assigning

all costs to VOC and zero to methane reduction. In the 2012 NSPS 

rulemaking we already found the cost of this control to be 

reasonable for reducing VOC emissions from wet seal centrifugal 

compressors in the production segment. Therefore, the cost of 

methane reduction is reasonable for centrifugal compressors in 

the production segment if we assign all costs to VOC under the 

single pollutant approach. 

Although we propose to find the cost of control to be 

reasonable because it is reasonable under the above approach, we 

also evaluate the cost of this control under the multipollutant

approach. 

Under the multipollutant approach, the costs are allocated 

based on the percentage reduction expected for each pollutant. 

Because option 3 reduces both methane and VOC by 95 percent, we 

attribute 50 percent of the costs to methane reduction and 50 
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percent of the cost to VOC reduction. Based on this formulation, 

the costs for methane reduction are half of the estimated costs 

under the first approach above and therefore we believe these 

costs are reasonable for the same reasons discussed above. For 

VOC, we estimate the multipollutant approach costs to be $13,853 

per ton in the transmission segment and $18,553 per ton in the 

storage segment.56 While these costs may seem high, as explained 

above, they are based on the assumption that a control device is 

required for each compressor, which is not the case in most 

instances. The estimates also do not reflect situations where 

installation of a control is not required because one is already 

available for use on site. For the reasons stated above, we 

believe the cost of VOC reduction with this control to be to 

lower than the above estimates in most instances. Because the 

operators of facilities in the transmission and storage segment 

typically do not own the gas they are handling, these costs do 

not account for gas savings in those segments. Although these 

reductions may not result in a direct financial benefit to the 

 

56 In the 2012 rulemaking, we already concluded that the cost of 

this control to be reasonable for reducing VOC emissions from 

wet seal centrifugal compressors in the production segment and 

set standards for such reduction. We are not reopening that 

decision here. Accordingly, we are not addressing VOC reduction 

in the production segment here. 
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operator, we believe it is worthwhile to note that overall these 

standards save a non-renewable resource. 

As discussed above in section VIII.A two additional 

approaches, based on new capital expenditures and annual 

revenues, for evaluating whether the costs are reasonable. For 

the capital expenditure analysis, we used the capital 

expenditures for 2012 for NAICS 4862 as reported in the U.S. 

Census data, which we believe is representative of the 

transmission and storage segment. The total capital costs for 

complying with the proposed standards for centrifugal 

compressors is 0.011 percent of the total capital expenditures, 

which we believe is reasonable. For the total revenue analysis, 

we used the revenues for 2012 for NAICS 486210, which we believe 

is representative of the transmission and storage segment. The 

total annualized costs for complying with the proposed standards 

is 0.001 percent of the total revenues, which we believe is

reasonable. 

For all types of affected facilities in the transmission 

and storage segment, the total capital costs for complying with 

the proposed standards is 0.24 percent of the total capital 

expenditures, andwhich is well below the percentage capital 

increase that courts have previously upheld as reasonable as 
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discussed in Section VIII.A.. Similarly, the total annualized 

costs for complying with the proposed standards is also very 

low, at 0.11 percent of the total revenues, which we believe is 

reasonable.

With this control option, there would be secondary air 

impacts from combustion. However we did not identify any nonair 

quality or energy impacts associated with this control 

technique. 

In light of the above, we find that the BSER for reducing 

VOC emissions from wet seal centrifugal compressors in the 

transmission and storage segment and for reducing methane 

emissions from all wet seal centrifugal compressors in the oil 

and natural gas source category are the same, i.e., to capture 

and route the emissions to a combustion control device. As 

discussed above, this option results in a 95 percent reduction 

of emissions for both methane and VOC. 

The 2012 NSPS requires that VOC emissions from wet seal 

centrifugal compressors in the natural gas production segment be 

reduced by 95 percent, which similarly reflects the reduction 

that can be achieved by capturing and routing to a combustion 

control device. We are, therefore, proposing to extend the 

existing 95 percent VOC reduction standard to all other wet seal 
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centrifugal compressors in the oil and natural gas source 

category (i.e., natural gas transmission and storage segments). 

We are also proposing to require 95 percent reduction of methane 

emissions from all wet seal centrifugal compressors in the oil 

and natural gas source category. As in the 2012 NSPS, our 

proposal would allow dry seal systems and routing emissions to a 

process as alternatives to routing to a combustion device to 

meet the proposed 95 percent emission reduction standards. We 

hope that by such provisions, owners and operators would be 

encouraged to employ these effective emission control options 

where feasible. As described above, the proposed VOC and methane 

standards would be the same as the current VOC standards for wet 

seal centrifugal compressors in the NSPS. 

C. Proposed Standards for Reciprocating Compressors 

In the 2012 NSPS, we established VOC standards for 

reciprocating compressors in the production (located other than 

at well sites) and processing segments of the oil and natural 

gas source category. In this action, we are proposing VOC 

standards for the remaining reciprocating compressors in the 

source category that are not located at a well site. We are also 

proposing methane standards for all reciprocating compressors in 

the oil and natural gas source category except for those that 
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are located at well sites57. Based on the analysis below, the 

proposed VOC and methane standards described above are the same 

as the reciprocating compressor standards currently in the NSPS.

Reciprocating compressors are used throughout the oil and 

natural gas industry and are a source of methane and VOC 

emissions. Emissions occur when natural gas leaks around the 

piston rod when pressurized natural gas is in the cylinder. The

most significant volumes of gas loss and resulting fugitive 

methane and VOC emissions are associated with piston rod packing 

systems. Rod packing systems are used to maintain a tight seal 

around the piston rod, preventing the high pressure gas in the 

compressor cylinder from leaking, while allowing the rod to move 

freely. This leakage rate is dependent on a variety of factors, 

including physical size of the compressor piston rod, operating 

speed and operating pressure. Higher leak rates are a 

consequence of improper fit, misalignment of the packing parts 

and wear. We estimate that reciprocating compressors have 

emissions of 0.198 tpy methane and 0.055 tpy VOC in the 

production segment (well sites), 12.3 tpy methane and 3.42 tpy 

VOC in the production segment (other than located at well site), 

 

57 As discussed later in this section, the control cost for 

reciprocating compressors at well site is not reasonable. 
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23.3 tpy methane and 6.48 tpy VOC in the processing segment, 

27.1 tpy methane and 0.75 tpy VOC in transmission segment, and 

28.2 tpy methane and 0.78 tpy VOC in the storage segment. 

In developing the 2012 NSPS, we examined two options to

reduce VOC emissions from reciprocating compressors. One 

approach was based on routing emission to a combustion device, 

as is used with wet seal centrifugal compressors. The other 

option was based on regular replacement of piston rod packing. 

Upon reconsideration of the standards in 2014, we evaluated a 

third option, routing of emissions to a process through a closed 

vent system under negative pressure. Information since the 2012 

NSPS development have not identified other control options for 

reciprocating compressors. 

We rejected combustion as the BSER because, as detailed in 

the 2011 TSD, routing of emissions to a control device can cause 

positive back pressure on the packing, which can cause safety 

issues due to gas backing up in the distance piece area and 

engine crankcase in some designs. While considering the option 

of routing of emissions to a process through a closed vent 

system under negative pressure, we determined that the negative 

pressure requirement not only ensures that all the emissions are 

conveyed to the process, it also avoids the issue of inducing 
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back pressure on the rod packing and the resultant safety 

concerns. Although this option can be used in some 

circumstances, it cannot be applied in every installation. As a 

result, this option was not further considered for the 

determination of the BSER.

As noted above, the most significant volumes of gas loss 

are associated with piston rod packing systems. We found that 

under the best conditions, new packing systems properly 

installed on a smooth, well-aligned shaft can be expected to 

leak a minimum of 11.5 scfh of natural gas. We determined that 

regular rod packing replacement, when carried out approximately 

every three years, effectively controls emissions and helps 

prevent excessive rod wear and determined that the BSER is 

regular replacement of rod packing. The control measures 

discussed above also reduce methane emissions. 

We are not aware of any other methods for controlling 

methane and VOC emissions from the rod packing of reciprocating 

compressors. We estimate that replacement of the compressor rod 

packing every 26,000 hours reduces methane emissions by 0.16 tpy 

in the production segment (well site) 6.84 tpy in the production 

segment (excluding the well site), 18.6 tpy in the processing 

segment, 21.7 tpy in the transmission segment, and 21.8 tpy in 
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the storage segment. Likewise, replacement of rod packing is 

estimated to reduce VOC emissions by 0.6 tpy in the transmission 

and storage segments.58 See the 2011 TSD and 2015 TSD for details 

of these calculations.

For the 2012 NSPS, we estimated the annual costs of 

replacing the rod packing to be $2,493 for the production 

segment (well sites), $1,669 for the production segment 

(excluding well sites), $1,413 for processing plants, $1,748 for 

transmission stations, and $2,077 for storage facilities without 

considering the cost savings realized from the recovered gas. 

Considering gas savings, the annual cost of replacing the rod 

packing was $2,457 for the production segment (well sites), $83 

for the production segment and a net savings for the processing 

segment. We did not consider gas savings for transmission and 

storage segments because owners and operators of these 

 

58 Estimated VOC emissions reductions from reciprocating 

compressors in the production segment (at well sites and other 

than well sites) and the processing segment are not included 

here because these emissions are already subject to the NSPS are 

not included in this proposed rule. Under the 2012 NSPS we found 

the cost of control for VOC emissions from reciprocating 

compressors at well sites to be unreasonable and final rule did 

not set standards for reciprocating compressors located at well 

sites.
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facilities do not necessarily own the gas they are handling and 

therefore would not realize gas savings.

As explained in section VIII.A, for purposes of this 

action, we have identified two approaches for evaluating whether 

the cost of a multipollutant control, such as rod packing 

replacement described above, is reasonable. As explained in that 

section, we believe that both approaches are appropriate for 

assessing the reasonableness of the multipollutant controls 

considered in this action. Therefore, we propose to find the 

cost of control to be reasonable as long as it is such under 

either of these two approaches. 

Under the single pollutant approach, which attributes all 

cost to one pollutant and zero to the other pollutant, we would 

find the cost of control reasonable if it is reasonable for 

reducing one pollutant alone. When assigning all costs to 

methane alone and zero to the simultaneous VOC reduction, the 

cost of control is $15,802 per ton for the production segment 

(well sites), $244 per ton of methane for the production segment

(excluding well sites), $76 per ton of methane for the 

processing segment, $81 per ton of methane in the transmission 

segment and $95 per ton of methane in the storage segment. When 

assigning all costs to VOC alone and zero to the simultaneous 
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methane reduction, the cost of control under this approach is 

$2,910 per ton of VOC reduced in the transmission segment, and 

$3,434 per ton of VOC reduced in the storage segment.59 In light 

of the above, we find the costs of rod-packing replacement are

reasonable for reducing methane and VOC emissions across the 

industry (except at well sites) under the single pollutant 

approach irrespective of which pollutant bears all of the costs. 

Under the multipollutant approach, because the control 

achieves the same reduction for both methane and VOC, we would 

apportion the cost equally between methane and VOC. Rod Packing 

replacement reduces the amount of natural gas emitted by the 

compressor. This natural gas contains both methane and VOC; 

therefore, reducing the amount of natural gas emitted will 

reduce methane and VOC in equal proportion. Using the 

multipollutant approach, the cost of control for methane is 

$7,901 per ton for the production segment (well sites), $122 per 

ton for the production segment (excluding well sites), $38 per 

ton for the processing segment, $40 per ton for the transmission 

 

59 VOC emissions reductions from reciprocating compressors in the 

production segment (at well sites and other than well sites) and 

the processing segment are already subject to the 2012 NSPS. We 

are not reopening those standards in this action. 
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segment, and $48 per ton for the storage segment. The cost of 

control for VOC under the multipollutant approach is $1,455 per 

ton for the transmission segment and $1,717 per ton for the 

storage segment.60 In light of the above, with the exception of 

compressors located at well sites, we consider the costs to be 

reasonable for the estimated methane reductions across the 

source category and the estimated VOC reductions for the 

currently unregulated compressors under both approaches. In the 

2012 NSPS rulemaking, we found the cost of rod packing not 

reasonable for reducing VOC emissions from reciprocating 

compressors at well sites. This finding remains unchanged under 

the two cost approaches discussed in section VIII.A. We also 

found the cost of control for methane emissions to not be 

reasonable for the amount of methane emissions achieved under 

either approach.

As discussed in section VIII.A, we also identified two 

additional approaches, based on new capital expenditures and 

annual revenues, for evaluating whether the costs are 

reasonable. For the capital expenditure analysis, we used the 

capital expenditures for 2012 for NAICS 4862 as reported in the 

 

60 See footnote 56.
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U.S. Census data, which we believe is representative of the 

transmission and storage segment. The total capital costs for 

complying with the proposed standards for reciprocating

compressors is 0.022 percent of the capital expenditures, which 

we believe is well below the percentage capital increase that 

courts have previously upheld as reasonable. as discussed in 

Section VIII.A.. For the total revenue analysis, we used the 

revenues for 2012 for NAICS 486210, which we believe is 

representative of the transmission and storage segment. The 

total annualized cost for complying with the proposed standards 

is 0.003 percent of the total revenues, which we believe is 

reasonablealso very low.

For all types of affected facilities in the transmission 

and storage segment, the total capital cost for complying with 

the proposed standards is 0.24 percent of the capital 

expenditures, and the total annualized cost for complying with 

the proposed standards is also very low, at 0.11 percent of the 

total revenues, which we believe is reasonable.

We did not identify any nonair quality health or 

environmental impacts or energy impacts associated with 

replacement of rod packing and therefore, no analyses was 

conducted. In light of the above, we propose that rod packing 
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replacement is the BSER for reducing methane and VOC emissions

from compressors in the oil and natural gas sector, with the 

exception of reciprocating compressors located at well sites. 

See the 2011 and 2015 TSDs, available in the docket, for detail 

on methodology used for emissions and cost of control 

estimation.

Because the VOC and methane emissions from reciprocating 

compressors are fugitive emissions that occur when natural gas 

leaks around the piston rod when pressurized natural gas is in 

the cylinder, it is technically infeasible capturing and routing 

emissions to a control device. Therefore, we are unable to set a 

numerical emission limit for reciprocating compressors. Pursuant 

to section 111(h), we are proposing an operation standard based 

on rod packing replacement. The proposed standards are the same 

as the current VOC standard in the NSPS for reciprocating 

compressors, which was also based on rod packing replacement.

Specifically we propose to replace rod packing every 3 years of 

operation. However, to account for segments of the industry in 

which reciprocating compressors operate in pressurized mode for 

a fraction of the calendar year (ranging from approximately 68 

percent up to approximately 90 percent), we determined that 

26,000 hours of operation would be, on average, comparable to 3 
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years of continuous operation. As a result, we are proposing a 

work practice standard based on our determination that 

replacement of rod packing no later than after 26,000 hours of 

operation or after 36 calendar months represents the BSER. The 

owner or operator would be required to monitor the hours of 

operation beginning with the installation of the reciprocating 

compressor affected facility. Cumulative hours of operation 

would be reported each year in the facility’s annual report. 

Once the hours of operation reached 26,000 hours, the owner or 

operator would be required to change the rod packing 

immediately, although unexpected shutdowns could be avoided by 

tracking hours of operation and planning for packing replacement 

at scheduled maintenance shutdowns before the hours of operation 

reached 26,000. Alternatively, owners and operators may replace 

rod packing every 36 months and would not be required to track 

operating hours of the compressor.

As with the current requirement for controlling VOC from 

these reciprocating compressors, we are allowing routing of 

emissions from the rod packing to a process through a closed 

vent system under negative pressure as an alternative to rod 

packing replacement. As mentioned above, it is our understanding 

that this technology can capture all emissions; however, it may 
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not be applicable to every compressor installation and situation 

and, therefore, it would be within the operator’s discretion to 

choose whichever option is most appropriate for the application 

and situation at hand.

Following the December 31, 2014, amendments to the NSPS, 

which added the alternative of routing of emissions from the rod 

packing to a process through a closed vent system under negative 

pressure, we received a petition for administrative 

reconsideration of the standard for reciprocating compressors.61

The petitioner requested that EPA provide an additional 

alternative to the rod packing replacement intervals of 26,000 

hours or 36 months. The alternative suggested by the petitioner 

would consist of monitoring of rod packing leakage to identify 

when the rate of rod packing leakage indicates that packing 

replacement is needed. We have requested additional information

from the petitioner on the technical details of the petitioner’s 

concept. As a result, we are unable at this time to evaluate the 

alternative suggested by the petitioner.

D. Proposed Standards for Pneumatic Controllers 

 

61 Letter from John P. Miguez, Founder and Sr. Partner, M-Squared 

Products & Services, Inc., to Gina McCarthy, EPA Administrator, 

Petition for Reconsideration, January 20, 2015.
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In the 2012 NSPS, we established VOC standards for 

pneumatic controllers in the production and processing segments 

of the oil and natural gas source category. In this action, we 

are proposing VOC standards for the remaining pneumatic 

controllers in the source category. We are also proposing 

methane standards for all pneumatic controllers in the oil and 

natural gas source category. Based on the analysis below, the 

BSER for reducing the methane and VOC emissions from the 

pneumatic controllers described above are the same as the BSER 

for those that are currently subject to the VOC standards. 

Accordingly, the proposed VOC and methane standards described 

above are the same as the pneumatic controller standards 

currently in the NSPS. 

Pneumatic controllers are automated instruments used for 

maintaining a process condition, such as liquid level, pressure, 

pressure differential and temperature that typically operate by 

using available high-pressure natural gas. 

In these “gas-driven” pneumatic controllers, natural gas 

may be released with every valve movement or continuously from 

the valve control pilot. The rate at which this release occurs 

is referred to as the device bleed rate. Bleed rates are 

dependent on the design of the device. Similar designs will have 
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similar steady-state rates when operated under similar 

conditions. Gas-driven pneumatic controllers are typically 

characterized as “high-bleed” or “low-bleed,” where a high-bleed 

device releases more than 6 scfh of gas. There are two basic 

designs: (1) continuous bleed devices (high or low-bleed) are 

used to modulate flow, liquid level or pressure, and gas is 

vented at a steady-state rate; and (2) intermittent devices 

perform quick control movements and only release gas when they 

open or close a valve or as they throttle the gas flow.62

Not all pneumatic controllers are gas driven. These “nongas driven” pneumatic controllers use sources of power other 

than pressurized natural gas, such as compressed “instrument”

air. Because these devices are not gas driven, they do not 

release natural gas (or methane or VOC emissions), but they do 

have energy impacts because electrical power is required to 

drive the instrument air compressor system.

As we explained for the 2012 NSPS, because manufacturers’ 

technical specifications for pneumatic controllers are stated in 

 

62 We did not address intermittent controllers in the 2012 NSPS, 

and we are not addressing them in this action. Intermittent 

controllers are inherently low emitting sources because they 

vent only when actuating and the total emissions are dependent 

on the applications in which they are used. 
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terms of natural gas bleed rate rather than methane or VOC, we 

used natural gas as a surrogate for VOC. We evaluated the impact 

of a high-bleed pneumatic controller emission rate (37 scfh of 

natural gas for the production and processing segments and 18

scfh of natural gas for the transmission and storage segments) 

contrasted with the emission rate of a low-bleed unit (1.39 scfh 

of natural gas for the production and processing segments and 

1.37 scfh of natural gas for the transmission and storage 

segment).63 We determined per-controller high-bleed pneumatic 

controller methane emissions to be 6.91 tpy in the production 

segment, 1 tpy in the processing segment and 3.01 tpy in the 

transmission and storage segment. We estimate high-bleed 

pneumatic controller emissions to be 0.08 tpy VOC in the 

transmission and storage segments.64 In contrast, we estimate the 

per-controller low-bleed pneumatic controller methane emissions 

 

63 Emission factors and emissions data for production and 

processing segments are from TSD for the 2011 proposed rule, 

available in the docket. Emission factors for transmission and 

storage are from Subpart W Continuous Bleed Controller Emission 

Factors (Table W-1A of 40 CFR Part 98, Subpart W). Available at 

http://www.ecfr.gov/cgi-bin/textidx?SID=dda4d1715e9926ee3517ac08e6258817&node=40:21.0.1.1.3.23&r

gn=div6#ap40.21.98_1238.1. 64 Estimated VOC emissions from pneumatic controllers in the 

production and processing segments are not included here because 

these emissions are already subject to the NSPS are not included 

in this proposed rule.
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to be 0.26 tpy in the production segment, 1 tpy in the 

processing segment, and 0.23 tpy in the transmission and storage 

segments. We estimate the low-bleed pneumatic controller VOC 

emissions to be 0.006 tpy in the transmission and storage 

segment. 

We are not aware of any add-on controls that are or can be 

used to reduce methane or VOC emissions from gas-driven 

pneumatic controllers. Therefore, the available control 

techniques for reducing methane and VOC emissions from pneumatic 

controllers are the same, which are: (1) use of a low-bleed 

controllers; or (2) use of non-gas driven controllers (i.e., 

instrument air systems). These are the same control options we 

previously identified in the 2012 NSPS for controlling VOC 

emissions from pneumatic controllers. We did not find other 

available control options from our white paper process or 

information review.

As in the 2012 NSPS, our current analysis indicates that in 

order to use an instrument air system, a constant reliable 

electrical supply would be required to run the compressors for 

the system. At sites without available electrical service 

sufficient to power an instrument air compressor, only gas 

driven pneumatic devices are technically feasible in all 
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situations. Therefore, for the production and transmission and 

storage segments, where electrical service sufficient to power 

an instrument air system is likely unavailable, we evaluated 

only the option to use low-bleed controllers in place of highbleed controllers.

During the development of the 2012 NSPS, we estimated 

methane emissions along with VOC emissions from pneumatic 

controllers. We estimated that for an average high-bleed 

pneumatic controller located in the production segment, the 

difference in emissions between a high-bleed controller and a 

low-bleed controller is 6.65 tpy methane.65 We also estimated 

that replacing a natural gas-driven pneumatic controller in the 

processing segment with an instrument air system would reduce 

methane emissions by 1 tpy. Further, we estimate that the 

emission reductions of replacing a high-bleed with a low-bleed 

pneumatic controller in the transmission and storage segment 

would be 2.79 tpy of methane and 0.077 tpy of VOC per 

controller.

 

65 We note that VOC emissions from pneumatic controllers in the 

production and processing segments are already subject to 

subpart OOOO. We are not reopening those standards in this 

rulemaking. 
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For purposes of this action, we have identified in section 

VIII.A two approaches for evaluating whether the cost of a 

multipollutant control, such as replacing a high-bleed 

controller with a low-bleed controller, is reasonable. As 

explained in that section, we believe that both the single and 

multipollutant approaches are appropriate for assessing the 

reasonableness of the multipollutant controls considered in this 

action. Therefore, we find the cost of control to be reasonable 

as long as it is such under either of these two approaches.

Under the single pollutant approach, we assign all costs to 

the reduction of one pollutant and zero to all other pollutants 

simultaneously reduced. For this approach, we would find the 

cost of control reasonable if it is reasonable for reducing one 

pollutant alone. The evaluation below for pneumatic controllers 

in the production, transmission and storage segments first

assigns all the costs to methane reduction alone, and uses an 

incremental capital cost difference between a new high-bleed 

controller and a new low-bleed controller of $165 for the 

production segment and $227 for the transmission and storage 

segment, which results in cost of control of $24 for the 

production segment and $25 for the transmission and storage 

segment. 
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We estimate the cost of replacing high-bleed controllers 

with low-bleed controllers to be $4 per ton of methane reduced 

in the production segment and $9 per ton of methane reduced in 

the transmission and storage segment. We find these costs to be 

reasonable for the amount of methane reduction it can achieve. 

Also, because all the costs have been attributed to methane 

reduction, the cost of simultaneous VOC reduction is zero and 

therefore reasonable. We also evaluated the cost by attributing 

all the costs to VOC reduction and estimated the cost to be $13

per ton of VOC reduction in the production segment and $323 per 

ton of VOC reduction in the transmission and storage segment.66

We also find these costs to be reasonable.

Although we propose to find the cost of control to be 

reasonable because it is reasonable under the above approach, we 

also evaluated the cost on this control under the multipollutant

approach. Under this approach, the costs are allocated based on 

the percentage reduction expected for each pollutant. Because 

 

66 We note that during the 2012 NSPS rulemaking, we already 

determined the costs of VOC reduction from pneumatic controllers 

at the production and processing segments to be reasonable. 

Accordingly, under the single-pollutant approach, the costs 

would also be reasonable for methane reduction as well for those 

pneumatic controllers. 
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replacing a high-bleed controller with a low-bleed controller 

reduces the natural gas emitted by the controller, both methane 

and VOC are reduced equally, we attribute 50 percent of the 

costs to methane reduction and 50 percent of the costs to VOC 

reduction. Based on this formulation, the costs for methane and 

VOC reduction are half of the estimated costs under the first 

approach and are therefore reasonable.

We also identified in section VIII.A two additional 

approaches, based on new capital expenditures and annual 

revenues, for evaluating whether the costs are reasonable. For 

the capital expenditure analysis, we used the capital 

expenditures for 2012 for NAICS 4862 as reported in the U.S. 

Census data, which we believe is representative of the 

transmission and storage segment. The total capital cost for 

complying with the proposed standards for pneumatic controllers

is 0.0022 percent of the total capital expenditures, which we 

believe is reasonable.is well below the percentage capital 

increase that courts have previously upheld as reasonable as 

discussed in Section VIII.A.. For the total revenue analysis, we 

used the revenues for 2012 for NAICS 486210, which we believe is 

representative of the transmission and storage segment. The 

total annualized cost for complying with the proposed standards 
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is 0.0001 percent of the total revenues, which we believe is 

reasonablealso very low.

For all types of affected facilities in the transmission 

and storage segment, the total capital costs for complying with 

the proposed standards is 0.24 percent of the total capital 

expenditures, and the total annualized costs for complying with 

the proposed standards is 0.11 percent of the total revenues, 

which we believe is reasonablealso very low.

With this option, we do not anticipate any secondary air 

impacts. We also did not identify any nonair quality or energy 

impacts associated with this control technique, therefore, these 

impacts were not analyzed.

In light of the above, we find that the BSER for reducing 

methane emissions from continuous bleed natural gas-driven 

pneumatic controllers in the production and transmission and 

storage segment and VOC emissions from the remaining unregulated 

pneumatic controllers (i.e., those in the transmission and 

storage segment) would be the installation of low-bleed 

pneumatic controllers. This is the same BSER we identified in 

the 2012 final rule for reducing VOC emissions from pneumatic 

controllers in the production and processing segments.
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Accordingly, we are proposing a methane emission standard 

for continuous-bleed, natural gas-driven pneumatic controllers 

in the production and transmission and storage segment to be a 

natural gas bleed rate of less than or equal to 6 scfh. We are 

also proposing a VOC emissions standard for continuous-bleed, 

natural gas-driven pneumatic controllers in the transmission and 

storage segment to be a natural gas bleed rate of less than or 

equal to 6 scfh. As described above, the proposed methane and 

VOC standards would be the same as the current VOC standards for 

pneumatic controllers in the production segment in the NSPS.

It is important to note that these costs are most likely 

over-estimates because they do not take into account the cost 

savings that would result based on the value of natural gas 

saved. Therefore, the above cost estimated, which we have 

already found to be reasonable, represent a conservative

scenario and that the cost of these controls are lower in most 

instances.

For the processing segment, which comprises pneumatic 

controllers at natural gas processing plants, we identified 

instrument air systems and replacement of high-bleed controllers 

with low-bleed controllers as control options for reducing 
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methane emissions from pneumatic controllers.67 These are the 

same options we identified for the 2012 rule to reduce VOC 

emissions from these pneumatic controllers. As described below, 

we first evaluated the cost of an instrument air system to 

reduce methane emissions. Since we found these costs to be 

reasonable (as discussed below), we did not evaluate the costs 

of replacing the high-bleed pneumatic controllers with low-bleed 

controllers because the replacement option would result in less 

methane emission reduction than the instrument air option. 

The annual costs of the instrument air system per gas 

processing plant without considering the cost savings realized 

from the recovered gas are $11,090, and $7,676 when considering 

these savings. See the 2012 Supplemental TSD68 for details of 

these calculations.

We evaluate the cost of using an instrument air system to 

reduce methane emissions from the pneumatic controllers at gas 

processing plants based on the two approaches identified earlier 

 

67 In the 2012 NSPS, EPA established VOC standards for pneumatic 

controllers at natural gas processing plants. We are not 

reopening up those standards in this proposed rule.

68 Oil and Natural Gas Sector: Standards of Performance for Crude 

Oil and Natural Gas Production, Transmission, and Distribution—

Background Supplemental Technical Support Document for the Final 

New Source Performance Standards, USEPA, Office of Air Quality 

Planning and Standards, April 2012.
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in this section for considering the cost of a multipollutant 

control (in this case the instrument air system). Under the 

single pollutant approach, which assigns all costs to the 

reduction of one pollutant and zero to all other pollutants 

simultaneously reduced, we would find the cost of control 

reasonable if it is reasonable for reducing one pollutant alone. 

In the 2012 NSPS rulemaking, we already determined that the cost 

of this control for reducing VOC emissions alone is reasonable 

for pneumatic controllers at gas processing plants (76 FR 

52760). Having assigned all the cost to VOC, the cost of methane 

reduction would be zero and therefore clearly reasonable. If we 

assign all the cost to methane instead, it is $738 per ton

without considering cost savings and $506 per ton considering 

cost savings. These costs do not appear excessive, nor do we 

have reason to believe that they are beyond what the industry 

can bear. In light of the above, we find the cost of reducing 

methane emissions from the pneumatic controllers at gas 

processing plants to be reasonable under the single pollutant 

approach. 

The second approach is to evaluate the cost on a 

multipollutant basis, based on the percentage reduction expected 

of VOC and methane. We estimate that replacing high-bleed 
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pneumatic controllers with a non-natural gas driven pneumatic 

controller (i.e., instrument air-powered) reduces methane 

emissions by 15 tpy and VOC emissions by 4.2 tpy at gas 

processing plants. Refer to the 2012 TSD for details of these 

calculations. Because the control achieves the same reduction 

for both methane and VOC, under this approach, we apportion the 

cost equally, resulting in a cost of control of $369 per ton of 

methane reduced without considering gas savings. Considering gas 

savings, the cost of control is $253 per ton of methane. These 

costs do not appear excessive, nor do we have reason to believe 

that they are beyond what the industry can bear. 

With respect to the VOC control cost under this approach, 

as mentioned above, in the 2012 NSPS rulemaking, we already 

determined that the cost of this control for reducing VOC 

emissions alone is reasonable for pneumatic controllers at gas 

processing plants (76 FR 52760). The cost of VOC reduction under 

the multiple pollutant approach would be half of that cost and 

therefore clearly reasonable. In light of the above, we find the 

cost of reducing methane emissions from pneumatic controllers at 

gas processing plants to be reasonable as well under the multipollutant approach. As mentioned above, we did not identify any 
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nonair quality or energy impacts associated with this control 

option, therefore no impacts were analyzed. 

Based on the above considerations, we propose that 

pneumatic controllers powered by an instrument air system are 

the BSER for reducing methane emission from pneumatic 

controllers at gas processing plants. This is the same BSER we 

identified for reducing VOC emissions from pneumatic controllers 

at gas processing plants in the 2012 final rule.

For the reasons discussed above and in the TSD, we have 

determined that BSER for reducing methane emissions from 

pneumatic controllers in the processing segment to be instrument 

air-activated controllers which represent an emission rate of

zero for methane. Accordingly, we are proposing a methane 

standard for pneumatic controllers in the processing segment to 

be a natural gas bleed rate of zero. This is the same as the VOC 

standard for these pneumatic controllers in the 2012 NSPS. 

We have identified situations where high-bleed controllers 

are necessary due to functional requirements, such as positive 

actuation or rapid actuation. An example would be controllers 

used on large emergency shutdown valves on pipelines entering or 

exiting compression stations. The current NSPS takes this into 

account by exempting pneumatic controllers from meeting the
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applicable emission standards if compliance would pose a 

functional limitation due to their actuation response time or 

other operating characteristics. We propose to similarly exempt 

pneumatic controllers from meeting the proposed methane standard

if compliance would pose a functional limitation due to their 

actuation response time or other operating characteristics. 

E. Proposed Standards for Pneumatic Pumps

In the 2012 NSPS, we did not establish standards for 

pneumatic pumps. Pneumatic pumps are devices that use gas 

pressure to drive a fluid by raising or reducing the pressure of 

the fluid by means of a positive displacement, a piston or set 

of rotating impellers. Gas powered pneumatic pumps are generally 

used at oil and natural gas production sites where electricity 

is not readily available and can be a significant source of 

methane and VOC emissions.69 As discussed previously, in April 

2014, the EPA published a white paper titled “Oil and Natural 

Gas Sector Pneumatic Devices.” The paper summarized the EPA’s 

understanding of methane and VOC emissions from pneumatic pumps 

and also presented the EPA’s understanding of mitigation 

techniques (practices and equipment) available to reduce these 

 

69 GRI/EPA, 1996d.
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emissions, including the efficacy and cost of the technologies 

and the prevalence of use in the industry. 

During our review of the public and peer review comments on 

the white paper and the Wyoming state rules, we identified 

different types of pneumatic pumps that are commonly used in the 

oil and natural gas sector. Wyoming is the only state of which 

we are aware that has air emission standards for pneumatic 

pumps. Pneumatic chemical and methanol injection pumps are 

generally used to pump fairly small volumes of chemicals or 

methanol into well-bores, surface equipment, and pipelines. 

Typically, these pumps include plunger pumps with a diaphragm or 

large piston on the gas end and a smaller piston on the liquid 

end to enable a high discharge pressure with a varied but much 

lower pneumatic supply gas pressure. They are typically used 

semi-continuously with some seasonal variation. Pneumatic 

diaphragm pumps are another type used widely in the oil and 

natural gas sector to move larger volumes of liquids per unit of 

time at lower discharge pressures than chemical and methanol 

injection pumps. The usage of these pumps is episodic including 

transferring bulk liquids such as motor oil, pumping out sumps, 

and circulation of heat trace medium at well sites in cold 

climates during winter months. 
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Emissions from pneumatic pumps occur when the gas used in 

the pump stroke is exhausted to enable liquid filling of the 

liquid chamber side of the diaphragm. Emissions are a function 

of the amount of fluid pumped, the pressure of the pneumatic 

supply gas, the number of pressure ratios between the pneumatic 

supply gas pressure and the fluid discharge pressure, and the 

mechanical inefficiency of the pump. 

Based on emission factors obtained from an EPA/GRI report70

we estimate emissions from natural gas-driven piston pumps 

(i.e., pneumatic chemical and methanol injection pumps) and 

diaphragm pumps in both the production and processing segments 

to be 2.48 scf natural gas per hour and 22.45 scf natural gas 

per hour respectively. Based on these emission rates, and using 

the gas composition developed during the 2012 NSPS for the 

production and processing segments (i.e., natural gas is 82.9 

percent methane and VOC constitutes 0.27797 pounds of VOC per

pound of methane), we estimate the baseline emissions from a 

natural gas-driven piston pump in either the production or 

processing segment to be 0.38 tpy of methane and 0.11 tpy of 

 

70 EPA/GRI. Methane Emissions from the Natural Gas Industry, 

Volume 13: Chemical Injection Pumps. June 1996 (EPA-600/R -96-

080m), Sections 5.1 – Diaphragm Pumps and 5.2 – Piston Pumps.
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VOC, and a gas-driven diaphragm pump to be 3.46 tpy of methane 

and 0.96 tpy of VOC.

We estimate that emissions in the transmission and storage 

segment are 2.21 scf natural gas per hour for a pneumatic piston

pump and 20.05 scf natural gas per hour for a diaphragm pump.

Based on these emissions rates, and using the gas composition 

developed during the 2012 NSPS for the transmission and storage 

segment (i.e., natural gas is 92.8 percent methane and VOC 

constitutes 0.0277 pounds of VOC per pound of methane), we 

estimate the baseline emissions from a natural gas-driven piston

pump to be 0.38 tpy of methane and 0.01 tpy of VOC, and a gasdriven diaphragm pump to be 3.46 tpy of methane and 0.10 tpy of 

VOC in the transmission and storage segment. These emission 

estimates are explained in detail in the TSD for this action 

available in the docket. 

As discussed in the white paper, we identified several 

options for reducing methane and VOC emissions from natural gasdriven pumps: replace natural gas-driven pumps with instrument 

air pumps, replace natural gas-driven pumps with solar-powered 

direct current pumps (solar pumps), replace natural gas-driven 

pumps with electric pumps, and route natural gas-driven pump 

emissions to a control device. In some applications, chemical 
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injection pumps can be retrofitted with instrument air to drive 

the pumps.71 During our review of the Wyoming state rule covering 

pneumatic pumps, we identified an additional mitigation option 

for reducing emission from piston and diaphragm natural gasdriven pumps, which involves routing the gas to a process72 or 

routing the gas to a combustor (often done as part of the 

storage vessel control system). As with the BSER for wet seal 

centrifugal compressors discussed earlier in this section, the 

emission reduction potential for this option is estimated at 95 

percent based on the efficiencies of the capture system and the 

combustion device. No further control options were identified 

from our white paper process or information review.

Instrument air systems and electric pumps require a 

reliable, constant supply of electrical power. Because of their 

remote locations, well sites, gathering and boosting stations

and potentially transmission stations and storage facilities may 

not necessarily have a constant, reliable electrical power 

 

71 U.S. EPA, 2011b. 72 Subpart OOOOa defines “route to a process” to mean that “the 

emissions are conveyed via a closed vent system to any enclosed 

portion of a process where the emissions are predominantly 

recycled and/or consumed in the same manner as a material that 

fulfills the same function in the process and/or transformed by 

chemical reaction into materials that are not regulated 

materials and/or incorporated into a product; and/or recovered.”
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supply. Therefore, we do not believe the use of instrument air 

systems and electric pumps are feasible at all facilities in the 

production and transmission and storage segments. However, we 

take comment on is the availability of a constant, reliable 

source of electrical power at facilities throughout the oil and 

natural gas source category. 

Natural gas processing plants are known to have a constant 

and reliable source of electrical power. Therefore, instrument 

air systems are technically feasible at natural gas processing 

plants. Because pumps powered by instrument air systems release 

no natural gas, the methane and VOC emissions are reduced by 100 

percent under this control option.

For natural gas processing plants, the potential emission 

reduction for the instrument air option is 3.46 tpy of methane 

and 0.96 tpy of VOC for each diaphragm pump, and 0.38 tpy of 

methane and 0.11 tpy of VOC for each piston pump replaced.

While solar pumps can be installed in certain situations, 

these pumps are not technically feasible in all situations for 

which piston pumps and diaphragm pumps are needed. Specifically, 

weather conditions in certain areas can limit the effectiveness 

of solar pumps and the capacity of solar pumps is also limited, 

so they cannot be used in all situations where larger pumps are 
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needed. Therefore, solar pumps are not universally feasible 

control option for the production and transmission and storage 

segments. 

As a result, we further analyzed the remaining potential 

control option for the production and transmission and storage 

segments, which is routing of natural gas-driven pump emissions 

to a process (e.g., used as fuel for a combustion source) or 

control device. Assuming that emissions are routed through a 

closed vent system to a control device or process, we believe 

these control options achieve a 95 percent reduction in 

emissions of methane and VOC.

Based on a 95 percent reduction, we estimate the reduction 

in emissions in the production segment to be 0.36 tpy methane 

and 0.10 tpy VOC per piston pump and 3.29 tpy of methane and 

0.91 tpy of VOC per diaphragm pump. In the transmission and 

storage segment, we estimate the reduction in emissions to be 

0.36 tpy of methane and 0.01 tpy VOC per piston pump and 3.29 

tpy of methane and 0.09 tpy of VOC per diaphragm pump. 

For purposes of this action, we have identified in section 

VIII.A two approaches for evaluating whether the cost of a 

multipollutant control, such as routing emissions to a 

combustion device, is reasonable. As explained in that section, 
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we believe that both approaches are appropriate for assessing 

the reasonableness of the multipollutant controls considered in 

this action. Therefore, we find the cost of control to be 

reasonable as long as it is such under either of these two 

approaches.

Under the single pollutant approach, we assign all costs to 

the reduction of one pollutant and zero to all other pollutants 

simultaneously reduced. For this approach, we would find the 

cost of control reasonable if it is reasonable for reducing one 

pollutant alone. In the evaluation below, we assign all the 

costs to methane reduction alone and then to VOC reduction 

alone. For installing a new control device in the production 

segment we estimate the cost of control for reducing methane 

emissions using a combustion device to be $60,602 per ton for 

piston pumps and $6,656 per ton for diaphragm pumps. The cost of

control for reducing VOC emissions for the production segment is 

$218,017 per ton for piston pumps and $23,944 for diaphragm 

pumps. For both the transmission and storage segment we estimate 

the cost of control for reducing methane emissions using a new 

combustion device to be $60,602 per ton for piston pumps and 

$6,656 per ton for diaphragm pumps. The cost of control for

reducing VOC emissions for both the transmission and storage 
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segment is $2,187,805 per ton for piston pumps and $240,279 for 

diaphragm pumps. We do not consider these cost to be reasonable.

Under the multipollutant approach we attributed half the 

cost to the methane reduction and half to the VOC reduction. For 

the production segment, we estimate the cost of reducing methane 

emissions using a new combustion device for piston pumps to be 

$30,301 per ton and the cost of reducing VOC emissions to be 

$109,009 per ton. For diaphragm pumps, the cost of reducing 

methane emissions is $3,328 per ton and the cost of reducing VOC 

emissions is $11,972 per ton. For both the transmission and 

storage segment, we estimate the cost of reducing methane 

emissions for piston pumps to be $30,301 per ton and the cost of 

reducing VOC emissions to be $1,093,903 per ton. For diaphragm 

pumps, the cost of reducing methane emissions is $3,328 per ton

and the cost of reducing VOC emissions is $120,140 per ton. We 

also do not consider these cost to be reasonable.

While the use of a new combustion device is not costeffective, the costs appear reasonable when using an existing 

combustion control device that is already on site. For routing 

the emissions in the production segment to an existing 

combustion control device, under the single pollutant approach, 

if we assign all costs to reducing methane emissions and zero to 
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VOC reduction, the cost is $789 per ton of methane reduced for 

piston pumps and $87 per ton of methane reduced for diaphragm 

pumps.73 If we assign all costs to VOC reduction and zero to 

methane reduction, the cost of reducing VOC emissions using an 

existing combustion control device in the production segment is 

$2,840 for piston pumps and $312 for diaphragm pumps. For both 

the transmission and storage segment, if we assign all costs to 

methane reduction and zero to VOC reduction, the cost of 

reducing methane emissions is $789 per ton for piston pumps and 

$87 per ton for diaphragm pumps.74 If we assign all costs to VOC 

reduction and zero to methane reduction, the cost of reducing 

VOC emissions in the transmission and storage segment is $28,501

for piston pumps and $3,130 for diaphragm pumps. As shown above, 

under the single pollutant approach (i.e., all costs are 

assigned to one pollutant and zero to the other), the costs are

reasonable regardless of which pollutant bears all the costs, 

except for the piston pump at the transmission and storage 

segment if all costs are assigned to VOC. In that case, while 

 

73 This is well below the amount we find reasonable for reducing 

fugitive methane emissions at well site (see Section VIII.G.1 

below). 

74 This is well below the amount we find reasonable for reducing 

fugitive methane emissions at well site (see Section VIII.G.1 

below). 
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the cost is high if it is all assigned to VOC reduction, the 

cost is reasonable when assigned to methane reduction. 

We also evaluated the cost of control for routing emissions 

to an existing control device under the multipollutant approach. 

For the production segment, we estimate the cost of reducing 

methane emissions for piston pumps to be $395 per ton and the 

cost of reducing VOC emissions to be $1,420 per ton. For 

diaphragm pumps, the cost of reducing methane emissions is $43

per ton and the cost of reducing VOC emissions is $156 per ton. 

For both the transmission and storage segment, we estimate the 

cost of reducing methane emissions for piston pumps to be $395 

per ton and the cost of reducing VOC emissions to be $14,250 per 

ton. For diaphragm pumps, the cost of reducing methane emissions 

is $43 per ton and the cost of reducing VOC emissions is $1,565

per ton. With respect to piston pumps at transmission and 

storage segments, we note that the control is cost-effective 

under the single pollutant approach. 

We further evaluated the cost of control for routing the 

emissions to a process by installing a new VRU or utilizing an 

existing VRU and found these costs to be similar to the costs 

presented above for new and existing combustion devices, 

respectively. We determined that the cost of control for routing 
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to a process is similar to the costs presented above for an

existing combustion device (see the TSD for this action for 

details of this analysis). 

The option of routing emissions to a control device would 

result in secondary impacts from combustion. However, we did not 

identify any nonair quality or energy impacts associated with 

this option.

For natural gas processing plants, we evaluated instrument 

air systems based on a 100 percent emissions reduction potential 

resulting in a natural gas emission rate of zero standard cubic 

feet per hour. We estimated the potential reduction in emissions 

to be 0.38 tpy of methane and 0.11 tpy of VOCs per piston pump 

and 3.46 tpy of methane and 0.96 tpy of VOC per diaphragm pump. 

Because instrument air systems are known to be used at 

natural gas processing plants, we evaluated this option based on 

the incremental additional cost of routing the natural gasdriven pumps to an existing instrument air system, assuming all 

natural gas processing plants currently use instrument air 

systems. We determined that the incremental cost would be the 

cost of aligning the capacity of the existing instrument air 

system to that needed after the addition of the pumps. We 

determined that the facility would likely either replace an 
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existing compressor or add a compressor to address any needed 

additional capacity. Because we do not have data on the number 

and distribution of types of natural gas-driven pumps at a 

typical natural gas processing plant, we developed several model 

plant scenarios. We varied the size of the plant (i.e., the 

total number of natural gas-driven pumps) from small, consisting 

of 4 natural gas-driven pumps per plant to large, consisting of 

100 natural gas-driven pumps per plant. We also, within the size 

of the plant, varied the distribution of the type of pumps using 

three distribution scenarios (i.e., 50 percent diaphragm and 50 

percent piston, 25 percent diaphragm and 75 percent piston, and 

75 percent diaphragm and 25 percent piston). For each model 

plant, we evaluated the cost of an appropriately sized 

compressor based on the required additional capacity needed by 

number and types of pumps. Details of this analysis are included 

in the TSD for this action.

Under the single pollutant approach, which assigns all 

costs to the reduction of one pollutant and zero to all other 

pollutants, the cost of control for the model plants ranges from 

$374 to $2,185 per ton of methane reduced when assigning all 

costs to alone to methane reduction, and ranges from $1,344 to 
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$7,861 per ton of VOC reduced when assigning all the costs alone 

to VOC reduction.

Under the multipollutant approach, we assigned half the 

cost of control to the methane reduction and half the cost to 

the VOC reduction. The cost of control under the second approach 

for the model plants ranges from $187 to $1,093 per ton of 

methane reduced and $672 and $3,930 per ton of VOC reduced. We 

find the control to be cost-effective under either approach. 

We also identified in section VIII.A two additional 

approaches, based on new capital expenditures and annual 

revenues, for evaluating whether the costs are reasonable. For 

the capital expenditure analysis, we used the capital 

expenditures for 2012 for NAICS 2111, 213111 and 213112 as 

reported in the U.S. Census data, which we believe are

representative of the production segment. The total capital cost 

for complying with the proposed standards for pneumatic pumps is 

0.02 percent of the total capital expenditures, which we believe 

is reasonable.is well below the percentage capital increase that 

courts have previously upheld as reasonable as discussed in 

Section VIII. A.. For the total revenue analysis, we used the 

revenues for 2012 for NAICS 211111, 211112 and 213112, which we 

believe are representative of the production segment. The total 
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annualized costs for complying with the proposed standards is 

0.001 percent of the total revenues, which we believe is 

reasonablealso very low.

For all types of affected facilities in the production 

segment, the total capital costs for complying with the proposed 

standards is 0.16 percent of the capital expenditures, and the 

total annualized costs for complying with the proposed standards 

is 0.13 percent of the total revenues, which we believe is 

reasonablealso very low.

In light of the above, we find that the BSER for reducing 

methane and VOC emissions from natural gas-driven piston and 

diaphragm pumps in the production and transmission and storage 

segments to be the same, which is to route the emissions to an 

existing control device or route the emissions to a process. As 

discussed above, this option results in a 95 percent reduction 

of emissions for both methane and VOC.

We find that the BSER for reducing methane and VOC 

emissions from natural gas-driven piston and diaphragm pumps at 

gas processing plants is to use an instrument air system in 

place of natural gas to drive the pumps. This option results in 

a 100 percent reduction of emissions for both methane and VOC.
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We are, therefore, proposing to require 95 percent methane 

and VOC control from all natural gas-driven pneumatic pumps in 

the production and transmission and storage segments. For gas 

processing plants, we are proposing to require 100 percent 

methane and VOC control from all pneumatic pumps. 

As discussed above in this section, solar-powered, 

electrically-powered and air-driven pumps cannot be employed in 

all applications. However, we encourage operators to use other 

than natural gas-driven pneumatic pumps where their use is 

technically feasible. To incentivize the use of such 

alternatives, we propose that “pneumatic pump affected facility”

be defined in §60.5365(h) to include only natural gas-driven 

pumps. As a result, pumps which are driven by means other than 

natural gas would not be affected facilities subject to the 

pneumatic pump provisions of the proposed NSPS. 

Public and peer review comments on the white paper noted 

that, in addition to piston injection pumps and diaphragm pumps,

gas assist glycol dehydrator pumps are used to pump lean glycol 

through glycol dehydrator systems. The glycol dehydrator pumps

tend to be more complex because they “scavenge” energy from the 

high pressure (rich) glycol flowing from the contactor to the 

regenerator to provide the bulk of the energy needed to pump the 
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lean glycol into the contactor. These types of pumps are used 

continuously when the glycol dehydrator is in use. Emissions 

from gas assist pumps are a function of the lean glycol 

circulation rate, the pressure of the contactor, and the model 

of the pump. Commenters of the white paper indicate that the 

emissions profile of all three types of pumps are very 

different. Commenters note that data for the EPA/GRI report for 

gas assisted glycol pumps is calculated based on two assumptions 

of process conditions, water removal, and information from the 

pump manufacturer which result in significant limitations for 

the calculated emission factor derived in the report.

Furthermore, commenters discuss the NEI have activity factors 

and emissions separated from the glycol process emissions for 

gas assist lean glycol pumps, however commenters believe that it 

is not clear whether the estimate is valid.75 Our understanding 

is that emissions from glycol dehydrator pumps are not

separately quantified because these emissions are released from

the same stack as the rest of the emissions from the dehydrator 

system, which are regulated under the NESHAP at 40 C.F.R. part 

63 HH and HHH. It is also our understanding from commenters that

 

75 June 13, 2014, API comments on EPA’s white paper on oil and 

natural gas sector pneumatic devices. 
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replacing the natural gas in gas-assisted lean glycol pumps with 

instrument air is not feasible and would create significant 

safety concerns. Commenters state that the only option for these 

types of pumps are to replace them with electric motor driven 

pumps however, solar and battery systems large enough to power 

these types of pumps are not feasible. The EPA is requesting

comment and additional information on the level of uncontrolled 

emissions from these pumps, how these pumps are vented through 

the dehydrator system, and the amount and characteristics of VOC 

and methane emissions from uncontrolled glycol dehydrators.

F. Proposed Standards for Well Completions

For the 2012 NSPS and this action, we have identified two 

subcategories of hydraulically fractured wells: (1) Nonexploratory and non-delineation wells, also known as development 

wells; and (2) exploratory (also known as wildcat wells) and 

delineation wells. An exploratory well is the first well drilled 

to determine the presence of a producing reservoir and the 

well’s commercial viability. A delineation well is a well 

drilled to determine the boundary of a field or producing 

reservoir. In the 2012 NSPS analysis, we determined that the 

emissions profile for subcategory 2 wells is the same as 

subcategory 1 wells as described above. In our review of white 
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paper comments and other information for this action, we found 

no information that would indicate this conclusion is not still 

valid.

1. Proposed Standards for Hydraulically Fractured NonWildcat and Non-Delineation Wells (Subcategory 1 Wells)

In the 2012 NSPS, we established VOC standards for 

subcategory 1 hydraulically fractured gas well completions and 

recompletions in the oil and natural gas source category. In 

this action, we are proposing VOC standards for subcategory 1 

oil well completions and recompletions and methane standards for 

all subcategory 1 well completions and recompletions in the oil 

and natural gas source category. Based on the analysis below, 

the proposed VOC and methane standards are the same as the gas 

well completion standards currently in the NSPS. 

As explained in the 2012 NSPS, well completions with 

hydraulic fracturing are a significant source of VOC and methane 

emissions, which occur when natural gas and non-methane 

hydrocarbons are vented to the atmosphere during flowback of a 

hydraulically fractured well. Flowback emissions are short-term 

in nature and occur over a period of several days following 

fracturing or refracturing of a well. Well completions include 

multiple steps after the well bore hole has reached the target 
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depth. These steps include inserting and cementing-in well 

casing, perforating the casing at one or more producing 

horizons, and often hydraulically fracturing one or more zones 

in the reservoir to stimulate production. Hydraulic fracturing 

is one technique for improving oil or gas production where the 

reservoir rock is fractured with very high pressure fluid, 

typically water emulsion with a proppant (generally sand) that 

“props open” the fractures after fluid pressure is reduced. 

Emissions are a result of the flowback of the fracture fluids 

and reservoir gas at high volume and velocity necessary to lift 

excess proppant and fluids to the surface. This multi-phase 

mixture is often directed to a surface impoundment or to vented 

tanks (“frac tanks”), where methane and VOC vapors escape to the 

atmosphere during the collection of water, sand and hydrocarbon 

liquids. For oil wells, as the fracture fluids are depleted, the 

flowback eventually contains more volume of crude oil from the 

formation.

Wells that are fractured generally have greater amounts of 

VOC and methane emissions than conventional wells because of the 

extended length of the flowback period required to purge the 

well of the fluids and sand that are associated with the 

fracturing operation. Along with the fluids and sand from the 
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fracturing operation, the flowback period may also result in 

emissions of methane and VOC that would not occur in large 

quantities at wells that are not fractured. 

There are a variety of factors that will determine the 

length of the flowback period and actual volume of emissions 

from a well completion such as the number of zones, depth, 

pressure of the reservoir, gas composition, etc. This 

variability means there will be variability in the emissions 

from well completions.

For the 2012 NSPS, we estimated that the emissions from an 

uncontrolled gas well completion were 155.5 ton of methane and 

22.7 tons of VOC per completion event. We also evaluated oil 

well completions emissions for the 2012 NSPS; however, based on 

that evaluation, we found oil well completion emissions to be 

very low and, therefore, no standard was set for oil well 

completions. 

For this action, we reviewed new emissions studies and 

information for oil well completions, as described in the 2014 

white paper titled “Oil and Natural Gas Sector Hydraulically 

Fractured Oil Well Completions and Associated Gas during Ongoing 
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Production.”76 While there was a wide variation in the results of 

these studies and analyses, even in the lowest estimates the 

potential methane and VOC emissions from hydraulically fractured 

oil well completions were significant. This conclusion is 

consistent with the Federal Implementation Plan (FIP) for the 

Fort Berthold Indian Reservation (FBIR) (78 FR 17836), in which 

the EPA found that the emissions from oil well completions are 

significant. One difference identified in our review of comments 

from the 2014 white paper process was that the average duration 

of an oil well completion is on the lower end of the duration 

identified in our 2012 analysis, or 3 days. Therefore, for this 

action, based on our review of these estimates and the 

methodologies used and in consideration of these comments, we 

estimate the potential emissions from hydraulically fractured 

oil well completions to be 9.72 tons methane and 8.14 tons VOC 

per 3-day completion event. These estimates are explained in 

detail in the 2012 TSD and the TSD for this action which are 

both available in the docket. 

 

76 Available at 

http://www.epa.gov/airquality/oilandgas/2014papers/20140415compl

etions.pdf.
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For the 2012 NSPS, we evaluated three options for reducing 

methane and VOC emissions from hydraulically fractured well 

completions: RECs, combustion (e.g., flaring), and the 

combination of REC with combustion. For this action, we reviewed 

public and peer comments on the white paper as well as state 

(i.e., Colorado77 and Wyoming78) and other federal regulations 

(i.e., FBIR FIP). We found that the available control techniques 

for reducing methane and VOC emissions from well completion are 

the same, and they were the same as the control options we 

previously identified for controlling VOC emissions: use of a 

REC, combustion, and the combination of REC with combustion. We 

did not find any other available control options from our white 

paper process or information review.

RECs are performed by separating the flowback water, sand, 

hydrocarbon condensate and natural gas to reduce the portion of 

natural gas and VOC vented to the atmosphere, while maximizing 

recovery of salable natural gas and condensate and routing the 

 

77 Colorado Oil and Gas Conservation Commission (COGCC) 805 

Series Rules (805.b.(3)A) at: http://cogcc.state.co.us/ and the 

Colorado Code of Regulations at: 

http://www.sos.state.co.us/CCR/Welcome.do. 78 WY BACT permitting guidance available at 

http://deq.state.wy.us/aqd/Oil%20and%20Gas/September%202013%20FI

NAL_Oil%20and%20Gas%20Revision_UGRB.pdf. 
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salable gas to a sales line and routing the recovered condensate 

to a completion or storage vessel for collection. Equipment 

required to conduct RECs may include tankage (e.g., “frac 

tanks”), special gas-liquid-sand separator traps and gas 

dehydration. 

Control by combustion is achieved through the use of a 

completion combustion device. Based on our review, we believe 

that traditional combustion control devices, (i.e., flares or 

enclosed combustion control devices), are infeasible for use on 

completion emissions because the flowback following hydraulic 

fracturing consists of liquids, gases and sand in a high-volume, 

multiphase slug flow. 

We evaluated RECs, completion combustion devices and the 

combination of RECs with completion combustion devices in order 

to determine the BSER for subcategory 1 wells. See the 2012 TSD 

and the TSD for this action, available in the docket, for 

further details on this evaluation. Our evaluation indicates 

that REC alone provides for a 90 percent control of emissions 

where gas emitted from the well is of suitable quality to be 

routed to a gathering line. However, in some cases, the initial 

gas produced from the well does not meet quality specifications 

for entering gathering lines, and as a result, the gas must be 
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either vented or combusted. Due to the potential for gas to be 

emitted, even during the use of a REC, we determined that the 

use of a REC alone, would not be the BSER for control of 

emissions from well completions. Our evaluation of REC combined 

with a completion combustion device indicated that this option 

resulted in a 95 percent control of both methane and VOC 

emissions. We believe this option maximizes gas recovery and 

minimizes venting to the atmosphere. 

Under the last option, combustion, we determined that a 

completion combustion device would achieve a 95 percent 

reduction in both methane and VOC emissions. However, we 

determined that combustion alone would not represent the BSER 

for well completions because, although the emissions reduction 

would be equal to the REC and completion combustion device 

combination (i.e., 95 percent control), the opportunity to 

realize gas recovery would be minimized and the generation of 

secondary combustion-related emissions would be increased. 

Based on the 95 percent emission reduction of a REC 

combined with a combustion device, in the 2012 NSPS, the 

emission reductions for a hydraulically fractured gas well 

completion event were estimated to be 147.4 tons of methane per 
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completion.79 In this analysis, we estimate the emission 

reductions for a hydraulically fractured oil well completion 

event to be 9.23 tons of methane and 7.73 tons of VOC per 

completion based on a 3-day completion event.

Equipment costs associated with RECs will vary from well to 

well. Costs of performing REC are projected to be between $700 

and $6,500 per day, varying based on if key pieces of equipment 

are readily available on site or temporarily brought on site. 

Based on the 2012 NSPS evaluation, the average cost of a REC 

combined with completion combustion device for a 7-day 

completion event was $33,327. Under our evaluation in this 

action, we estimate the cost for a REC combined with a 

completion combustion device for a 3-day completion event to be 

$17,183. However, in both cases, there are savings associated 

with the use of RECs because the gas recovered can be 

incorporated into the production stream and sold. With the 

consideration of gas savings, the cost of a REC combined with a 

completion combustion device for a 7-day completions event for a 

gas well was estimated to have a net savings. With the 

 

79 Emissions of VOC from hydraulically fractured subcategory 1 

gas wells are subject to the current NSPS and are not included 

in this action.
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consideration of gas savings, the cost of a REC combined with a 

completion combustion device for a 3-day completions event for 

an oil well was estimated to be $13,586.

We determined that the completion combustion device option 

for well completions also reduces both methane and VOC emissions 

by 95 percent. Therefore, the emissions reductions would be the 

same as those cited above for the REC combined with a completion 

combustion device. The annual cost for a completion combustion 

device alone was estimated be $3,523 for the 2012 NSPS for gas 

wells and $3,723 under this action for oil wells.

For purposes of this action, we have identified in section 

VIII.A two approaches (single pollutant approach and 

multipollutant approach) for evaluating whether the cost of a 

multipollutant control is reasonable. As explained in that 

section, we believe that both approaches are appropriate for 

assessing the reasonableness of the multipollutant controls 

considered in this action. Therefore, we find the cost of 

control to be reasonable as long as it is such under either of 

these two approaches.

Under the single pollutant approach, we assign all costs to 

the reduction of one pollutant and zero to all other pollutants 

simultaneously reduced. For this approach, we would find the 
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cost of control reasonable if it is reasonable for reducing one 

pollutant alone. As shown in the evaluation below, which assigns 

all the costs to methane reduction alone, and based on an 

average cost of $33,327 per completion event for a gas well80, a 

REC combined with a completion combustion device, would cost 

$226 per ton of methane reduced per gas well completion without 

cost savings.81 As noted above, this option maximizes gas 

recovery and minimizes venting to the atmosphere. Thus, when the 

value of the natural gas recovered (approximately 1,609 Mcf of 

natural gas) is considered, there is a net savings realized for 

this option for a subcategory 1 gas well completion or 

recompletion. We find these costs to be reasonable for the 

amount of methane reduction it can achieve. Also, because all 

the costs have been attributed to methane reduction, the cost of 

the simultaneous VOC reduction is zero and therefore reasonable. 

Based on the $17,183 annual cost of a REC combined with a 

completion combustion device for a 3-day completion event for an 

 

80 As was determined for the 2012 NSPS. 81 In 2012 we already found that the cost of this control to be 

reasonable for reducing VOC emissions from subcategory 1 gas 

well completions and recompletions. We are not reopening that 

decision in this action. Therefore, this cost finding is 

relevant only to methane reduction from subcategory 1 

hydraulically fractured gas well completions.
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oil well completion, with the cost attributed only to methane 

and zero cost attributed to VOC, the cost of control would be 

$1,861 per ton of methane reduced per oil well completion 

without considering cost savings attributable to recovery of 

natural gas. As noted above, this option maximizes gas recovery 

and minimizes venting to the atmosphere. Thus, when the value of 

the natural gas recovered (approximately 999 Mcf of natural gas) 

is considered, the cost of control would be $1,471 per ton of 

methane reduced. Under this approach, the cost of control with 

all cost attributed to VOC would be $2,222 per ton of VOC 

reduced without considering natural gas savings and $1,757 with 

savings realized from natural gas recovery. Although the cost of 

control for a 3-day completion event at an oil well is higher

than the cost at a gas well, we believe that the emissions 

reductions collectively are significant to justify the cost. 

Furthermore, we believe that the industry can bear the cost and 

survive.

Under the multipollutant approach, we assign 50 percent of 

the cost to methane and 50 percent to VOC. The cost of a REC 

with completion combustion for a gas well under this approach 

would be $930 per ton of methane and $1,111 per ton of VOC 

reduced without considering natural gas savings. With 
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consideration of natural gas savings, the cost of control is 

$736 per ton of methane and $879 per ton of VOC reduced. Based 

on this formulation, the costs for pollutant reduction are half 

of the estimated costs under the single pollutant approach above 

and therefore we believe these costs are not excessive for the 

same reasons discussed above.

Under the single pollutant approach, based on the $3,723 

annual cost of a completion combustion device alone, with the 

cost attributed only to methane and zero attributed to VOC, the 

cost of control would be $403 per ton of methane reduced per oil 

well completion. Under this approach, the cost of control with 

cost attributed to VOC would be $481 per ton of VOC reduced. 

Under the multipollutant approach, we assign 50 percent of the 

cost to methane and 50 percent to VOC. The cost of control under 

this approach would be $202 per ton of methane and $241 per ton 

of VOC reduced. We think that these costs are reasonable.

See the TSD, available in the docket for this action, for 

a detailed description of the cost of control analysis. 

We believe that the cost for both options, a REC combined 

with combustion and combustion alone, are reasonable, given the 

emission reduction that would be achieved. However, given that 

the reductions in emissions are equal between the two control 
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options, the REC combined with combustion option provides a 

better environmental benefit with the recovery of natural gas 

and reduced secondary combustion-related emissions. Aside from 

the potential hazards (in some cases) associated with combustion 

devices, we did not identify any nonair environmental impacts, 

health or energy impacts associated with REC combined with 

combustion, therefore these impacts were not analyzed. 

The use of a completion combustion device with this option 

would produce secondary impacts in the form of combustionrelated emissions. We estimate that, for subcategory 1 oil wells 

completed using a combination of REC and combustion for the year 

2020, the combustion control-related emissions would be 

approximately 26 tons of total hydrocarbons, 69 tons of carbon 

monoxide, 24,846 tons of carbon dioxide, and 13 tons of nitrogen 

oxides.82 This is based on the assumption that 5 percent of the 

flowback gas is combusted for subcategory 1 oil wells 

(controlled with a REC combined with a completion combustion 

device). 

 

82 Because the current NSPS requires control of gas well 

completions using this option, we do not include the secondary 

emissions for control of methane from gas well completions.
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We estimate that this option of control for subcategory 1 

oil well completions, for the projected year 2020, will result 

in estimated emission reductions of 127,478 tons of methane and 

106,750 tons of VOC. Thus, we believe that the benefit of the 

methane and VOC reductions far outweigh the secondary impacts of 

combustion emissions formation during use of the completion 

combustion operation. Further, should only combustion be 

considered for all oil well completions, including the 

subcategory 1 wells, the secondary impacts would be far greater 

than those shown above. Secondary impacts of combustion alone 

are presented in the discussion of subcategory 2 wells below in 

this section.

We also identified in section VIII.A two additional 

approaches, based on new capital expenditures and annual 

revenues, for evaluating whether the costs are reasonable. For 

the capital expenditure analysis, we used the capital 

expenditures for 2012 for NAICS 2111, 213111 and 213112 as 

reported in the U.S. Census data, which we believe are 

representative of the production segment. The total capital 

costs for complying with the proposed standards for subcategory 

1 wells is 0081 percent of the total capital expenditures, which 

we believe is reasonable.is well below the percentage capital 
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increase that courts have previously upheld as reasonable as 

discussed in Section VIII.A.. For the total revenue analysis, we 

used the revenues for 2012 for NAICS 211111, 211112 and 213112, 

which we believe are representative of the production segment. 

The total annualized costs for complying with the proposed 

standards is 0.033 percent of the total revenues, which we 

believe is reasonablealso very low.

For all types of affected facilities in the production 

segment, the total capital costs for complying with the proposed 

standards is 0.16 percent of the total capital expenditures, and 

the total annualized costs for complying with the proposed 

standards is 0.13 percent of the total revenues, which we 

believe is reasonablealso very low.

For the reasons stated above, we determine the BSER for 

subcategory 1 (developmental wells) is the combination of REC 

and the use of a completion combustion device. We considered 

setting a numerical performance standard; however, we determined 

that it is not feasible to prescribe or enforce a numerical 

performance standard in this case because the gas can be

discharged at multiple locations along with water and sand in a 

multiphase slug flow during the flowback process and, therefore, 

may not always be emitted at the same specific location in the 
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process or through one conveyance designed and constructed to 

emit or capture such pollutant. Therefore, pursuant to section 

111(h)(2) of the CAA, we are proposing an operational standard 

for subcategory 1 wells that would require a combination of gas 

capture and recovery and completion combustion devices to 

minimize venting of gas and condensate vapors to the atmosphere, 

with provisions for venting in lieu of combustion for situations 

in which combustion would present safety hazards or for periods 

when the flowback gas is noncombustible. 

For the purposes of these standards we have separated the 

flowback period into two stages, the “initial flowback stage” 

and the “separation flowback stage.” The initial flowback stage 

begins with the first flowback from the well following hydraulic 

fracturing or refracturing and is characterized by high 

volumetric flow water, containing sand, fracturing fluids and 

debris from the formation with very little gas being brought to 

the surface, usually in multiphase slug flow. Due to the high 

volume of the flowback and the small amounts of gas in the 

initial flowback, operation of a separator may be initially 

technically infeasible, and there may not be sufficient gas for 

combustion. During these conditions, the emissions cannot be 
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controlled from the flowback. During this stage, liquids are 

collected and routed to completion vessels. 

For the reasons explained above, during the initial 

flowback stage, we propose that the flowback be routed to a 

storage vessel or to a well completion vessel that can be a frac 

tank, a lined pit or any other vessel. The purpose of this 

requirement is to avoid having operators route the flowback to 

an unlined pit or onto the ground. During the initial flowback 

stage, there is no requirement for controlling emissions from 

the vessel, and any gas in the flowback during this stage may be 

vented. However, the operator must route the flowback to a 

separator unless it is technically infeasible for a separator to 

function. Conditions that could prevent proper operation of the 

separator include insufficient gas concentration, low pressure 

gas, and multiphase slug flow containing solids that could clog 

the separator. We stress that operators have the responsibility 

to direct the flowback to a separator as soon as conditions 

allow a separator to function and in accordance with the General 

Provision requirements to operate the affected facility in a 

manner consistent with good air pollution control practices for 

minimizing emissions.
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The second stage is defined as the “separation flowback 

stage.” The point at which the separator can function marks the 

beginning of the separation flowback stage. This stage is 

characterized by the separator operating with a gaseous phase 

and one or more liquid phases in the separator. The end of the 

separation flowback stage marks the end of the flowback period 

and is defined as the point at which the well is shut in and the 

flowback equipment is permanently disconnected from the well, or 

the startup of production. The end of the separation flowback 

stage (i.e., the end of flowback) is characterized by certain 

indicators. Permanent disconnection of the temporary equipment 

used during flowback can be an indicator of flowback having 

ended. For example, during flowback, skid-mounted choke 

manifolds are used to limit flowback and assist in directing the 

flow. Temporary lines laid on the ground from the wellhead to 

the choke manifold and to the flowback separators and frac tanks 

are connected with “hammer unions” which are pipe unions that 

are designed for ease of making temporary connections and are 

characterized by “ears” that allow the joint to be made up 

quickly by striking with a hammer. After flowback has subsided 

and the well has cleaned up sufficiently, the well is 

temporarily shut in to disconnect the temporary flowback 
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equipment. We believe that when the operator permanently 

disconnects choke manifolds, temporary separators, sand traps 

and other equipment connected with temporary lines and hammer 

unions, it is a reliable indicator that flowback has ended and 

the well is ready for production. At that point, we believe that 

operators will remove these temporary equipment used during 

flowback to avoid incurring unnecessary charges for additional 

days the equipment remains onsite. The well could start 

production immediately or it could remain shut in until 

permanent equipment is installed. 

During the separation flowback stage, the operator must 

route all salable quality natural gas from the separator to a 

gas flow line or collection system, re-inject the gas into the 

well or another well, use the gas as an on-site fuel source or 

use the gas for another useful purpose that a purchased fuel or 

raw material would serve. If, during the separation flowback 

stage, it is technically infeasible to route the recovered gas 

to a flow line or collection system, re-inject the gas or use 

the gas as fuel or for other useful purpose, the recovered gas 

must be combusted. No direct venting of recovered gas is allowed 

during the separation flowback stage except when combustion 

creates a fire or safety hazard or can damage tundra, permafrost 
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or waterways. With regard to infeasibility of collecting the 

salable quality gas, we believe that owners and operators plan 

their operations to extract a target product and evaluate 

whether the appropriate infrastructure access is available to 

ensure their product has a viable path to market before 

completing a well. However, there may be cases in which, for 

reason(s) not within an operator’s control, the well is 

completed and flowback occurs without a suitable flow line 

available. We are aware that this situation may be more common 

for wells that are primarily drilled to produce oil. In those 

instances, §60.5375(a)(3) requires the combustion of the gas 

unless combustion poses an unsafe condition as described above. 

During the separation flowback stage, all liquids from the 

separator must be directed to a storage vessel or to a well 

completion vessel, routed to a collection system or be reinjected into the well or another well.

The proposed operational standard would be accompanied by 

requirements for documentation of the overall duration of the 

completion event, duration of recovery using REC, duration of 

combustion, duration of venting, and specific reasons for 

venting in lieu of combustion.
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2. Proposed Standards for Hydraulically Fractured 

Exploratory and Delineation Wells (Subcategory 2 Wells)

In the 2012 NSPS, we established VOC standards for 

subcategory 2 hydraulically fractured exploratory and 

delineation gas well completions. In this action, we are 

proposing VOC standards for the hydraulically fractured 

exploratory and delineation oil well completions and we are also 

proposing methane standards for all hydraulically fractured 

exploratory and delineation well completions in the oil and 

natural gas source category. Based on the analysis below, the 

proposed VOC and methane standards described above are the same 

as the current standards for hydraulically fractured exploratory 

and delineation gas well completion standards currently in the 

NSPS.

As noted above, for the 2012 NSPS analysis, we determined 

that the emissions profile for subcategory 2 wells is the same 

as subcategory 1 wells as described above. In our review of 

white paper comment and other information for this action, we 

found no information that would indicated this conclusion is not 

still valid. Specifically, we determined the emissions from a 
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hydraulically fractured oil well were 9.72 tons of methane and 

8.14 tons of VOC per 3-day completion event.83

In our analysis for the 2012 NSPS, we determined that a REC 

is not an option for subcategory 2 wells because there is no 

infrastructure in place to get the recovered gas to market or 

further processing. Typically, these types of wells generally 

are not in proximity to existing gathering lines at the time the 

well is completed. Therefore, for these wells, the only 

potential control option identified (both under the 2012 NSPS 

and under this action) is combustion of gases using a completion 

combustion device, as described above. Also as explained above, 

because of the high-volume, multiphase slug flow nature of the 

flowback gas, water and sand, control by a traditional flare or 

other control devices, such as vapor recovery units, is 

infeasible, since these devices would be overcome by the erratic 

high-volume flow of liquids, which leaves combustion as the only 

available control system for subcategory 2 wells. As also 

discussed above, combustion can present a fire hazard or other 

undesirable impacts in some situations. In our review of white 

 

83 Emissions of VOC from hydraulically fractured subcategory 2 

gas wells are subject to the current NSPS and are not included 

in this action.
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paper comment and other information for this action, we found no 

information that would indicate this conclusion is not still 

valid. 

Based on the 95 percent emission reduction of a completion 

combustion device, the emission reductions for a subcategory 2 

hydraulically fractured gas well completion or recompletion are 

estimated to be 147.4 tons of methane per completion event.84 The 

emission reductions for a subcategory 2 hydraulically fractured 

oil well completion or recompletion event are estimated to be 

around 9.23 tons of methane and 7.73 tons of VOC per 3-day 

completion. 

As noted above, for purposes of this action, we have 

identified in section VIII.A two approaches (single pollutant 

and multipollutant approaches) for evaluating whether the cost 

of a multipollutant control is reasonable. As explained in that 

section, we believe that both approaches are appropriate for 

assessing the reasonableness of the multipollutant controls 

considered in this action. Therefore, we find the cost of 

 

84 Emissions of VOC from hydraulically fractured subcategory 2 

gas wells are subject to the current NSPS and are not included 

in this action.
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control to be reasonable as long as it is such under either of 

these two approaches.

Under the single pollutant approach, we assign all costs to 

the reduction of one pollutant and zero to all other pollutants 

simultaneously reduced. For this approach, we would find the 

cost of control reasonable if it is reasonable for reducing one 

pollutant alone. As shown in the evaluation below, which assigns 

all the costs to methane reduction alone, based on an average 

annual cost of $3,723 per completion, the cost of control for a 

completion combustion device is estimated to be $24 per ton of 

methane for subcategory 2 gas well completion event. We find 

these costs to be reasonable for the amount of methane reduction 

it can achieve. Also, because all the costs have been attributed 

to methane reduction, the cost of the simultaneous VOC reduction 

is zero and therefore reasonable.85 We estimate the cost of 

control for subcategory 2 oil wells to be $403 per ton of 

methane and $481 per ton of VOC per oil well completion. We 

 

85 In 2012 we already found that the cost of this control to be 

reasonable for reducing VOC emissions from hydraulically 

fractured subcategory 2 gas well completions. We are not 

reopening that decision in this action. Therefore, this cost 

finding is relevant only to methane from hydraulically fractured 

subcategory 2 gas well completions.
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consider these costs to be reasonable considering the level of 

emissions reductions.

We also evaluated the cost of this control under the 

multipollutant approach. Under this approach, the costs would be 

allocated based on the estimated percentage reduction expected 

for each pollutant. Because completion combustion devices 

reduces both methane and VOC by 95 percent, we attributed 50 

percent of the costs to methane reduction and 50 percent of the 

cost to VOC reduction. The costs for methane reduction would be 

half of the estimated costs under the first approach above, for 

both gas and oil wells, which we have found to be reasonable. 

See the TSD, available in the docket for this action, for a 

detailed description of the cost of control analysis. 

Aside from the potential hazards associated with use of a 

completion combustion device in some cases, we did not identify 

any nonair environmental impacts, health or energy impacts 

associated with completion combustion devices, therefore no 

analysis was completed. However, completion combustion devices 

would produce combustion-related air pollutants. For 870
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subcategory 2 oil well completions86 for the projected year 2020, 

we estimated that 66 tons of total hydrocarbons, 175 tons of 

carbon monoxide, 62,628 tons of carbon dioxide, 32 tons of 

nitrogen oxides and 1 ton of particulate matter would be 

produced as secondary emissions. This is based on the assumption 

that 95 percent of flowback gas is combusted by the combustion 

device. This control option is estimated to reduce emissions for 

the projected year 2020 by 135,516 tons of methane and 113,481

tons of VOC. Thus, we believe that the benefit of the methane 

and VOC reduction far outweighs the secondary impact of 

combustion-related pollutants as a result of completion 

combustion control.

We also identified in section VIII.A two additional 

approaches, based on new capital expenditures and annual 

revenues, for evaluating whether the costs are reasonable. For 

the capital expenditure analysis, we used the capital 

expenditures for 2012 for NAICS 2111, 213111 and 213112 as 

reported in the U.S. Census data, which we believe are 

representative of the production segment. The total capital cost 

 

86 Because subcategory 2 hydraulically fractured gas well 

completions are subject to the current NSPS, we do not consider 

secondary impacts for the destruction of methane under this 

action.
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for complying with the proposed standards for subcategory 2 

wells is 0.002 percent of the capital expenditures, which we 

believe is reasonable.is well below the percentage capital 

increase that courts have previously upheld as reasonable as 

discussed in Section VIII.A.. For the total revenue analysis, we 

used the revenues for 2012 for NAICS 211111, 211112 and 213112, 

which we believe are representative of the production segment. 

The total annualized cost for complying with the proposed 

standards is 0.001 percent of the total revenues, which we 

believe is reasonablealso very low.

For all types of affected facilities in the production 

segment, the total capital costs for complying with the proposed 

standards is 0.16 percent of the total capital expenditures, and 

the total annualized costs for complying with the proposed 

standards is 0.13 percent of the total revenues, which we 

believe is reasonablealso very low.

In light of the above, we propose to determine that the 

BSER for subcategory 2 wells would be use of a completion 

combustion device. As we explained above, the gas is discharged 

at multiple locations during flowback and is mixed with water 

and sand in multiphase slug flow and therefore we determined 

that it is not feasible to set a numerical performance standard.
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Pursuant to CAA section 111(h)(2), we are proposing an 

operational standard for subcategory 2 well completions that 

would require minimization of venting of gas and hydrocarbon 

vapors during the completion operation through the use of a 

completion combustion device, with provisions for venting in 

lieu of combustion for situations in which combustion would 

present safety hazards or for periods when the flowback gas is 

noncombustible. The owners and operators of these wells also 

have a general duty to safely maximize resource recovery and 

minimize releases to the atmosphere during flowback and 

subsequent recovery.

As with subcategory 1 wells, for the purposes of these 

standards we have separated the flowback period into two stages, 

the “initial flowback stage” and the “separation flowback 

stage.” During the initial flowback stage, the requirements for 

the subcategory 2 wells would be the same as the subcategory 1 

wells. The flowback must be routed to a storage vessel or to a 

well completion vessel that can be a frac tank, a lined pit or 

any other vessel. During the initial flowback stage, there is no 

requirement for controlling emissions from the vessel, and any 

gas in the flowback during this stage may be vented. 
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During the separation flowback stage, the operator must 

route all salable quality gas from the separator to a gas flow 

line or collection system, combust the gas, re-inject the gas 

into the well or another well, use the gas as an on-site fuel 

source or use the gas for another useful purpose that a 

purchased fuel or raw material would serve. No direct venting of 

recovered gas is allowed during the separation flowback stage 

except when combustion creates a fire or safety hazard or can 

damage tundra, permafrost or waterways. During the separation 

flowback stage, all liquids from the separator must be directed 

to a storage vessel or to a well completion vessel, routed to a 

collection system or re-injected into the well or another well.

Consistent with requirements for subcategory 1 wells, 

owners or operators of subcategory 2 wells would be required to 

document completions and provide justification for periods when 

gas was vented in lieu of combustion. 

We estimate that these control options for these sources 

would reduce the total emissions from all hydraulically 

fractured and refractured oil well completions for the projected 

year 2020 by 135,516 tons of methane and 113,481 tons of VOC. 

Thus, we believe that the benefit of the methane and VOC 

reductions far outweigh the secondary impact of combustion 
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emissions formation during use of the completion combustion 

operation.

Several public and peer reviewer comments on the white 

paper noted that these technologies are currently in regular use 

by industry to control oil well completion and recompletion 

emissions.87 In addition, these control technologies are the same 

as those required in the 2012 NSPS to control completion 

emissions from hydraulically fractured gas well completions.

The EPA is aware that oil wells cannot perform a REC if 

there is not sufficient well pressure or gas content during the 

well completion to operate the surface equipment required for a 

REC. In the 2012 NSPS the EPA did not require low pressure gas 

wells to perform REC, but operators were required to control 

those well completions using combustion.88 We solicit comment on 

the types of oil wells that will not be capable of performing a 

 

87 The EPA received six peer review comments and several 

submissions of technical information and data on this paper, 

available for review at 

http://www.epa.gov/airquality/oilandgas/whitepapers.html.

88 Following publication of the 2012 NSPS, EPA received a joint 

petition for administrative reconsideration of the rule. The 

petitioners questioned the technical merits of the low pressure 

well definition and asserted that the public had not had an 

opportunity to comment on the definition. EPA re-proposed the 

definition of ”low pressure gas well,” on March 23, 2015 (80 FR 

15180), and took comment on IPAA’s alternative definition. EPA 

has finalized this definition in a separate action. 
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REC or combusting completion emissions due to technical 

considerations such as low pressure or low gas content, or other 

physical characteristics such as location, well depth, length of 

hydraulic fracturing, or drilling direction (e.g., horizontal, 

vertical, directional). Additionally, we solicit comment on all 

aspects of our proposal to regulate methane and VOC emissions 

from hydraulically fractured oil well completions. 

As shown in the analyses presented above, the BSER for 

hydraulically fractured oil wells is the same as that for gas 

wells. Accordingly, we are proposing to apply the current 

requirements for hydraulically fractured gas well completions to 

hydraulically fractured oil well completions. It is logical that 

the BSER analyses would result in the same BSER determinations 

for hydraulically fractured gas and oil wells, because the 

available options for controlling emissions and their current 

use in the field are the same. Several public and peer reviewer 

comments on the white paper noted that the control technologies 

used for controlling emissions from hydraulically fractured oil 

well completions are the same as those used for completions of 

hydraulically fractured gas wells. The commenters further noted 

that in many cases it is difficult to distinguish gas wells from 

oil wells, because many wells produce both gas and oil. 
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Consistent standards for completions of hydraulically fractured 

gas wells and completions of hydraulically fractured oil wells 

will remove the need for operators to distinguish a gas well 

completion from an oil well completion for the purposes of 

complying with subpart OOOO. This change will improve the 

implementation of the standards by providing greater certainty 

as to which well completions must comply with the standards.

We are requesting comment on excluding low production wells 

(i.e., those with an average daily production of 15 barrel 

equivalents or less)89 from the standards for well completions. 

It is our understanding that low production wells have 

inherently low emissions from well completions and many are 

owned and operated by small businesses. We are concerned about 

the burden of the well completion requirement on small 

businesses, in particular where there is little emission 

reduction to be achieved. We recognize that identification of 

these wells prior to completion events is difficult. We believe 

that drilling of a low production well is unintentional and may

be infrequent, but production may nevertheless proceed due to 

 

89 For the purposes of this discussion, we define ‘low production 

well’ as a well with an average daily production of 15 barrel 

equivalents or less. This reflects the definition of a stripper 

well property in IRC 613A(c)(6)(E).
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economic reasons. We solicit comment and information on 

emissions associated with low production wells, characteristics 

of these wells and supporting information that would help 

owners/operators and enforcement personnel identify these wells 

prior to completion. In addition, we understand that a daily 

average of 15 barrel equivalents is representative of low 

production wells for some purposes, we solicit comment on the 

appropriateness of this threshold for applying the standards for 

well completions. 

Further, we are proposing that wells with a gas-to-oil 

ratio (GOR) of less than 300 scf of gas per barrel of oil 

produced would not be affected facilities subject to the well 

completion provisions of the NSPS.90 We solicit comment on 

whether a GOR of 300 is the appropriate applicability threshold, 

and if the GOR of nearby wells would be a reliable indicator in 

determining the GOR of a new or modified well. The reason for 

the proposed threshold GOR of 300 is that separators typically 

do not operate at a GOR less than 300, which is based on 

 

90 On February 24, 2015, API submitted a comment to EPA stating 

that oil wells with GOR values less than 300 do not have 

sufficient gas to operate a separator. 

http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2014-

0831-0137. 
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industry experience rather than a vetted technical specification 

for separator performance. Though, in theory, any amount of free 

gas could be separated from the liquid, the reality is that this 

is not practical given the design and operating parameters of 

separation units operating in the field. 

We believe that having no threshold may create a 

significant burden for operators to control emissions for these 

wells with just a trace of gas. EIA data show that the number of 

"oil only" wells drilled from 2007-2012 was less than 20 

percent.91 The potential emission characteristic of oils with a 

GOR of 300 is relevant when deciding whether this is a 

reasonable threshold. Primarily, the concern is volatility. The 

threshold must be low enough that the oil produced is considered 

non-volatile. Non-volatile "black oils" (oil likely to not have 

gases or light hydrocarbons associated with it) are generally 

defined as having GOR values in the range of 200 to 900.92

Therefore, oil wells with GORs less than 300 are at the lower 

end of this range, and will not likely have enough gas 

associated that it can be separated. Therefore, the EPA is 

proposing that the NSPS requirements for well completions do not 

 

91 http://www.eia.gov/todayinenergy/detail.cfm?id=13571# 92 http://petrowiki.org/Oil_fluid_characteristics
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apply to completions wells with hydraulic fracturing that have a 

GOR of less than 300 scf/barrel.

We are soliciting comment on whether the well completion 

provisions of the proposed rule can be implemented on the

effective date of the rule in the event of potential shortage of 

REC equipment and, if not, how a phase in could be structured.

We believe that there will be a sufficient supply of REC 

equipment available by the time the NSPS becomes effective. 

However, we request comment on whether sufficient supply of this 

equipment and personnel to operate it will be available to 

accommodate the increased number of RECs by the effective date 

of the NSPS. We also request specific estimates of how much time 

would be required to get enough equipment in operation to 

accommodate the full number of RECs performed annually. In the 

event that public comments indicate that available equipment 

would likely be insufficient to accommodate the increase in 

number of REC performed, we are considering phasing in 

requirements for well completions in the final rule. Such a 

phased in approach could be structured to provide for control of 

the highest emitting wells first, with other wells being 

included at a later date. We solicit comment on whether GOR of 

the well and production level of the well should be bases for 
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the phasing of requirements for RECs. We also solicit 

suggestions for other ways to address a potential short-term REC 

equipment shortage that may hinder operators’ compliance with 

the proposed NSPS. Additionally, we solicit comment on what an 

appropriate threshold should be for low production wells.

Finally, we solicit comment on criteria that could help 

clarify availability of gathering lines. Availability of a 

gathering line is one consideration affecting feasibility of 

recovery of natural gas during completion of hydraulically 

fractured wells. There are several factors that can affect 

availability of a gathering line including, but not limited to, 

the capacity of an existing gathering line to accept additional 

throughput, the ability of owners and operators to obtain rights 

of way to cross properties, and the distance from the well to an 

existing gathering line. We are aware that some states require

collection of gas if a gathering line is present within a 

specific distance from the well. For example, Montana allows gas 

from wells to be flared only in cases where the well is farther 

than one-half mile from a gas pipeline.93 We solicit comment on 

 

93 Administrative Rules of Montana (ARM) Title 17

Chapter 8 Air Quality Subchapter 16 – Emission Control 

Requirements for Oil and Gas Well Facilities Operating Prior to 
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whether distance from a gathering line is a valid criterion on 

which to base requirements for gas recovery and, if so, what 

would an appropriate distance for such a threshold. In addition, 

we solicit comment on any other factors that could be specified 

in the NSPS for requiring recovery of gas from well completions.

3. Use of a separator during flowback

For subcategory 1, subcategory 2 and low pressure gas 

wells, the current NSPS at §60.5375(a) and (f) requires routing 

of flowback to a separator unless it is technically infeasible 

for a separator to function. The NSPS also provides in 

§60.5375(f) that subcategory 2 and low pressure wells are 

required to control emissions through combustion using a 

completion combustion device (which can include a pit flare) 

rather than being required to perform a REC. It was our 

understanding that a separator could be used at some point 

during the flowback period of every well completion. Recent 

information indicates that some wells, because of certain 

characteristics of the reservoir, do not need to employ a 

separator. In those cases, we understand that operators direct 

 

Issuance of a Montana Air Quality Permit. Emission Control 

Requirements, 17.8.1603 Available at: 

http://www.deq.mt.gov/dir/legal/Chapters/Ch08-toc.mcpx
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the flowback to a pit and can combust gas contained in the 

flowback as it emerges from the pipe. At some point, after the 

well has flowed sufficiently to clean up the wellbore and the 

gas is of salable quality, production begins or the well is 

temporarily shut in. As a result of this new information, our 

initial understanding may not apply.

We solicit comment on (1) the role of the separator in well 

completions and whether a separator can be employed for every 

well completion; and (2) the appropriate relationship of the 

separator in the context of our requirements that cover a very 

broad spectrum of wells. We solicit further information that 

would help inform our consideration of this issue as we seek to 

ensure we have adequately established appropriate requirements 

for all well completions subject to the NSPS.

G. Proposed Standards for Fugitive Emissions from Well Sites and 

Compressor Stations 

In April 2014, the EPA published the white paper titled 

“Oil and Natural Gas Sector Leaks”94 which summarized the EPA’s 

current understanding of fugitive emissions of methane and VOC 

at onshore oil and natural gas production, processing, and 

 

94 Available at 

http://www.epa.gov/airquality/oilandgas/2014papers/20140415leaks

.pdf. 
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transmission and storage facilities. The white paper also 

outlined our understanding of the mitigation techniques 

(practices and technology) available to reduce these emissions 

along with the cost and effectiveness of these practices and 

technologies. 

The detection of fugitive emissions from oil and natural 

gas well sites and compressor stations, which are comprised of 

compressors at natural gas transmission, storage, gathering and 

boosting stations, can be determined using several technologies. 

Historically, fugitive emissions were detected using sensory 

monitoring (e.g., visual, olfactory or sound) or EPA Method 21 

to determine if a leak exceeded a set threshold (e.g., the leak 

concentration was greater than the leak definition for the 

component). As described in the white paper, we found that many 

fugitive emission surveys are now conducted using OGI in the oil 

and natural gas source category, a technology that provides a 

visible image of gas emissions or leaks to the atmosphere. The 

OGI instrument works by using spectral wavelength filtering and 

an array of infrared detectors to visualize the infrared 

absorption of hydrocarbons and other gaseous compounds. As the 

gas absorbs radiant energy at the same waveband that the filter 

transmits to the detector, the gas and motion of the gas is 
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imaged. The OGI instrument can be used for monitoring a large 

array of components at a facility and is an effective means of 

detecting fugitive emissions when the technology is used 

appropriately. 

Several studies in the white paper estimated that OGI can 

monitor 1,875-2,100 components per hour. In comparison, the 

average screening rate using a Method 21 instrument (e.g., 

organic vapor analyzer, flame ionization detector, flow 

measurement devices) is roughly 700 components per day. However, 

the EPA’s recent work with OGI instruments suggests these 

studies underestimate the amount of time necessary to thoroughly 

monitor components for fugitive emissions using OGI instruments. 

Even though the amount of time may be underestimated, we believe 

the use of OGI can reduce the amount of time necessary to 

conduct fugitive emissions monitoring since multiple fugitive 

emissions components can be surveyed simultaneously, thus 

reducing the cost of identifying fugitive emissions in upstream 

oil and natural gas facilities when compared to using a handheld 

TVA or OVA, which requires a manual screening of each fugitive 

emissions component. 

1. Fugitive Emissions from Well Sites
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Fugitive emissions may occur for many reasons at well sites 

such as when connection points are not fitted properly, thief 

hatches are not properly weighted or sealed or when seals and 

gaskets start to deteriorate. Changes in pressure or mechanical 

stresses can also cause fugitive emissions. Potential sources of 

fugitive emissions, fugitive emissions components, include 

agitator seals, connectors, pump diaphragms, flanges, 

instruments, meters, open-ended lines, pressure relief devices, 

pump seals, valves or open thief hatches or holes in storage 

vessels, pressure vessels, separators, heaters and meters. For 

purposes of this proposed rule, fugitive emissions do not 

include venting emissions from devices that vent as part of 

normal operations, such as gas-driven pneumatic controllers or 

gas-driven pneumatic pumps.

Based on our review of the public and peer review comments 

on the white paper and the Colorado and Wyoming state rules, we 

believe that there are two options for reducing methane and VOC 

fugitive emissions at well sites: (1) a fugitive emissions 

monitoring program based on individual component monitoring 

using EPA Method 21 for detection combined with repairs, or (2) 

a fugitive emissions monitoring program based on the use of OGI 

detection combined with repairs. Several public and peer 
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reviewer comments on the white paper noted that these 

technologies are currently used by industry to reduce fugitive 

emissions from the production segment in the oil and natural gas 

industry. 

Each of these control options are evaluated below based on 

varying the frequency of conducting the survey and fugitive 

emissions repair threshold (e.g., the specified concentration

when using Method 21 or visible identification of methane or VOC

when an OGI instrument is used). For our analysis, we considered 

quarterly, semiannual and annual survey frequency. For Method 21 

monitoring and repair, we considered 10,000 ppm, 2,500 ppm and 

500 ppm fugitive repair thresholds. The leak definition 

concentrations for other NSPS referencing Method 21 range from 

500 – 10,000 ppm. Therefore, we selected 500 ppm, 2,500 ppm and 

10,000 ppm. For OGI, we considered visible emissions as the 

fugitive repair threshold (i.e., emissions that can be seen 

using OGI instrumentation). EPA’s recent work with OGI indicates

that fugitive emissions at a concentration of 10,000 ppm are 

generally detectable using OGI instrumentation provided that the 

right operating conditions (e.g., wind speed and background 
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temperature) are present. Work is ongoing to determine the 

lowest concentration that can be reliably detected using OGI.95

In order to estimate fugitive methane and VOC emissions 

from well sites, we used fugitive emissions component counts 

from the GRI/EPA report96 for natural gas production well sites, 

and fugitive emissions component counts from the GHG inventory 

and API for oil production well sites. The types of production 

equipment located at natural gas production well pads include: 

gas wellheads, separators, meters/piping, heaters, and 

dehydrators. The types of oil well production equipment include: 

oil well heads, separators, headers and heater/treaters. The 

types of fugitive emissions components that are associated with 

both oil and natural gas wells include but are not limited to: 

valves, connectors, open-ended lines and valves (OEL), and 

pressure relief device (PRD). Fugitive emissions component 

counts for each piece of equipment in the gas production segment

were calculated using the average fugitive emissions component 

counts in the Eastern U.S. and the Western U.S. from the EPA/GRI 

 

95 Draft Technical Support Document Appendices, Optical Gas 

Imaging Protocol (40 CFR Part 60, Appendix K), August 11, 2015 

96 Gas Research Institute/U.S. Environmental Protection Agency, 

Research and Development, Methane Emission Factors from the 

Natural Gas Industry, Volume 8, Equipment Leaks, June 1996 (EPA600/R-96-080h).
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report. These data were used to develop a natural gas well site 

model plant. Fugitive emissions components counts for these 

equipment types in the oil production segment were obtained from 

an American Petroleum Institute (API) workbook.97 These data were 

used to develop an oil production well site model plant.

Since we have emission factors for only a subset of the 

components which are possible sources for fugitive emissions, 

our emission estimates are believed to be lower than the 

emissions profile for the entire set of fugitive emissions 

components that would typically be found at a well site.

The fugitive emission factors from AP-42,98 which provided a 

single source of total organic compounds (TOC) emission factors

that include non-VOCs, such as methane and ethane, were used to 

estimate emissions and evaluate the cost of control of a 

fugitive emissions program for oil and natural gas production 

well sites. Using the AP-42 factors, the methane and VOC 

fugitive emissions from a natural gas well site are estimated to 

be 4.5 tpy and 1.3 tpy, respectively. For an oil production well 

site, the estimated fugitive methane and VOC emissions are 1.1 

 

97 API Workbook 4638, 1996. 98 U.S. Environmental Protection Agency, Protocol for Equipment 

Leak Emission Estimates, Table 2-4, November 1995 (EPA-453/R-95-

017).
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tpy and 0.3 tpy, respectively. The calculation of these emission 

estimates are explained in detail in the background TSD for this 

proposal available in the docket. 

Information in the white paper related to the potential 

emission reductions from the implementation of an OGI monitoring 

program varied from 40 to 99 percent. The causes for this range 

in reduction efficiency were the frequency of monitoring surveys 

performed and different assumptions made by the study authors.

According to the calculations, which are based on uncontrolled 

emission factors for well pads contained within the EPA Oil and 

Natural Gas Sector Technical Support Document (2011), the 

Colorado Air Quality Control Commission, Initial Economic Impact 

Analysis for Proposed Revisions to Regulation Number 7 (5 CCR 

1001-9) and the FINAL ECONOMIC IMPACT ANALYSIS For Industry’s 

Proposed Revisions to Colorado Air Quality Control Commission 

Regulation Number 3, 6, and 7 (5 CCR 1001-9) (January 30, 2014),

a quarterly monitoring program in combination with a repair 

program can reasonably be expected to reduce fugitive methane 

and VOC emissions at well sites by 80 percent. Although 

information in the white paper indicated emission reductions as 

high as 99 percent may be achievable with OGI, we do not believe 

such levels can be consistently achieved for all of types of 
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components that may be subject to a fugitive emissions 

monitoring program. Therefore, using engineering judgement and 

experience obtained through our existing programs for finding 

and repairing leaking components, we selected 80 percent as an 

emission reduction level that can reasonably be expected to be 

achieved with a quarterly monitoring program. Due to the 

increased amount of time between each monitoring survey and 

subsequent repair, we believe that the level of emissions 

reduction achieved by less frequent monitoring surveys will be 

reduced from this level. Therefore, we assigned an emission 

reduction of 60 percent to semiannual monitoring survey and 

repair frequency and 40 percent to annual frequency, consistent 

with the reduction levels used by the Colorado Air Quality 

Control Commission in their initial and final economic impacts 

analyses. We solicit comment on the appropriateness of the 

percentage of emission reduction level that can be reasonably 

expected to be achieved with quarterly, semiannual, and annual 

monitoring program frequencies. 

For Method 21, we estimated emissions reductions using The 

EPA Equipment Leaks Protocol document, which provides emissions 

factor data based on leak definition and monitoring frequencies 

primarily for the Synthetic Organic Chemical Manufacturing 
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Industry (SOCMI) and Petroleum Refining Industry along with the

emissions rates contained within the Technology Review for 

Equipment Leaks document.99 We used these data along with the 

monitoring frequency (e.g., annual, semiannual, and quarterly) 

at fugitive repair thresholds at 500, 2,500 and 10,000 ppm to 

determine uncontrolled emissions. Using this information we 

calculated an expected emissions reduction percentage for each 

of the combinations of monitoring frequency and repair 

threshold.

We also looked at the costs of a monitoring and repair 

program under various monitoring frequencies and repair 

thresholds (for Method 21), including the cost of OGI monitoring 

survey, repair, monitoring plan development, and the costeffectiveness of the various options.100 For purposes of this 

action, we have identified in section VIII.A two approaches

(single and multipollutant approaches) for evaluating the costeffectiveness of a multipollutant control, such as the fugitive 

emissions monitoring and repair programs identified above for 

reducing both methane and VOC emissions. As explained in that 

 

99 Memorandum to Jodi Howard, EPA/OAQPS from Cindy Hancy, RTI 

International, Analysis of Emission Reduction Techniques for 

Equipment Leaks, December 21, 2011. EPA-HQ-OAR-2002-0037-0180 100 See pages 68-69 of the TSD.
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section, we believe that both the single and multipollutant 

approaches are appropriate for assessing the reasonableness of 

the multipollutant controls considered in this action. 

Therefore, we find the cost of control to be warranted as long 

as it is such under either of these two approaches.

Under the first approach (single pollutant approach), we 

assign all costs to the reduction of one pollutant and zero to 

all other pollutants simultaneously reduced. Under the second 

approach (multipollutant approach), we allocate the annualized 

cost across the pollutant reductions addressed by the control 

option in proportion to the relative percentage reduction of 

each pollutant controlled. In the multipollutant approach, since 

methane and VOC emissions are controlled proportionally equal, 

half the cost is apportioned to the methane emission reductions 

and half the cost is apportioned to the VOC emission reductions. 

In this evaluation, we evaluated both approaches across the 

range of identified monitoring survey options: OGI monitoring 

and repair performed quarterly, semiannually and annually; and 

Method 21 performed quarterly, semiannually and annually, with a 

fugitive emissions repair threshold of 500, 2,500 and 10,000 ppm 

at each frequency. The calculation of the costs, emission 

reductions, and cost of control for each option are explained in 
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detail in the TSD. As shown in the TSD, while the costs for 

repairing components that are found to have fugitive emissions 

during a fugitive monitoring survey remain the same, the annual 

repair costs will differ based on monitoring frequency. 

As shown in our TSD, both OGI and Method 21 monitoring 

survey methodologies costs generally increase with increasing 

monitoring frequency (i.e., quarterly monitoring has a higher 

cost of control than annual monitoring). For EPA Method 21

specifically, the cost also increases with decreasing fugitive 

emissions repair threshold (i.e., 500 ppm results in a higher 

cost of control than 10,000 ppm). However, as shown in the TSD,

the cost of control based on the OGI methodology for annual, 

semiannual, and quarterly monitoring frequencies for a model 

well site are estimated to be more cost-effective than Method 21 

for those same monitoring frequencies.101 We therefore focus our 

BSER analysis based on the use of OGI.

For the reasons stated below, we find that the control 

cost based on quarterly monitoring using OGI ismay not be costeffective based on the information available. As shown in the 

TSD, under the single pollutant approach, if all costs are 

 

101 See the 2015 TSD for full comparison. 
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assigned to methane and zero to VOC reduction, the cost is 

$3,753 per ton of methane reduced, and $3,521 per ton if savings 

of the natural gas recovered is taken into account. If all costs

are assigned to VOC and zero to methane reduction, the cost is 

$13,502 per ton of VOC reduced, and $12,668 per ton if savings 

of the natural gas recovered is taken into account. Under the 

multipollutant approach, the cost of control for VOC based on 

quarterly monitoring is $6,751 per ton, and $6,334 per ton of 

VOC reduced if savings are considered. In a previous NSPS 

rulemaking [72 FR 64864 (November 16, 2007)], we had concluded 

that a VOC control option was not cost-effective at a cost of 

$5,700 per ton. In light of the above, we find that the cost of 

monitoring/repair based on quarterly monitoring at well sites 

using OGI is not cost-effective for reducing VOC and methane 

emissions under either approach. Having found the control cost 

using OGI based on quarterly monitoring not to be costeffective, we now evaluate the control cost based on annual and 

semi-annual monitoring using OGI. As shown in the TSD, the costs 

between annual and semi-annual monitoring are comparable. 

Because semi-annual monitoring achieves greater emissions 

reduction, we focus our analysis on the cost based on semiannual monitoring.
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While the cost appears high under the single pollutant 

approach, we find the costs to be reasonable under the 

multipollutant approach for the following reasons. As shown in 

the TSD, for VOC reduction, the cost is $4,979 per ton; when 

savings of the natural gas recovered are taken into account, the 

cost is reduced to $4,562 per ton. For methane reduction, the 

control cost is $1,384 per ton; when cost savings of the natural 

gas recovered is taken into account, the cost is reduced to 

$1,268 per ton. As explained above, we believe that we have 

underestimated the emissions from these well sites; therefore, 

we believe the use of OGI is more cost-effective than the amount 

presented here. Furthermore, while being used to survey fugitive 

components at a well site, the OGI may potentially help an owner 

and operator detect and repair other sources of visible

emissions not covered by the NSPS. One example would be an 

intermittently acting pneumatic controller that is stuck open.

The OGI could help the owner and operator detect and address and 

reduce such inadvertent emissions, resulting in more cost saving 

from more natural gas recovered. 

We also identified in section VIII.A two additional 

approaches, based on new capital expenditures and annual 

revenues, for evaluating whether the costs are reasonable. For 
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monitoring and repair of fugitive emissions at well sites, we 

believe that the total revenue analysis is more appropriate than 

the capital expenditure analysis and therefore we did not 

perform the capital expenditure analysis. For the total revenue 

analysis, we used the revenues for 2012 for NAICS 211111, 211112 

and 213112, which we believe are representative of the 

production segment. The total annualized costs for complying 

with the proposed standards is 0.085 percent of the total 

revenues, which we believe is reasonablevery low.

For all types of affected facilities in the production, the 

total annualized costs for complying with the proposed standards 

is 0.13 percent of the total revenues, which we believe is 

reasonablealso very low.

For the reasons stated above, we find the cost of 

monitoring and repairing fugitive emissions at well sites based 

on semi-annual monitoring using OGI to be reasonable. To ensure 

that no fugitive emissions remain, a resurvey of the repaired 

components is necessary. We expect that most of the repair and 

resurveys are conducted at the same time as the initial 

monitoring survey while OGI personnel are still on-site.

However, there may be some components that cannot not be 

repaired right away and in some instances not until after the 
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initial OGI personnel are no longer on site. In that event, 

resurvey with OGI would require rehiring OGI personnel, which 

would make the resurvey not cost effective. On the other hand, 

as shown in TSD, the cost of conducting resurvey using Method 21 

is $2 per component, which is reasonable. 

We did not find any nonair quality health and environmental 

impacts, or energy requirements associated with the use of OGI 

or Method 21 for monitoring, repairing and resurvey fugitive 

components at well sites. Based on the above analysis, we 

believe that the BSER for reducing fugitive methane and VOC 

emissions at well sites is a monitoring and repair standard 

based on semi-annual monitoring using OGI and resurvey using 

Method 21.

As mentioned above, OGI monitoring requires trained OGI 

personnel and specialized equipment.OGI instruments. Many owners 

and operators, in particular small businesses, may not own OGI 

equipmentinstruments or have staff who are trained and qualified 

to use such instrumentinstruments; some may not have the capital 

to acquire the OGI instrument or provide training to their 

staff. While our cost analysis takes into account that owners 

and operators may need to hire contractors to perform the 

monitoring survey using OGI, we do not have information on the 
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number of available contractors and equipment.OGI instruments.

In light of our estimated 20,000 active wells in 2012 and that 

the number will increase annually, we are concerned that some 

owners and operators, in particular small businesses, may have 

difficulty securing the requisite OGI contractors and/or 

equipmentOGI instrumentation to perform monitoring surveys on a 

semi-annual basis. Larger companies, due to the economic clout 

they have by offering the contractors more work due to the 

higher number of wells they own, may preferentially retain the 

services of a large portion of the available contractors. This 

may result in small businesses experiencing a longer wait time 

to obtain contractor services. In light of the potential concern 

above, we are co-proposing monitoring survey on an annual basis 

at the same time soliciting comment and supporting information 

on the availability of trained OGI contractors and equipmentOGI 

instrumentation to help us evaluate whether owners and operators 

would have difficulty acquiring the necessary equipment and 

personnel to perform a semi-annual monitoring and, if so, 

whether annual monitoring would alleviate such problem.problems. 

Recognizing that additional data may be available, such as 

emissions from super emitters that may have higher emission 

factors than those considered in this analysis, we are also 
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taking comment on requiring monitoring survey on a quarterly 

basis. 

CAA section 111(h)(1) states that the Administrator may 

promulgate a work practice standard or other requirements, which 

reflects the best technological system of continuous emission 

reduction when it is not feasible to enforce an emission 

standard. CAA section 111(h)(2) defines the phrase “not feasible 

to prescribe or enforce an emission standard” as follows:

[A]ny situation in which the Administrator determines that 

(A) a hazardous air pollutant or pollutants cannot be 

emitted through a conveyance designed and constructed to 

emit or capture such pollutant, or that any requirement 

for, or use of, such a conveyance would be inconsistent 

with any Federal, State, or local law, or (B) the 

application of measurement methodology to a particular 

class of sources is not practicable due to technological 

and economic limitations.

The work practice standards for fugitive emissions from 

well sites are consistent with CAA section 111(h)(1)(A), because 

no conveyance to capture fugitive emissions exist for fugitive 

emissions components at a well site. In addition, OGI does not 

measure the extent the fugitive emissions from fugitive 
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emissions components. For the reasons stated above, pursuant to 

CAA section 111(h)(1)(b), we are proposing work practice 

standards for fugitive emissions from the collection of fugitive 

emission components at well sites.

The proposed work practice standards include details for 

development of a fugitive emissions monitoring plan, repair 

requirements and recordkeeping and reporting requirements. The 

fugitive emissions monitoring plan includes operating parameters 

to ensure consistent and effective operation for OGI such as 

procedures for determining the maximum viewing distance and wind 

speed during monitoring. The proposed standards would require a 

source of fugitive emissions to be repaired or replaced as soon 

as practicable, but no later than 15 calendar days after 

detection of the fugitive emissions. We have historically 

allowed 15 days for repair/resurvey in LDAR programs, which 

appears to be sufficient time. Further, in light of the number 

of components at a well site and the number that would need to 

be repaired, we believe that 15 days is also sufficient for 

conducting the required repairs under the proposed fugitive 
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emission standards.102 That said, we are also soliciting comment 

on whether 15 days is an appropriate amount of time for repair 

of sources of fugitive emissions at well sites.103 

Many recent studies have shown a skewed distribution for 

emissions related to leaks, where a majority of emissions come 

from a minority of sources.104 Commenters on the white papers 

agreed that emissions from equipment leaks exhibit a skewed 

distribution, and pointed to other examples of data sets in 

which the majority of fugitive methane and VOC emissions come 

from a minority of components (e.g., gross emitters). Based on 

this information, we solicit comment on whether the fugitive 

emissions monitoring program should be limited to “gross 

emitters.” 

We believe that a properly maintained facility would likely 

detect very little to no fugitive emissions at each monitoring 

survey, while a poorly maintained facility would continue to 

detect fugitive emissions. As shown in our TSD, we estimate the 

number of fugitive emission components at a well site to be 

 

102 In our TSD we estimate the number of fugitive emissions 

components to be around 700 and of those components we estimate 

that about 1 percent would need to be repaired. 103 This timelines is consistent with the timeline originally 

established in 1983 under 40 C.F.R. part 60 subpart VV. 
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around 700. We believe that a facility with proper operation 

would likely find one to five percent of components to have 

fugitive emissions. To encourage proper maintenance, we are 

proposing that the owner or operator may go to annual monitoring 

if the initial two consecutive semiannual monitoring surveys 

show that less than one percent of the collection of fugitive 

emissions components at the well site has fugitive emissions.

For the same reason, we are proposing that the owner or operator 

conduct quarterly monitoring if the initial two semi-annual 

monitoring surveys show that more than five percent of the 

collection of fugitive emissions components at the well site has 

fugitive emissions. We believe the first year to be the tune-up 

year to allow owners and operators the opportunity to refine the 

requirements of their monitoring/repair plan. After that initial 

year, the required monitoring frequency would be annual if a 

monitoring survey shows less than one percent of components to 

have fugitive emissions; semi-annual if one to five percent of 

total components have fugitive emissions; and quarterly if over 

five percent of total components have fugitive emissions. We 

solicit comment on this approach, including the percentage used 

to adjust the monitoring frequency. We also solicit comment on

the appropriateness of performance based monitoring frequencies. 
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We also solicit comment on the appropriateness of triggering

different monitoring frequencies based on the percentage of 

components with fugitive emissions. Under the proposed 

standards, the affected facility would be defined as the 

collection of fugitive emissions components at a well site. To 

clarify which components are subject to the fugitive emissions 

monitoring provisions, we propose to add a definition to 

§60.5430 for “fugitive emissions component” as follows:

Fugitive emissions component means any component that has 

the potential to emit fugitive emissions of methane or VOC

at a well site or compressor station site, including but 

not limited to valves, connectors, pressure relief devices, 

open-ended lines, access doors, flanges, closed vent 

systems, thief hatches or other openings on a storage 

vessels, agitator seals, distance pieces, crankcase vents, 

blowdown vents, pump seals or diaphragms, compressors, 

separators, pressure vessels, dehydrators, heaters, 

instruments, and meters. Devices that vent as part of 

normal operations, such as a natural gas-driven pneumatic 

controllers or natural gas-driven pumps, are not fugitive 

emissions components, insofar as the natural gas discharged 

from the device’s vent is not considered a fugitive 
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emission. Emissions originating from other than the vent, 

such as the seals around the bellows of a diaphragm pump 

would be considered fugitive emissions.

Thus, all fugitive emissions components at the affected facility 

would be monitored for fugitive emissions of methane and VOC. 

For the reasons stated in section VII.G.1, for purposes of 

the proposed standards for fugitive emissions at well sites, 

modification of a well site is defined as when a new well is 

drilled or a well at the well site (where collection of fugitive 

emissions components are located) is hydraulically fractured or 

refractured. As explained in that section, other than these 

events, we are not aware of any other physical change to a well 

site that would result in an increase in emissions from the 

collection of fugitive components at such well site. To clarify 

and ease implementation, we propose to define “modification” to 

include only these two events for purposes of the fugitive 

emissions provisions at well sites. 

To encourage broadly applied fugitive emissions monitoring, 

we solicit comment on whether new or modified well sites should 

not be affected facilities subject to the fugitive emission 

standards of the NSPS if, at the time such standards are 

promulgated, the owner or operator has a corporate-wide fugitive 
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emissions monitoring plan in place and is implementing such a 

plan through a legally and practically enforceable requirement

in an operating permit or other requirement established under a 

Federal, State, local or tribal authority that meets the NSPS 

standards, including the repair and recordkeeping requirements.

In the 2012 NSPS, we provided that completion requirements 

do not apply to refracturing of an existing well that is 

completed responsibly (i.e. green completions). Building on the 

2012 NSPS, the EPA intends to continue to encourage corporatewide voluntary efforts to achieve emission reductions through 

responsible, transparent and verifiable actions that would 

obviate the need to meet obligations associated with NSPS 

applicability, as well as avoid creating disruption for 

operators following advanced responsible corporate practices. 

It has come to our attention that some owners and operators may 

already have in place, and are implementing, corporate-wide 

fugitive emissions monitoring and repair programs at their well 

sites that are equivalent to, or more stringent than our 

proposed standards. Such corporate efforts present the potential 

to further the development of LDAR technologies. To encourage 

companies to continue such good corporate policies and encourage 

advancement in the technology and practices, we solicit comment 
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on criteria we can use to determine whether and under what 

conditions well sites operating under corporate LDAR regimes can 

be deemed to be meeting the equivalent of the NSPS standards for 

well site fugitive emissions such that we can define those 

regimes as constituting alternative methods of compliance or 

otherwise provide appropriate regulatory streamlining. We also 

solicit comment on how to address enforceability of such 

alternative approaches (i.e., how to assure that these well 

sites are achieving, and will continue to achieve, equal or 

better emission reduction than our proposed standards). We 

recognize that meeting an NSPS performance level should not, 

standing alone, be a basis for a source not becoming an affected 

facility.

We are requesting comment on whether the fugitive emissions 

requirements should apply to all fugitive emissions components

at modified well sites or just to those components that are 

connected to the fractured, refractured or added well. For some 

modified well sites, the fractured or refractured or added well 

may only be connected to a subset of the fugitive emissions 

components on site. We are soliciting comment on whether the 

fugitive emission requirements should only apply to that subset. 

However, we are aware that the added complexity of 
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distinguishing covered and non-covered sources may create 

difficulty in implementing these requirements. However, we note 

that it may be advantageous to the operator from an operational 

perspective to monitor all the components at a well site since 

the monitoring equipment is already onsite.

As explained above, Method 21 is not as cost-effective as 

OGI for monitoring. That said, there may be reasons why and 

owner and operator may prefer to use Method 21 over OGI. While 

we are confident with the ability of Method 21 to detect 

fugitive emissions and therefore consider it a viable 

alternative to OGI, we solicit comment on the appropriate 

fugitive emissions repair threshold for Method 21 monitoring 

surveys. As mentioned above, EPA’s recent work with OGI 

indicates that fugitive emissions at a concentration of 10,000 

ppm is generally detectable using OGI instrumentation provided 

that the right operating conditions (e.g., wind speed and 

background temperature) are present. Work is ongoing to 

determine the lowest concentration that can be reliably detected 

using OGI As mentioned above, we believe that OGI. In light of 

the above, we solicit comment on whether the fugitive emissions 

repair threshold for Method 21 monitoring surveys should be set 
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at 10,000 ppm or whether a different threshold is more 

appropriate (including information to support such threshold).

While we did not identify OGI as the BSER for resurvey 

because of the potential cost associated with rehiring OGI 

personnel, there is no such additional cost for those who either 

own the OGI instrument or can perform repair/resurvey at the 

same time. Therefore, the proposed rule would allow the use 

either OGI or Method 21 for resurvey. When Method 21 is used to 

resurvey components, we are proposing that the component is 

repaired if the Method 21 instrument indicates a concentration 

less than 500 ppm above background. This has been historically 

used in other LDAR programs as an indicator of no detectable 

emissions. 

The proposed standards would require that operators begin 

monitoring fugitive emissions components at a well site within 

30 days of the initial startup of the first well completion for 

a new well or within 30 days of well site modification. We are 

proposing a 30 day period to allow owners and operators the 

opportunity to secure qualified contractors and equipment 

necessary for the initial monitoring survey. We are requesting 

comment on whether 30 days is an appropriate amount of time to 

begin conducting fugitive emissions monitoring.
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We received new information indicating that some companies 

could experience logistical challenges with the availability of 

OGI instrumentation and qualified OGI technicians and operators 

to perform monitoring surveys and in some instances repairs. We 

solicit comment on both the availability of OGI instruments and 

the availability of qualified OGI technicians and operators to 

perform surveys and repairs.

We solicit comment on excluding low production wells from 

the fugitives program.We are proposing to exclude low production 

well sites (i.e., a low production site is defined by the 

average combined oil and natural gas production for the wells at 

the site being less than 15 barrels of oil equivalent (boe) per 

day averaged over the first 30 days of production)105 from the 

standards for fugitives emissions from well sites. We believe 

the lower production associated with these wells would generally 

result in lower fugitive emissions. Therefore, we are requesting 

comment on excluding fugitive components at well sites with low 

production wells (i.e., those with an average daily production 

 

105 For the purposes of this discussion, we define ‘low 

production well’ as a well with an average daily production of 

15 barrel equivalents or less. This reflects the definition of a 

stripper well property in IRC 613A(c)(6)(E).
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of 15 barrel equivalents or less)106 from the standards for 

fugitive emissions at well sites. It is our understanding that 

fugitive emissions at a well site with low production wellswell

sites are inherently low and that such well sites are mostly 

owned and operated by small businesses. We are concerned about 

the burden of the fugitive emission requirement on small 

businesses, in particular where there is little emission 

reduction to be achieved. To more fully evaluate the

contemplated exclusion, we solicit comment on the air emissions 

associated with low production wells, and the relationship 

between production and fugitive emissions. Specifically, we 

solicit comment on the relationship between production and 

fugitive emissions over time. While we have learned that a daily 

average of 15 barrel per day is representative of low production 

wells, we solicit comment on the appropriateness of this 

threshold for applying the standards for fugitive emission at 

well sites.

We are also requesting comment on whether there are well 

sites that have inherently low fugitive emissions, even when a 

 

106 For the purposes of this discussion, we define ‘low 

production well’ as a well with an average daily production of 

15 barrel equivalents or less. This reflects the definition of a 

stripper well property in IRC 613A(c)(6)(E).
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new well is drilled or a well site is fractured or refractured 

and, if so, descriptions of such type(s) of well sites. The

proposed standards are not intended to cover well sites with no 

fugitive emissions of methane or VOC. We are aware that some 

sites may have inherently low fugitive emissions due to the 

characteristics of the site, such as the gas to oil ratio of the 

wells or the specific types of equipment located on the well 

site. We solicit comment on these characteristics and data that 

would demonstrate that these sites have low methane and VOC 

fugitive emissions.

We are requesting comment on whether there are other 

fugitive emission detection technologies for fugitive emissions 

monitoring, since this is a field of emerging technology and 

major advances are expected in the near future. We are aware of 

several types of technologies that may be appropriate for 

fugitive emissions monitoring such as Geospatial Measurement of 

Air Pollutants using OTM-33 approaches (e.g., Picarro Surveyor), 

passive sorbent tubes using EPA Methods 325A and B, active 

sensors, gas cloud imaging (e.g., Rebellion photonics), and 

Airborne Differential Absorption Lidar (DIAL). Therefore, we are 

specifically requesting comments on details related to these and 

other technologies such as the detection capability; an 
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equivalent fugitive emission repair threshold to what is 

required in the proposed rule for OGI; the frequency at which 

the fugitive emissions monitoring surveys should be performed 

and how this frequency ensures appropriate levels of fugitive 

emissions detection; whether the technology can be used as a 

stand-alone technique or whether it must be used in conjunction 

with a less frequent (and how frequent) OGI monitoring survey; 

the type of restrictions necessary for optimal use; and the 

information that is important for inclusion in a monitoring plan 

for these technologies.

2. Fugitive Emissions from Compressor Stations 

Fugitive emissions at compressor stations in the oil and 

natural gas source category may occur for many reasons (e.g.,

when connection points are not fitted properly, or when seals 

and gaskets start to deteriorate). Changes in pressure and 

mechanical stresses can also cause fugitive emissions. Potential 

sources of fugitive emissions include agitator seals, distance 

pieces, crank case vents, blowdown vents, connectors, pump seals 

or diaphragms, flanges, instruments, meters, open-ended lines, 

pressure relief devices, valves, open thief hatches or holes in 

storage vessels, and similar items on glycol dehydrators (e.g.,

pumps, valves, and pressure relief devices). Equipment that 
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vents as part of normal operations, such as gas driven pneumatic 

controllers, gas driven pneumatic pumps or the normal operation 

of blowdown vents are not considered to be sources of fugitive 

emissions. 

Based on our review of the public and peer review comments 

on the white paper and the Colorado and Wyoming state rules, we 

believe that there are two options for reducing methane and VOC 

fugitive emissions at compressor stations: (1) a fugitive 

emissions monitoring program based on individual component 

monitoring using EPA Method 21 for detection combined with 

repairs, or (2) a fugitive emissions monitoring program based on 

the use of OGI detection combined with repairs. Several public 

and peer reviewer comments on the white paper noted that these 

technologies are currently used by industry to reduce fugitive 

emissions from the production segment in the oil and natural gas 

industry. 

Each of these control options are evaluated below based on 

varying the frequency of conducting the monitoring survey and 

fugitive emissions repair threshold (e.g., the specified 

concentration when using Method 21 or visible identification of 

methane or VOC when an OGI instrument is used). For our 

analysis, we considered quarterly, semiannual and annual 
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monitoring frequencies. For Method 21, we considered 10,000 ppm, 

2,500 ppm and 500 ppm fugitive repair thresholds. The leak 

definitions for other NSPS referencing Method 21 range from 500 

– 10,000 ppm. Therefore, we selected 500 ppm, 2,500 ppm and 

10,000 ppm. For OGI, we considered visible emissions as the 

fugitive repair threshold (i.e., emissions that can be seen 

using OGI). EPA’s recent work with OGI indicate that fugitive 

emissions at a concentration of 10,000 ppm are generally 

detectable using OGI instrumentation, provided that the right 

operating conditions (e.g., wind speed and background 

temperature) are present. Work is ongoing to determine the 

lowest concentration that can be reliably detected using OGI.107

In order to estimate fugitive emissions from compressor 

stations, we used component counts from the GRI/EPA report108 for 

each of the compressor station segments. Fugitive emission 

factors from AP-42109 were used to estimate emissions from 

 

107 Draft Technical Support Document Appendices, Optical Gas 

Imaging Protocol (40 CFR Part 60, Appendix K), August 11, 2015

108 Gas Research Institute/U.S. Environmental Protection Agency, 

Research and Development, Methane Emission Factors from the 

Natural Gas Industry, Volume 8, Equipment Leaks, June 1996 (EPA600/R-96-080h). 109 U.S. Environmental Protection Agency, Protocol for Equipment 

Leak Emission Estimates, Table 2-4, November 1995 (EPA-453/R-95-

017).
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gathering and boosting stations in the production segment and 

emission factors from the GRI/EPA report were used to estimate 

fugitive emission from transmission and storage compressor 

stations and evaluate the cost of control for these segments. 

Since we have emission factors for only a subset of the 

components which are possible sources for fugitive emissions, 

our emission estimates are believed to be lower than the 

emissions profile for the entire set of components that would

typically be found at a compressor station.

The fugitive emission factors from AP-42,110 which provided 

a single source of TOC emission factors that include non-VOCs, 

such as methane and ethane, were used to estimate emissions and 

evaluate the cost of control of a fugitive emissions program for 

compressor stations. Using the GRI/EPA and AP-42 data, fugitive 

emissions from gathering and boosting stations were estimated to 

be 35.1 tpy of methane and 9.8 tpy of VOC. Fugitive emissions 

from natural gas transmission stations were estimated to be 62.4 

tpy of methane and 1.7 tpy of VOC. Fugitive emissions from 

natural gas storage facilities were estimated to be 164.4 tpy of 

 

110 U.S. Environmental Protection Agency, Protocol for Equipment 

Leak Emission Estimates, Table 2-4, November 1995 (EPA-453/R-95-

017).
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methane and 4.6 tpy of VOC. The calculation of these emission 

estimates are explained in detail in the TSD available in the 

docket. 

Information in the white paper related to the potential 

emission reductions from the implementation of an OGI monitoring 

program varied from 40 to 99 percent. The causes for this range 

in reduction efficiency were the frequency of monitoring surveys 

performed and different assumptions made by the study authors. 

According to the calculations, which are based on uncontrolled 

emission factors for well pads contained within the EPA Oil and 

Natural Gas Sector Technical Support Document (2011), the 

Colorado Air Quality Control Commission, Initial Economic Impact 

Analysis for Proposed Revisions to Regulation Number 7 (5 CCR 

1001-9) and the FINAL ECONOMIC IMPACT ANALYSIS For Industry’s 

Proposed Revisions to Colorado Air Quality Control Commission 

Regulation Number 3, 6, and 7 (5 CCR 1001-9) (January 30, 2014), 

a -quarterly monitoring program in combination with a repair 

program can reasonably be expected to reduce fugitive methane 

and VOC emissions at well sites by 80 percent. Although 

information in the white paper indicated emission reductions as 

high as 99 percent may be achievable with OGI, we do not believe 

such levels can be consistently achieved for all of types of 
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components that may be subject to a fugitive emissions 

monitoring program. Therefore, using engineering judgement and 

experience obtained through our existing programs for finding 

and repairing leaking components, we selected 80 percent as an 

emission reduction level that can reasonably be expected to be 

achieved with a quarterly monitoring program. Due to the 

increased amount of time between each monitoring survey and 

subsequent repair, we believe that the level of emissions 

reduction achieved by less frequent monitoring surveys will be 

reduced from this level. Therefore, we assigned an emission 

reduction of 60 percent to semiannual monitoring survey and 

repair frequency and 40 percent to annual frequency, consistent 

with the reduction levels used by the Colorado Air Quality 

Control Commission in their initial and final economic impacts 

analyses. We solicit comment on the appropriateness of the 

percentage of emission reduction level that can be reasonably 

expected to be achieved with quarterly, semiannual, and annual 

monitoring program frequencies. 

For Method 21, we estimated emissions reductions using The 

EPA Equipment Leaks Protocol document, which provides emissions 

factor data based on leak definition and monitoring frequencies 

primarily for the Synthetic Organic Chemical Manufacturing 
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Industry (SOCMI) and Petroleum Refining Industry along with the 

emissions rates contained within the Technology Review for 

Equipment Leaks document.111 We used these data along with the 

monitoring frequency (e.g., annual, semiannual, and quarterly) 

at fugitive repair thresholds at 500, 2,500 and 10,000 ppm to 

determine uncontrolled emissions. Using this information we 

calculated an expected emissions reduction percentage for each 

of the combinations of monitoring frequency and repair threshold

which range from 

We also looked at the costs of a monitoring and repair 

program under various monitoring frequencies and repair 

thresholds (for Method 21), including the cost of OGI monitoring 

survey, repair, monitoring plan development, and the costeffectiveness of the various options.112 For purposes of this 

action, we have identified in section VIII.A two approaches

(single pollutant and multipollutant approaches) for evaluating 

whether the cost of a multipollutant control, such as the 

fugitive emissions monitoring and repair programs identified 

above, is reasonable. As explained in that section, we believe 

 

111 Memorandum to Jodi Howard, EPA/OAQPS from Cindy Hancy, RTI 

International, Analysis of Emission Reduction Techniques for 

Equipment Leaks, December 21, 2011. EPA-HQ-OAR-2002-0037-0180 112 See pages 68-69 of the TSD.
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that both approaches are appropriate for assessing the 

reasonableness of the multipollutant controls considered in this 

action. Therefore, we find the cost of control to be reasonable 

as long as it is such under either of these two approaches.

Under the first approach (single pollutant approach), we 

assign all costs to the reduction of one pollutant and zero to 

all other pollutants simultaneously reduced. Under the second 

approach (multipollutant approach), we apportion the annualized 

cost across the pollutant reductions addressed by the control 

option in proportion to the relative percentage reduction of 

each pollutant controlled. In the multipollutant approach, since 

methane and VOC are controlled equally, half the cost is 

apportioned to the methane emission reductions and half the cost 

is apportioned to the VOC emission reductions. In this 

evaluation, we evaluated both approaches across the range of 

identified monitoring survey options: OGI monitoring and repair 

performed quarterly, semiannually and annually; and Method 21 

monitoring performed quarterly, semiannually and annually, with 

a fugitive emissions repair threshold of 500, 2,500 and 10,000 

ppm at each frequency. The calculation of the costs, emission 

reductions, and cost of control for each option are explained in 

detail in the TSD. As shown in the TSD, while the costs for 
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repairing components that are found to have fugitive emissions 

during a fugitive monitoring survey remain the same, the annual 

repair costs will differ based on monitoring frequency.

As shown in our TSD, both OGI and Method 21 monitoring

survey methodologies costs generally increase with increasing 

monitoring frequency (i.e., quarterly monitoring has a higher 

cost of control than annual monitoring). For EPA Method 21

specifically, the cost also increases with decreasing fugitive 

emissions repair threshold (i.e., 500 ppm results in a higher 

cost of control than 10,000 ppm). However, as shown in the TSD, 

the cost of control based on the OGI methodology for annual, 

semiannual, and quarterly monitoring frequencies are estimated 

to be more cost-effective than Method 21 for those same 

monitoring frequencies.113 We therefore focus our BSER analysis 

based on the use of OGI.

As shown in the TSD, the costs are comparable for all three 

monitoring frequencies using OGI. For the reasons explained 

below, we find the monitoring/repair program using OGI at 

compressor stations to be cost-effective for all three 

monitoring frequencies. Under the single pollutant approach, if 

 

113 See the 2015 TSD for full comparison. 
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we assign all control costs to VOC and zero to methane 

reduction, the costs range from $3,110 to $4,273 per ton of VOC 

reduced ($2,338 to $3,502 with gas saving) and zero for methane, 

which indicate that the control is cost-effective. Even if we 

assign all of the costs to methane and zero to VOC reduction, 

the costs, which range from $686 to $930 per ton of methane 

reduced ($471 to $715 per ton with gas savings), are well below 

our cost-effectiveness estimates for the semi-annul monitoring 

and repair option for reducing fugitive emissions at compressor 

stations, which we find to be reasonable for the reasons stated 

above. Under the multipollutant approach, the costs for VOC 

reduction range from $1,555 to $2,136 ($1,169 to $1,751 with gas 

saving). The costs for methane reduction range from $343 to 

$465 per ton ($236 to $358 per ton with gas savings). Again 

these cost estimates for methane reductions are well below our 

estimates for the monitoring/repair program at compressor 

stations using OGI based on semiannual monitoring, which we find 

to be reasonable for the reasons stated above. Further, as 

previously explained, we believe the emission reduction values 

used in these calculations underestimate the actual emission 

reductions that would be achieved by a fugitives monitoring and 

repair program, so these cost of control values likely represent 
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a high end cost assumption. Therefore, we believe the use of OGI 

is more cost-effective than the amounts presented here. The 

calculation of the costs, emission reductions, and cost of 

control calculations for each option are explained in detail in 

the TSD for this action available in the docket.

While the costs are comparable for all three monitoring 

frequencies using OGI, for the reasons stated below, we have 

concerns with the potential compliance burdens, in particular on 

small businesses, associated with quarterly monitoring, and we 

believe that semi-annual monitoring could achieve meaningful 

reduction without such potential issues.

Further practical aspects we considered for the methodology 

of each monitoring survey include the likeliness that many 

owners and operators will hire a contractor to conduct the 

monitoring survey due to the cost of the specialized equipment 

needed to perform the monitoring survey and the training 

necessary to properly operate the OGI equipment. We also believe 

that small businesses are most likely to hire such contractors 

because they are less likely to have excess capital to purchase 

monitoring equipment and train operators. We are concerned that 

the limited supply of qualified contractors to perform 

monitoring surveys may lead to disadvantages for small 
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businesses. Larger businesses, due to the economic clout they 

have by offering the contractors more work due to the higher 

number of compressor stations they own, may preferentially 

retain the services of a large portion of the available 

contractors. This may result in small businesses experiencing a 

longer wait time to obtain contractor services. 

Specifically for conducting OGI monitoring surveys, we 

believe that many operators will hire OGI contractors to conduct 

the OGI surveys. The proposed fugitive emissions monitoring plan 

requires that operators verify the capability of OGI 

instrumentation, determine viewing distance, and determine the 

maximum wind speed. Additionally, there are specific 

requirements for conducting the survey such as how to operate 

OGI in adverse monitoring conditions or how to deal with 

interferences such as steam. Each corporate-wide plan will need 

to include these requirements and will require OGI contractors 

and operators to be trained to meet these requirement. The 

monitoring plan requirements will also cause the surveys to take 

more time, thus affecting the availability of OGI equipment and 

contractors. Therefore, if we specify quarterly monitoring 

surveys, we are concerned that the available supply of qualified 

contractors and OGI instruments may not be sufficient for small 
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businesses to obtain timely monitoring surveys. For the reasons 

stated above, we have concerns with the potential compliance 

burdens, in particular on small businesses, associated with 

quarterly monitoring, and we believe that semi-annual monitoring 

could achieve meaningful reduction without such potential 

issues.

We also identified in section VIII.A two additional 

approaches, based on new capital expenditures and annual 

revenues, for evaluating whether the costs are reasonable. For 

monitoring and repair of fugitive emissions at compressor

stations, we believe that the total revenue analysis is more 

appropriate than the capital expenditure analysis and therefore 

we did not perform the capital expenditure analysis. For the 

total revenue analysis, we used the revenues for 2012 for NAICS 

486210, which we believe is representative of the production 

segment. The total annualized costs for complying with the 

proposed standards is 0.103 percent of the total revenues, which 

we believe is reasonablevery low.

For all types of affected facilities in the transmission 

and storage segment, the total annualized costs for complying 

with the proposed standards is 0.13 percent of the total 

revenues, which we believe is reasonablealso very low.
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For the reasons stated above, we find the cost of 

monitoring and repairing fugitive emissions at compressor 

stations based on semi-annual monitoring using OGI to be 

reasonable. To ensure that no fugitive emissions remain, a 

resurvey of the repaired components is necessary. We expect that 

most of the repair and resurveys are conducted at the same time 

as the initial monitoring survey while OGI personnel are still 

on-site. However, there may be some components that cannot be 

repaired right away and in some instances not until after the 

initial OGI personnel are no longer on site. In that event, 

resurvey with OGI would require rehiring OGI personnel, which 

would make the resurvey not cost effective. On the other hand, 

as shown in the TSD, the cost of conducting a resurvey using 

Method 21 is $2 per component, which is reasonable.

We did not find any nonair quality health and environmental 

impacts, or energy requirements associated with the use of OGI 

or Method 21 for monitoring, repairing and resurveying fugitive 

emissions components at compressor stations. Based on the above 

analysis, we believe that the BSER for reducing fugitive methane 

and VOC emissions at compressor stations is a monitoring and 

repair standard based on semi-annual monitoring using OGI and 

resurvey using Method 21.
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Although we identified OGI with semiannual monitoring as 

the BSER, we acknowledge that some states have promulgated rules 

that allow for annual monitoring of fugitive emission sources. 

In addition, EPA regulates GHGs in 40 CFR part 98 subpart W and 

requires annual fugitive emissions surveys for emissions 

reporting. As previously discussed we believe that we have 

underestimated our baseline fugitive emissions estimate for well 

sites and compressors and the emission reductions may be greater 

than we have estimated. However, because we continue to support 

efforts by states to establish fugitive emissions monitoring 

programs and to establish efficiencies across programs, we 

solicit comment on an alternate option for the fugitive emission 

monitoring program based on setting the initial monitoring 

frequency to an annual or quarterly frequency. 

CAA section 111(h)(1) states that the Administrator may 

promulgate a work practice standard or other requirements, which 

reflects the best technological system of continuous emission

reduction when it is not feasible to enforce an emission 

standard. CAA section 111(h)(2) defines the phrase “not feasible 

to prescribe or enforce an emission standard” as follows:

[A]ny situation in which the Administrator determines that 

(A) a hazardous air pollutant or pollutants cannot be 
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emitted through a conveyance designed and constructed to 

emit or capture such pollutant, or that any requirement 

for, or use of, such a conveyance would be inconsistent 

with any Federal, State, or local law, or (B) the

application of measurement methodology to a particular 

class of sources is not practicable due to technological 

and economic limitations.

The work practice standards for fugitive emissions from 

compressor stations are consistent with CAA section 

111(h)(1)(A), because no conveyance to capture fugitive 

emissions exist for fugitive emissions components. In addition, 

OGI does not measure the extent the fugitive emissions from 

fugitive emissions components. For the reasons stated above, 

pursuant to CAA section 111(h)(1)(b), we are proposing work 

practice standards for fugitive emissions from compressor 

stations.

The proposed work practice standards include details for 

development of a fugitive emissions monitoring plan, repair 

requirements and recordkeeping and reporting requirements. The 

fugitive emissions monitoring plan includes operating parameters 

to ensure consistent and effective operation for OGI such as 

procedures for determining the maximum viewing distance and wind 
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speed during monitoring. The proposed standards would require a 

source of fugitive emissions to be repaired or replaced as soon 

as practicable, but no later than 15 calendar days after 

detection of the fugitive emissions. We have historically 

allowed 15 days for repair/resurvey in LDAR programs, which 

appears to be sufficient time. Further, in light of the number 

of components at a compressor station and the number that would 

need to be repaired, we believe that 15 days is also sufficient 

for conducting the required repairs under the proposed fugitive 

emission standards. That said, we are also soliciting comment on 

whether 15 days is an appropriate amount of time for repair of 

sources of fugitive emissions at compressor stations.114

Many recent studies have shown a skewed distribution for 

emissions related to leaks, where a majority of emissions come 

from a minority of sources.115 Commenters on the white papers 

agreed that emissions from equipment leaks exhibit a skewed 

distribution, and pointed to other examples of data sets in 

which the majority of methane and VOC fugitive emissions come 

from a minority of components (e.g., gross emitters). Based on 

 

114 This timeline is consistent with the timeline originally 

established in 1983 under 40 CFR part 60 subpart VV. 115 See 2015 TSD.
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this information, we solicit comment on whether the fugitive 

emissions monitoring program should be limited to “gross 

emitters.” 

We believe that a properly maintained facility would likely 

detect very little to no fugitive emissions at each monitoring 

survey, while a poorly maintained facility would continue to 

detect fugitive emissions. We believe that a facility with 

proper operation would likely find one to five percent of 

components to have fugitive emissions. To encourage proper 

maintenance, we are proposing that the owner or operator may go 

to annual monitoring if the initial two consecutive semiannual 

monitoring surveys show that less than one percent of the 

collection of fugitive emissions components at the compressor 

station has fugitive emissions. For the same reason, we are 

proposing that the owner or operator conduct quarterly 

monitoring if the initial two semi-annual monitoring surveys 

show that more than five percent of the collection of fugitive 

emissions components at the compressor station has fugitive 

emissions. We believe the first year to be the tune-up year to 

allow owners and operators the opportunity to refine the 

requirements of their monitoring/repair plan. After that initial 

year, the required monitoring frequency would be annual if a 
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monitoring survey shows less than one percent of components to 

have fugitive emissions; semi-annual if one to five percent of 

total components have fugitive emissions; and quarterly if over 

five percent of total components have fugitive emissions. We 

solicit comment on this approach, including the percentage used 

to adjust the monitoring frequency. We also solicit comment on 

the appropriateness of performance based monitoring frequencies.

We also solicit comment on the appropriateness of triggering 

different monitoring frequencies based on the percentage of 

components with fugitive emissions. 

Under the proposed standards, the affected facility would 

be defined as the collection of fugitive emissions components at 

a compressor station. To clarify which components are subject to 

the fugitive emissions monitoring provisions, we propose to add 

a definition to §60.5430 for “fugitive emissions component” as 

follows:

Fugitive emissions component means any component that has 

the potential to emit fugitive emissions of methane or VOC

at a well site or compressor station site, including but 

not limited to valves, connectors, pressure relief devices, 

open-ended lines, access doors, flanges, closed vent 

systems, thief hatches or other openings on a storage 
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vessels, agitator seals, distance pieces, crankcase vents, 

blowdown vents, pump seals or diaphragms, compressors, 

separators, pressure vessels, dehydrators, heaters, 

instruments, and meters. Devices that vent as part of 

normal operations, such as a natural gas-driven pneumatic 

controller or a natural gas-driven pump, are not fugitive 

emissions components, insofar as the natural gas discharged 

from the device’s vent is not considered a fugitive 

emission. Emissions originating from other than the vent, 

such as the seals around the bellows of a diaphragm pump, 

would be considered fugitive emissions.

Thus, all fugitive emissions components at the affected 

facility would be monitored for fugitive emissions of methane

and VOC. 

For the reasons stated in section VII.G.2, for purposes of 

the proposed standards for fugitive emission at compressor 

stations, we propose that a modification occurs only when a 

compressor is added to the compressor station or when physical 

change is made to an existing compressor at a compressor station 

that increases the compression capacity of the compressor 

station. As explained in that section, since fugitive emissions 

at compressor stations are from compressors and their associated 
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piping, connections and other ancillary equipment, expansion of 

compression capacity at a compressor station, either through

addition of a compressor or physical change to the an existing 

compressor, would result in an increase in emissions to the 

fugitive emissions components. Other than these events, we are 

not aware of any other physical change to a compressor station 

that would result in an increase in emissions from the 

collection of fugitive components at such compressor station. To 

provide clarity and ease of implementation, for the purposes of 

the proposed standards for fugitive emissions at compressor 

stations, we are proposing to define modification as the 

addition of a compressor at an existing compressor station or 

when a physical change is made to an existing compressor at a 

compressor station that increases the compression capacity of 

the compressor station.

To encourage broadly applied fugitive emissions monitoring, 

we solicit comment on the whether new or modified compressor 

stations should not be affected facilities subject to the 

fugitive emission standards of the NSPS, if, at that time such

standards are promulgated, the owner or operator has a 

corporate-wide fugitive emissions monitoring plan in place and 

is implementing such a plan through legally and practically 
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enforceable requirements in an operating permit or other 

requirement established under a Federal, State, local or tribal 

authority that meets the NSPS standards, including the repair 

and recordkeeping requirements.

We are requesting comment on whether the fugitive emissions 

requirements should apply to all of the fugitive emissions 

sources at the compressor station for modified compressor 

stations or just to fugitive sources that are connected to the 

added compressor. For some modified compressor stations, the 

added compressor may only be connected to a subset of the 

fugitive emissions sources on site. We are soliciting comment on 

whether the fugitive emission requirements should only apply to 

that subset. However, we are aware that the added complexity of 

distinguishing covered and non-covered sources may create 

difficulty in implementing these requirements. However, we note 

that it may be advantageous to the operator from an operational 

perspective to monitor all the components at a compressor 

station since the monitoring equipment is already onsite.

As explained above, Method 21 is not as cost-effective as 

OGI for monitoring. That said, there may be reasons why and 

owner and operator may prefer to use Method 21 over OGI. While 

we are confident with the ability of Method 21 to detect 
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fugitive emissions and therefore consider it a viable 

alternative to OGI, we solicit comment on the appropriate 

fugitive emissions repair threshold for Method 21 monitoring 

surveys. As mentioned above, EPA’s recent work with OGI 

indicates that fugitive emissions at a concentration of 10,000 

ppm is generally detectable using OGI instrumentation provided 

that the right operating conditions (e.g., wind speed and 

background temperature) are present. Work is ongoing to 

determine the lowest concentration that can be reliably detected 

using OGI As mentioned above, we believe that OGI. In light of 

the above, we solicit comment on whether the fugitive emissions 

repair threshold for Method 21 surveys should be set at 10,000 

ppm or whether a different threshold is more appropriate 

(including information to support such threshold).

While we did not identify OGI as the BSER for resurvey 

because of the potential cost associated with rehiring OGI 

personnel, there is no such additional cost for those who either 

own the OGI instrument or can perform repair/resurvey at the 

same time. Therefore, the proposed rule would allow the use 

either OGI or Method 21 for resurvey. When Method 21 is used to 

resurvey components, we are proposing that the component is 

repaired if the Method 21 instrument indicates a concentration 
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of less than 500 ppm above background. This has been 

historically used in other LDAR programs as an indicator of no 

detectable emissions. 

The proposed standards would require that operators begin 

monitoring fugitive emissions components at compressor stations 

with 30 days of the initial startup of a new compressor station 

or within 30 days of a modification of a compressor station. We 

are proposing 30 day period to allow owners and operators the 

opportunity to secure qualified contractors and equipment 

necessary for the initial monitoring survey. We are requesting 

comment on whether 30 days is an appropriate amount of time to 

begin conducting fugitive emissions monitoring. 

We received new information indicating that some companies 

could experience logistical challenges with the availability of 

OGI instrumentation and qualified OGI personnel to perform 

monitoring surveys and in some instances repairs. We solicit 

comment on both the availability of OGI instruments and the 

availability of qualified OGI personnel to perform monitoring

surveys and repairs. 

We are requesting comment on whether there are other 

fugitive emission detection technologies for fugitive emissions 
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monitoring, since this is a field of emerging technology and 

major advances are expected in the near future. We are aware of 

several types of technologies that may be appropriate for 

fugitive emissions monitoring such as Geospatial Measurement of 

Air Pollutants using OTM-33 approaches (e.g., Picarro Surveyor), 

passive sorbent tubes using EPA Methods 325A and B, active 

sensors, gas cloud imaging (e.g., Rebellion photonics), and 

Airborne Differential Absorption Lidar (DIAL). Therefore, we are 

specifically requesting comments on details related to these and 

other technologies such as the detection capability; an 

equivalent fugitive emission repair threshold to what is 

required in the proposed rule for OGI; the frequency at which 

the fugitive emissions monitoring survey should be performed and 

how this frequency ensures appropriate levels of fugitive 

emissions detection; whether the technology can be used as a 

stand-alone technique or whether it must be used in conjunction 

with a less frequent (and how frequent) OGI monitoring survey; 

the type of restrictions necessary for optimal use; and the 

information that is important for inclusion in a monitoring plan 

for these technologies.

H. Proposed Standards for Equipment Leaks at Natural Gas 

Processing Plants
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In the 2012 NSPS, we established VOC standards for 

equipment leaks at onshore natural gas processing plants in the 

oil and natural gas source category. In this action, we are 

proposing methane standards for onshore natural gas processing 

plants. Based on the analysis below, the proposed methane 

standards are the same as the VOC standards currently in the 

NSPS.

Natural gas is primarily made up of methane. However, 

whether natural gas is associated gas from oil wells or nonassociated gas from gas or condensate wells, it commonly exists 

in mixtures with other hydrocarbons. These hydrocarbons are 

often referred to as natural gas liquids (NGL). They are sold

separately and have a variety of different uses. The raw natural 

gas often contains water vapor, H2S, CO2, helium, nitrogen and 

other compounds. Natural gas processing consists of separating

certain hydrocarbons and fluids from the natural gas to produced 

“pipeline quality” dry natural gas. While some of the processing 

can be accomplished in the production segment, the complete

processing of natural gas takes place in the natural gas 

processing segment. Natural gas processing operations separate 

and recover NGL or other nonmethane gases and liquids from a 

stream of produced natural gas through components performing one 
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or more of the following processes: oil and condensate 

separation, water removal, separation of NGL, sulfur and CO2

removal, fractionation of natural gas liquid and other 

processes, such as the capture of CO2 separated from natural gas 

streams for delivery outside the facility.

In the analysis for the 2012 NSPS, we estimated nationwide 

methane emissions from equipment leaks at onshore natural gas 

processing plants to be 51.4 tpy. We identified four control 

options for reducing methane emissions from these equipment 

leaks in the 2012 TSD: (1) subpart VVa level of control; (2) 

monthly survey using optical gas imaging (OGI) and an annual 

Method 21 survey; (3) monthly OGI survey without the annual 

Method 21 survey; and (4) annual OGI survey. 

In April 2014, the EPA published the white paper titled 

“Oil and Natural Gas Sector Leaks”116 which summarized the EPA’s 

current understanding of fugitive emissions of methane and VOC 

at onshore oil and natural gas production, processing, and 

transmission and storage facilities. The white paper also 

outlined our understanding of the available mitigation 

 

116 Available at 

http://www.epa.gov/airquality/oilandgas/2014papers/20140415leaks

.pdf. 
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techniques (practices and equipment) available to reduce these 

emissions along with the cost and effectiveness of these 

practices and technologies. Based on our review of the public 

and peer review comments on the white paper and our additional 

research, we did not identify any additional control options 

beyond those that we identified for the 2012 NSPS.

For purposes of this action, we have identified two 

approaches in section VIII.A for evaluating whether the cost of 

a multipollutant control, such as the leak detection and repair 

programs described above, is reasonable. As explained in that 

section above, we believe that both approaches are appropriate 

for assessing the reasonableness of the multipollutant controls 

considered in this action. Therefore, we find the cost of 

control to be reasonable as long as it is such under either of 

these two approaches.

Under the first approach (single pollutant approach), which 

assigns all costs to the reduction of one pollutant and zero to 

all other pollutants simultaneously reduced, we find the cost of 

control reasonable if it is reasonable for reducing one 

pollutant alone. The annualized costs for option 1 (subpart VVa 

level of control) is $45,160 without considering the cost 

savings of the recovered natural gas, and $33,915 considering 
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the cost savings. We estimate the cost of reducing methane 

emissions from equipment leaks at natural gas processing plants 

under this option to be $931 per ton. The annualized costs for 

option 2 (monthly survey using OGI and annual Method 21 survey)

is $87,059 without considering the cost savings of the recovered 

natural gas, and $75,813 considering the cost savings. We 

estimate the cost of reducing methane emissions from equipment 

leaks at natural gas processing plants under this option to be 

$1,795 per ton. At the time of the analysis for the 2012 NSPS, 

we were unable to estimate the methane emission reduction of 

options 3 (monthly OGI survey) and 4 (annual OGI survey-only 

programs) since OGI currently does not have the capability to 

quantify emissions. 

We find the costs for methane emission reductions for 

option 1 (subpart VVa level of control) to be reasonable for the 

amount of methane emissions it can achieve. Also, because all of 

the costs have been attributed to methane reduction, the cost of 

simultaneous VOC reduction is zero and therefore reasonable.117

 

117 In 2012 we already found that the cost of this control to be 

reasonable for reducing VOC emissions from natural gas 

processing plants. We are not reopening that decision in this 

action. 
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Although we propose to find the cost of control to be 

reasonable because it is reasonable under the above approach, we 

also evaluated the cost of option 1 (subpart VVa level of 

control) under the second approach (mutlipollutant approach). 

Under the second approach, we apportion the annualized cost 

across the pollutant reductions addressed by the control option 

in proportion to the relative percentage reduction of each 

pollutant controlled. In this case, since methane and VOC are 

controlled equally, half the cost is apportioned to the methane 

emission reductions and half the cost is apportioned to the VOC 

emission reductions. Under this approach, the costs are 

allocated based on the percentage reduction expected for each 

pollutant. Because option 1 (subpart VVa level of control)

reduces the fugitive emission of natural gas from equipment 

components, emissions of methane and VOC will be reduced 

equally. Therefore, we attribute 50 percent of the costs to 

methane reduction and 50 percent to VOC reduction. Based on this 

formulation, the costs for methane reduction are half of the 

estimated costs under the first approach above and are therefore 

reasonable.

With option 1 (subpart VVa level of control) there would be 

no secondary air impacts, therefore no impacts were assessed. 
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Also, we did not identify any nonair quality or energy impacts 

associated with this control technique, therefore no impacts 

were assessed.

In light of the above, we find that the BSER for reducing 

methane emissions from equipment leaks at natural gas processing 

plants is a leak detection and repair program at the subpart VVa 

level of control, and we are proposing to require such a program 

at natural gas processing plants. As described above, the 

proposed methane standard would be the same as the current VOC 

standard for natural gas processing plants in the NSPS.

I. Liquids Unloading Operations

Liquids unloading is an operation that is conducted at 

natural gas wells to remove accumulated liquids that can impede 

or even halt production of natural gas due to insufficient gas 

flow within the wellbore. Fluid accumulation is a common problem 

in both aging and newer natural gas wells. The typical industry 

practices used to accomplish liquids unloading include using 

plunger lifts, beam pumps, remedial treatments, or venting the 

well to atmosphere (also referred to as blowing down the well).

The emissions from liquids unloading result from the intentional 

venting of gas from the wellbore during activities conducted on 

or near equipment associated with the removal of accumulated 
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fluids. The volume of gas vented is presumed to be the total 

volume of gas in the casing and tubing minus the volume of water 

accumulated in the well. Wells can require multiple unloading 

events per year; however, the number and frequency of unloading 

events and volume of emissions generated vary widely. Some wells 

conduct liquids unloading without venting, through use of 

closed-loop systems and other technologies. 

Based on the information and data available to the EPA 

during development of the 2012 NSPS, the EPA conducted a 

preliminary screening of emissions sources with the goal of 

maximizing emission reductions for new sources. At the time, 

there was not sufficient data available to determine whether 

liquids unloading was an issue for hydraulically fractured 

wells, which represent the majority of projected future 

production and new sources. In petitions on the 2012 NSPS, some 

petitioners asserted that the EPA should have regulated the 

methane and VOC emissions from liquids unloading operations 

because these emissions are significant and there are data that 

demonstrate that cost-effective mitigation technologies are 

available to address the emissions. 

Data on liquids unloading operations supplied to the EPA 

subsequent to the 2012 rule finalization provided significantly 
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better insight into emissions from liquids unloading. Data were 

provided in a study conducted by members of the American 

Petroleum Institute (API) and America’s Natural Gas Alliance 

(ANGA) and published in a report titled “Characterizing Pivotal 

Sources of Methane Emissions from Natural Gas Production, 

Summary and Analysis of API and ANGA Survey Responses”, 

hereafter referred to the API/ANGA study, available in the 

docket. These data demonstrate that venting for liquids 

unloading can and does result in significant increases in 

emissions for the well in comparison to wells that do not vent 

for liquids unloading operations. In addition, data reported to 

the GHGRP show emissions from venting for liquids unloading 

similar in magnitude to those calculated using API/ANGA study 

data. 

The 2014 white paper on liquids unloading discussed the 

most recent information and data available for the analysis of 

emissions (including the API/ANGA survey and GHGRP data) and 

industry practices or control technologies available to address 

these emissions. Commenters on the white paper noted that 

venting for liquids unloading is a significant source of 

emissions and that these emissions are highly skewed, with a 

minority of sources being responsible for a large fraction of 
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total emissions. As a result, commenters urged the EPA to 

further study these operations and that regulation of those 

operations at this time would be premature. 

Since publication of the white paper, additional data have 

become available on liquids unloading emissions from Allen et 

al., 2014. The Allen et al. data confirm the findings of 

previous studies, that venting for liquids unloading is a 

significant source of emissions and that emissions are highly 

skewed. Data reviewed also show that liquids unloading events 

are highly variable and often well-specific. Furthermore, 

questions remain concerning the difficulty of effective control

for these high-emitting events in many cases and the 

applicability and limitations of specific control technologies 

such as plunger lift systems for supporting a new source 

performance standard. For analysis conducted in the development 

of this proposal, we revised our estimate of methane and VOC 

emissions from liquids unloading based on the API/ANGA study 

data and Allen et al. Based on the emissions data discussed in 

the white paper, and on new data available from Allen et al., we 

believe that the emissions from liquids unloading operations are 

significant. However, as noted in section VII.I, the EPA does 

not have sufficient information to propose standards for liquids 
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unloading. The EPA is continuing to study this issue and is 

soliciting information and data on control technologies or 

practices for reducing these emissions. 

Specifically, we are soliciting comment on the level of 

methane and VOC emissions per unloading event, the number of 

unloading events per year, and the number of wells that perform 

liquids unloading. In addition, we solicit comment on (1) 

characteristics of the well that play a role in the frequency of 

liquids unloading events and the level of emissions, (2) 

demonstrated techniques to reduce the emissions from liquids 

unloading events, including the use of smart automation, and the 

effectiveness and cost of these techniques, (3) whether there 

are demonstrated techniques that can be employed on new wells 

that will reduce the emissions from liquids unloading events in 

the future, and (4) whether emissions from liquids unloading can 

be captured and routed to a control device and whether this has 

been demonstrated in practice.

IX. Implementation Improvements

A. Storage Vessel Control Device Monitoring and Testing 

Provisions

We are proposing regulatory text changes that address 

performance testing and monitoring of control devices used for 
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new storage vessel installations and centrifugal compressor 

emissions, specifically relating to in-field performance testing 

of enclosed combustors. Industry reconsideration petitioners 

assert that the compliance demonstration and monitoring 

requirements finalized in the 2012 NSPS were overly complex and

stringent given the large number of affected storage vessels 

each year and the remoteness of the well sites at which they are 

installed. The petitioners argue that the well sites are 

unmanned for periods of time up to a month. The additional 

information provided by petitioners raised significant concerns

that the compliance monitoring provisions and field testing 

provisions of the 2012 NSPS may not have been appropriate for 

the large number of affected storage vessels, which was much 

greater than we had expected, and of which many are in remote

locations. 

In the reconsideration of the NSPS that was finalized in 

2013, we streamlined certain monitoring and continuous 

compliance demonstration requirements, while we more fully 

evaluated the proper requirements. Instead of the detailed 

Method 21 monitoring requirements, the revised requirements 

included monthly sensory (i.e., OVA) inspections of: (1) closedvent system joints, seams and other sealed connections (e.g., 
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welded joints); (2) other closed-vent system components such as 

peak pressure and vacuum valves; and (3) the physical integrity 

of tank thief hatches, covers, seals and pressure relief 

devices. Instead of the continuous parameter monitoring system 

(CPMS) requirements, the revised requirements included the

following inspection requirements: (1) monthly observation for 

visible smoke emissions employing section 11 of EPA Method 22 

for a 15 minute period; (2) monthly visual inspection of the

physical integrity of the control device; and (3) monthly check 

of the pilot flame and signs of improper operations. Lastly, 

instead of the field performance testing requirements in § 

60.5413, we required that, where controls are used to reduce

emissions, sources use control devices that by design can 

achieve 95 percent or more emission reduction and operate such 

devices according to the manufacturer’s instructions, procedures

and maintenance schedule, including appropriate sizing of the 

combustor for the application.

After evaluating these streamlined requirements and other 

potential options, we believe that performance testing of 

enclosed combustors is necessary to assure that they are 

achieving the required 95 percent control. However, petitioners

also assert that the previous performance testing requirements 
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were unreasonably strenuous for a control device needing to 

demonstrate 95 percent control efficiency. They assert that in 

order for an enclosed combustor to meet a requirement of 20 

parts per million volume (ppmv) it would have to be achieving 

greater than the required 95 percent control. After an 

evaluation of the requirement we agree with the comment and are 

proposing to revise this requirement from 20 ppmv to 600 ppmv; a 

value that more appropriately reflects 95 percent control of VOC 

inflow to these control devices. The EPA solicits comment on the 

appropriateness of this level of control and invites commenters 

to provide data that demonstrates the VOC composition of field 

gas from a variety of oil and gas field well sites across the 

nation.

As proposed, initial and ongoing performance testing will 

be required for any enclosed combustors used to comply with the 

emissions standard for an affected facility and whose make and 

model are not listed on the EPA Oil and Natural Gas Web site 

(http://www.epa.gov/airquality/oilandgas/implement.html) as 

those having already met a Manufacturer’s Performance Test 

demonstration. Performance testing of combustors not listed at 

the above site would also be conducted on an ongoing basis, 
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every 60 months of service, and monthly monitoring of visible 

emissions from each unit is also required.

We are proposing amendments to make the requirements for 

monitoring of visible emissions consistent for all enclosed

combustion units. Currently enclosed combustors that have met 

the Manufacturer’s Performance Test requirement must conduct 

quarterly observation for visible smoke emissions employing 

section 11 of EPA Method 22 for a 60 minute period. 40 CFR 

60.5413(e)(3). Certain petitioners have suggested it may ease 

implementation to adjust the frequency and duration to monthly 

15 minute EPA Method 22 tests, which is currently required for 

continuous monitoring of enclosed combustors that are not 

manufacturer tested. 40 CFR 60.5417(h)(1). If this change were 

made then all enclosed combustors would have the same monitoring 

requirements which could potentially make compliance easier for 

owners and operators. Because both monitoring requirements 

assure compliance of the enclosed combustors, and having the 

same requirement would ease implementation burden, we propose to

amend 40 CFR 60.5413(e)(3) to require monthly 15 minute-period 

observation using EPA Method 22 Test, as suggested by the 

petitioner. 

B. Other Improvements
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Following publication of the 2012 NSPS and the 2013 storage 

vessel amendments, we subsequently determined, following review 

of reconsideration petitions and discussions with affected 

parties, that the final rule warrants correction and

clarification in certain areas. Each of these areas is discussed 

below.

1. Initial Compliance Requirements for Bypass Devices

Initial compliance requirements in §60.5411(c)(3)(i)(A) for 

a bypass device that could divert an emission stream away from a 

control device were previously amended to allow for initiating a 

notification via remote alarm to the nearest field office 

indicating that the bypass device was activated. However, the 

previous amendments did not address parallel requirements for 

continuous compliance in § 60.5416. In order to maintain 

consistency with the previously amended §60.5411, we are 

proposing to amend §60.5416(c)(3)(i) to include notification via 

remote alarm to the nearest field office. We are proposing to 

require both an alarm at the bypass device and a remote alarm.

This is important in this source category due to the great 

number of unmanned sites, especially well sites. Previously, the 

only option was an alarm at the device location. We believe this

change will ensure that personnel will be alerted to a potential 
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uncontrolled emissions release whether they are in the vicinity 

of the bypass device when it is activated or at a remote 

monitoring location. Finally, we are proposing similar 

amendments to parallel requirements at §60.5411(a)(3)(i)(A) for 

closed vent systems used with reciprocating compressors and 

centrifugal compressor wet seal degassing systems.

2. Recordkeeping Requirements

Petitioners noted that the recordkeeping requirements of 

§60.5420(c) do not include the repair logs for control devices 

failing a visible emissions test required by §60.5413(c). We 

agree that these recordkeeping requirements should be listed and 

are proposing to add them at §60.5420(c)(14).

3. Due Date for Initial Annual Report

Petitioners pointed out that the preamble to the 2013 final 

rule stated that the initial annual report is due on January 15, 

2014; however, §60.5420(b) states that initial annual report is 

due 90 days after the end of the initial compliance period. The 

petitioners correctly contend that this equates to a due date of 

January 13, 2014. Although we inadvertently stated a date three 

months after the end of the initial compliance period (rather 

than 90 days after) in the preamble, we are not proposing to 

amend the rule at this time. Rather, we will consider any 
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initial annual report submitted no later than January 15, 2014 

to be a timely submission. All subsequent annual reports must be 

submitted by the correct date of January 13 of the year.

4. Flare Design and Operation Standards

The petitioners requested that the EPA clarify the 

regulatory compliance requirements for storage vessel affected 

facilities with respect to flares. Currently subpart OOOO 

contains conflicting references to the NSPS general provisions 

that obscures the EPA’s intent to require compliance with the 

requirements for the design and operation of flares under §60.18 

of the General Provisions. To clarify EPA’s intent, the EPA is 

proposing to remove the provision of Table 3 in subpart OOOO 

that exempts flares from complying with the requirements for the 

design and operation of flares under 40 CFR 60.18 of the General 

Provisions. By removing the exemption from the General 

Provisions from subpart OOOO, this clarifies that flares used to 

comply with subpart OOOO are subject to the design and operation 

requirements in the general provisions.

It has recently come to EPA’s attention that that there may 

be affected facilities which use pressure assisted-flares (e.g., 

sonic flares) to control emissions during periods of startup, 

shutdown, emergency and/or maintenance activities. While 
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compliance with the NSPS emission limits can be achieved using 

such flares, when designed and operated properly, it is EPA’s 

understanding that pressure-assisted flares cannot meet the 

maximum exit velocity of 400 feet per second as required by 40 

CFR 60.18(b). Pressure-assisted flares are designed to operate 

with a high velocities up to sonic velocity conditions (e.g., 

700 to 1,400 feet per second) for common hydrocarbon gases.

In order to evaluate the use of pressure-assisted flares by 

the oil and natural gas industry and determine whether to 

develop operating parameters for pressure-assisted flares for 

purposes of subparts OOOO (and subpart OOOOa should it be 

finalized), the EPA is soliciting comment on where in the source 

category, under what conditions (e.g., maintenance), and how 

frequently pressure-assisted flares are used to control 

emissions from an affected facility, as defined within this 

subpart. In addition, we request information on: (1) the 

importance of, and assessment of flame stability; (2) the 

importance of, and ranges of the heat content of flared gas; (3) 

the importance and ranges of gas pressure and flare tip 

pressure; (4) the importance of and examples of appropriate 

flare head design; (5) a cross-country review of waste gas 

composition; (6) and appropriate methodology to measure the 
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resultant flare destruction efficiency. The EPA also requests 

comment on the appropriate parameters to monitor to ensure 

continuous compliance. This information is critical for the 

potential development of operating parameters for pressureassisted flares given the limited to no information currently 

available for this type of flare in the oil and natural gas 

industry. 

5. Exemption to Notification Requirement for Reconstruction

The petitioners asked for the EPA to consider whether a 

single remaining notification of reconstruction required under 

§60.15(d) of the General Provisions was necessary, given that 

the EPA had already provided an exemption to parallel 

requirements for construction, startup, and modification. The

EPA agrees with the petitioner that the notification of 

reconstruction requirements under §60.15(d) is unnecessary. The 

EPA considers it unnecessary because subpart OOOO specifies

notification of reconstruction for affected unit pneumatic 

controllers, centrifugal compressors, and storage vessels under 

§60.5410 and §60.5420 in lieu of the general notification 

requirement in §60.15(d). The EPA, therefore, proposes to add in

Table 3 that §60.15(d) does not apply to affected facility 
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pneumatic controllers, centrifugal compressors, and storage 

vessels subject to subpart OOOO.

6. Disposal of Carbon from Control Devices

We are re-proposing the provisions for management of waste 

from spent carbon canisters that were finalized in

§60.5412(c)(2) of the 2012 NSPS to allow for comment. 

Petitioners assert that the requirements for RCRA-level 

management of waste from spent carbon canisters are unnecessary 

and overly burdensome. Further, they assert that those 

provisions were not in the proposal which excluded them from 

review and comment. We do not agree that these provisions are 

overly burdensome because RCRA hazardous waste units are not the 

only options made available to manage the spent carbon. In the 

scenario where the carbon is to be burned, the EPA sought a 

means to assure that sufficient precaution was taken to assure 

complete destruction of the carbon and adsorbed compounds.

These same requirements apply to spent carbon from units subject 

to NESHAP subpart HH in oil and natural gas production, further 

supporting our decision to seek consistent and appropriate 

levels of control for burning spent carbon from an adsorption 

system. We are re-proposing the provisions here to allow for 

review and comment. Petitioners may submit alternatives that 
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would allow for consistent treatment of spent carbon from the 

oil and natural gas sector, and that assure destruction of the 

compounds adsorbed in carbon adsorption control units.

7. Definition of Capital Expenditure

Petitioners requested that the EPA clarify the definition 

of “capital expenditure” in subpart OOOO. The term is used in 

section §60.5365(f), which describes the applicability of the 

equipment leaks provisions for onshore natural gas processing 

plants. Specifically, 40 CFR 60.5365(f)(1) states that “addition 

or replacement of equipment for the purpose of process 

improvement that is accomplished without a capital expenditure 

shall not by itself be considered a modification under this 

subpart.” Subpart OOOO does not define “capital expenditure” but 

states in 40 CFR 60.5430 (definition section) that “all terms 

not defined herein shall have the meaning given them in the Act, 

in subpart A or subpart VVa of part 60.” The term “capital 

expenditure” is defined in the General Provisions subpart A, as 

well as in subpart VVa. However, this definition in subpart VVa 

is currently stayed. The EPA agrees with the commenter that this 

capital expenditure approach applies to onshore natural gas 

processing plants that are subject to subpart OOOO. The EPA had 

previously adopted this method for determining modification in 
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subpart KKK. In fact, the capital expenditure provision in 

subpart OOOO, 40 CFR 60.5365(f)(1) was carried over from subpart 

KKK 40 CFR 60.630(c). Subpart KKK does not specifically define 

“capital expenditure;” it states in 40 CFR 60.631 that “as used 

in this subpart, all terms not defined herein shall have the 

meaning given them in the Act, in subpart A or subpart VV of 

part 60...” This means that the definition of capital expenditure 

in subpart KKK is the current definition in VV. 

In conducting the EPA’s 8-year review of subpart KKK, the 

EPA promulgated subpart OOOO, which includes certain revisions 

to subpart KKK. The EPA revised the existing NSPS requirements 

for LDAR to reflect the procedures and leak definition 

established by 40 CFR part 60, subpart VVa (77 FR 49498). 

Specifically, the revision to subpart KKK, which is codified in 

subpart OOOO, includes a lower leak definitions for valves and 

pumps and requires monitoring of connectors.

The EPA’s 8-year review and revision of subpart KKK did not 

include any change to the capital expenditure provision as it 

applies to oil and natural gas processing plants. This means 

that the technique used to determine whether there is a 

modification based on capital expenditure under OOOO remains the 
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same technique as in subpart KKK (i.e., based on the definition 

of “capital expenditure” in subpart VV). 

However, as the petitioner correctly noted, the year that 

is the basis for calculating Y (the percent of replacement cost) 

is designed to reflect the year of the proposed standards for 

the relevant subpart at issue; as such, the definition of 

“capital expenditure” in subpart VV does not reflect the year 

subpart OOOO was proposed (i.e., 2011) and is therefore 

inaccurate for application to subpart OOOO as is. To address 

this issue, the EPA is proposing to provide in subpart OOOO a 

definition for “capital expenditure” that essentially mirrors118

the definition in subpart VV but with the year revised to 

reflect the year subpart OOOO was proposed (i.e., 2011). 

The EPA disagrees with the petitioner that the appropriate 

applicable basic annual asset guideline repair allowance, 

designated “B” in the formula, is 12.5, which is the B value for 

Subpart VVa. Since “capital expenditure” method was not among 

the updates the EPA made in its review of the subpart KKK (and 

subpart OOOO is the updated version of KKK), the allowance in 

 

118 The proposed definition does not include B values listed in 

subpart VV for other subparts because those values are 

irrelevant to subpart OOOO.
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KKK (i.e., 4.5 according to subpart VV) remains applicable to 

onshore gas affected facilities. Further, B values are based on 

the annual asset guideline repair allowance specified in IRS 

Revenue Procedure 83-35. The specified allowance value is 4.5 

for exploration and production of petroleum and natural gas 

deposits. Also, as evident from the “capital expenditure” 

definitions in both subparts VV and VVa, the B values are 

subpart-specific and therefore the EPA has promulgated specific 

B values for different subparts. Whereas subpart VV includes a 

specific B value for natural gas processing plants covered by 

subpart KKK (natural gas processing plants), there is no such 

value in subpart VVa referencing subpart KKK. For the reasons 

stated above, the EPA clarifies that the B value for purposes of 

subpart OOOO is 4.5; it is not 12.5, as the petitioner suggests.

In sum, to provide clarity the EPA is proposing to 

specifically define the term “capital expenditure” in subpart 

OOOO. In this proposed definition, EPA is updating the formula 

to reflect the calendar year that subpart OOOO was proposed, as 

well as specifying that the B value for subpart OOOO is 4.5. 

These updates are necessary for proper calculation of capital 

expenditure under subpart OOOO.

8. Initial Compliance Clarification
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An issue was raised in an administrative petition that EPA 

did not adequately respond to a comment on the 2011 proposed 

NSPS regarding compliance period for the LDAR requirements for 

On-Shore Natural Gas Processing Plants. The comment at issue119

requested that EPA include in subpart OOOO a provision similar 

to subpart KKK, 40 CFR § 60.632(a), which allows a compliance 

period of up to 180 days after initial start-up. The commenter 

was “concerned that a modification at an existing facility or a 

subpart KKK regulated facility could subject the facility to 

Subpart OOOO LDAR requirements without adequate time to bring 

the whole process unit into compliance with the new 

regulation.” 120

We clarify that subpart OOOO, as promulgated in 2012, 

already includes a provision similar to subpart KKK, §60.632(a), 

as requested in the comment. Specifically, §60.5400(a) requires 

 

119 Comments of the Gas Processors Association Regarding the 

Proposed Rule, Oil and Natural Gas Sector: New Source 

Performance Standards and National Emission Standards for 

Hazardous Air Pollutants Reviews, 76 Fed. Reg. 52,738 (Aug. 23, 

2011). Pp. 3, 32-33. 120 Comments of the Gas Processors Association Regarding the 

Proposed Rule, Oil and Natural Gas Sector: New Source 

Performance Standards and National Emission Standards for 

Hazardous Air Pollutants Reviews, 76 Fed. Reg. 52,738 (Aug. 23, 

2011). Pp. 33.
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compliance with 40 CFR §60.482-1a (a), which provides that 

“[e]ach owner or operator subject to the provisions of this 

subpart shall demonstrate compliance ... within 180 days of 

initial startup.” This provision applies to all new, modified, 

and reconstructed sources. With respect to modification, which 

was of specific concern to the commenter, a change to a unit 

sufficient to trigger a modification and thus application of the 

subpart OOOO LDAR requirements for on-shore natural gas 

processing plants would be followed by startup, which would mark 

the beginning of the 180 day compliance period provided in 40 

CFR §60.482-1a (a) (incorporated by reference in subpart OOOO 

§60.5400(a)).

9. Tanks Associated with Water Recycling Operations

In many cases, flowback water from well completions and 

water produced during ongoing production is collected, treated 

and recycled to reduce the volume of potable water withdrawn

from wells or other sources. Large, non-earthen tanks are used 

to collect the water for recycling following separation to 

remove crude oil, condensate, intermediate hydrocarbon liquids

and natural gas. These collection tanks used for water recycling 

are very large vessels having capacities of 25,000 barrels or 

more, with annual throughput of millions of barrels of water. In 
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contrast, industry standard storage vessels commonly found in

well site tank batteries and used to contain crude oil, 

condensate, intermediate hydrocarbon liquids and produced water

typically have capacities in the 500 barrel range. 

In the 2012 NSPS, we had envisioned the storage vessel 

provisions as regulating the vessels in well site tank batteries 

and not these large tanks primarily used for water recycling. It 

was never our intent to cover these large water recycling tanks. 

It recently came to our attention that these water recycling 

tanks could be inadvertently subject to the NSPS due to the 

extremely low VOC content combined with the millions of barrels 

of throughput each year, which could result in a potential to 

emit VOC exceeding the NSPS storage vessel threshold of 6 tpy.121

The EPA encourages efforts on the part of owners and operators 

to maximize recycling of flowback and produced water. We are 

concerned that the inadvertent coverage of these tanks under the 

NSPS could discourage recycling. It is our understanding that, 

due to the size and throughput of these tanks, combined with the 

 

121 Letter from Obie O’Brien, Vice President – Government 

Affairs/Corporate Outreach, Apache Corporation, to EPA Docket, 

Docket ID Number EPA-HQ-OAR-2010-4755, April 20, 2015. Similar 

letters from Rockwater Energy Solutions (EPA-HQ-OAR-2010-4756) 

and Permian Basin Petroleum Association (EPA-HQ-OAR-2010-4757).
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trace amounts of VOC emissions that are difficult to control, 

that operators may choose to discontinue recycling to avoid 

noncompliance with the NSPS.

As a result, we are considering changes in the final rule 

to remove tanks that are used for water recycling from potential 

NSPS applicability. We solicit comment on approaches that could 

be taken to amend the definition of “storage vessel” or other 

changes to the NSPS that would resolve this issue without 

excluding storage vessels appropriately covered by the NSPS. In 

addition, we solicit comment on location, capacity or other 

criteria that would be appropriate for such purpose.

X. Next Generation Compliance and Rule Effectiveness

A. Independent Third-Party Verification

The EPA is taking comment on establishing a third-party 

verification program as discussed below. Third-party 

verification is when an independent third-party verifies to a 

regulator that a regulated entity is meeting one or more of its 

compliance obligations. The regulator retains the ultimate 

responsibility to monitor and enforce compliance but, as a 

practical matter, gives significant weight to the third-party 

verification provided in the context of a regulatory program 

with effective standards, procedures, transparency and 
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oversight. While requiring regulated entities to monitor and 

report should improve compliance by establishing minimum 

requirements for a regulated entity’s employees and managers, 

well-structured third-party compliance monitoring and reporting 

may further improve compliance. 

The third-party verification program would be designed to 

ensure that the third-party reviewers are competent, 

independent, and accredited, apply clear and objective criteria 

to their design plan reviews, and report appropriate information 

to regulators. Additionally, there would need to be mechanisms 

to ensure regular and effective oversight of third-party 

reviewers by the EPA and/or states which may include public 

disclosure of information concerning the third parties and their 

performance and determinations, such as licensing or 

registration. 

The EPA is considering a broad range of possible design 

features for such a program under the following two scenarios: 

A) Third-Party Verification of Closed Vent System Design and B) 

Third-Party Verification of IR Camera Fugitives Monitoring 

Program. These include those discussed or included in the 

following articles, rules, and programs:
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(1) Lesley K. McAllister, Regulation by Third-Party 

Verification, 53 B.C. L. REV. 1, 22-23 (2012);

(2) Lesley K. McAllister, THIRD-PARTY PROGRAMS FINAL REPORT 

(2012) (prepared for the Administrative Conference of the 

United States), available at 

http://www.acus.gov/report/third-party-programs-finalreport;

(3) Esther Duflo et al., Truth-Telling By Third-Party 

Auditors and the Response of Polluting Firms: Experimental 

Evidence From India, 128 Q. J. OF ECON. 4 at 1499-1545 

(2013);

(4) EPA CAA Renewable Fuel Standard (RFS) program: The RFS 

regulations include requirements for obligated parties to, 

in relevant part, submit independent third-party 

engineering reviews to the EPA before generating Renewable 

Identification Numbers (RINs).122

(5) Massachusetts Underground Storage Tank (UST) thirdparty inspection program: The owners/operators of most 

underground storage tanks in Massachusetts are required to 

have their USTs inspected by third-party inspectors every 

 

122 EPA, Renewable Fuel Standards (RFS), 

http://www.epa.gov/OTAQ/fuels/renewablefuels/.
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three years. While the third-party inspectors are hired 

directly by the tank owners and operators, they report to 

the Massachusetts Department of Environmental Protection 

(MassDEP). The third parties conduct and document detailed 

inspections of USTs and piping systems, review facility 

recordkeeping to ensure it meets UST program requirements, 

and submit reports on their findings electronically to 

MassDEP.123 

(6) Massachusetts licensed Hazardous Waste Site Cleanup 

Professional program: Private parties who are financially 

responsible under Massachusetts law for assessing and 

cleaning up confirmed and suspected hazardous waste sites 

must retain a licensed Hazardous Waste Site Cleanup 

Professional (commonly called a "Licensed Site 

Professional" or simply an "LSP") to oversee the assessment 

and cleanup work.124

We have identified one potential area for third-party 

verification under this rule. 

 

123 MassDEP, Third-Party Underground Storage Tank (UST) 

Inspection Program, 

http://www.mass.gov/eea/agencies/massdep/toxics/ust/third-partyust-inspection-program.html. 124 http://www.mass.gov/eea/agencies/massdep/cleanup/licensedsite-professionals.html.
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Professional Engineer Certification of Closed Vent System 

and Control Device Design and Installation

When produced liquids from oil and natural gas operations 

are routed from the separator to the condensate storage tank, a 

drop in pressure from operating pressure to atmospheric pressure 

occurs. This results in “flash emissions” as gases are liberated 

from the condensate stream due to the change in pressure. The 

magnitude of flash emissions can dwarf normal working and 

breathing losses of a storage tank. If the control system 

(closed vent system and control device, including pressure 

relief devices and thief hatches on storage vessels) cannot 

accommodate the peak instantaneous flow rate of flash emissions, 

working losses, breathing losses and any other additional 

vapors, this may cause pressure relief devices and thief hatches 

to “pop” and they may not properly reseat, resulting in 

immediate and potentially continuing excess emissions. Through 

our energy extraction enforcement initiative, we have seen this 

to be the case, due in large part to undersized control systems 

that may have been inadequately designed to accommodate only 

working and breathing losses of a storage tank. We have worked 

in conjunction with states, including Colorado, in conducting 

inspection campaigns associated with storage vessels. In two 
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inspection campaigns, in two different regions, we recorded 

venting from thief hatches or other parts of the control system 

at over 60 percent of the tank batteries inspected. Another 

inspection campaign resulted in a much higher leak rate, with of 

23 of 25 tank batteries experiencing fugitive emissions. 

One potential remedy for the inadequate design and sizing 

of the closed vent system would be to require an independent 

third-party (independent of the well site owner/operator and 

control device manufacturer), such as a professional engineer, 

to review the design and verify that it is designed to 

accommodate all emissions scenarios, including flash emissions 

episodes. Another element of the professional engineer 

verification could be that the professional engineer verifies 

that the control system is installed correctly and that the 

design criteria is properly utilized in the field.

Another approach to detecting overpressure in a closed vent 

system would be to require a continuous pressure monitoring 

device or system, located on the thief hatches, pressure relief 

devices and other bypasses from the closed vent system. Through 

our inspections, we have seen thief hatch pressure settings 

below the pressure settings of the storage tanks to which they 
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are affixed. This results in emissions escaping from the thief 

hatch and not making it to the control device. 

The EPA requests comment on these approaches. Specifically, 

we request comment as to whether we should specify criteria by 

which the PE verifies that the closed vent system is designed to 

accommodate all streams routed to the facility’s control system, 

or whether we might cite to current engineering codes that 

produce the same outcome. We also request comment as to what 

types of cost-effective pressure monitoring systems can be 

utilized to ensure that the pressure settings on relief devices 

is not lower than the operating pressure in the closed vent to 

the control device and what types of reporting from such systems 

should be required, such as through a supervisory control and 

data acquisition (SCADA) system. 

B. Fugitives Emissions Verification

As discussed in sections VII.G and VIII.G, the EPA is 

proposing the use of OGI as a low cost way to find leaks. While 

we believe we are proposing a robust method to ensure that OGI

surveys are done correctly, we have ample experience from our 

enhanced leak detection and repair (LDAR) efforts under our Air 

Toxics Enforcement Initiative, that even when methods are in 

place, routine monitoring for fugitives may not be as effective 
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in practice as in design. Similar to the audits included as part 

of consent decrees under the Initiative (See U.S. et. Al. v. BP 

Products North America Inc.), we are soliciting comment on an

audit program of the collection of fugitive emissions components 

at well sites and compressor stations.

For this rule, we are anticipating a structure in which the 

facilities themselves are responsible for determining and 

documenting that their auditors are competent and independent 

pursuant to specified criteria. The Agency seeks comment as to 

whether this approach is appropriate for the type of auditing we 

describe below, or whether an alternative approach, such as 

requiring auditors to have accreditation from a recognized 

auditing body or EPA, or other potentially relevant and 

applicable consensus standards and protocols (e.g., American 

National Standards Institute (ANSI), ASTM International (ASTM), 

European Committee for Standardization (CEM), International 

Organization for Standardization (ISO), and National Institute 

of Standards and Technology (NIST) standards), would be 

preferable. 

In order to ensure the competence and independence of the 

auditor, certain criteria should be met. Competence of the 

auditor can include safeguards such as licensing as a 
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Professional Engineer (PE), knowledge with the requirements of 

rule and the operation of monitoring equipment (e.g., optical 

gas imaging), experience with the facility type and processes 

being audited and the applicable recognized and generally 

accepted good engineering practices, and training or 

certification in auditing techniques. 

Independence of the auditor can be ensured by provisions 

and safeguards in the contracts and relationships between the 

owner and operator of the affected facility with auditors. 

These can include: the auditor and its personnel must not have 

conducted past research, development, design, construction 

services, or consulting for the owner or operator within the 

last 3 years; the auditor and its personnel must not provide 

other business or consulting services to the owner or operator, 

including advice or assistance to implement the findings or 

recommendations in the Audit report, for a period of at least 3 

years following the Auditor’s submittal of the final Audit 

report; and all auditor personnel who conduct or otherwise 

participate in the audit must sign and date a conflict of 

interest statement attesting the personnel have met and followed 

the auditors’ policies and procedures for competence, 

impartiality, judgment, and operational integrity when auditing 
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under this section; and must receive no financial benefit from 

the outcome of the Audit, apart from payment for the auditing 

services themselves. In addition, owners or operators cannot 

provide future employment to any of the auditor’s personnel who 

conducted or otherwise participated in the Audit for a period of 

at least 3 years following the Auditor’s submittal of its final 

Audit report and must be empowered to direct their auditors to 

produce copies of any of the audit-related reports and records 

specified in those sections. Both the owners and operators and 

their auditors should sign supporting certifications statements.

To further minimize audit bias, an audit structure might require 

that audit report drafts and final audit reports be submitted to 

EPA at the same time, or before, they are provided to the owners 

and operators. Furthermore, the audits conducted by the auditors 

under this rule should not be claimed as a confidential attorney 

work products even if the auditors are themselves, or managed by 

or report to, attorneys.

 There may be other options, in addition to the approaches 

above, that may increase owner or operator flexibility, but 

these options also present risks of introducing bias into the 

program, resulting in less robust and effective audit reports. 

EPA invites comment on the structure above as well as 
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alternative auditor/auditing approaches with less rigorous 

independence criteria. For example, EPA could, in the final 

rule, allow for audits to be performed by auditors with some 

potential conflicts of interest (e.g., employees of parent 

company, affiliates, vendors/contractors that participated in 

developing source master plan(s) and/or site-specific plan(s),

etc.) and/or allow a person at the facility itself who is a 

registered PE or who has the requisite training in conducting 

optical gas imaging monitoring to conduct the audit. If such 

approaches are adopted in the final rule, the Agency could seek 

to place appropriate restrictions on auditors and auditing with 

less than full independence from their client facilities in an 

effort to increase confidence that the auditors will act 

accurately when performing their activities under the rule. 

Such provisions could include ones addressed to ensuring that 

auditor personnel who assess a facility’s compliance with the 

fugitives monitoring requirements do not receive any financial 

benefit from the outcome of their auditing decisions, apart from 

their basic salaries or remuneration for having conducted the 

audits.

Additional examples of the types of restrictions that could 

be placed on such self-auditing to potentially improve auditor 
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impartiality and auditing outcomes appear in the U.S. and CARB 

v. Hyundai Motor Company, et al. Consent Decree (CD). Until the 

CDs corrective measures are fully implemented, the defendants 

must audit their fleets to ensure that vehicles sold to the 

public conform to the vehicles’ certification. The CD provides 

that the audit team will be in the United States, will be 

independent from the group that performed the original 

certification work, and must perform their audits without access 

to or knowledge of the defendants’ original certification test 

data which the CD-required audits are intended to backcheck. 

EPA seeks comment as to whether similar restrictions could be 

effective for any potential enhanced self-auditing conducted 

under the rule. 

Finally, EPA seeks comment on whether, and to what extent, 

the public should have access to the compliance reports, 

portions or summaries of them and/or any other information or 

documentation produced pursuant to the auditing provisions. EPA 

is also considering the approach it should take to balance

public access to the audits and the need to protect Confidential 

Business Information (CBI). To balance these potentially 

competing interests, EPA is reviewing a variety of approaches 

that may include limiting public access to portions of the 
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audits and/or posting public audit grades or scores to inform 

the public of the auditing outcomes without compromising 

confidential or sensitive information. EPA seeks comment on 

these transparency and public access to information issues in 

the context of the proposed auditing provisions. 

A suggested structure which incorporates concepts from the 

discussion above, and relevant to an audit of the fugitives 

monitoring program of the collection of fugitive emissions 

components at well sites and compressor stations could include 

the following structure:

Within the first year of applicability to the rule, an OGI 

trained auditor, experienced with the facility type and 

processes being audited and the applicable recognized and 

generally accepted good engineering practices, and trained or 

certified in auditing techniques, and who has not:

a. served as a fugitive emissions monitoring technician at 

the source,

b. conducted past research, development, design, 

construction services, or consulting for the owner or 

operator within the last 3 years or; 

c. provided other business or consulting services to the 

owner or operator, including advice or assistance to 
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implement the findings or recommendations in the Audit 

report, for a period of at least 3 years following the 

Auditor’s submittal of the final Audit report;

shall:

a. Verify that the source has established a master and site 

specific monitoring plan;

b. Verify that the master and site specific monitoring plan 

includes the elements described in the rule;

c. Verify that the fugitive components were monitored in 

accordance with the master and site specific monitoring 

plan and at the appropriate frequency under the plan(s) and 

the rule;

d. Verify that proper documentation and sign offs have 

been recorded for all fugitive components placed on the 

delay of repair list;

e. Ensure that repairs have been performed in the 

required periods under the rule;

f. Review monitoring data for feasibility (e.g., do the 

survey results reflect a feasible timeframe in which to 

conduct the monitoring survey) and unusual trends;
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g. Verify that proper calibration records and monitoring 

instrument maintenance information are maintained;

h. Verify that other fugitives emissions monitoring

records are maintained as required; and

i. Observe in the field each technician who is conducting 

fugitive emissions monitoring to ensure that monitoring is 

being conducted as described in the rule and the master and 

site specific plan;

j. Submit a report to the EPA and the facility outlining 

the findings of the audit with deficiencies and corrective 

actions provided.

k. Sign a certification statement that the report was 

prepared by the auditor conducting the audit (or under 

his/her direction or supervision), that the report is true, 

accurate, and complete, that the Audit was prepared 

pursuant to, and meets the requirements of, 40 CFR Part 60 

subpart OOOOa, and any other applicable auditing, 

competency, and independence/impartiality/conflict of 

interest standards and protocols. 

Upon the receipt of the auditor’s report, the source should 

correct any deficiencies detected or observed within four 

months. The source would be required to maintain a record that: 
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(i) records the auditor’s report; and (ii) describes the nature 

and timing of any corrective actions taken. The source would be 

required to submit in their periodic compliance report, a 

summary of the findings of the auditor’s report and a 

description and timing of any corrective actions taken. EPA 

envisions that the audit would be repeated with some frequency 

and requests comment on the appropriate frequency, and any 

actions, trends or compliance triggers which might require or 

allow deviation from the frequency. 

C. Third-Party Information Reporting

Third-party information reporting occurs when a third-party

reports information on a regulated source’s performance, 

directly to the regulator. To promote improved compliance, 

third-party information reporting reduces information 

asymmetries between what the regulated entities know about 

themselves and the regulators’ knowledge about the entities. 

An example of third-party information reporting involves 

federal income tax law where certain income must be 

independently reported to the Internal Revenue Service (IRS) by 

payers of the income. Because the information is required to be 

identical to that reported by taxpayers, the government can 
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compare the dual disclosures for consistency. Taxpayers know 

this and are deterred from failing to report or underreporting. 

 We outlined a potential third-party information reporting 

structure for oil and natural gas in our 2013 proposed 

amendments. We continue to believe that application of such a 

reporting structure is a natural outgrowth for implementation of 

the manufacturer performance testing requirements under subpart

OOOO and subparts HH/HHH. As previously discussed in the 2013 

proposal, an owner or operator that purchases a specific model 

of control device that the manufacturer has demonstrated 

achieves the combustion control device performance requirements 

in NSPS subpart OOOO (a “listed device”) is exempt from 

conducting their own performance test and submitting performance 

test results. To provide further incentive to use such a listed 

device, the EPA can “level the playing field” by ensuring that 

exemption claims are valid. Using the framework of third-party 

information reporting, the owner or operator would demonstrate 

initial compliance by providing proof of purchase of the listed 

device, reporting certain information, such as device model, 

serial number, geospatial coordinates and date of installation 

in their annual report following the end of the compliance 

period during which the device was installed. In the final rule, 
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the EPA could conceivably supplement the owner/operator 

reporting requirement with a manufacturer reporting requirement 

providing the names of entities that had purchased the listed 

device. The manufacturer report to the EPA could be very simple, 

such as a “notice and go” or “post card” type report. This could 

allow a simple cross check of the owner’s or operator’s report 

with the manufacturer’s sales confirmation, making compliance 

checks easy and provide assurance to the Agency that the source 

has in fact purchased and installed a manufacturer performance 

tested device, improving compliance with the rule.

As noted above, we have currently evaluated and posted 15

enclosed combustor models, allaying concerns that it would take 

“years of work” to avoid compliance complications with the 

process. The EPA continues to encourage the option to use listed 

devices and believe that operators have an incentive to do so, 

in lessened initial and on-going compliance demonstration costs. 

Third-party information reporting could lessen any lingering 

concerns with implementation and potential compliance 

complications. However, we understand the issues for this 

sector, with making the “postcard” model work as we envisioned. 

One of the issues is related to the granularity of the reporting 

by the manufacturer as compared to the reporting by the source 
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to the EPA or delegated authority. For example, the manufacturer 

may only know that they sold 500 units of a particular control 

device, but may not know where it is actually installed. Lack of 

a unique “user ID” being reported by both sides can limit the 

utility of the postcard model in this instance. We solicit 

comment on potential third-party approaches such as the “post 

card” reporting described above that could be implemented to 

streamline and enhance compliance.

As stated above, a primary concern is that an owner or 

operator would install a control device, and not conduct a 

performance test, claiming that they installed a device listed 

on the Oil and Gas page. We believe that we can build on the 

success of GIS imbedded digital photos for green completions 

(“REC PIX”), already in the rule, by developing a similar 

requirement for installed manufacturer tested control devices. 

Enhancing the records and reports by requiring specifics of the 

control device (make, model and serial number) and requiring the 

digital picture, will allow us to match a particular control 

device at a specific location with control device models listed 

on the Oil and Gas page.125 Having this information 

 

125 see www.epa.gov/oilandgas
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electronically reported to CEDRI will further enhance our 

ability to evaluate compliance with the rule.

While we are soliciting comment on third-party reporting by 

combustor vendors directly to the EPA, we propose to require 

that owners or operators include information regarding purchase 

of a pre-tested combustor model in their Notice of Compliance 

Status as part of the first annual report following the 

compliance period in which the combustor commences operation. 

The information would include (1) make, model and serial number 

of the purchased device; (2) date of purchase; (3) inlet gas 

flow rate; (4) latitude and longitude of the emission source 

being controlled by the combustor; (5) digital GIS and date 

stamp-imbedded photo of the combustor once it is installed; and 

(6) certification of continuous compliance. The owner or 

operator would be required to submit information to CEDRI in 

lieu of a field performance test.

D. Electronic Reporting and Transparency

1. Include Robust Federal Reporting with Easy Access to 

Information

We have the opportunity to expand transparency by making 

the information we have today more accessible, and making new 

information, obtained from advanced emissions monitoring and 
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electronic reporting, publicly available. This approach will 

empower communities to play an active role in compliance 

oversight and improve the performance of both the government and 

regulated entities. On September 30, 2013, the EPA established 

that the default assumption for all new EPA rules is to use ereporting, absent a compelling reason to use paper reporting.126 

Current reporting requirements in most rules and permits direct 

regulated entities to submit paper reports and forms to the EPA, 

states, and tribes. Under electronic, or e-reporting, paper 

reporting is replaced by standardized, Internet-based, 

electronic reporting to a central repository using specifically 

developed forms, templates and tools. E-reporting is not simply 

a regulated entity emailing an electronic copy of a document 

(e.g., a PDF file) to the government, but also a means to make 

collected information easily accessible to the public and other 

stakeholders.

On March 20, 2015, the EPA proposed the “Electronic 

Reporting and Recordkeeping Requirements for New Source 

Performance Standards” (80 FR 15099, March 20, 2015). If 

adopted, the rule would revise the part 60 General Provisions 

 

126 EPA, Policy Statement on E-Reporting in EPA Regulations 

(September 30, 2013).
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and various NSPS subparts in part 60 of title 40 of the Code of 

Federal Regulations (CFR) to require affected facilities to 

submit specified air emissions data reports to the EPA 

electronically and to allow affected facilities to maintain 

electronic records of these reports. This proposed rule focuses 

on the submission of electronic reports to the EPA that provide 

direct measures of air emissions data such as summary reports, 

excess emission reports, performance test reports and 

performance evaluation reports. 

Subpart OOOO is one of the rules potentially affected by 

this rulemaking. When promulgated, §60.5420(c)(9) would be 

amended to require the submittal of reports to the EPA via the 

CEDRI. (CEDRI can be accessed through the EPA’s CDX 

(https://cdx.epa.gov/).) The owner or operator would be required 

to use the appropriate electronic report in CEDRI for this 

subpart or an alternate electronic file format consistent with 

the extensible markup language (XML) schema listed on the CEDRI 

Web site (http://www.epa.gov/ttn/chief/cedri/index.html). If the 

reporting form specific to this subpart is not available in 

CEDRI at the time that the report is due, the owner or operator

would submit the report to the Administrator at the appropriate 

address listed in §60.4 of the General Provisions. The owner or 
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operator must begin submitting reports via CEDRI no later than 

90 days after the form becomes available in CEDRI. The EPA is 

currently working to develop the form for subpart OOOO. 

2. Potential to Enhance Public Transparency through Web site 

Posting on Company Maintained Web site

The public disclosure of compliance information by 

regulated entities to customers, ratepayers, or stakeholders has 

been shown to reduce pollution and improve compliance. This 

disclosure will empower communities and other stakeholders to 

play an active role in compliance oversight and improve the 

performance of both the government and regulated entities. A 

study of the Safe Drinking Water Act’s (SDWA) Consumer 

Confidence Reports (CCR) requirements linked direct disclosures 

of compliance information to drinking water customers to 

statistically significant compliance improvements and reduced 

pollution.127 Additional studies have linked public information 

 

127 Lori S. Bennear and Sheila M. Olmstead, Impacts of the “Right 

to Know”: Information Disclosure and the Violation of Drinking 

Water Standards, 56 J. ENVT’L ECON. & MGMT. 117 (2008) (finding 

that when larger utilities were required to mail annual Consumer 

Confidence Reports on water-supplier compliance pursuant to the 

1998 Safe Drinking Water Act amendments, those utilities’ total 

violations were reduced by 30-44% and more severe health 

violations by 40-57%). 
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disclosure to pollution reductions128, improved water pollution 

control practices,129 reduced air emissions and improved 

environmental regulatory compliance,130 and health and safety 

improvements in the automobile and restaurant markets. 

 

128 Using a micro-level data set linking Toxic Release Inventory 

(TRI) releases to plant-level Census data, one researcher found, 

among other things, that state and local government use of TRI 

disclosures helped induce firms to become cleaner. Linda T.M. 

Bui, Public Disclosure of Private Information as a Tool for 

Regulating Environmental Emissions: Firm-Level Responses by 

Petroleum Refineries to the Toxics Release Inventory (Brandeis 

Univ. Working Paper Series, Working Paper No. 05-13, 2005), 

available at ftp://ftp2.census.gov/ces/wp/2005/CES-WP-05-13.pdf. 

See also, Shameek Komar & Mark A. Cohen, Information As 

Regulation: The Effect of Community Right to Know Laws on Toxic 

Emissions, 32 J. ENVT’L ECON. & MGMT. 109 (1997), available at 

http://www.sciencedirect.com/science/article/pii/S00950696969095

59 (finding that the top 40 firms with the largest drop in stock 

price following their disclosure of TRI emissions subsequently 

reduced their average emissions more than other firms in their 

industry, including the top 40 firms with the largest TRI 

emissions per thousand dollars in revenue [TRI/$]; these firms 

both significantly reduced their average emissions and made 

significant attempts to improve their environmental performance 

by reducing the frequency and severity of chemical and oil 

spills). 

129 DAVID WHEELER, WORLD BANK REPORT NO. 16513-BR, INFORMATION IN 

POLLUTION MANAGEMENT: THE NEW MODEL 14 (1997), available at 

http://web.worldbank.org/archive/website01004/WEB/IMAGES/BRAZILI

N.PDF (finding that Indonesia’s Program for Pollution Control, 

Evaluation and Rating improved the studied facilities’ ratings 

pursuant to a color-coded scheme). 130 In 1990, the Ministry of Environment, Lands and Parks of 

British Columbia, Canada (MOE) employed a public disclosure 

strategy releasing a list of industrial operations that were not 

in compliance with their waste management permits or were deemed 

to be a potential pollution concern. Simultaneously, the 
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A 2014 study specific to the oil and natural gas industry131

relied solely on publicly available information that companies 

provide on their web sites, or in publicly released financial 

statements or other reports linked from their web sites. The 

report focused on promoting improved operational practices among 

oil and natural gas companies engaged in horizontal drilling and 

hydraulic fracturing. According to the report, “[f]ollowing the 

maxim of what gets measured, gets managed,” this report 

encourages oil and natural gas companies to increase disclosures 

about their use of current best practices to minimize the 

environmental risks and community impacts of their “fracking” 

activities. A key finding of the report was that across the 

industry, “companies are failing to provide investors and other 

 

Government of British Columbia introduced revised regulations to 

its pulp and paper regulations setting stricter standards and 

also increasing the maximum amount of fines under the Waste 

Management Act. Results indicated that the public disclosure 

strategy had a larger impact on both emissions levels and 

compliance status than traditional enforcement strategies, 

including fines, orders, and penalties. The results also 

indicated that the adoption of stricter standards and higher 

penalties also had a significant impact on decreasing emissions 

levels. Jérôme Foulon et al., Incentives for Pollution Control: 

Regulation and Public Disclosure 5 (World Bank Pol’y Res., 

Working Paper No. 2291, 2000), available at 

http://papers.ssrn.com/sol3/papers.cfm?abstract_id=629138. 131 Richard Liroff, D. F. (2014). Disclosing the Facts: 

Transparency and Risk in Hydraulic Fracturing.
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key stakeholders with quantitative, play-by-play disclosure of 

operational impacts and best management practices” (while noting 

an increase in any level of reporting over 2013). 

The EPA solicits comment on requiring owners and operators 

of affected facilities to report quantitative environmental 

results on their corporate maintained web sites. Such results 

might include monitoring data (including fugitives), 

quantification of excess emissions and corrective actions, 

results of performance tests, affected facility status with 

respect to a standard contained in a rule, and third-party 

certifications. The EPA requests comment on whether all owner 

and operators should be required to do this, or only a subset 

(e.g., based on size of entity, complexity or number of 

operations, web presence, etc.) and what data we should require 

them to report; keeping in mind that monitoring and reporting 

requirements that may be sufficient for government regulators 

may be insufficient for the public. Government regulators may be 

satisfied with a regulation that requires a facility to monitor 

specified parameters (e.g., operating temperature) to generally 

assure that the facility is operating properly, and to perform a 

formal compliance test (e.g., measuring actual smokestack 

emissions) only upon the government’s request. 
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3. Potential to Promote Advances in Data Capture (e.g., 

“Check-in App” with location and photos)

One of the advances of the digital age is the ability to 

“check-in” with geospatial accuracy at any location. For 

example, in the 2012 NSPS, we provided a mechanism by which 

owners and operators could streamline annual reporting of well 

completions by using a digital camera to document that a well 

completion was performed in compliance with the NSPS. In lieu of 

submitting voluminous hard copies of well completion records in 

their annual report, the owner or operator could document the 

completions with a digital photograph of the REC equipment in 

use, with the date and geospatial coordinates shown on the 

photographs. These photographs would be submitted digitally or 

in hard copy form with the next annual report, along with a list 

of well completions performed with identifying information for 

each well completed. This option has been referred to as “REC 

PIX.” Building on the success of REC PIX, the EPA would like to 

explore this opportunity as it relates to advances in data 

capture to ensure that other compliant practices are in effect. 

For example, pictures of storage vessels could provide visual 

evidence of staining related to excess emissions events. As 

discussed previously, digital pictures and frame captures can 
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help ensure that optical gas imaging for fugitive emissions is 

being performed properly. The EPA requests comments on viability 

and benefits of this approach, and to which areas it might be 

expanded.

XI. Impacts of This Proposed Rule

A. What are the air impacts?

For this action, the EPA estimated the emission reductions 

that will occur due to the implementation of the proposed

emission limits. The EPA estimated emission reductions based on 

the control technologies proposed as the BSER. This analysis 

estimates regulatory impacts for the analysis years of 2020 and 

2025. The analysis of 2020 is assumed to represent the first 

year the full suite of proposed standards is in effect and thus 

represents a single year of potential impacts. We estimate 

impacts in 2025 to illustrate how new and modified sources 

accumulate over time under the proposed NSPS. The regulatory 

impact estimates for 2025 include sources newly affected in 2025 

as well as the accumulation of affected sources from 2020 to 

2024 that are also assumed to be in continued operation in 2025, 

thus incurring compliance costs and emissions reductions in 

2025. 
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While the EPA is proposing an exclusion from fugitive 

emission requirements for low production well sites, there is 

uncertainty in how many well sites this exclusion might affect 

in the future. As a result, the analyses in this RIA presents a 

“low” impact case and “high” impact case for fugitive emissions 

requirements at well sites. The low impact case excludes from 

analysis an estimate low production sites, based on the first 

month of production data from wells newly completed or modified 

in 2012. The high impact case includes these well sites. 

National-level results for the proposed NSPS, then, are 

presented as ranges.

In 2020, we have estimated that the proposed NSPS would 

reduce about 170,000 to 180,000 tons of methane emissions and 

120,000 tons of VOC emissions from affected facilities. In 2025, 

we have estimated that the proposed NSPS would reduce about

340,000 to 400,000 tons of methane emissions and 170,000 to

180,000 tons of VOC emissions from affected facilities. The NSPS 

is also expected to concurrently reduce about 310 to 400 tons 

HAP in 2020 and 1,900 to 2,500 tons HAP in 2025. 

As described in the TSD and RIA for this proposal, the EPA 

projected affected facilities using a combination of historical 

data from the U.S. GHG Inventory, and projected activity levels, 
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taken from the Energy Information Administration (EIA’s) Annual 

Energy Outlook (AEO). The EPA also considered state regulations 

with similar requirements to the proposed NSPS in projecting 

affected sources for impacts analysis supporting this proposed 

rule. The EPA solicits comments on these projection methods as 

well as solicits information that would improve our estimate of 

the turnover rates and rates of modification of relevant sources

and the number of wells on multi-well well sites.

B. What are the energy impacts?

Energy impacts in this section are those energy 

requirements associated with the operation of emission control 

devices. Potential impacts on the national energy economy from 

the rule are discussed in the economic impacts section. There 

would be little national energy demand increase from the 

operation of any of the environmental controls proposed in this 

action.

The proposed NSPS encourages the use of emission controls 

that recover hydrocarbon products, such as methane that can be 

used on-site as fuel or reprocessed within the production 

process for sale. We estimated that the proposed standards will 

result in a total cost of about $150 to $170 million in 2020 and

$320 to $420 million in 2025 (in 2012 dollars).
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C. What are the compliance costs?

The EPA estimates the total capital cost of the proposed 

NSPS will be $170 to $180 million in 2020 and $280 to $330

million in 2025. The estimate of total annualized engineering 

costs of the proposed NSPS is $180 to $200 million in 2020 and 

$370 to $500 million in 2025. This annual cost estimate includes 

the cost of capital, operating and maintenance costs, and 

monitoring, reporting, and recordkeeping costs. This estimated 

annual cost does not take into account any producer revenues 

associated with the recovery of salable natural gas. The EPA 

estimates that about 8.2 million Mcf in 2020 and 16 to 19 

million Mcf of natural gas in 2025 will be recovered by 

implementing the proposed NSPS. In the engineering cost 

analysis, we assume that producers are paid $4 per thousand 

cubic feet (Mcf) for the recovered gas at the wellhead. After 

accounting for these revenues, the estimate of total annualized 

engineering costs of the proposed NSPS are estimated to be $150 

to $170 million in 2020 and $320 to $420 million in 2025. The 

price assumption is influential on estimated annualized 

engineering costs. A simple sensitivity analysis indicates 

$1/Mcf change in the wellhead price causes a change in estimated 
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engineering compliance costs of about $8.2 million in 2020 and

$16 to $19 million in 2025.

D. What are the economic and employment impacts?

The EPA used the National Energy Modeling System (NEMS) to 

estimate the impacts of the proposed rule on the United States 

energy system. The NEMS is a publically-available model of the 

United States energy economy developed and maintained by the 

Energy Information Administration of the DOE and is used to 

produce the Annual Energy Outlook, a reference publication that 

provides detailed forecasts of the United States energy economy. 

The EPA modeled the high impact case of the proposed 

NSPS with respect the low production exemption from the well 

site fugitive emissions requirements. As such the NEMS-based 

estimates of energy system impacts are likely high end 

estimates. 

The NEMS-based analysis estimates natural gas and crude oil 

production levels remain essentially unchanged under the 

proposed rule in 2020, while slight declines are estimated for 

2020 for both natural gas (about 4 billion cubic feet (bcf) or 

about 0.01 percent) and crude oil production (about 2,000 

barrels per day or 0.03 percent). Wellhead natural gas prices 

for onshore lower 48 production are not estimated to change in 
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2020 under the proposed rule, but are estimated to increase 

about $0.007 per Mcf or 0.14 percent in 2025. Meanwhile, well 

crude oil prices for onshore lower 48 production are not 

estimated to change, despite the incidence of new compliance 

costs from the proposed NSPS. Meanwhile, net imports of natural 

gas are estimated to decline slightly in 2020 (by about 1 bcf or 

0.05 percent) and in 2025 (by about 3 bcf or 0.09 percent). 

Crude oil imports are estimated to not change in 2020 and 

increase by about 1,000 barrels per day (or 0.02 percent) in 

2025.

Executive Order 13563 directs federal agencies to consider 

the effect of regulations on job creation and employment. 

According to the Executive Order, “our regulatory system must 

protect public health, welfare, safety, and our environment 

while promoting economic growth, innovation, competitiveness, 

and job creation. It must be based on the best available 

science.” (Executive Order 13563, 2011) Although standard 

benefit-cost analyses have not typically included a separate 

analysis of regulation-induced employment impacts, we typically 

conduct employment analyses. During the current economic 

recovery, employment impacts are of particular concern and 

questions may arise about their existence and magnitude. 
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EPA estimated the labor impacts due to the installation, 

operation, and maintenance of control equipment, control 

activities, and labor associated with new reporting and 

recordkeeping requirements. We estimated up-front and continual, 

annual labor requirements by estimating hours of labor required 

for compliance and converting this number to full-time 

equivalents (FTEs) by dividing by 2,080 (40 hours per week 

multiplied by 52 weeks). The up-front labor requirement to 

comply with the proposed NSPS is estimated at about 50 to 70

FTEs in 2020 and 50 to 70 FTEs in 2025. The annual labor 

requirement to comply with proposed NSPS is estimated at about 

470 to 530 FTEs in 2020 and 1,100 to 1,400 FTEs in 2025.

We note that this type of FTE estimate cannot be used to 

identify the specific number of people involved or whether new 

jobs are created for new employees, versus displacing jobs from 

other sectors of the economy.

E. What are the benefits of the proposed standards?

The proposed rule is expected to result in significant 

reductions in emissions. In 2020, the proposed rule is

anticipated to reduce 170,000 to 180,000 tons of methane (a GHG 

and a precursor to global ozone formation), 120,000 tons of VOC 

(a precursor to both PM (2.5 microns and less) (PM2.5) and ozone 
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formation), and 310 to 400 tons of HAP. In 2025, the proposed 

rule is anticipated to reduce 340,000 to 400,000 tons of 

methane, 170,000 to 180,000 tons of VOC, and 1,900 to 2,500 tons 

of HAP. These pollutants are associated with substantial health 

effects, climate effects, and other welfare effects. 

The proposed standards are expected to reduce methane 

emissions annually by about 3.8 to 4.0 million metric tons CO2

Eq. in 2020 and by about 7.7 to 9.0 million metric tons CO2 Eq. 

in 2025. The methane reductions represent about 2 percent in 

2020 and 4 to 5 percent in 2025 of the baseline methane 

emissions for this sector reported in the U.S. GHG Inventory for 

2013 (about 182 million metric tons CO2 Eq. when petroleum 

refineries and petroleum transportation are excluded because 

these sources are not examined in this proposal). However, it is 

important to note that the emission reductions are based upon 

predicted activities in 2020 and 2025; the EPA did not forecast 

sector-level emissions in 2020 and 2025 for this rulemaking.

Methane is a potent GHG that, once emitted into the 

atmosphere, absorbs terrestrial infrared radiation that 

contributes to increased global warming and continuing climate 

change. Methane reacts in the atmosphere to form tropospheric 

ozone and stratospheric water vapor, both of which also 
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contribute to global warming. When accounting for the impacts 

changing methane, tropospheric ozone, and stratospheric water 

vapor concentrations, the Intergovernmental Panel on Climate 

Change (IPCC) 5th Assessment Report (2013) found that historical 

emissions of methane accounted for about 30 percent of the total 

current warming influence (radiative forcing) due to historical 

emissions of GHGs. Methane is therefore a major contributor to 

the climate change impacts described previously. In 2013, total 

methane emissions from the oil and natural gas industry 

represented nearly 29 percent of the total methane emissions 

from all sources and account for about 3 percent of all CO2-

equivalent emissions in the United States, with the combined 

petroleum and natural gas systems being the largest contributor 

to U.S. anthropogenic methane emissions.

We calculated the global social benefits of methane

emission reductions expected from the proposed NSPS standards 

for oil and natural gas sites using estimates of the social cost 

of methane (SC-CH4), a metric that estimates the monetary value 

of impacts associated with marginal changes in methane emissions 

in a given year. The SC-CH4 estimates applied in this analysis 

were developed by Marten et al. (2014) and are discussed in 

greater detail below.
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A similar metric, the social cost of CO2 (SC-CO2), provides 

important context for understanding the Marten et al. SC-CH4

estimates.132 The SC-CO2 is a metric that estimates the monetary 

value of impacts associated with marginal changes in CO2

emissions in a given year. Similar to the SC-CH4, it includes a 

wide range of anticipated climate impacts, such as net changes 

in agricultural productivity, property damage from increased 

flood risk, and changes in energy system costs, such as reduced 

costs for heating and increased costs for air conditioning. 

Estimates of the SC-CO2 have been used by the EPA and other 

federal agencies to value the impacts of CO2 emissions changes in 

benefit cost analysis for GHG-related rulemakings since 2008. 

The SC-CO2 estimates were developed over many years, using 

the best science available, and with input from the public. 

Specifically, an interagency working group (IWG) that included 

EPA and other executive branch agencies and offices used three 

integrated assessment models (IAMs) to develop the SC-CO2

estimates and recommended four global values for use in 

 

132 Previous analyses have commonly referred to the social cost 

of carbon dioxide emissions as the social cost of carbon or SCC. 

To more easily facilitate the inclusion of non-CO2 GHGs in the 

discussion and analysis the more specific SC-CO2 nomenclature is 

used to refer to the social cost of CO2 emissions.
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regulatory analyses. The SC-CO2 estimates were first released in 

February 2010 and updated in 2013 using new versions of each 

IAM. The 2010 SC-CO2 Technical Support Document (2010 TSD) 

provides a complete discussion of the methods used to develop 

these estimates and the current SC-CO2 TSD presents and discusses 

the 2013 update (including recent minor technical corrections to 

the estimates).133

The SC-CO2 TSDs discuss a number of limitations to the SCCO2 analysis, including the incomplete way in which the IAMs 

capture catastrophic and non-catastrophic impacts, their 

incomplete treatment of adaptation and technological change, 

uncertainty in the extrapolation of damages to high 

temperatures, and assumptions regarding risk aversion. 

Currently, IAMs do not assign value to all of the important 

physical, ecological, and economic impacts of climate change 

recognized in the climate change literature due to a lack of 

precise information on the nature of damages and because the 

science incorporated into these models understandably lags 

behind the most recent research. Nonetheless, these estimates 

and the discussion of their limitations represent the best 

 

133 Both the 2010 SC-CO2 TSD and the current TSD are available at: 

https://www.whitehouse.gov/omb/oira/social-cost-of-carbon.
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available information about the social benefits of CO2 reductions 

to inform benefit-cost analysis. EPA and other agencies continue 

to engage in research on modeling and valuation of climate 

impacts with the goal to improve these estimates, and continue 

to consider feedback on the SC-CO2 estimates from stakeholders 

through a range of channels, including public comments on Agency 

rulemakings a separate recent OMB public comment solicitation, 

and through regular interactions with stakeholders and research 

analysts implementing the SC-CO2 methodology. See the RIA of this 

rule for additional details.

A challenge particularly relevant to this proposal is that 

the IWG did not estimate the social costs of non-CO2 GHG 

emissions at the time the SC-CO2 estimates were developed. In 

addition, the directly modeled estimates of the social costs of 

non-CO2 GHG emissions previously found in the published 

literature were few in number and varied considerably in terms 

of the models and input assumptions they employed134 (EPA 2012).

 

134 U.S. EPA. 2012. Regulatory Impact Analysis Final New Source 

Performance Standards and Amendments to the National Emissions 

Standards for Hazardous Air Pollutants for the Oil and Natural 

Gas Industry. Office of Air Quality Planning and Standards, 

Health and Environmental Impacts Division. April.

http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_n

eshap_nsps_ria.pdf. Accessed March 30, 2015.
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As a result, benefit-cost analyses informing U.S. federal 

rulemakings to date have not fully considered the monetized 

benefits associated with CH4 emissions mitigation. To understand 

the potential importance of monetizing non-CO2 GHG emissions 

changes, EPA has conducted sensitivity analysis in some of its 

past regulatory analyses using an estimate of the GWP of CH4 to 

convert emission impacts to CO2 equivalents, which can then be 

valued using the SC-CO2 estimates. This approach approximates the 

social cost of methane (SC-CH4) using estimates of the SC-CO2 and 

the GWP of CH4.135

The published literature documents a variety of reasons 

that directly modeled estimates of SC-CH4 are an analytical 

improvement over the estimates from the GWP approximation 

approach. Specifically, several recent studies found that GWPweighted benefit estimates for methane are likely to be lower 

 

135 For example, see (1) U.S. EPA. (2012). “Regulatory impact 

analysis supporting the 2012 U.S. Environmental Protection 

Agency final new source performance standards and amendments to 

the national emission standards for hazardous air pollutants for 

the oil and natural gas industry.” Retrieved from 

http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_n

eshap_nsps_ria.pdf and (2) U.S. EPA. (2012). “Regulatory impact 

analysis: Final rulemaking for 2017–2025 light-duty vehicle 

greenhouse gas emission standards and corporate average fuel 

economy standards.” Retrieved from 

http://www.epa.gov/otaq/climate/documents/420r12016.pdf 
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than the estimates derived using directly modeled social cost 

estimates for these gases.136 The GWP reflects only the relative 

integrated radiative forcing of a gas over 100 years in 

comparison to CO2. The directly modeled social cost estimates

differ from the GWP-scaled SC-CO2 because the relative 

differences in timing and magnitude of the warming between gases 

are explicitly modeled, the non-linear effects of temperature 

change on economic damages are included, and rather than 

treating all impacts over a hundred years equally, the modeled 

damages over the time horizon considered (2300 in this case) are 

discounted to present value terms. A detailed discussion of the 

limitations of the GWP approach can be found in the RIA.

In general, the commenters on previous rulemakings strongly 

encouraged the EPA to incorporate the monetized value of non-CO2

GHG impacts into the benefit cost analysis. However they noted 

the challenges associated with the GWP approach, as discussed 

above, and encouraged the use of directly modeled estimates of 

the SC-CH4 to overcome those challenges.

 

136 See Waldhoff et al. (2011); Marten and Newbold (2012); and 

Marten et al. (2014).
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Since then, a paper by Marten et al. (2014) has provided 

the first set of published SC-CH4 estimates in the peer-reviewed 

literature that are consistent with the modeling assumptions 

underlying the SC-CO2 estimates.137,138 Specifically, the 

estimation approach of Marten et al. used the same set of three 

IAMs, five socioeconomic and emissions scenarios, equilibrium 

climate sensitivity distribution, three constant discount rates, 

and aggregation approach used by the IWG to develop the SC-CO2

estimates. 

The SC-CH4 estimates from Marten et al. (2014) are presented 

below in Table 6. More detailed discussion of the SC-CH4

estimation methodology, results and a comparison to other 

published estimates can be found in the RIA and in Marten et al.

 

137 Marten et al. (2014) also provided the first set of SC-N2O 

estimates that are consistent with the assumptions underlying 

the IWG SC-CO2 estimates. 138 Marten, A. L., E. A. Kopits, C. W. Griffiths, S. C. Newbold & 

A. Wolverton (2014, online publication; 2015, print 

publication). Incremental CH4 and N2O mitigation benefits 

consistent with the U.S. Government's SC-CO2 estimates, Climate 

Policy, DOI: 10.1080/14693062.2014.912981. 
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TABLE 6: SOCIAL COST OF CH4, 2012 – 2050a [in 2012$ per metric 

ton] (Source: Marten et al., 2014b)

Year SC-CH4

5%

Average

3%

Average

2.5%

Average

3%

95th percentile

2012 $430 $1000 $1400 $2800

2015 490 1100 1500 3000

2020 580 1300 1700 3500

2025 700 1500 1900 4000

2030 820 1700 2200 4500

2035 970 1900 2500 5300

2040 1100 2200 2800 5900

2045 1300 2500 3000 6600

2050 1400 2700 3300 7200

Notes:

a There are four different estimates of the SC-CH4, each one

emissions-year specific. The first three shown in the table are 

based on the average SC-CH4 from three integrated assessment 

models at discount rates of 5, 3, and 2.5 percent. The fourth 

estimate is the 95th percentile of the SC-CH4 across all three 

models at a 3 percent discount rate. See RIA for details. b The estimates in this table have been adjusted to reflect the 

minor technical corrections to the SC-CO2 estimates described 

above. See the Corrigendum to Marten et al. (2014), 

http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550 .

The application of these directly modeled SC-CH4 estimates 

from Marten et al. (2014) in a benefit-cost analysis of a 

regulatory action is analogous to the use of the SC-CO2

estimates. In addition, the limitations for the SC-CO2 estimates 

discussed above likewise apply to the SC-CH4 estimates, given the 

consistency in the methodology.

The EPA recently conducted a peer review of the application 

of the Marten et al. (2014) non-CO2 social cost estimates in 
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regulatory analysis and received responses that supported this 

application. See the RIA for a detailed discussion.

In light of the favorable peer review and past comments 

urging the EPA to value non-CO2 GHG impacts in its rulemakings, 

the Agency has used the Marten et al. (2014) SC-CH4 estimates to 

value methane impacts expected from this proposed rulemaking and 

has included those benefits in the main benefits analysis. The 

EPA seeks comments on the use of these directly modeled 

estimates, from the peer-reviewed literature, for the social 

cost of non-CO2 GHGs in today’s rulemaking. 

The methane benefits calculated using Marten et al. (2014) 

are presented for years 2020 and 2025. Applying this approach to 

the methane reductions estimated for the NSPS proposal, the 2020

methane benefits vary by discount rate and range from about 

$9388 million to approximately $550 million; the mean SC-CH4 at 

the 3-percent discount rate results in an estimate of about $200 

to $210 million in 2020. The methane benefits increase in the 

2025, ranging from $250220 million to $1.4 billion, depending on 

discount rate used; the mean SC-CH4 at the 3-percent discount 

rate results in an estimate of about $460 to $550 million in 

2025.

TABLE 7: ESTIMATED GLOBAL BENEFITS OF METHANE REDUCTIONS
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(in millions, 2012$)

Discount rate and 

statistic

Year

2020 2025

Million metric tonnes 

of methane reduced 0.15 to 0.16 0.31 to 0.36

Million metric tonnes 

of CO2 Eq. 3.8 to 4.0 7.7 to 9.0

5% (average) $88 to $93 $220 to $250

3% (average) $200 to $210 $460 to $550

2.5% (average) $260 to $280 $600 to $700

3% (95th percentile) $520 to $550 $1,200 to $1,400

In addition to the limitation discussed above, and the 

referenced documents, there are additional impacts of individual 

GHGs that are not currently captured in the IAMs used in the 

directly modeled approach of Marten et al. (2014), and therefore 

not quantified for the rule. For example, in addition to being a 

GHG, methane is a precursor to ozone. The ozone generated by 

methane has important non-climate impacts on agriculture, 

ecosystems, and human health. The RIA describes the specific 

impacts of methane as an ozone precursor in more detail and 

discusses studies that have estimated monetized benefits of 

these methane generated ozone effects. The EPA continues to 

monitor developments in this area of research and seeks comment 

on the potential inclusion of health impacts of ozone generated 

by methane in future regulatory analysis.

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With the data available, we are not able to provide 

credible health benefit estimates for the reduction in exposure 

to HAP, ozone and PM2.5 for these rules, due to the differences 

in the locations of oil and natural gas emission points relative 

to existing information and the highly localized nature of air 

quality responses associated with HAP and VOC reductions. This 

is not to imply that there are no benefits of the rules; rather, 

it is a reflection of the difficulties in modeling the direct 

and indirect impacts of the reductions in emissions for this 

industrial sector with the data currently available.139 In 

addition to health improvements, there will be improvements in 

 

139 Previous studies have estimated the monetized benefits-perton of reducing VOC emissions associated with the effect that 

those emissions have on ambient PM2.5 levels and the health 

effects associated with PM2.5 exposure (Fann, Fulcher, and 

Hubbell, 2009). While these ranges of benefit-per-ton estimates 

can provide useful context, the geographic distribution of VOC 

emissions from the oil and gas sector are not consistent with 

emissions modeled in Fann, Fulcher, and Hubbell (2009). In 

addition, the benefit-per-ton estimates for VOC emission 

reductions in that study are derived from total VOC emissions 

across all sectors. Coupled with the larger uncertainties about 

the relationship between VOC emissions and PM2.5 and the highly 

localized nature of air quality responses associated with HAP 

and VOC reductions, these factors lead us to conclude that the 

available VOC benefit-per-ton estimates are not appropriate to 

calculate monetized benefits of these rules, even as a bounding 

exercise.
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visibility effects, ecosystem effects and climate effects, as 

well as additional product recovery.

Although we do not have sufficient information or modeling 

available to provide quantitative estimates for this rulemaking, 

we include a qualitative assessment of the health effects 

associated with exposure to HAP, ozone and PM2.5 in the RIA for 

this rule. These qualitative effects are briefly summarized 

below, but for more detailed information, please refer to the 

RIA, which is available in the docket. One of the HAPs of 

concern from the oil and natural gas sector is benzene, which is 

a known human carcinogen. VOC emissions are precursors to both 

PM2.5 and ozone formation. As documented in previous analyses 

(U.S. EPA, 2006140, U.S. EPA, 2010141, and U.S. EPA, 2014142), 

 

140 U.S. EPA. RIA. National Ambient Air Quality Standards for 

Particulate Matter, Chapter 5. Office of Air Quality Planning 

and Standards, Research Triangle Park, NC. October 2006. 

Available on the Internet at 

<http://www.epa.gov/ttn/ecas/regdata/RIAs/Chapter%205--

Benefits.pdf>.

141 U.S. EPA. RIA. National Ambient Air Quality Standards for 

Ozone. Office of Air Quality Planning and Standards, Research 

Triangle Park, NC. January 2010. Available on the Internet at 

<http://www.epa.gov/ttn/ecas/regdata/RIAs/s1-

supplemental_analysis_full.pdf>.

142 U.S. EPA. RIA. National Ambient Air Quality Standards for 

Ozone. Office of Air Quality Planning and Standards, Research 
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exposure to PM2.5 and ozone is associated with significant public 

health effects. PM2.5 is associated with health effects, including 

premature mortality for adults and infants, cardiovascular 

morbidity such as heart attacks, and respiratory morbidity such 

as asthma attacks, acute bronchitis, hospital admissions and 

emergency room visits, work loss days, restricted activity days 

and respiratory symptoms, as well as visibility impairment.143

Ozone is associated with health effects, including hospital and 

emergency department visits, school loss days and premature 

mortality, as well as injury to vegetation and climate 

effects.144

Finally, the control techniques to meet the standards are 

anticipated to have minor secondary emissions impacts, which may 

partially offset the direct benefits of this rule. The magnitude 

 

Triangle Park, NC. December 2014. Available on the Internet at 

<http://www.epa.gov/ttnecas1/regdata/RIAs/20141125ria.pdf>.

143 U.S. EPA. Integrated Science Assessment for Particulate 

Matter (Final Report). EPA-600-R-08-139F. National Center for 

Environmental Assessment—RTP Division. December 2009. Available 

at <http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546>.

144 U.S. EPA. Air Quality Criteria for Ozone and Related 

Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. 

Washington, DC: U.S. EPA. February 2006. Available on the 

Internet at 

http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
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of these secondary air pollutant impacts is small relative to 

the direct emission reductions anticipated from this rule.

In particular, EPA has estimated that an increase in 

flaring of methane in response to this rule will produce a 

variety of emissions, including 610,000 tons of CO2 in 2020 and 

750,000 tons of CO2 in 2025. EPA has not estimated the monetized 

value of the secondary emissions of CO2 because much of the 

methane that would have been released in the absence of the 

flare would have eventually oxidized into CO2 in the atmosphere. 

Note that the CO2 produced from the methane oxidizing in the 

atmosphere is not included in the calculation of the SC-CH4. 

However, EPA recognizes that because the growth rate of the SCCO2 estimates are lower than their associated discount rates, the 

estimated impact of CO2 produced in the future from oxidized 

methane would be less than the estimated impact of CO2 released 

immediately from flaring, which would imply a small disbenefit 

associated with flaring. Assuming an average methane oxidation 

period of 8.7 years, consistent with the lifetime used in IPCC 

AR4, the disbenefits associated with destroying one ton of 

methane and releasing the CO2 emissions in 2020 instead of being 

released in the future via the methane oxidation process is 

estimated to be $6 to $25, depending on the SC-CO2 value or 0.7 
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percent to 1.0 percent of the SC-CH4 estimates for 2020. The 

analogous estimates for 2025 are $7 to $34 or 0.8 percent to 1.0

percent of the SC-CH4 estimates for 2025. While EPA is not 

accounting for the CO2 disbenefits at this time, we request 

comment on the appropriateness of the monetization of such 

impacts using the SC-CO2 and aspects of the calculation. See RIA 

for further details about the calculation.

XII. Statutory and Executive Order Reviews

Additional information about these statutes and Executive 

Orders can be found at http://www2.epa.gov/lawsregulations/laws-and-executive-orders. 

A. Executive Order 12866: Regulatory Planning and Review and 

Executive Order 13563: Improving Regulation and Regulatory 

Review

This action is an economically significant regulatory 

action that was submitted to the OMB for review. Any changes 

made in response to OMB recommendations have been documented in 

the docket. The EPA prepared an analysis of the potential costs 

and benefits associated with this action.

In addition, the EPA prepared a Regulatory Impact Analysis 

(RIA) of the potential costs and benefits associated with this 

action. The RIA available in the docket describes in detail the 
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empirical basis for the EPA’s assumptions and characterizes the 

various sources of uncertainties affecting the estimates below. 

Table 8 shows the results of the cost and benefits analysis for 

these proposed rules. 

TABLE 8. SUMMARY OF THE MONETIZED BENEFITS, SOCIAL COSTS AND NET 

BENEFITS FOR THE PROPOSED OIL AND NATURAL GAS NSPS IN 2020 AND 

2025 (MILLIONS OF 2012$)

2020 2025

Total 

Monetized 

Benefits1

$200 to $210 million $460 to $550 million

Total Costs2 $150 to $170 million $410320 to $420 million

Net 

Benefits3 $3835 to $42 million $140120 to $150 million

Nonmonetized 

Benefits

Non-monetized climate benefits

Health effects of PM2.5 and ozone exposure from 

120,000 tons of VOC in 2020 and 170,000 to 

180,000 tons of VOC in 2025

Health effects of HAP exposure from 310 to 400 

tons of HAP in 2020 and 1,900 to 2,500 tons of 

HAP in 2025

Health effects of ozone exposure from 170,000 to 

180,000 tons of methane in 2020 and 340,000 to 

400,000 tons methane in 2025

Visibility impairment

Vegetation effects 1 We estimate methane benefits associated with four different 

values of a one ton CH4 reduction (model average at 2.5 percent 

discount rate, 3 percent, and 5 percent; 95th percentile at 3 

percent). For the purposes of this table, we show the benefits 

associated with the model average at 3 percent discount rate, 

however we emphasize the importance and value of considering the 

full range of social cost of methane values. We provide 

estimates based on additional discount rates in preamble section 

XI and in the RIA. Also, the specific control technologies for 

the proposed NSPS are anticipated to have minor secondary 

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disbenefits. The net CO2-equivalent (CO2 Eq.) methane emission 

reductions are 3.8 to 4.0 million metric tons in 2020 and 7.7 to 

9.0 million metric tons in 2025. 2 The engineering compliance costs are annualized using a 7 

percent discount rate and include estimated revenue from 

additional natural gas recovery as a result of the NSPS. When 

rounded, the cost estimates are the same for the 3 percent 

discount rate as they are for the 7 percent discount rate cost 

estimates, so rounded net benefits do not change when using a 3 

percent discount rate.

3 Figures may not sum due to rounding.

B. Paperwork Reduction Act (PRA)

The Office of Management and Budget (OMB) has previously 

approved the information collection activities contained in 40

CFR part 60, subpart OOOO under the PRA and has assigned OMB 

control number 2060-0673 and ICR number 2437.01; a summary can 

be found at 77 F.R. 49537. The information collection 

requirements in today’s proposed rule titled, Standards of 

Performance for Crude Oil and Natural Gas Facilities for 

Construction, Modification, or Reconstruction (40 CFR part 60 

subpart OOOOa) have been submitted for approval to the OMB under 

the PRA. The ICR document prepared by the EPA has been assigned 

EPA ICR Number 2523.01. You can find a copy of the ICR in the 

docket for this rule, and is briefly summarized below. 

The information to be collected for the proposed NSPS is 

based on notification, performance tests, recordkeeping and 

reporting requirements which will be mandatory for all operators 
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subject to the final standards. Recordkeeping and reporting 

requirements are specifically authorized by section 114 of the 

CAA (42 U.S.C. 7414). The information will be used by the 

delegated authority (state agency, or Regional Administrator if 

there is no delegated state agency) to ensure that the standards

and other requirements are being achieved. Based on review of 

the recorded information at the site and the reported 

information, the delegated permitting authority can identify 

facilities that may not be in compliance and decide which 

facilities, records, or processes may need inspection. All 

information submitted to the EPA pursuant to the recordkeeping 

and reporting requirements for which a claim of confidentiality 

is made is safeguarded according to Agency policies set forth in 

40 CFR part 2, subpart B. 

Potential respondents under subpart OOOOa are owners or 

operators of new, modified or reconstructed oil and natural gas 

affected facilities as defined under the rule. None of the 

facilities in the United States are owned or operated by state, 

local, tribal or the Federal government. All facilities are 

privately owned for-profit businesses. The requirements in this 

action result in industry recording keeping and reporting burden 

associated with review of the requirements for all affected 

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entities, gathering relevant information, performing initial 

performance tests and repeat performance tests if necessary, 

writing and submitting the notifications and reports, developing 

systems for the purpose of processing and maintaining 

information, and train personnel to be able to respond to the 

collection of information. 

The estimated average annual burden (averaged over the 

first 3 years after the effective date of the standards) for the 

recordkeeping and reporting requirements in subpart OOOOa for 

the 2,552 owners and operators that are subject to the rule is 

92,658 labor hours, with an annual average cost of $3,163,699. 

The annual public reporting and recordkeeping burden for this 

collection of information is estimated to average 3.9 hours per 

response. Respondents must monitor all specified criteria at 

each affected facility and maintain these records for 5 years.

Burden is defined at 5 CFR 1320.3(b).

An agency may not conduct or sponsor, and a person is not 

required to respond to, a collection of information unless it 

displays a currently valid OMB control number. The OMB control 

numbers for the EPA’s regulations in 40 CFR are listed in 40 CFR 

part 9. 
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Submit your comments on the Agency’s need for this 

information, the accuracy of the provided burden estimates and 

any suggested methods for minimizing respondent burden to the 

EPA using the docket identified at the beginning of this rule. 

You may also send your ICR-related comments to OMB’s Office of 

Information and Regulatory Affairs via email to 

RIA_submissions@omb.eop.gov, Attention: Desk Officer for the 

EPA. Since OMB is required to make a decision concerning the ICR 

between 30 and 60 days after receipt, OMB must receive comments 

no later than [insert date 30 days after publication in the 

Federal Register]. The EPA will respond to any ICR-related 

comments in the final rule. 

C. Regulatory Flexibility Act (RFA)

The RFA generally requires an agency to prepare a 

regulatory flexibility analysis of any rule subject to notice 

and comment rulemaking requirements under the Administrative 

Procedure Act or any other statute unless the agency certifies 

that the rule will not have a significant economic impact on a

substantial number of small entities. Small entities include 

small businesses, small organizations, and small governmental 

jurisdictions.
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For purposes of assessing the impacts of this rule on small 

entities, a small entity is defined as: (1) A small business in 

the oil or natural gas industry whose parent company has no more 

than 500 employees (or revenues of less than $7 million for 

firms that transport natural gas via pipeline); (2) a small 

governmental jurisdiction that is a government of a city, 

county, town, school district, or special district with a 

population of less than 50,000; and (3) a small organization 

that is any not-for-profit enterprise which is independently 

owned and operated and is not dominant in its field.

Pursuant to section 603 of the RFA, the EPA prepared an 

initial regulatory flexibility analysis (IRFA) that examines the 

impact of the proposed rule on small entities along with 

regulatory alternatives that could minimize that impact. The 

complete IRFA is available for review in the docket and is 

summarized here. 

[XXX PLACEHOLDER FOR IRFA SUMMARY. IRFA IS IN DEVELOPMENT AS 

PART OF THE SBAR PROCESS]

The IRFA describes the reason why the proposed rule is 

being considered and describes the objectives and legal basis of 

the proposed rule, as well as discusses related rules affecting 

the oil and natural gas sector. The IRFA describes the EPA’s 
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examination of small entity effects prior to proposing a 

regulatory option and provides information about steps taken to

minimize significant impacts on small entities while achieving 

the objectives of the rule.

The EPA also summarized the potential regulatory cost 

impacts of the proposed rule and alternatives in Section 3 of 

the RIA. The analysis in the IRFA drew upon the same analysis 

and assumptions as the analyses presented in the RIA. The IRFA 

analysis is presented in its entirely in Section 7.3 of the RIA.

Identifying impacts on specific entities is challenging 

because of the difficulty of predicting potentially affected new 

or modified sources at the firm level. To identify potentially 

affected entities under the proposed NSPS, the EPA combined 

information from industry databases to identify firms drilling 

and completing wells in 2012, as well as identified their oil 

and natural gas production levels for that year. 

The EPA based the analysis in the IRFA on impacts estimates 

for the proposed requirements for hydraulically fractured and 

re-fractured oil well completions and well site fugitive 

emissions. While the IRFA does not incorporate potential impacts 

from other provisions of the proposed NSPS, the completions and 

fugitive emissions provisions represent a large majority of the 
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estimated compliance costs of the proposed NSPS in 2020 and 

2025. Note incorporating impacts from other provisions in this 

analysis is a limitation and underestimates impacts, but the EPA 

believes that detailed analysis of the two provisions impacts on 

small entities is illustrative of impacts on small entities from 

the proposed rule in its entirety.

We projected the 2012 base year estimates of incrementally 

affected facilities to 2020 and 2025 levels based on the same 

growth rates used to project future activities as described in 

the TSD and consistent with other analyses in the RIA. This 

approach assumes that no other firms perform potentially 

affected activities and firms performing oil and natural gas 

activities in 2012 will continue to do so in 2020 and 2025. 

While likely true for many firms, this will not be the case for 

all firms. 

For some firms, we estimated their 2012 sales levels by 

multiplying 2012 oil and natural gas production levels reported 

in an industry database by assumed oil and natural gas prices at 

the wellhead. For natural gas, we assumed the $4/Mcf for natural 

gas. For oil prices, we estimated revenues using two alternative 

prices, $70/bbl and $50/bbl. In the results, we call the case 
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using $70/bbl the “primary scenario” and the case using the 

$50/bbl as the “low oil price scenario”.

For projected 2020 and 2025 potentially affected 

activities, we allocated compliance costs across entities based 

upon the costs estimated in the TSD and used in the RIA. The RIA 

and IRFA also estimates the potential implications of the 

proposed exclusion for low producing sites from the fugitive 

emission requirements. Fewer sites in the program due to this 

exclusion will likely lead to lower costs and emissions. 

The analysis indicates about 1,200 to 2,100 small entities 

may be subject to the requirements for hydraulically fractured 

and re-fractured oil well completions and fugitive emissions 

requirements at well sites. The low end of this range reflects 

an estimate of how many entities might be excluded as a result 

of the low production fugitive emissions exemption. Also the 

cost-to-sales ratios with ratios greater than 1 percent and 3 

percent increase from 2020 to 2025 as affected sources 

accumulate under the proposed NSPS. Cost-to-sales ratios 

exceeding 1 percent and 3 percent are also reduced from the case 

without the entities that might be excluded from fugitive 

emissions requirements as a result of the low production 

exemption. 
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The analysis above is subject to a number of caveats and 

limitations. These are discussed in detail in the IRFA, as well 

as in Section 3 of the RIA.As required by section 609(b) of the 

RFA, the EPA also convened a Small Business Advocacy Review 

(SBAR) Panel to obtain advice and recommendations from small 

entity representatives that potentially would be subject to the 

rule's requirements. The SBAR Panel evaluated the assembled 

materials and small-entity comments on issues related to 

elements of an IRFA. A copy of the full SBAR Panel Report is 

available in the rulemaking docket.

D. Unfunded Mandates Reform Act (UMRA)

This action does not contain any unfunded mandate as 

described in UMRA, 2 U.S.C. 1531–1538, and does not 

significantly or uniquely affect small governments. The action 

imposes no enforceable duty on any state, local or tribal 

governments or the private sector.

E. Executive Order 13132: Federalism

This action does not have federalism implications. It will 

not have substantial direct effects on the states, on the 

relationship between the national government and the states, or 

on the distribution of power and responsibilities among the 

various levels of government. These final rules primarily affect 

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private industry and would not impose significant economic costs 

on state or local governments.

F. Executive Order 13175: Consultation and Coordination with 

Indian Tribal Governments 

This action has tribal implications. However, it will 

neither impose substantial direct compliance costs on federally 

recognized tribal governments, nor preempt tribal law. The 

majority of the units impacted by this rulemaking on tribal 

lands are owned by private entities, and tribes will not be 

directly impacted by the compliance costs associated with this 

rulemaking. There would only be tribal implications associated 

with this rulemaking in the case where a unit is owned by a 

tribal government or a tribal government is given delegated

authority to enforce the rulemaking. 

The EPA consulted with tribal officials under the “EPA 

Policy on Consultation and Coordination with Indian Tribes”

early in the process of developing this regulation to permit 

them to have meaningful and timely input into its development. 

Additionally, the EPA has conducted meaningful involvement with 

tribal stakeholders throughout the rulemaking process. We 

provided an update on the methane strategy on the January 29, 

2015, NTAA and EPA Air Policy call. As required by section 7(a), 
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the EPA’s Tribal Consultation Official has certified that the 

requirements of the Executive Order have been met in a 

meaningful and timely manner. A copy of the certification is 

included in the docket for this action.

Consistent with previous actions affecting the oil and 

natural gas sector, there is significant tribal interest because 

of the growth of the oil and natural gas production in Indian 

country. The EPA specifically solicits additional comment on 

this proposed action from tribal officials.

G. Executive Order 13045: Protection of Children from 

Environmental Health Risks and Safety Risks 

This action is subject to Executive Order 13045 (62 FR 

19885, April 23, 1997) because it is an economically significant 

regulatory action as defined by Executive Order 12866, and the 

EPA believes that the environmental health or safety risk 

addressed by this action has a disproportionate effect on 

children. Accordingly, the agency has evaluated the 

environmental health and welfare effects of climate change on 

children. 

 GHGs including methane contribute to climate change and are 

emitted in significant quantities by the oil and gas sector. The 

EPA believes that the GHG emission reductions resulting from 
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implementation of these final guidelines will further improve 

children’s health. 

The assessment literature cited in the EPA’s 2009 

Endangerment Finding concluded that certain populations and life 

stages, including children, the elderly, and the poor, are most 

vulnerable to climate-related health effects. The assessment 

literature since 2009 strengthens these conclusions by providing 

more detailed findings regarding these groups’ vulnerabilities 

and the projected impacts they may experience.

These assessments describe how children’s unique 

physiological and developmental factors contribute to making 

them particularly vulnerable to climate change. Impacts to 

children are expected from heat waves, air pollution, infectious 

and waterborne illnesses, and mental health effects resulting 

from extreme weather events. In addition, children are among 

those especially susceptible to most allergic diseases, as well 

as health effects associated with heat waves, storms, and 

floods. Additional health concerns may arise in low income 

households, especially those with children, if climate change 

reduces food availability and increases prices, leading to food 

insecurity within households.
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More detailed information on the impacts of climate change 

to human health and welfare is provided in Section V of this 

preamble.

H. Executive Order 13211: Actions Concerning Regulations That 

Significantly Affect Energy Supply, Distribution, or Use

Executive Order 13211 (66 FR 28355, May 22, 2001) provides 

that agencies will prepare and submit to the Administrator of 

the Office of Information and Regulatory Affairs, Office of 

Management and Budget, a Statement of Energy Effects for certain 

actions identified as “significant energy actions.” Section 4(b) 

of Executive Order 13211 defines “significant energy actions” as 

any action by an agency (normally published in the Federal 

Register) that promulgates or is expected to lead to the 

promulgation of a final rule or regulation, including notices of 

inquiry, advance notices of proposed rulemaking, and notices of 

proposed rulemaking: (1)(i) that is a significant regulatory

action under Executive Order 12866 or any successor order, and 

(ii) is likely to have a significant adverse effect on the 

supply, distribution, or use of energy; or (2) that is 

designated by the Administrator of the Office of Information and 

Regulatory Affairs as a significant energy action.
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This action is not a “significant energy action” as defined 

in Executive Order 13211 (66 FR 28355, May 22, 2001), because it 

is not likely to have a significant adverse effect on the 

supply, distribution, or use of energy. The basis for these 

determinations follows. 

The EPA used the National Energy Modeling System (NEMS) to 

estimate the impacts of the proposed rule on the United States 

energy system. The NEMS is a publically-available model of the 

United States energy economy developed and maintained by the 

Energy Information Administration of the DOE and is used to 

produce the Annual Energy Outlook, a reference publication that 

provides detailed forecasts of the United States energy economy. 

The EPA modeled the high impact case of the proposed 

NSPS with respect the low production exemption from the well 

site fugitive emissions requirements. As such the NEMS-based 

estimates of energy system impacts are likely high end 

estimates. 

The NEMS-based analysis estimates natural gas and crude oil 

production levels remain essentially unchanged under the 

proposed rule in 2020, while slight declines are estimated for 

2020 for both natural gas (about 4 billion cubic feet (bcf) or 

about 0.01 percent) and crude oil production (about 2,000 
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barrels per day or 0.03 percent). Wellhead natural gas prices 

for onshore lower 48 production are not estimated to change in 

2020 under the proposed rule, but are estimated to increase 

about $0.007 per Mcf or 0.14 percent in 2025. Meanwhile, well 

crude oil prices for onshore lower 48 production are not 

estimated to change, despite the incidence of new compliance 

costs from the proposed NSPS. Meanwhile, net imports of natural 

gas are estimated to decline slightly in 2020 (by about 1 bcf or 

0.05 percent) and in 2025 (by about 3 bcf or 0.09 percent). 

Crude oil imports are estimated to not change in 2020 and 

increase by about 1,000 barrels per day (or 0.02 percent) in 

2025.

Additionally, the NSPS establishes several performance 

standards that give regulated entities flexibility in 

determining how to best comply with the regulation. In an 

industry that is geographically and economically heterogeneous, 

this flexibility is an important factor in reducing regulatory 

burden. For more information on the estimated energy effects of 

this proposed rule, please see the Regulatory Impact Analysis 

which is in the docket for this proposal.

I. National Technology Transfer and Advancement Act (NTTAA) and 

1 C.F.R. part 51 
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Section 12(d) of the National Technology Transfer and 

Advancement Act of 1995 (NTTAA), Public Law No. 104–113 (15 

U.S.C. 272 note) directs the EPA to use voluntary consensus

standards (VCS) in its regulatory activities unless to do so 

would be inconsistent with applicable law or otherwise 

impractical. VCS are technical standards (e.g., materials

specifications, test methods, sampling procedures, and business 

practices) that are developed or adopted by VCS bodies. NTTAA 

directs the EPA to provide Congress, through OMB, explanations 

when the Agency decides not to use available and applicable VCS.

The proposed rule involves technical standards. Therefore, 

the EPA conducted searches for the Oil and Natural Gas Sector: 

Emission Standards for New and Modified Sources through the 

Enhanced National Standards Systems Network (NSSN) Database 

managed by the American National Standards Institute (ANSI).

Searches were conducted for EPA Methods 1, 1A, 2, 2A, 2C, 2D, 

3A, 3B, 3C, 4, 6, 10, 15, 16, 16A, 21, 22, and 25A of 40 C.F.R. 

part 60 Appendix A. No applicable voluntary consensus standards 

were identified for EPA Methods 1A, 2A, 2D, 21, and 22. All 

potential standards were reviewed to determine the practicality 

of the VCS for this rule. In this rule, the EPA is proposing to 

include in a final EPA rule regulatory text for 40 CFR part 60, 
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subpart OOOOa that includes incorporation by reference. In 

accordance with requirements of 1 CFR 51.5, the EPA is proposing 

to incorporate by reference ANSI/ASME PTC 19-10–1981, Flue and 

Exhaust Gas Analyses (Part 10) to be used in lieu of EPA Methods 

3B, 6, 6A, 6B, 15A and 16A manual portions only and not the 

instrumental portion. This standard is available from the 

American Society of Mechanical Engineers (ASME), Three Park 

Avenue, New York, NY 10016–5990.

 The EPA welcomes comments on this aspect of the proposed 

rulemaking and, specifically, invites the public to identify 

potentially-applicable VCS and to explain why such standards 

should be used in this regulation. 

J. Executive Order 12898: Federal Actions to Address 

Environmental Justice in Minority Populations and Low-Income 

Populations

The EPA believes the human health or environmental 

risk addressed by this action will not have potential 

disproportionately high and adverse human health or 

environmental effects on minority, low-income or indigenous 

populations. The EPA has determined this because the rulemaking 

increases the level of environmental protection for all affected 

populations without having any disproportionately high and 
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adverse human health or environmental effects on any population, 

including any minority, low-income or indigenous populations. 

The EPA has provided meaningful participation opportunities for 

minority, low-income, indigenous populations and tribes during 

the pre-proposal period by conducting community calls and 

webinars. Additionally, the EPA will conduct outreach for 

communities after the rulemaking is finalized.
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List of Subjects in 40 CFR Part 60

Administrative practice and procedure, Air pollution 

control, Intergovernmental relations, Reporting and 

recordkeeping. 

Dated:

___________________________

Gina McCarthy,

Administrator.
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For the reasons set out in the preamble, title 40, chapter 

I of the Code of Federal Regulations is proposed to be amended 

as follows:

PART 60-STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

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

follows:

Authority: 42 U.S.C. 4701, et seq.

Subpart OOOO—Standards of Performance for Crude Oil and Natural 

Gas Production, Transmission and Distribution for which 

Construction, Modification or Reconstruction Commenced after 

August 23, 2011, and on or before [date of publication in the 

Federal Register]

2. The heading for Subpart OOOO is revised to read as set 

forth above.

3. Section 60.5360 is revised to read as follows:

§60.5360 What is the purpose of this subpart?

This subpart establishes emission standards and compliance 

schedules for the control of volatile organic compounds (VOC) 

and sulfur dioxide (SO2) emissions from affected facilities that 

commence construction, modification or reconstruction after 

August 23, 2011, and on or before [date of publication in the 
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Federal Register].

4. Section 60.5365 is amended by:

a. Revising the introductory text; and

b. Revising paragraph (h)(4).

The revisions read as follows:

§60.5365 Am I subject to this subpart?

You are subject to the applicable provisions of this 

subpart if you are the owner or operator of one or more of the 

onshore affected facilities listed in paragraphs (a) through (g) 

of this section for which you commence construction, 

modification or reconstruction after August 23, 2011, and on or 

before [date of publication in the Federal Register].

* * * * *

(h) * * *

(4) A gas well facility initially constructed after August 

23,

2011, and on or before [date of publication in the Federal 

Register] is considered an affected facility regardless of this 

provision.

5. Section 60.5370 is amended by adding paragraph (d) read 

as follows:

§60.5370 When must I comply with this subpart?
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* * * * *

(d) You are deemed to be in compliance with this subpart if 

you are in compliance with all applicable provisions of subpart 

OOOOa of this part.

6. Section 60.5411 is amended by: revising paragraphs

(a)(3)(i)(A) and (c)(3)(i)(A) to read as follows:

§60.5411 What additional requirements must I meet to determine 

initial compliance for my covers and closed vent systems routing 

materials from storage vessels and centrifugal compressor wet 

seal degassing systems?

* * * * *

(a) * * *

(3) * * *

(i) * * *

(A) You must properly install, calibrate, maintain, and 

operate a flow indicator at the inlet to the bypass device that 

could divert the stream away from the control device or process 

to the atmosphere. Set the flow indicator to trigger an audible 

alarm, and initiate notification via remote alarm to the nearest 

field office, when the bypass device is open such that the 

stream is being, or could be, diverted away from the control 

device or process to the atmosphere. You must maintain records 
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of each time the alarm is activated according to §60.5420(c)(8).

* * * * *

(c) * * *

(3) * * *

(i) * * *

(A) You must properly install, calibrate, maintain, and 

operate a flow indicator at the inlet to the bypass device that 

could divert the stream away from the control device or process 

to the atmosphere. Set the flow indicator to trigger an audible 

alarm and initiate notification via remote alarm to the nearest 

field office, when the bypass device is open such that the 

stream is being, or could be, diverted away from the control 

device or process to the atmosphere. You must maintain records 

of each time the alarm is activated according to §60.5420(c)(8).

* * * * *

7. Section 60.5412 is amended by:

a. Revising paragraphs (a)(1)(ii) and (d)(1) introductory 

text; and

b. Adding paragraph (d)(1)(iv).

The revisions and addition read as follows:

§60.5412 What additional requirements must I meet for 

determining initial compliance with control devices used to 
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comply with the emission standards for my storage vessel or 

centrifugal compressor affected facility?

* * * * *

(a) * * *

(1) * * *

(ii) You must reduce the concentration of TOC in the 

exhaust gases at the outlet to the device to a level equal to or 

less than 600 parts per million by volume as propane on a dry 

basis corrected to 3 percent oxygen as determined in accordance 

with the requirements of §60.5413.

* * * * *

(d) * * *

(1) Each enclosed combustion device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, boiler, or process 

heater) must be designed to reduce the mass content of VOC 

emissions by 95.0 percent or greater. You must follow the 

requirements in paragraphs (d)(1)(i) through (iv) of this 

section.

* * * * *

(iv) Each combustion control device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, boiler, or process 

heater) must be designed and operated in accordance with one of 
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the performance requirements specified in paragraphs (A) through 

(D) of this section.

(A) You must reduce the mass content of methane and VOC in 

the gases vented to the device by 95.0 percent by weight or 

greater as determined in accordance with the requirements of 

§60.5413.

(B) You must reduce the concentration of TOC in the exhaust 

gases at the outlet to the device to a level equal to or less 

than 600 parts per million by volume as propane on a dry basis 

corrected to 3 percent oxygen as determined in accordance with 

the requirements of §60.5413.

(C) You must operate at a minimum temperature of 760°C for 

a control device that can demonstrate a uniform combustion zone 

temperature during the performance test conducted under 

§60.5413.

(D) If a boiler or process heater is used as the control 

device, then you must introduce the vent stream into the flame 

zone of the boiler or process heater.

* * * * *

8. Section 60.5413 is amended by revising paragraph (e)(3) 

to read as follows:

§60.5413 What are the performance testing procedures for control 
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devices used to demonstrate compliance at my storage vessel or

centrifugal compressor affected facility?

* * * * *

(e) * * *

(3) Devices must be operated with no visible emissions, 

except for periods not to exceed a total of 1 minute during any 

15-minute period. A visible emissions test conducted according 

to section 11 of EPA Method 22, 40 CFR part 60, appendix A, must 

be performed at least once every calendar month, separated by at 

least 15 days between each test. The observation period shall be 

15 minutes.

* * * * *

9. Section 60.5415 is amended by revising paragraph 

(b)(2)(vii)(B) to read as follows:

§60.5415 How do I demonstrate continuous compliance with the 

standards for my gas well affected facility, my centrifugal 

compressor affected facility, my stationary reciprocating 

compressor affected facility, my pneumatic controller affected 

facility, my storage vessel affected facility, and my affected 

facilities at onshore natural gas processing plants?

* * * * *

(b) * * *
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(2) * * *

(vii) * * *

(B) Devices must be operated with no visible emissions, 

except for periods not to exceed a total of 1 minute during any 

15-minute period. A visible emissions test conducted according 

to section 11 of Method 22, 40 CFR part 60, appendix A, must be 

performed at least once every calendar month, separated by at 

least 15 days between each test. The observation period shall be 

15 minutes.

* * * * *

10. Section 60.5416 is amended by revising paragraph 

(c)(3)(i) to read as follows:

§60.5416 What are the initial and continuous cover and closed 

vent system inspection and monitoring requirements for my 

storage vessel and centrifugal compressor affected facility?

* * * * *

(c) * * * 

(3) * * *

(i) You must properly install, calibrate and maintain a 

flow indicator at the inlet to the bypass device that could 

divert the stream away from the control device or process to the 

atmosphere. Set the flow indicator to trigger an audible alarm, 
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and initiate notification via remote alarm to the nearest field 

office, when the bypass device is open such that the stream is 

being, or could be, diverted away from the control device or 

process to the atmosphere. You must maintain records of each 

time the alarm is activated according to §60.5420(c)(8).

* * * * *

11. Section 60.5417 is amended by adding paragraph (h)(4) 

to read as follows:

§60.5417 What are the continuous control device monitoring 

requirements for my storage vessel or centrifugal compressor 

affected facility?

* * * * *

(h) * * *

(4) Conduct a periodic performance test no later than 60 

months after the initial performance test as specified in 

§60.5413(b)(5)(ii) and conduct subsequent periodic performance 

tests at intervals no longer than 60 months following the 

previous periodic performance test.

12. Section 60.5420 is amended by:

a. Revising paragraph (c) introductory text; and

b. Adding paragraph (c)(14).

The revision and addition reads as follows:
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§60.5420 What are my notification, reporting, and recordkeeping 

requirements?

* * * * *

(c) Recordkeeping requirements. You must maintain the 

records identified as specified in §60.7(f) and in paragraphs 

(c)(1) through (14) of this section. All records required by 

this subpart must be maintained either onsite or at the nearest 

local field office for at least 5 years.

* * * * *

(14) A log of records as specified in §§60.5412(d)(1)(iii) 

and 60.5413(e)(4) for all inspection, repair and maintenance 

activities for each control devices failing the visible 

emissions test.

13. Section 60.5430 is revised by:

a. Adding, in alphabetical order, a definition for the term 

“capital expenditure;” and

b. Revising the definition for “group 2 storage vessel.”

The addition and revision read as follows:

§60.5430 What definitions apply to this subpart?

* * * * *
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Capital expenditure means, in addition to the definition in 

40 CFR 60.2, an expenditure for a physical or operational change 

to an existing facility that:

(1) Exceeds P, the product of the facility's replacement 

cost, R, and an adjusted annual asset guideline repair 

allowance, A, as reflected by the following equation: P = R × A, 

where

(i) The adjusted annual asset guideline repair allowance, 

A, is the product of the percent of the replacement cost, Y, and 

the applicable basic annual asset guideline repair allowance, B, 

divided by 100 as reflected by the following equation:

A = Y × (B ÷ 100);

(ii) The percent Y is determined from the following 

equation: Y = 1.0 − 0.575 log X, where X is 2011 minus the year

of construction; and

(iii) The applicable basic annual asset guideline repair 

allowance, B, is 4.5.

* * * * *

Group 2 storage vessel means a storage vessel, as defined 

in this section, for which construction, modification or 

reconstruction has commenced after April 12, 2013, and on or 

before [date of publication in the Federal Register].
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* * * * *

14. Amend Table 3 to Subpart OOOO by revising entries 

“§60.15” and “§60.18” to read as follows:

Table 3 to Subpart OOOO of Part 60 – Applicability of General 

Provisions to Subpart OOOO

General 

Provisions 

Citation

Subject of 

Citation

Applies 

to 

subpart? Explanation

* * * * * * *

§60.15 Reconstruction Yes Except that 

§60.15(d) does not 

apply to pneumatic 

controllers, 

centrifugal 

compressors or 

storage vessels.

* * * * * * *

§60.18 General control 

device 

requirements

Yes

* * * * * * *

15. Add subpart OOOOa, consisting of sections 60.5360a through 

60.5430a, to part 60 to read as follows:

Subpart OOOOa—Standards of Performance for Crude Oil and Natural 

Gas Facilities for which Construction, Modification, or 
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Reconstruction Commenced after [date of publication in the 

Federal Register]

Sec.

60.5360a What is the purpose of this subpart?

60.5365a Am I subject to this subpart?

60.5370a When must I comply with this subpart?

60.5375a What methane and VOC standards apply to well affected 

facilities?

60.5380a What methane and VOC standards apply to centrifugal 

compressor affected facilities?

60.5385a What methane and VOC standards apply to reciprocating 

compressor affected facilities?

60.5390a What methane and VOC standards apply to pneumatic 

controller affected facilities?

§60.5393a What methane and VOC standards apply to pneumatic pump 

affected facilities?

60.5395a What VOC standards apply to storage vessel affected 

facilities?

60.5397a What fugitive emissions methane and VOC standards 

apply to the collection of fugitive emissions components at a 
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well site and the collection of fugitive emissions components at 

a compressor station?

60.5400a What equipment leak methane and VOC standards apply to 

affected facilities at an onshore natural gas processing plant?

60.5401a What are the exceptions to the equipment leak methane 

and VOC standards for affected facilities at onshore natural gas 

processing plants?

60.5402a What are the alternative emission limitations for 

equipment leaks from onshore natural gas processing plants?

60.5405a What standards apply to sweetening unit affected 

facilities at onshore natural gas processing plants?

60.5406a What test methods and procedures must I use for my 

sweetening unit affected facilities at onshore natural gas 

processing plants?

60.5407a What are the requirements for monitoring of emissions 

and operations from my sweetening unit affected facilities at 

onshore natural gas processing plants?

60.5408a What is an optional procedure for measuring hydrogen 

sulfide in acid gas—Tutwiler Procedure?

60.5410a How do I demonstrate initial compliance with the 

standards for my well, centrifugal compressor, reciprocating 

compressor, pneumatic controller, pneumatic pump, storage 
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vessel, collection of fugitive emissions components at a well 

site, and collection of fugitive emissions components at a 

compressor station, and equipment leaks and sweetening unit 

affected facilities at onshore natural gas processing plants?

60.5411a What additional requirements must I meet to determine 

initial compliance for my covers and closed vent systems routing 

emissions from centrifugal compressor wet seal fluid degassing 

systems, reciprocating compressors, pneumatic pump and storage 

vessels?

60.5412a What additional requirements must I meet for 

determining initial compliance with control devices used to 

comply with the emission standards for my centrifugal 

compressor, pneumatic pump and storage vessel affected 

facilities?

60.5413a What are the performance testing procedures for 

control devices used to demonstrate compliance at my centrifugal 

compressor, pneumatic pump and storage vessel affected 

facilities?

60.5415a How do I demonstrate continuous compliance with the 

standards for my well, centrifugal compressor, reciprocating 

compressor, pneumatic controller, pneumatic pump, storage 

vessel, collection of fugitive emissions components at a well 
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site, and collection of fugitive emissions components at a 

compressor station affected facilities, and affected facilities 

at onshore natural gas processing plants?

60.5416a What are the initial and continuous cover and closed 

vent system inspection and monitoring requirements for my 

centrifugal compressor, reciprocating compressor, pneumatic 

pump, and storage vessel affected facilities?

60.5417a What are the continuous control device monitoring 

requirements for my centrifugal compressor, pneumatic pump, and 

storage vessel affected facilities?

60.5420a What are my notification, reporting, and recordkeeping 

requirements?

60.5421a What are my additional recordkeeping requirements for 

my affected facility subject to methane and VOC requirements for 

onshore natural gas processing plants?

60.5422a What are my additional reporting requirements for my 

affected facility subject to methane and VOC requirements for 

onshore natural gas processing plants?

60.5423a What additional recordkeeping and reporting 

requirements apply to my sweetening unit affected facilities at 

onshore natural gas processing plants?

60.5425a What parts of the General Provisions apply to me?
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60.5430a What definitions apply to this subpart?

60.5431a – 60.5499a [Reserved]

Table 1 to Subpart OOOOa of Part 60 – Required Minimum Initial 

SO2 Emission Reduction Efficiency (Zi)

Table 2 to Subpart OOOOa of Part 60 – Required Minimum SO2

Emission Reduction Efficiency (Zc)

Table 3 to Subpart OOOOa of Part 60 – Applicability of General 

Provisions to Subpart OOOOa

Subpart OOOOa—Standards of Performance for Crude Oil and Natural 

Gas Facilities for which Construction, Modification or 

Reconstruction Commenced After [date of publication in the 

Federal Register]

§60.5360a What is the purpose of this subpart?

This subpart establishes emission standards and compliance 

schedules for the control of methane, volatile organic compounds 

(VOC) and sulfur dioxide (SO2) emissions from affected facilities 

in the crude oil and natural gas source category that commence 

construction, modification or reconstruction after [date of 

publication in the Federal Register]. The effective date of the 

rule is [date 60 days after publication of final rule in the 

Federal Register]. 

§60.5365a Am I subject to this subpart?
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You are subject to the applicable provisions of this 

subpart if you are the owner or operator of one or more of the 

onshore affected facilities listed in paragraphs (a) through (j) 

of this section for which you commence construction, 

modification or reconstruction after [date of publication in the 

Federal Register].

(a) Each well affected facility, which is a single well 

that conducts a well completion operation following hydraulic 

fracturing or refracturing and has a gas-to-oil ratio of greater 

than 300 scf of gas per barrel of oil produced. The provisions 

of this paragraph do not affect the affected facility status of 

well sites for the purposes of §60.5397a. The provisions of 

paragraphs (a)(1) through (4) of this section apply to wells 

that are hydraulically refractured: 

(1) A well that conducts a well completion operation 

following hydraulic refracturing is not an affected facility, 

provided that the requirements of §60.5375a(a)(1) through (4) 

are met. However, hydraulic refracturing of a well constitutes a 

modification of the well site for purposes of §60.5397a, 

regardless of affected facility status of the well itself.
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(2) A well completion operation following hydraulic 

refracturing not conducted pursuant to §60.5375a(a)(1) through 

(4) is a modification to the well.

(3) Refracturing of a well does not affect the modification 

status of other equipment, process units, storage vessels, 

compressors, pneumatic pumps, or pneumatic controllers. 

(4) A well initially constructed after [date of publication 

in the Federal Register], that conducts a well completion 

operation following hydraulic refracturing is considered an 

affected facility regardless of this provision.

(b) Each centrifugal compressor affected facility, which is 

a single centrifugal compressor using wet seals. A centrifugal 

compressor located at a well site, or an adjacent well site and 

servicing more than one well site, is not an affected facility 

under this subpart.

(c) Each reciprocating compressor affected facility, which 

is a single reciprocating compressor. A reciprocating compressor 

located at a well site, or an adjacent well site and servicing 

more than one well site, is not an affected facility under this 

subpart.

(d)(1) Each pneumatic controller affected facility not 

located at a natural gas processing plant, which is a single 
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continuous bleed natural gas-driven pneumatic controller 

operating at a natural gas bleed rate greater than 6 scfh.

(2) Each pneumatic controller affected facility located at 

a natural gas processing plant, which is a single continuous 

bleed natural gas-driven pneumatic controller.

(e) Each storage vessel affected facility, which is a 

single storage vessel with the potential for VOC emissions equal 

to or greater than 6 tpy as determined according to this 

section, except as provided in paragraphs (e)(1) through (4) of 

this section. The potential for VOC emissions must be calculated 

using a generally accepted model or calculation methodology, 

based on the maximum average daily throughput determined for a 

30-day period of production prior to the applicable emission 

determination deadline specified in this section. The 

determination may take into account requirements under a legally 

and practically enforceable limit in an operating permit or 

other requirement established under a Federal, State, local or 

tribal authority.

(1) For each new, modified or reconstructed storage vessel 

receiving liquids pursuant to the standards for well affected 

facilities in §60.5375a, including wells subject to 
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§60.5375a(f), you must determine the potential for VOC emissions 

within 30 days after startup of production.

(2) A storage vessel affected facility that subsequently 

has its potential for VOC emissions decrease to less than 6 tpy 

shall remain an affected facility under this subpart.

(3) For storage vessels not subject to a legally and 

practically enforceable limit in an operating permit or other 

requirement established under Federal, state, local or tribal 

authority, any vapor from the storage vessel that is recovered 

and routed to a process through a VRU designed and operated as 

specified in this section is not required to be included in the 

determination of VOC potential to emit for purposes of 

determining affected facility status, provided you comply with 

the requirements in paragraphs (e)(3)(i) through (iv) of this 

section.

(i) You meet the cover requirements specified in 

§60.5411a(b).

(ii) You meet the closed vent system requirements specified 

in §60.5411a(c).

(iii) You maintain records that document compliance with 

paragraphs (e)(3)(i) and (ii) of this section.
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(iv) In the event of removal of apparatus that recovers and 

routes vapor to a process, or operation that is inconsistent 

with the conditions specified in paragraphs (e)(3)(i) and (ii) 

of this section, you must determine the storage vessel's 

potential for VOC emissions according to this section within 30 

days of such removal or operation.

(4) For each new, reconstructed, or modified storage vessel 

with startup, startup of production, or which is returned to 

service, affected facility status is determined as follows: If a 

storage vessel is reconnected to the original source of liquids 

or is used to replace any storage vessel affected facility, it 

is a storage vessel affected facility subject to the same 

requirements as before being removed from service, or applicable 

to the storage vessel affected facility being replaced, 

immediately upon startup, startup of production, or return to 

service.

(f) The group of all equipment, except compressors, within 

a process unit is an affected facility.

(1) Addition or replacement of equipment for the purpose of 

process improvement that is accomplished without a capital 

expenditure shall not by itself be considered a modification 

under this subpart.
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(2) Equipment associated with a compressor station, 

dehydration unit, sweetening unit, underground storage vessel, 

field gas gathering system, or liquefied natural gas unit is 

covered by §§60.5400a, 60.5401a, 60.5402a, 60.5421a, and 

60.5422a of this subpart if it is located at an onshore natural 

gas processing plant. Equipment not located at the onshore 

natural gas processing plant site is exempt from the provisions 

of §§60.5400a, 60.5401a, 60.5402a, 60.5421a, and 60.5422a of 

this subpart.

(3) The equipment within a process unit of an affected 

facility located at onshore natural gas processing plants and 

described in paragraph (f) of this section are exempt from this 

subpart if they are subject to and controlled according to 

subparts VVa, GGG or GGGa of this part.

(g) Sweetening units located at onshore natural gas 

processing plants that process natural gas produced from either 

onshore or offshore wells.

(1) Each sweetening unit that processes natural gas is an 

affected facility; and

(2) Each sweetening unit that processes natural gas 

followed by a sulfur recovery unit is an affected facility.
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(3) Facilities that have a design capacity less than 2 long 

tons per day (LT/D) of hydrogen sulfide (H2S) in the acid gas 

(expressed as sulfur) are required to comply with recordkeeping 

and reporting requirements specified in §60.5423a(c) but are not 

required to comply with §§60.5405a through 60.5407a and 

§§60.5410a(g) and 60.5415a(g) of this subpart.

(4) Sweetening facilities producing acid gas that is 

completely reinjected into oil-or-gas-bearing geologic strata or 

that is otherwise not released to the atmosphere are not subject 

to §§60.5405a through 60.5407a, 60.5410a(g), 60.5415a(g), and 

60.5423a of this subpart.

(h)(1) For natural gas processing plants, each pneumatic 

pump affected facility, which is a single natural gas-driven 

chemical/methanol pump or natural gas-driven diaphragm pump.

(2) For locations other than natural gas processing plants, 

each pneumatic pump affected facility, which is a single natural 

gas-driven chemical/methanol pump or natural gas-driven 

diaphragm pump for which a control device is located on site. 

(i) The (i) Except as provided in §60.5365a(i)(1)

through (i)(2), the collection of fugitive emissions components 

at a well site, as defined in §60.5430a, is an affected 
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facility. For purposes of §60.5397a, a “modification” to a well 

site occurs when: 

(1(1) A well site with average combined oil and 

natural gas production for the wells at the site being less than 

15 barrels of oil equivalent (boe) per day averaged over the 

first 30 days of production, is not an affected facility under 

this subpart.

(2) A well site that only contains one or more wellheads is 

not an affected facility under this subpart.

(3) For purposes of §60.5397a, a “modification” to a well 

site occurs when: 

(i) a new well is drilled at an existing well site; or 

(2ii) a well at an existing well site is hydraulically 

fractured; or 

(iii) a well at an existing well site is hydraulically 

refractured.

(j) The collection of fugitive emissions components at a 

compressor station, as defined in §60.5430a, is an affected 

facility. For purposes of §60.5397a, a “modification” to a 

compressor station occurs when:

(1) A new compressor is constructed at an existing 

compressor station; or

Formatted: Indent: First line: 0.5"
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(2) A physical change is made to an existing compressor at 

a compressor station that increases the compression capacity of 

the compressor station. 

(3) Reserved 

§60.5370a When must I comply with this subpart?

(a) You must be in compliance with the standards of this 

subpart no later than [date 60 days after publication of final 

rule in the Federal Register] or upon startup, whichever is 

later.

(b) The provisions for exemption from compliance during 

periods of startup, shutdown and malfunctions provided for in 40 

CFR 60.8(c) do not apply to this subpart.

(c) You are exempt from the obligation to obtain a permit 

under 40 CFR part 70 or 40 CFR part 71, provided you are not 

otherwise required by law to obtain a permit under 40 CFR 

70.3(a) or 40 CFR 71.3(a). Notwithstanding the previous 

sentence, you must continue to comply with the provisions of 

this subpart.

§60.5375a What methane and VOC standards apply to well affected 

facilities?
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If you are the owner or operator of a well affected 

facility, you must reduce methane and VOC emissions by complying 

with paragraphs (a) through (f) of this section.

(a) Except as provided in paragraph (f) of this section, 

for each well completion operation with hydraulic fracturing you 

must comply with the requirements in paragraphs (a)(1) through 

(4) of this section. You must maintain a log as specified in 

paragraph (b) of this section.

(1) For each stage of the well completion operation, as 

defined in §60.5430a, follow the requirements specified in 

paragraphs (a)(1)(i) and (ii) of this section.

(i) During the initial flowback stage, route the flowback 

into one or more well completion vessels or storage vessels and 

commence operation of a separator unless it is technically 

infeasible for a separator to function. Any gas present in the 

initial flowback stage is not subject to control under this 

section.

(ii) During the separation flowback stage, route all 

recovered liquids from the separator to one or more well 

completion vessels or storage vessels, re-inject the recovered 

liquids into the well or another well or route the recovered 

liquids to a collection system. Route the recovered gas from the 
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separator into a gas flow line or collection system, re-inject 

the recovered gas into the well or another well, use the 

recovered gas as an on-site fuel source, or use the recovered 

gas for another useful purpose that a purchased fuel or raw 

material would serve. If it is technically infeasible to route 

the recovered gas as required above, follow the requirements in 

paragraph (a)(3) of this section. If, at any time during the 

separation flowback stage, it is not technically feasible for a 

separator to function, you must comply with (a)(1)(i) of this 

section.

(2) All salable quality recovered gas must be routed to the 

gas flow line as soon as practicable. In cases where salable 

quality gas cannot be directed to the flow line due to technical 

infeasibility, you must follow the requirements in paragraph 

(a)(3) of this section.

(3) You must capture and direct recovered gas to a 

completion combustion device, except in conditions that may 

result in a fire hazard or explosion, or where high heat 

emissions from a completion combustion device may negatively 

impact tundra, permafrost or waterways. Completion combustion 

devices must be equipped with a reliable continuous ignition 

source.
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(4) You have a general duty to safely maximize resource 

recovery and minimize releases to the atmosphere during flowback 

and subsequent recovery.

(b) You must maintain a log for each well completion 

operation at each well affected facility. The log must be 

completed on a daily basis for the duration of the well 

completion operation and must contain the records specified in 

§60.5420a(c)(1)(iii).

(c) You must demonstrate initial compliance with the 

standards that apply to well affected facilities as required by 

§60.5410a.

(d) You must demonstrate continuous compliance with the 

standards that apply to well affected facilities as required by 

§60.5415a.

(e) You must perform the required notification, 

recordkeeping and reporting as required by §60.5420a.

(f)(1) For each well affected facility specified in 

paragraphs (f)(1)(i) and (ii) of this section, you must comply 

with the requirements of paragraphs (f)(2) and (3) of this 

section.

(i) Each well completion operation with hydraulic 

fracturing at a wildcat or delineation well.
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(ii) Each well completion operation with hydraulic 

fracturing at a non-wildcat low pressure well or non-delineation 

low pressure well.

(2) Route the flowback into one or more well completion 

vessels and commence operation of a separator unless it is 

technically infeasible for a separator to function. Any gas 

present in the flowback before the separator can function is not 

subject to control under this section. You must capture and 

direct recovered gas to a completion combustion device, except 

in conditions that may result in a fire hazard or explosion, or 

where high heat emissions from a completion combustion device 

may negatively impact tundra, permafrost or waterways. 

Completion combustion devices must be equipped with a reliable 

continuous ignition source. You must also comply with paragraphs 

(a)(4) and (b) through (e) of this section.

(3) You must maintain records specified in 

§60.5420a(c)(1)(iii) for wildcat, delineation and low pressure 

wells.

§60.5380a What methane and VOC standards apply to centrifugal 

compressor affected facilities?
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You must comply with the methane and VOC standards in 

paragraphs (a) through (d) of this section for each centrifugal 

compressor affected facility.

(a)(1) You must reduce methane and VOC emissions from each 

centrifugal compressor wet seal fluid degassing system by 95.0 

percent or greater.

(2) If you use a control device to reduce emissions, you 

must equip the wet seal fluid degassing system with a cover that 

meets the requirements of §60.5411a(b). The cover must be 

connected through a closed vent system that meets the 

requirements of §60.5411a(a) and the closed vent system must be 

routed to a control device that meets the conditions specified 

in §60.5412a(a), (b) and (c). As an alternative to routing the 

closed vent system to a control device, you may route the closed 

vent system to a process.

(b) You must demonstrate initial compliance with the 

standards that apply to centrifugal compressor affected 

facilities as required by §60.5410a(b).

(c) You must demonstrate continuous compliance with the 

standards that apply to centrifugal compressor affected 

facilities as required by §60.5415a(b).
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(d) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420a.

§60.5385a What methane and VOC standards apply to reciprocating 

compressor affected facilities?

You must reduce methane and VOC emissions by complying with 

the standards in paragraphs (a) through (d) of this section for 

each reciprocating compressor affected facility.

(a) You must replace the reciprocating compressor rod 

packing according to either paragraph (a)(1) or (2) of this 

section or you must comply with paragraph (a)(3) of this 

section.

(1) Before the compressor has operated for 26,000 hours. 

The number of hours of operation must be continuously monitored 

beginning upon initial startup of your reciprocating compressor 

affected facility, or the date of the most recent reciprocating 

compressor rod packing replacement, whichever is later.

(2) Prior to 36 months from the date of the most recent rod 

packing replacement, or 36 months from the date of startup for a 

new reciprocating compressor for which the rod packing has not 

yet been replaced.

(3) Collect the methane and VOC emissions from the rod 

packing using a rod packing emissions collection system which 
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operates under negative pressure and route the rod packing 

emissions to a process through a closed vent system that meets 

the requirements of §60.5411a(a).

(b) You must demonstrate initial compliance with standards 

that apply to reciprocating compressor affected facilities as 

required by §60.5410a.

(c) You must demonstrate continuous compliance with 

standards that apply to reciprocating compressor affected 

facilities as required by §60.5415a.

(d) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420a.

§60.5390a What methane and VOC standards apply to pneumatic 

controller affected facilities?

For each pneumatic controller affected facility you must 

comply with the methane and VOC standards, based on natural gas 

as a surrogate for methane and VOC, in either paragraph (b)(1) 

or (c)(1) of this section, as applicable. Pneumatic controllers 

meeting the conditions in paragraph (a) of this section are 

exempt from this requirement.

(a) The requirements of paragraph (b)(1) or (c)(1) of this 

section are not required if you determine that the use of a 

pneumatic controller affected facility with a bleed rate greater 
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than the applicable standard is required based on functional 

needs, including but not limited to response time, safety and 

positive actuation. However, you must tag such pneumatic 

controller with the month and year of installation, 

reconstruction or modification, and identification information 

that allows traceability to the records for that pneumatic 

controller, as required in §60.5420a(c)(4)(ii).

(b)(1) Each pneumatic controller affected facility at a 

natural gas processing plant must have a bleed rate of zero.

(2) Each pneumatic controller affected facility at a 

natural gas processing plant must be tagged with the month and 

year of installation, reconstruction or modification, and 

identification information that allows traceability to the 

records for that pneumatic controller as required in 

§60.5420a(c)(4)(iv).

(c)(1) Each pneumatic controller affected facility at a 

location other than at a natural gas processing plant must have 

a bleed rate less than or equal to 6 standard cubic feet per 

hour.

(2) Each pneumatic controller affected facility 

constructed, modified or reconstructed on or after October 15, 

2013, at a location other than at a natural gas processing plant 
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must be tagged with the month and year of installation, 

reconstruction or modification, and identification information 

that allows traceability to the records for that controller as 

required in §60.5420a(c)(4)(iii).

(d) You must demonstrate initial compliance with standards 

that apply to pneumatic controller affected facilities as 

required by §60.5410a.

(e) You must demonstrate continuous compliance with 

standards that apply to pneumatic controller affected facilities 

as required by §60.5415a.

(f) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420a, except 

that you are not required to submit the notifications specified 

in §60.5420a(a).

§60.5393a What methane and VOC standards apply to pneumatic pump 

affected facilities?

For each pneumatic pump affected facility you must comply 

with the methane and VOC standards, based on natural gas as a 

surrogate for methane and VOC, in either paragraph (a)(1) or 

(b)(1) of this section, as applicable. 
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(a)(1) Each pneumatic pump affected facility at a natural 

gas processing plant must have a natural gas emission rate of 

zero.

(2) Each pneumatic pump affected facility at a natural gas 

processing plant must be tagged with the month and year of 

installation, reconstruction or modification, and identification 

information that allows traceability to the records for that 

pneumatic pump as required in §60.5420a(c)(16)(i).

(b)(1) Each pneumatic pump affected facility at a location 

other than a natural gas processing plant must reduce natural 

gas emissions by 95.0 percent, except as provided in paragraph 

(b)(2) of this section.

(2) You are not required to install a control device solely 

for the purposes of complying with the 95.0 percent reduction of 

paragraph (b)(1) of this section. If you do not have a control 

device installed on-site by the compliance date, then you must 

comply instead with the provisions of paragraphs (b)(2)(i) and 

(ii) of this section.

(i) Submit a certification in accordance with 

§60.5420(b)(8)(i).

(ii) If you subsequently install a control device, you are 

no longer required to submit the certification in 
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§60.5420(b)(8)(i) and must be in compliance with the 

requirements of paragraph (b)(1) of this section within 30 days 

of installation of the control device. Compliance with this 

requirement should be reported in the next annual report in 

accordance with §60.5420(b)(8)(iii). 

(3) Each pneumatic pump affected facility at a location 

other than a natural gas processing plant must be tagged with 

the month and year of installation, reconstruction or 

modification, and identification information that allows 

traceability to the records for that pump as required in 

§60.5420a(c)(16)(i).

(4) If you use a control device to reduce emissions, you 

must connect the pneumatic pump affected facility through a 

closed vent system that meets the requirements of §60.5411a(a) 

and route emissions to a control device that meets the 

conditions specified in §60.5412a(a), (b) and (c) and 

performance tested in accordance with §60.5413a. As an 

alternative to routing the closed vent system to a control 

device, you may route the closed vent system to a process.

(c) You must demonstrate initial compliance with standards 

that apply to pneumatic pump affected facilities as required by 

§60.5410a.
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(d) You must demonstrate continuous compliance with 

standards that apply to pneumatic pump affected facilities as 

required by §60.5415a.

(e) You must perform the required notification, 

recordkeeping, and reporting as required by §60.5420a, except 

that you are not required to submit the notifications specified 

in §60.5420a(a).

§60.5395a What VOC standards apply to storage vessel affected 

facilities?

Except as provided in paragraph (e) of this section, you 

must comply with the VOC standards in this section for each 

storage vessel affected facility.

(a) You must comply with either the requirements of 

paragraphs (a)(1) and (a)(2) or the requirements of paragraph 

(a)(3) of this section. If you choose to meet the requirements 

in paragraph (a)(3) of this section, you are not required to 

comply with the requirements of paragraph (a)(2) of this section 

except as provided in paragraphs (a)(3)(i) and (ii) of this 

section.

(1) Determine potential for VOC emissions in accordance 

with §60.5365a(e). 
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(2) Reduce VOC emissions by 95.0 percent within 60 days 

after startup. For storage vessel affected facilities receiving 

liquids pursuant to the standards for well affected facilities 

in §60.5375a, you must achieve the required emissions reductions 

within 60 days after startup of production as defined in 

§60.5430a. 

(3) Maintain the uncontrolled actual VOC emissions from the 

storage vessel affected facility at less than 4 tpy without 

considering control. Prior to using the uncontrolled actual VOC 

emission rate for compliance purposes, you must demonstrate that 

the uncontrolled actual VOC emissions have remained less than 4 

tpy as determined monthly for 12 consecutive months. After such 

demonstration, you must determine the uncontrolled actual VOC 

emission rate each month. The uncontrolled actual VOC emissions 

must be calculated using a generally accepted model or 

calculation methodology, and the calculations must be based on 

the average throughput for the month. You must comply with 

paragraph (a)(2) of this section if your storage vessel affected 

facility meets the conditions specified in paragraphs (a)(3)(i) 

or (ii) of this section.

(i) If a well feeding the storage vessel affected facility 

undergoes fracturing or refracturing, you must comply with 
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paragraph (a)(2) of this section as soon as liquids from the 

well following fracturing or refracturing are routed to the 

storage vessel affected facility.

(ii) If the monthly emissions determination required in 

this section indicates that VOC emissions from your storage 

vessel affected facility increase to 4 tpy or greater and the 

increase is not associated with fracturing or refracturing of a 

well feeding the storage vessel affected facility, you must 

comply with paragraph (a)(2) of this section within 30 days of 

the monthly determination.

(b) Control requirements. (1) Except as required in 

paragraph (b)(2) of this section, if you use a control device to 

reduce VOC emissions from your storage vessel affected facility, 

you must equip the storage vessel with a cover that meets the 

requirements of §60.5411a(b) and is connected through a closed 

vent system that meets the requirements of §60.5411a(c), and you 

must route emissions to a control device that meets the

conditions specified in §60.5412a(c) and (d). As an alternative 

to routing the closed vent system to a control device, you may 

route the closed vent system to a process that reduces VOC 

emissions by at least 95.0 percent.
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(2) If you use a floating roof to reduce emissions, you 

must meet the requirements of §60.112b(a)(1) or (2) and the 

relevant monitoring, inspection, recordkeeping, and reporting 

requirements in 40 CFR part 60, subpart Kb.

(c) Requirements for storage vessel affected facilities 

that are removed from service or returned to service. If you 

remove a storage vessel affected facility from service, you must 

comply with paragraphs (c)(1) through (3) of this section. A 

storage vessel is not an affected facility under this subpart 

for the period that it is removed from service.

(1) For a storage vessel affected facility to be removed 

from service, you must comply with the requirements of paragraph 

(c)(1)(i) and (ii) of this section.

(i) You must completely empty and degas the storage vessel, 

such that the storage vessel no longer contains crude oil, 

condensate, produced water or intermediate hydrocarbon liquids. 

A storage vessel where liquid is left on walls, as bottom 

clingage or in pools due to floor irregularity is considered to 

be completely empty.

(ii) You must submit a notification as required in 

§60.5420a(b)(6)(v) in your next annual report, identifying each 
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storage vessel affected facility removed from service during the 

reporting period and the date of its removal from service.

(2) If a storage vessel identified in paragraph (c)(1)(ii) 

of this section is returned to service, you must determine its 

affected facility status as provided in §60.5365a(e).

(3) For each storage vessel affected facility returned to 

service during the reporting period, you must submit a 

notification in your next annual report as required in 

§60.5420a(b)(6)(vi), identifying each storage vessel affected 

facility and the date of its return to service.

(d) Compliance, notification, recordkeeping, and reporting. 

You must comply with paragraphs (d)(1) through (3) of this 

section.

(1) You must demonstrate initial compliance with standards 

as required by §60.5410a(h) and (i).

(2) You must demonstrate continuous compliance with 

standards as required by §60.5415a(e)(3).

(3) You must perform the required notification, 

recordkeeping and reporting as required by §60.5420a.

(e) Exemptions. This subpart does not apply to storage 

vessels subject to and controlled in accordance with the 
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requirements for storage vessels in 40 CFR part 60, subpart Kb, 

40 CFR part 63, subparts G, CC, HH, or WW.

§60.5397a What fugitive emissions methane and VOC standards 

apply to the affected facility which is the collection of 

fugitive emissions components at a well site and the affected 

facility which is the collection of fugitive emissions 

components at a compressor station?

For each affected facility under §60.5365a(i) and (j), you 

must reduce methane and VOC emissions by complying with the 

requirements of paragraphs (a) through (l) of this section. 

These requirements are independent of the closed vent system and 

cover requirements in §60.5411a. 

(a) You must monitor all fugitive emission components, as 

defined in 60.5430a, in accordance with paragraphs (b) through 

(i). You must repair all sources of fugitive emissions in 

accordance with paragraph (j). You must keep records in 

accordance with paragraph (k) and report in accordance with 

paragraph (l). For purposes of this section, fugitive emissions 

are defined as: any visible emission from a fugitive emissions 

component observed using optical gas imaging. 

 (b) You must develop a corporate-wide fugitive emissions 

monitoring plan that covers the collection of fugitive emissions 
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components at well sites and compressor stations in accordance 

with paragraph (c) of this section, and you must develop a sitespecific fugitive emissions monitoring plan specific to each 

collection of fugitive emissions components at a well site and 

each collection of fugitive emissions components at a compressor 

station in accordance with paragraph (d) of this section. 

Alternatively, you may develop a site-specific plan for each 

collection of fugitive emissions components at a well site and 

each collection of fugitive emissions components at a compressor 

station that covers the elements of both the corporate-wide and 

site-specific plans.

(c) Your corporate-wide monitoring plan must include the 

elements specified in paragraphs (c)(1) through (8) of this 

section, as a minimum.

(1) Frequency for conducting surveys. Surveys must be 

conducted at least as frequently as required by paragraphs (f) 

through (i) of this section.

(2) Technique for determining fugitive emissions.

(3) Manufacturer and model number of fugitive emissions 

detection equipment to be used.

(4) Procedures and timeframes for identifying and repairing 

fugitive emissions components from which fugitive emissions are 
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detected, including timeframes for fugitive emission components 

that are unsafe to repair. Your repair schedule must meet the 

requirements of paragraph (j) of this section at a minimum.

(5) Procedures and timeframes for verifying fugitive 

emission component repairs.

(6) Records that will be kept and the length of time 

records will be kept.

(7) Your plan must also include the elements specified in 

paragraphs (c)(7)(i) through (vii) of this section.

(i) Verification that your optical gas imaging equipment 

meets the specifications of paragraphs (c)(7)(i)(A) and (B) of 

this section. This verification is an initial verification and 

may either be performed by the facility, by the manufacturer, or 

by a third-party. For the purposes of complying with the 

fugitives emissions monitoring program with optical gas imaging, 

a fugitive emission is defined as any visible emissions observed 

using optical gas imaging. 

(A) Your optical gas imaging equipment must be capable of 

imaging gases in the spectral range for the compound of highest 

concentration in the potential fugitive emissions.

(B) Your optical gas imaging equipment must be capable of 

imaging a gas that is half methane, half propane at a 
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concentration of ≤10,000 ppm at a flow rate of ≥60g/hr from a 

quarter inch diameter orifice.

(ii) Procedure for a daily verification check.

(iii) Procedure for determining the operator’s maximum 

viewing distance from the equipment and how the operator will 

ensure that this distance is maintained.

(iv) Procedure for determining maximum wind speed during 

which monitoring can be performed and how the operator will 

ensure monitoring occurs only at wind speeds below this 

threshold.

(v) Procedures for conducting surveys, including the items 

specified in paragraphs (c)(7)(v)(A) through (C) of this 

section.

(A) How the operator will ensure an adequate thermal 

background is present in order to view potential fugitive 

emissions.

(B) How the operator will deal with adverse monitoring 

conditions, such as wind.

(C) How the operator will deal with interferences (e.g., 

steam).

(vi) Training and experience needed prior to performing 

surveys.
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(vii) Procedures for calibration and maintenance. 

Procedures must comply with those recommended by the 

manufacturer.

(d) Your site-specific monitoring plan must include the 

elements specified in paragraphs (d)(1) through (3) of this 

section, as a minimum.

(1) Deviations from your master plan.

(2) Sitemap.

(3) Your plan must also include your defined walking path. 

The walking path must ensure that all fugitive emissions 

components are within sight of the path and must account for 

interferences.

(e) Each monitoring survey shall observe each fugitive 

emissions component for fugitive emissions.

(f)(1) You must conduct an initial monitoring survey within 

30 days of the first well completion for each collection of 

fugitive emissions components at a new well site or upon the 

date the well site begins the production phase for other wells. 

For a modified collection of fugitive emissions components at a 

well site, the initial monitoring survey must be conducted 

within 30 days of the well site modification.
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(2) You must conduct an initial monitoring survey within 30 

days of the startup of a new compressor station for each new 

collection of fugitive emissions components at the new 

compressor station. For modified compressor stations, the 

initial monitoring survey of the collection of fugitive 

emissions components at a modified compressor station must be 

conducted within 30 days of the modification.

(g) A monitoring survey of each collection of fugitive 

emissions components at a well site and collection of fugitive 

emissions components at a compressor station shall be conducted 

at least semiannually after the initial survey. Consecutive 

semiannual monitoring surveys shall be conducted at least 4

months apart.

(h) The monitoring frequency specified in paragraph (g) of 

this section shall be increased to quarterly in the event that 

two consecutive semiannual monitoring surveys detect fugitive 

emissions at greater than 5.0 percent of the fugitive emissions 

components at a well site or at greater than 5.0 percent of the 

fugitive emissions components at a compressor station.

(i) The monitoring frequency specified in paragraph (g) of 

this section may be decreased to annual in the event that two 

consecutive semiannual surveys detect fugitive emissions at less 
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than 1.0 percent of the fugitive emissions components at a well 

site, or at less than 1.0 percent of the fugitive emissions 

components at a compressor station. The monitoring frequency 

shall return to semiannual if a survey detects fugitive 

emissions between 1.0 percent and 5.0 percent of the fugitive 

emissions components at the well site, or between 1.0 percent

and 5.0 percent of the fugitive emissions components at the 

compressor station, and shall return to quarterly if a survey 

detects fugitive emissions at greater than 5.0 percent of the 

fugitive emissions components at the well site, or greater than 

5.0 percent of the fugitive emissions components at the 

compressor station.

(j) For fugitive emissions components also subject to the 

repair provisions of §§60.5416a(b)(9) through (12) and (c)(4) 

through (7), those provisions apply instead to those closed vent 

system and covers, and the repair provisions of paragraphs 

(j)(1) and (2) of this section do not apply to those closed vent 

systems and covers. 

(1) Each identified source of fugitive emissions shall be 

repaired or replaced as soon as practicable, but no later than 

15 calendar days after detection of the fugitive emissions. If 

the repair or replacement is technically infeasible or unsafe to 
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repair during operation of the unit, the repair or replacement 

must be completed during the next scheduled shutdown or within 6 

months, whichever is earlier.

(2) Each repaired or replaced fugitive emissions component 

must be resurveyed as soon as practicable, but no later than 15 

days of finding such fugitive emissions, to ensure that there is 

no leak.

(i) For repairs that cannot be made during the monitoring 

survey when the fugitive emissions are initially found, the 

operator may resurvey the repaired fugitive emissions components 

using either Method 21 or optical gas imaging within 15 days of 

finding such fugitive emissions.

(ii) Operators that use Method 21 to resurvey the repaired 

fugitive emissions components, are subject to the resurvey 

provisions specified in paragraphs (j)(2)(ii)(A) and (B).

(A) A fugitive emissions component is repaired when the 

Method 21 instrument indicates a concentration of less than 500 

ppm above background.

(B) Operators must use the Method 21 monitoring 

requirements specified in paragraph §60.5401a(g).

(iii) Operators that use optical gas imaging to resurvey 

the repaired fugitive emissions components, are subject to the 
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resurvey provisions specified in paragraphs (j)(2)(iii)(A) and 

(B). 

(A) A fugitive emissions component is repaired when the 

optical gas imaging instrument shows no indication of visible 

emissions.

(B) Operators must use the optical gas imaging monitoring 

requirements specified in paragraph (a).

(k) Records for each monitoring survey shall be maintained 

as specified §60.5420a(c)(15) and must contain, at a minimum, 

the information specified in paragraphs (k)(1) through (6) of 

this section.

(1) Date of the survey.

(2) Beginning and end time of the survey.

(3) Name of operator(s) performing survey. You must note 

the training and experience of the operator.

(4) Ambient temperature, sky conditions, and maximum wind 

speed at the time of the survey.

(5) Any deviations from the monitoring plan or a statement 

that there were no deviations from the monitoring plan.

(6) Documentation of each source of fugitive emissions 

(e.g., fugitive emissions components), including the information 

specified in paragraphs (k)(6)(i) through (ii) of this section
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(i) Location.

(ii) One or more digital photographs of each required 

monitoring survey being performed. The digital photograph must 

include the date the photograph was taken and the latitude and 

longitude of the well site or compressor station imbedded within 

or stored with the digital file. As an alternative to imbedded 

latitude and longitude within the digital photograph, the 

digital photograph may consist of a photograph of the monitoring 

survey being performed with a photograph of a separately 

operating GIS device within the same digital picture, provided 

the latitude and longitude output of the GIS unit can be clearly 

read in the digital photograph.

(iii) The date of successful repair of the fugitive 

emissions component.

(iv) The instrument used to resurvey a repaired fugitive 

emissions component that could not be repaired during the 

initial fugitive emissions finding.

(l) Annual reports shall be submitted for each collection 

of fugitive emissions components at a well site and each 

collection of fugitive emissions components at a compressor 

station that include the information specified in 

§60.5420a(b)(7). Multiple collection of fugitive emissions 
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components at a well site or collection of fugitive emissions at 

a compressor station may be included in a single annual report.

§60.5400a What equipment leak methane and VOC standards apply to 

affected facilities at an onshore natural gas processing plant?

This section applies to the group of all equipment, except 

compressors, within a process unit.

(a) You must comply with the requirements of §§60.482-

1a(a), (b), and (d), 60.482-2a, and 60.482-4a through 60.482-

11a, except as provided in §60.5401a.

(b) You may elect to comply with the requirements of 

§§60.483-1a and 60.483-2a, as an alternative.

(c) You may apply to the Administrator for permission to 

use an alternative means of emission limitation that achieves a 

reduction in emissions of methane and VOC at least equivalent to 

that achieved by the controls required in this subpart according 

to the requirements of §60.5402a.

(d) You must comply with the provisions of §60.485a except 

as provided in paragraph (f) of this section.

(e) You must comply with the provisions of §§60.486a and 

60.487a of this part except as provided in §§60.5401a, 60.5421a, 

and 60.5422a.
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(f) You must use the following provision instead of 

§60.485a(d)(1): Each piece of equipment is presumed to be in VOC 

service or in wet gas service unless an owner or operator 

demonstrates that the piece of equipment is not in VOC service 

or in wet gas service. For a piece of equipment to be considered 

not in VOC service, it must be determined that the VOC content 

can be reasonably expected never to exceed 10.0 percent by 

weight. For a piece of equipment to be considered in wet gas 

service, it must be determined that it contains or contacts the 

field gas before the extraction step in the process. For 

purposes of determining the percent VOC content of the process 

fluid that is contained in or contacts a piece of equipment, 

procedures that conform to the methods described in ASTM E169-

93, E168-92, or E260-96 (incorporated by reference as specified 

in §60.17) must be used.

§60.5401a What are the exceptions to the methane and VOC 

equipment leak standards for affected facilities at onshore 

natural gas processing plants?

(a) You may comply with the following exceptions to the 

provisions of §60.5400a(a) and (b).

(b)(1) Each pressure relief device in gas/vapor service may 

be monitored quarterly and within 5 days after each pressure 
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release to detect leaks by the methods specified in §60.485a(b) 

except as provided in §60.5400a(c) and in paragraph (b)(4) of 

this section, and §60.482-4a(a) through (c) of subpart VVa of 

this part.

(2) If an instrument reading of 500 ppm or greater is 

measured, a leak is detected.

(3)(i) When a leak is detected, it must be repaired as soon 

as practicable, but no later than 15 calendar days after it is 

detected, except as provided in §60.482-9a.

(ii) A first attempt at repair must be made no later than 5 

calendar days after each leak is detected.

(4)(i) Any pressure relief device that is located in a 

nonfractionating plant that is monitored only by non-plant 

personnel may be monitored after a pressure release the next 

time the monitoring personnel are on-site, instead of within 5 

days as specified in paragraph (b)(1) of this section and 

§60.482-4a(b)(1) of subpart VVa of this part.

(ii) No pressure relief device described in paragraph 

(b)(4)(i) of this section may be allowed to operate for more 

than 30 days after a pressure release without monitoring.

(c) Sampling connection systems are exempt from the 

requirements of §60.482-5a.
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(d) Pumps in light liquid service, valves in gas/vapor and 

light liquid service, pressure relief devices in gas/vapor 

service, and connectors in gas/vapor service and in light liquid 

service that are located at a nonfractionating plant that does 

not have the design capacity to process 283,200 standard cubic 

meters per day (scmd) (10 million standard cubic feet per day) 

or more of field gas are exempt from the routine monitoring 

requirements of §§60.482-2a(a)(1), 60.482-7a(a), 60.482-11a(a), 

and paragraph (b)(1) of this section.

(e) Pumps in light liquid service, valves in gas/vapor and 

light liquid service, pressure relief devices in gas/vapor 

service, and connectors in gas/vapor service and in light liquid 

service within a process unit that is located in the Alaskan 

North Slope are exempt from the routine monitoring requirements 

of §§60.482-2a(a)(1), 60.482-7a(a), 60.482-11a(a), and paragraph 

(b)(1) of this section.

(f) An owner or operator may use the following provisions 

instead of §60.485a(e):

(1) Equipment is in heavy liquid service if the weight 

percent evaporated is 10 percent or less at 150°C (302°F) as 

determined by ASTM Method D86-96 (incorporated by reference as 

specified in §60.17).
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(2) Equipment is in light liquid service if the weight 

percent evaporated is greater than 10 percent at 150°C (302°F) 

as determined by ASTM Method D86-96 (incorporated by reference 

as specified in §60.17).

(g) An owner or operator may use the following provisions 

instead of §60.485a(b)(2): A calibration drift assessment shall 

be performed, at a minimum, at the end of each monitoring day. 

Check the instrument using the same calibration gas(es) that 

were used to calibrate the instrument before use. Follow the 

procedures specified in Method 21 of appendix A-7 of this part, 

Section 10.1, except do not adjust the meter readout to 

correspond to the calibration gas value. Record the instrument 

reading for each scale used as specified in §60.486a(e)(8). 

Divide these readings by the initial calibration values for each 

scale and multiply by 100 to express the calibration drift as a 

percentage. If any calibration drift assessment shows a negative 

drift of more than 10 percent from the initial calibration 

value, then all equipment monitored since the last calibration 

with instrument readings below the appropriate leak definition 

and above the leak definition multiplied by (100 minus the 

percent of negative drift/divided by 100) must be re-monitored. 

If any calibration drift assessment shows a positive drift of 
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more than 10 percent from the initial calibration value, then, 

at the owner/operator's discretion, all equipment since the last 

calibration with instrument readings above the appropriate leak 

definition and below the leak definition multiplied by (100 plus 

the percent of positive drift/divided by 100) may be remonitored.

§60.5402a What are the alternative emission limitations for 

methane and VOC equipment leaks from onshore natural gas 

processing plants?

(a) If, in the Administrator's judgment, an alternative 

means of emission limitation will achieve a reduction in methane 

and VOC emissions at least equivalent to the reduction in 

methane and VOC emissions achieved under any design, equipment, 

work practice or operational standard, the Administrator will 

publish, in the Federal Register, a notice permitting the use of 

that alternative means for the purpose of compliance with that 

standard. The notice may condition permission on requirements 

related to the operation and maintenance of the alternative 

means.

(b) Any notice under paragraph (a) of this section must be 

published only after notice and an opportunity for a public 

hearing.
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(c) The Administrator will consider applications under this 

section from either owners or operators of affected facilities, 

or manufacturers of control equipment.

(d) The Administrator will treat applications under this 

section according to the following criteria, except in cases 

where the Administrator concludes that other criteria are 

appropriate:

(1) The applicant must collect, verify and submit test 

data, covering a period of at least 12 months, necessary to 

support the finding in paragraph (a) of this section.

(2) If the applicant is an owner or operator of an affected 

facility, the applicant must commit in writing to operate and 

maintain the alternative means so as to achieve a reduction in 

methane and VOC emissions at least equivalent to the reduction 

in methane and VOC emissions achieved under the design, 

equipment, work practice or operational standard.

§60.5405a What standards apply to sweetening units at onshore 

natural gas processing plants?

(a) During the initial performance test required by 

§60.8(b), you must achieve at a minimum, an SO2 emission 

reduction efficiency (Zi) to be determined from Table 1 of this 
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subpart based on the sulfur feed rate (X) and the sulfur content 

of the acid gas (Y) of the affected facility.

(b) After demonstrating compliance with the provisions of 

paragraph (a) of this section, you must achieve at a minimum, an 

SO2 emission reduction efficiency (Zc) to be determined from 

Table 2 of this subpart based on the sulfur feed rate (X) and 

the sulfur content of the acid gas (Y) of the affected facility.

§60.5406a What test methods and procedures must I use for my 

sweetening units affected facilities at onshore natural gas 

processing plants?

(a) In conducting the performance tests required in §60.8, 

you must use the test methods in appendix A of this part or 

other methods and procedures as specified in this section, 

except as provided in paragraph §60.8(b).

(b) During a performance test required by §60.8, you must 

determine the minimum required reduction efficiencies (Z) of SO2

emissions as required in §60.5405a(a) and (b) as follows:

(1) The average sulfur feed rate (X) must be computed as 

follows:

XX = KKQQaaYY

Where:
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X = average sulfur feed rate, Mg/D (LT/D).

Qa = average volumetric flow rate of acid gas from sweetening 

unit, dscm/day (dscf/day).

Y = average H2S concentration in acid gas feed from sweetening 

unit, percent by volume, expressed as a decimal.

K = (32 kg S/kg-mole)/((24.04 dscm/kg-mole)(1000 kg S/Mg)).

= 1.331 × 10−3Mg/dscm, for metric units.

= (32 lb S/lb-mole)/((385.36 dscf/lb-mole)(2240 lb S/long ton)).

= 3.707 × 10−5 long ton/dscf, for English units.

(2) You must use the continuous readings from the process 

flowmeter to determine the average volumetric flow rate (Qa) in 

dscm/day (dscf/day) of the acid gas from the sweetening unit for 

each run.

(3) You must use the Tutwiler procedure in §60.5408a or a 

chromatographic procedure following ASTM E260-96 (incorporated 

by reference as specified in §60.17) to determine the H2S 

concentration in the acid gas feed from the sweetening unit (Y). 

At least one sample per hour (at equally spaced intervals) must 

be taken during each 4-hour run. The arithmetic mean of all 

samples must be the average H2S concentration (Y) on a dry basis 

for the run. By multiplying the result from the Tutwiler 
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procedure by 1.62 × 10−3, the units gr/100 scf are converted to 

volume percent.

(4) Using the information from paragraphs (b)(1) and (b)(3) 

of this section, Tables 1 and 2 of this subpart must be used to 

determine the required initial (Zi) and continuous (Zc) reduction

efficiencies of SO2 emissions.

(c) You must determine compliance with the SO2 standards in 

§60.5405a(a) or (b) as follows:

(1) You must compute the emission reduction efficiency (R) 

achieved by the sulfur recovery technology for each run using 

the following equation:

RR = (100SS) /(SS + EE)

(2) You must use the level indicators or manual soundings 

to measure the liquid sulfur accumulation rate in the product 

storage vessels. You must use readings taken at the beginning 

and end of each run, the tank geometry, sulfur density at the 

storage temperature, and sample duration to determine the sulfur 

production rate (S) in kg/hr (lb/hr) for each run.

(3) You must compute the emission rate of sulfur for each 

run as follows:

EE = CCeeQQssss/KK1

Where:
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E = emission rate of sulfur per run, kg/hr.

Ce = concentration of sulfur equivalent (SO2+ reduced sulfur), 

g/dscm (lb/dscf).

Qsd = volumetric flow rate of effluent gas, dscm/hr (dscf/hr).

K1 = conversion factor, 1000 g/kg (7000 gr/lb).

(4) The concentration (Ce) of sulfur equivalent must be the 

sum of the SO2 and TRS concentrations, after being converted to 

sulfur equivalents. For each run and each of the test methods 

specified in this paragraph (c) of this section, you must use a 

sampling time of at least 4 hours. You must use Method 1 of 

appendix A-1 of this part to select the sampling site. The 

sampling point in the duct must be at the centroid of the crosssection if the area is less than 5 m2 (54 ft2) or at a point no 

closer to the walls than 1 m (39 in) if the cross-sectional area 

is 5 m2 or more, and the centroid is more than 1 m (39 in) from 

the wall.

(i) You must use Method 6 of appendix A-4 of this part to 

determine the SO2 concentration. You must take eight samples of 

20 minutes each at 30-minute intervals. The arithmetic average 

must be the concentration for the run. The concentration must be 

multiplied by 0.5 × 10−3 to convert the results to sulfur 
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equivalent. In place of Method 6 of Appendix A of this part, you 

may use ANSI/ASME PTC 19.10-1981, Part 10 (manual portion only) 

(incorporated by reference as specified in §60.17)

(ii) You must use Method 15 of appendix A-5 of this part to 

determine the TRS concentration from reduction-type devices or 

where the oxygen content of the effluent gas is less than 1.0 

percent by volume. The sampling rate must be at least 3 

liters/min (0.1 ft3/min) to insure minimum residence time in the 

sample line. You must take sixteen samples at 15-minute 

intervals. The arithmetic average of all the samples must be the 

concentration for the run. The concentration in ppm reduced 

sulfur as sulfur must be multiplied by 1.333 × 10−3 to convert 

the results to sulfur equivalent.

(iii) You must use Method 16A of appendix A-6 of this part 

or Method 15 of appendix A-5 of this part or ANSI/ASME PTC

19.10-1981, Part 10 (manual portion only) (incorporated by 

reference as specified in §60.17) to determine the reduced 

sulfur concentration from oxidation-type devices or where the 

oxygen content of the effluent gas is greater than 1.0 percent 

by volume. You must take eight samples of 20 minutes each at 30-

minute intervals. The arithmetic average must be the 

concentration for the run. The concentration in ppm reduced 
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sulfur as sulfur must be multiplied by 1.333 × 10−3 to convert 

the results to sulfur equivalent.

(iv) You must use Method 2 of appendix A-1 of this part to 

determine the volumetric flow rate of the effluent gas. A 

velocity traverse must be conducted at the beginning and end of 

each run. The arithmetic average of the two measurements must be 

used to calculate the volumetric flow rate (Qsd) for the run. For 

the determination of the effluent gas molecular weight, a single 

integrated sample over the 4-hour period may be taken and 

analyzed or grab samples at 1-hour intervals may be taken, 

analyzed, and averaged. For the moisture content, you must take 

two samples of at least 0.10 dscm (3.5 dscf) and 10 minutes at 

the beginning of the 4-hour run and near the end of the time 

period. The arithmetic average of the two runs must be the 

moisture content for the run.

§60.5407a What are the requirements for monitoring of emissions 

and operations from my sweetening unit affected facilities at 

onshore natural gas processing plants?

(a) If your sweetening unit affected facility is located at 

an onshore natural gas processing plant and is subject to the 

provisions of §60.5405a(a) or (b) you must install, calibrate, 

maintain, and operate monitoring devices or perform measurements 
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to determine the following operations information on a daily 

basis:

(1) The accumulation of sulfur product over each 24-hour 

period. The monitoring method may incorporate the use of an 

instrument to measure and record the liquid sulfur production 

rate, or may be a procedure for measuring and recording the 

sulfur liquid levels in the storage vessels with a level 

indicator or by manual soundings, with subsequent calculation of 

the sulfur production rate based on the tank geometry, stored 

sulfur density, and elapsed time between readings. The method 

must be designed to be accurate within ±2 percent of the 24-hour 

sulfur accumulation.

(2) The H2S concentration in the acid gas from the 

sweetening unit for each 24-hour period. At least one sample per 

24-hour period must be collected and analyzed using the equation 

specified in §60.5406a(b)(1). The Administrator may require you 

to demonstrate that the H2S concentration obtained from one or 

more samples over a 24-hour period is within ±20 percent of the 

average of 12 samples collected at equally spaced intervals 

during the 24-hour period. In instances where the H2S 

concentration of a single sample is not within ±20 percent of 
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the average of the 12 equally spaced samples, the Administrator 

may require a more frequent sampling schedule.

(3) The average acid gas flow rate from the sweetening 

unit. You must install and operate a monitoring device to 

continuously measure the flow rate of acid gas. The monitoring 

device reading must be recorded at least once per hour during 

each 24-hour period. The average acid gas flow rate must be 

computed from the individual readings.

(4) The sulfur feed rate (X). For each 24-hour period, you 

must compute X using the equation specified in §60.5406a(b)(1).

(5) The required sulfur dioxide emission reduction 

efficiency for the 24-hour period. You must use the sulfur feed 

rate and the H2S concentration in the acid gas for the 24-hour 

period, as applicable, to determine the required reduction 

efficiency in accordance with the provisions of §60.5405a(b).

(b) Where compliance is achieved through the use of an 

oxidation control system or a reduction control system followed 

by a continually operated incineration device, you must install, 

calibrate, maintain, and operate monitoring devices and 

continuous emission monitors as follows:

(1) A continuous monitoring system to measure the total 

sulfur emission rate (E) of SO2 in the gases discharged to the 
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atmosphere. The SO2 emission rate must be expressed in terms of 

equivalent sulfur mass flow rates (kg/hr (lb/hr)). The span of 

this monitoring system must be set so that the equivalent 

emission limit of §60.5405a(b) will be between 30 percent and 70 

percent of the measurement range of the instrument system.

(2) Except as provided in paragraph (b)(3) of this section: 

A monitoring device to measure the temperature of the gas 

leaving the combustion zone of the incinerator, if compliance 

with §60.5405a(a) is achieved through the use of an oxidation 

control system or a reduction control system followed by a 

continually operated incineration device. The monitoring device 

must be certified by the manufacturer to be accurate to within 

±1 percent of the temperature being measured.

(3) When performance tests are conducted under the 

provision of §60.8 to demonstrate compliance with the standards 

under §60.5405a, the temperature of the gas leaving the 

incinerator combustion zone must be determined using the 

monitoring device. If the volumetric ratio of sulfur dioxide to 

sulfur dioxide plus total reduced sulfur (expressed as SO2) in 

the gas leaving the incinerator is equal to or less than 0.98, 

then temperature monitoring may be used to demonstrate that 

sulfur dioxide emission monitoring is sufficient to determine 
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total sulfur emissions. At all times during the operation of the 

facility, you must maintain the average temperature of the gas 

leaving the combustion zone of the incinerator at or above the 

appropriate level determined during the most recent performance 

test to ensure the sulfur compound oxidation criteria are met. 

Operation at lower average temperatures may be considered by the 

Administrator to be unacceptable operation and maintenance of 

the affected facility. You may request that the minimum 

incinerator temperature be reestablished by conducting new 

performance tests under §60.8.

(4) Upon promulgation of a performance specification of 

continuous monitoring systems for total reduced sulfur compounds 

at sulfur recovery plants, you may, as an alternative to 

paragraph (b)(2) of this section, install, calibrate, maintain, 

and operate a continuous emission monitoring system for total 

reduced sulfur compounds as required in paragraph (d) of this 

section in addition to a sulfur dioxide emission monitoring 

system. The sum of the equivalent sulfur mass emission rates 

from the two monitoring systems must be used to compute the 

total sulfur emission rate (E).

(c) Where compliance is achieved through the use of a 

reduction control system not followed by a continually operated 
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incineration device, you must install, calibrate, maintain, and 

operate a continuous monitoring system to measure the emission 

rate of reduced sulfur compounds as SO2 equivalent in the gases 

discharged to the atmosphere. The SO2 equivalent compound 

emission rate must be expressed in terms of equivalent sulfur 

mass flow rates (kg/hr (lb/hr)). The span of this monitoring 

system must be set so that the equivalent emission limit of 

§60.5405a(b) will be between 30 and 70 percent of the 

measurement range of the system. This requirement becomes 

effective upon promulgation of a performance specification for 

continuous monitoring systems for total reduced sulfur compounds 

at sulfur recovery plants.

(d) For those sources required to comply with paragraph (b) 

or (c) of this section, you must calculate the average sulfur 

emission reduction efficiency achieved (R) for each 24-hour 

clock interval. The 24-hour interval may begin and end at any 

selected clock time, but must be consistent. You must compute 

the 24-hour average reduction efficiency (R) based on the 24-

hour average sulfur production rate (S) and sulfur emission rate 

(E), using the equation in §60.5406a(c)(1).
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(1) You must use data obtained from the sulfur production 

rate monitoring device specified in paragraph (a) of this 

section to determine S.

(2) You must use data obtained from the sulfur emission 

rate monitoring systems specified in paragraphs (b) or (c) of 

this section to calculate a 24-hour average for the sulfur 

emission rate (E). The monitoring system must provide at least 

one data point in each successive 15-minute interval. You must 

use at least two data points to calculate each 1-hour average. 

You must use a minimum of 18 1-hour averages to compute each 24-

hour average.

(e) In lieu of complying with paragraphs (b) or (c) of this 

section, those sources with a design capacity of less than 152 

Mg/D (150 LT/D) of H2S expressed as sulfur may calculate the 

sulfur emission reduction efficiency achieved for each 24-hour 

period by: 

RR = KK2SS

XX

Where:

R = The sulfur dioxide removal efficiency achieved during the 

24-hour period, percent.

K2 = Conversion factor, 0.02400 Mg/D per kg/hr (0.01071 LT/D per 

lb/hr).
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S = The sulfur production rate during the 24-hour period, kg/hr 

(lb/hr).

X = The sulfur feed rate in the acid gas, Mg/D (LT/D).

(f) The monitoring devices required in paragraphs (b)(1), 

(b)(3) and (c) of this section must be calibrated at least 

annually according to the manufacturer's specifications, as 

required by §60.13(b).

(g) The continuous emission monitoring systems required in 

paragraphs (b)(1), (b)(3), and (c) of this section must be 

subject to the emission monitoring requirements of §60.13 of the 

General Provisions. For conducting the continuous emission 

monitoring system performance evaluation required by §60.13(c), 

Performance Specification 2 of appendix B of this part must 

apply, and Method 6 of appendix A-4 of this part must be used 

for systems required by paragraph (b) of this section. In place 

of Method 6 of appendix A-4 of this part, ASME PTC 19.10-1981 

(incorporated by reference—see §60.17) may be used.

§60.5408a What is an optional procedure for measuring hydrogen 

sulfide in acid gas—Tutwiler Procedure?

The Tutwiler procedure may be found in the Gas Engineers 

Handbook, Fuel Gas Engineering practices, The Industrial Press, 
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93 Worth Street, New York, NY, 1966, First Edition, Second 

Printing, page 6/25 (Docket A-80-20-A, Entry II-I-67).

(a) When an instantaneous sample is desired and H2S

concentration is 10 grains per 1000 cubic foot or more, a 100 ml 

Tutwiler burette is used. For concentrations less than 10

grains, a 500 ml Tutwiler burette and more dilute solutions are 

used. In principle, this method consists of titrating hydrogen 

sulfide in a gas sample directly with a standard solution of 

iodine.

(b) Apparatus. (See Figure 1 of this subpart) A 100 or 500 

ml capacity Tutwiler burette, with two-way glass stopcock at 

bottom and three-way stopcock at top which connect either with 

inlet tubulature or glass-stoppered cylinder, 10 ml capacity, 

graduated in 0.1 ml subdivision; rubber tubing connecting 

burette with leveling bottle.

(c) Reagents. (1) Iodine stock solution, 0.1N. Weight 12.7 

g iodine, and 20 to 25 g cp potassium iodide (KI) for each liter 

of solution. Dissolve KI in as little water as necessary; 

dissolve iodine in concentrated KI solution, make up to proper 

volume, and store in glass-stoppered brown glass bottle.

(2) Standard iodine solution, 1 ml=0.001771 g I. Transfer 

33.7 ml of above 0.1N stock solution into a 250 ml volumetric 
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flask; add water to mark and mix well. Then, for 100 ml sample 

of gas, 1 ml of standard iodine solution is equivalent to 100 

grains H2S per cubic feet of gas.

(3) Starch solution. Rub into a thin paste about one 

teaspoonful of wheat starch with a little water; pour into about 

a pint of boiling water; stir; let cool and decant off clear 

solution. Make fresh solution every few days.

(d) Procedure. Fill leveling bulb with starch solution. 

Raise (L), open cock (G), open (F) to (A), and close (F) when 

solutions starts to run out of gas inlet. Close (G). Purge gas 

sampling line and connect with (A). Lower (L) and open (F) and 

(G). When liquid level is several ml past the 100 ml mark, close 

(G) and (F), and disconnect sampling tube. Open (G) and bring 

starch solution to 100 ml mark by raising (L); then close (G). 

Open (F) momentarily, to bring gas in burette to atmospheric 

pressure, and close (F). Open (G), bring liquid level down to 10 

ml mark by lowering (L). Close (G), clamp rubber tubing near (E) 

and disconnect it from burette. Rinse graduated cylinder with a 

standard iodine solution (0.00171 g I per ml); fill cylinder and 

record reading. Introduce successive small amounts of iodine

through (F); shake well after each addition; continue until a 
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faint permanent blue color is obtained. Record reading; subtract 

from previous reading, and call difference D.

(e) With every fresh stock of starch solution perform a 

blank test as follows: Introduce fresh starch solution into 

burette up to 100 ml mark. Close (F) and (G). Lower (L) and open 

(G). When liquid level reaches the 10 ml mark, close (G). With 

air in burette, titrate as during a test and up to same end 

point. Call ml of iodine used C. Then, 

 Grains H2S per 100 cubic foot of gas = 100(D-C)

(f) Greater sensitivity can be attained if a 500 ml 

capacity Tutwiler burette is used with a more dilute (0.001N) 

iodine solution. Concentrations less than 1.0 grains per 100 

cubic foot can be determined in this way. Usually, the starchiodine end point is much less distinct, and a blank 

determination of end point, with H2S-free gas or air, is 

required.
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Figure 1. Tutwiler burette (lettered items mentioned in text).
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§60.5410a How do I demonstrate initial compliance with the 

standards for my well, centrifugal compressor, reciprocating 

compressor, pneumatic controller, pneumatic pump, storage 

vessel, collection of fugitive emissions components at a well 

site, collection of fugitive emissions components at a 

compressor station, and equipment leaks and sweetening unit 

affected facilities at onshore natural gas processing plants?

You must determine initial compliance with the standards 

for each affected facility using the requirements in paragraphs 

(a) through (j) of this section. The initial compliance period 

begins on [date 60 days after publication of final rule in the 

Federal Register], or upon initial startup, whichever is later, 

and ends no later than 1 year after the initial startup date for 

your affected facility or no later than 1 year after [date 60 

days after publication of final rule in the Federal Register]. 

The initial compliance period may be less than one full year.

(a) To achieve initial compliance with the methane and VOC 

standards for each well completion operation conducted at your 

well affected facility you must comply with paragraphs (a)(1) 

through (a)(4) of this section.

(1) You must submit the notification required in 

§60.5420a(a)(2).
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(2) You must submit the initial annual report for your well 

affected facility as required in §60.5420a(b).

(3) You must maintain a log of records as specified in 

§60.5420a(c)(1)(i) through (iv) for each well completion 

operation conducted during the initial compliance period.

(4) For each well affected facility subject to both 

§60.5375a(a)(1) and (3), as an alternative to retaining the 

records specified in §60.5420a(c)(1)(i) through (iv), you may 

maintain records of one or more digital photographs with the 

date the photograph was taken and the latitude and longitude of 

the well site imbedded within or stored with the digital file 

showing the equipment for storing or re-injecting recovered 

liquid, equipment for routing recovered gas to the gas flow line 

and the completion combustion device (if applicable) connected 

to and operating at each well completion operation that occurred 

during the initial compliance period. As an alternative to 

imbedded latitude and longitude within the digital photograph, 

the digital photograph may consist of a photograph of the 

equipment connected and operating at each well completion 

operation with a photograph of a separately operating GIS device 

within the same digital picture, provided the latitude and 
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longitude output of the GIS unit can be clearly read in the 

digital photograph.

(b)(1) To achieve initial compliance with standards for 

your centrifugal compressor affected facility you must reduce 

methane and VOC emissions from each centrifugal compressor wet 

seal fluid degassing system by 95.0 percent or greater as 

required by §60.5380a and as demonstrated by the requirements of 

§60.5413a.

(2) If you use a control device to reduce emissions, you 

must equip the wet seal fluid degassing system with a cover that 

meets the requirements of §60.5411a(b) that is connected through 

a closed vent system that meets the requirements of §60.5411a(a) 

and is routed to a control device that meets the conditions 

specified in §60.5412a(a), (b) and (c). As an alternative to 

routing the closed vent system to a control device, you may 

route the closed vent system to a process that reduces VOC 

emissions by at least 95.0 percent.

(3) You must conduct an initial performance test as 

required in §60.5413a within 180 days after initial startup or 

by [date 60 days after publication of final rule in the Federal 

Register], whichever is later, and you must comply with the 
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continuous compliance requirements in §60.5415a(b)(1) through 

(3).

(4) You must conduct the initial inspections required in 

§60.5416a(a) and (b).

(5) You must install and operate the continuous parameter 

monitoring systems in accordance with §60.5417a(a) through (g), 

as applicable.

(6) You must submit the notifications required in 

60.7(a)(1), (3), and (4).

(7) You must submit the initial annual report for your 

centrifugal compressor affected facility as required in 

§60.5420a(b) for each centrifugal compressor affected facility.

(8) You must maintain the records as specified in 

§60.5420a(c).

(c) To achieve initial compliance with the standards for 

each reciprocating compressor affected facility you must comply 

with paragraphs (c)(1) through (4) of this section.

(1) If complying with §60.5385a(a)(1) or (2), during the 

initial compliance period, you must continuously monitor the 

number of hours of operation or track the number of months since 

the last rod packing replacement.
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(2) If complying with §60.5385a(a)(3), you must operate the 

rod packing emissions collection system under negative pressure 

and route emissions to a process through a closed vent system 

that meets the requirements of §60.5411a(a).

(3) You must submit the initial annual report for your 

reciprocating compressor as required in §60.5420a(b).

(4) You must maintain the records as specified in 

§60.5420a(c) for each reciprocating compressor affected 

facility.

(d) To achieve initial compliance with methane and VOC 

emission standards for your pneumatic controller affected 

facility you must comply with the requirements specified in 

paragraphs (d)(1) through (6) of this section, as applicable.

(1) You must demonstrate initial compliance by maintaining 

records as specified in §60.5420a(c)(4)(ii) of your 

determination that the use of a pneumatic controller affected 

facility with a bleed rate greater than the applicable standard

is required as specified in §60.5390a(a).

(2) You own or operate a pneumatic controller affected 

facility located at a natural gas processing plant and your 

pneumatic controller is driven by a gas other than natural gas 

and therefore emits zero natural gas.
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(3) You own or operate a pneumatic controller affected 

facility located other than at a natural gas processing plant 

and the manufacturer's design specifications indicate that the 

controller emits less than or equal to 6 standard cubic feet of 

gas per hour.

(4) You must tag each new pneumatic controller affected 

facility according to the requirements of §60.5390a(b)(2) or 

(c)(2).

(5) You must include the information in paragraph (d)(1) of 

this section and a listing of the pneumatic controller affected 

facilities specified in paragraphs (d)(2) and (3) of this 

section in the initial annual report submitted for your 

pneumatic controller affected facilities constructed, modified 

or reconstructed during the period covered by the annual report 

according to the requirements of §60.5420a(b).

(6) You must maintain the records as specified in 

§60.5420a(c) for each pneumatic controller affected facility.

(e) To achieve initial compliance with emission standards 

for your pneumatic pump affected facility you must comply with 

the requirements specified in paragraphs (e)(1) through (6) of 

this section, as applicable.
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(1) You own or operate a pneumatic pump affected facility 

located at a natural gas processing plant and your pneumatic 

pump is driven by a gas other than natural gas and therefore 

emits zero natural gas.

(2) You own or operate a pneumatic pump affected facility 

located other than at a natural gas processing plant and your 

pneumatic pump is controlled by at least 95 percent.

(3) You own or operate a pneumatic pump affected facility 

located other than at a natural gas processing plant and your 

pneumatic pump is not controlled by at least 95 percent because 

a control device is not available at the site, you must submit 

the certification in 60.5420a(b)(8)(i). 

(4) You must tag each new pneumatic pump affected facility 

according to the requirements of §60.5393a(a)(2) or (b)(3).

(5) You must include a listing of the pneumatic pump 

affected facilities specified in paragraphs (e)(1) through (3) 

of this section in the initial annual report submitted for your 

pneumatic pump affected facilities constructed, modified or 

reconstructed during the period covered by the annual report 

according to the requirements of §60.5420a(b).

(6) You must maintain the records as specified in 

§60.5420a(c) for each pneumatic pump affected facility.
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(f) For affected facilities at onshore natural gas 

processing plants, initial compliance with the methane and VOC 

requirements is demonstrated if you are in compliance with the 

requirements of §60.5400a.

(g) For sweetening unit affected facilities at onshore 

natural gas processing plants, initial compliance is 

demonstrated according to paragraphs (g)(1) through (3) of this 

section.

(1) To determine compliance with the standards for SO2

specified in §60.5405a(a), during the initial performance test 

as required by §60.8, the minimum required sulfur dioxide 

emission reduction efficiency (Zi) is compared to the emission 

reduction efficiency (R) achieved by the sulfur recovery 

technology as specified in paragraphs (g)(1)(i) and (ii) of this 

section.

(i) If R ≥ Zi, your affected facility is in compliance.

(ii) If R < Zi, your affected facility is not in compliance.

(2) The emission reduction efficiency (R) achieved by the 

sulfur reduction technology must be determined using the 

procedures in §60.5406a(c)(1).

(3) You have submitted the results of paragraphs (g)(1) and 

(2) of this section in the initial annual report submitted for 
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your sweetening unit affected facilities at onshore natural gas 

processing plants.

(h) For each storage vessel affected facility, you must 

comply with paragraphs (h)(1) through (6) of this section. You 

must demonstrate initial compliance by [date 60 days after 

publication of final rule in the Federal Register], or within 60 

days after startup, whichever is later.

(1) You must determine the potential VOC emission rate as 

specified in §60.5365a(e).

(2) You must reduce VOC emissions in accordance with 

§60.5395a(a).

(3) If you use a control device to reduce emissions, you 

must equip the storage vessel with a cover that meets the 

requirements of §60.5411a(b) and is connected through a closed 

vent system that meets the requirements of §60.5411a(c) to a 

control device that meets the conditions specified in 

§60.5412a(d) within 60 days after startup for storage vessels 

constructed, modified or reconstructed at well sites with no 

other wells in production, or upon startup for storage vessels 

constructed, modified or reconstructed at well sites with one or 

more wells already in production.
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(4) You must conduct an initial performance test as 

required in §60.5413a within 180 days after initial startup or 

within 180 days of [date 60 days after publication of final rule 

in the Federal Register], whichever is later, and you must 

comply with the continuous compliance requirements in 

§60.5415a(e).

(5) You must submit the information required for your 

storage vessel affected facility as specified in §60.5420a(b).

(6) You must maintain the records required for your storage 

vessel affected facility, as specified in §60.5420a(c) for each 

storage vessel affected facility.

(i) For each storage vessel affected facility, you must 

submit the notification specified in §60.5395a(b)(2) with the 

initial annual report specified in §60.5420a(b).

(j) To achieve initial compliance with the fugitive 

emission standards for each collection of fugitive emissions 

components at a well site and each collection of fugitive 

emissions components at a compressor station, you must comply 

with paragraphs (j)(1) through (5) of this section.

(1) You must develop a fugitive emissions monitoring plan 

for each collection of fugitive emissions components at a well 
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site and each collection of fugitive emissions components at a 

compressor station as required in §60.5397a(a).

(2) You must conduct an initial monitoring survey as 

required in §60.5397a(f).

(3) You must maintain the records specified in 

§60.5420a(c).

(4) You must repair each identified source of fugitive 

emissions for each affected facility as required in 

§60.5397a(j).

(5) You must submit the initial annual report for each 

collection of fugitive emissions components at a well site and 

each collection of fugitive emissions components at a compressor 

station compressor station as required in §60.5420a(b).

§60.5411a What additional requirements must I meet to determine 

initial compliance for my covers and closed vent systems routing 

emissions from centrifugal compressor wet seal fluid degassing 

systems, reciprocating compressors, pneumatic pumps and storage 

vessels?

You must meet the applicable requirements of this section 

for each cover and closed vent system used to comply with the 

emission standards for your centrifugal compressor wet seal 
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degassing systems, reciprocating compressors, pneumatic pumps 

and storage vessels.

(a) Closed vent system requirements for reciprocating 

compressors, centrifugal compressor wet seal degassing systems 

and pneumatic pumps. (1) You must design the closed vent system 

to route all gases, vapors, and fumes emitted from the 

reciprocating compressor rod packing emissions collection 

system, the wet seal fluid degassing system or pneumatic pump to 

a control device or to a process that meets the requirements 

specified in §60.5412a(a) through (c).

(2) You must design and operate the closed vent system with 

no detectable emissions as demonstrated by §60.5416a(b).

(3) You must meet the requirements specified in paragraphs 

(a)(3)(i) and (ii) of this section if the closed vent system 

contains one or more bypass devices that could be used to divert 

all or a portion of the gases, vapors, or fumes from entering 

the control device.

(i) Except as provided in paragraph (a)(3)(ii) of this 

section, you must comply with either paragraph (a)(3)(i)(A) or 

(B) of this section for each bypass device.

(A) You must properly install, calibrate, maintain, and 

operate a flow indicator at the inlet to the bypass device that 
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could divert the stream away from the control device or process 

to the atmosphere. Set the flow indicator to trigger an audible 

and visible alarm, and initiate notification via remote alarm to 

the nearest field office, when the bypass device is open such 

that the stream is being, or could be, diverted away from the 

control device or process to the atmosphere. You must maintain 

records of each time the alarm is activated according to 

§60.5420a(c)(8).

(B) You must secure the bypass device valve installed at 

the inlet to the bypass device in the non-diverting position 

using a car-seal or a lock-and-key type configuration.

(ii) Low leg drains, high point bleeds, analyzer vents, 

open-ended valves or lines, and safety devices are not subject 

to the requirements of paragraph (a)(3)(i) of this section.

(b) Cover requirements for storage vessels and centrifugal 

compressor wet seal fluid degassing systems. (1) The cover and 

all openings on the cover (e.g., access hatches, sampling ports, 

pressure relief devices and gauge wells) shall form a continuous 

impermeable barrier over the entire surface area of the liquid 

in the storage vessel or wet seal fluid degassing system.

(2) Each cover opening shall be secured in a closed, sealed 

position (e.g., covered by a gasketed lid or cap) whenever 
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material is in the unit on which the cover is installed except 

during those times when it is necessary to use an opening as 

follows:

(i) To add material to, or remove material from the unit 

(this includes openings necessary to equalize or balance the 

internal pressure of the unit following changes in the level of 

the material in the unit);

(ii) To inspect or sample the material in the unit;

(iii) To inspect, maintain, repair, or replace equipment 

located inside the unit; or

(iv) To vent liquids, gases, or fumes from the unit through 

a closed-vent system designed and operated in accordance with 

the requirements of paragraph (a) or (c) of this section to a 

control device or to a process.

(3) Each storage vessel thief hatch shall be equipped, 

maintained and operated with a weighted mechanism or equivalent, 

to ensure that the lid remains properly seated and sealed under 

normal operating conditions, including such times when working, 

standing/breathing, and flash emissions may be generated. You 

must select gasket material for the hatch based on composition 

of the fluid in the storage vessel and weather conditions.
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(c) Closed vent system requirements for storage vessel 

affected facilities using a control device or routing emissions 

to a process. (1) You must design the closed vent system to 

route all gases, vapors, and fumes emitted from the material in 

the storage vessel to a control device that meets the 

requirements specified in §60.5412a(c) and (d), or to a process.

(2) You must design and operate a closed vent system with 

no detectable emissions, as determined using olfactory, visual 

and auditory inspections. Each closed vent system that routes 

emissions to a process must be operational 95 percent of the 

year or greater.

(3) You must meet the requirements specified in paragraphs 

(c)(3)(i) and (ii) of this section if the closed vent system 

contains one or more bypass devices that could be used to divert 

all or a portion of the gases, vapors, or fumes from entering 

the control device or to a process.

(i) Except as provided in paragraph (c)(3)(ii) of this 

section, you must comply with either paragraph (c)(3)(i)(A) or 

(B) of this section for each bypass device.

(A) You must properly install, calibrate, maintain, and 

operate a flow indicator at the inlet to the bypass device that 

could divert the stream away from the control device or process 
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to the atmosphere. Set the flow indicator to trigger and audible 

and visible alarm, and initiate notification via remote alarm to 

the nearest field office, when the bypass device is open such 

that the stream is being, or could be, diverted away from the 

control device or process to the atmosphere. You must maintain 

records of each time the alarm is sounded according to 

§60.5420a(c)(8).

(B) You must secure the bypass device valve installed at 

the inlet to the bypass device in the non-diverting position 

using a car-seal or a lock-and-key type configuration.

(ii) Low leg drains, high point bleeds, analyzer vents, 

open-ended valves or lines, and safety devices are not subject 

to the requirements of paragraph (c)(3)(i) of this section.

§60.5412a What additional requirements must I meet for 

determining initial compliance with control devices used to 

comply with the emission standards for my centrifugal 

compressor, pneumatic pump and storage vessel affected 

facilities?

You must meet the applicable requirements of this section 

for each control device used to comply with the emission 

standards for your centrifugal compressor affected facility, 
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pneumatic pump affected facility, or storage vessel affected 

facility.

(a) Each control device used to meet the emission reduction 

standard in §60.5380a(a)(1) for your centrifugal compressor 

affected facility or §60.5393a(b)(1) for your pneumatic pump 

must be installed according to paragraphs (a)(1) through (3) of 

this section. As an alternative, you may install a control 

device model tested under §60.5413a(d), which meets the criteria 

in §60.5413a(d)(11) and §60.5413a(e).

(1) Each combustion device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, boiler, or process 

heater) must be designed and operated in accordance with one of 

the performance requirements specified in paragraphs (a)(1)(i) 

through (iv) of this section.

(i) You must reduce the mass content of methane and VOC in 

the gases vented to the device by 95.0 percent by weight or

greater as determined in accordance with the requirements of 

§60.5413a.

(ii) You must reduce the concentration of TOC in the 

exhaust gases at the outlet to the device to a level equal to or 

less than 600 parts per million by volume as propane on a dry 
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basis corrected to 3 percent oxygen as determined in accordance 

with the requirements of §60.5413a.

(iii) You must operate at a minimum temperature of 760°C 

for a control device that can demonstrate a uniform combustion 

zone temperature during the performance test conducted under 

§60.5413a.

(iv) If a boiler or process heater is used as the control 

device, then you must introduce the vent stream into the flame 

zone of the boiler or process heater.

(2) Each vapor recovery device (e.g., carbon adsorption 

system or condenser) or other non-destructive control device 

must be designed and operated to reduce the mass content of 

methane and VOC in the gases vented to the device by 95.0 

percent by weight or greater as determined in accordance with 

the requirements of §60.5413a. As an alternative to the 

performance testing requirements, you may demonstrate initial 

compliance by conducting a design analysis for vapor recovery 

devices according to the requirements of §60.5413a(c).

(3) You must design and operate a flare in accordance with 

the requirements of §60.5413a(a)(1).

(b) You must operate each control device installed on your 

centrifugal compressor or pneumatic pump affected facility in 
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accordance with the requirements specified in paragraphs (b)(1) 

and (2) of this section.

(1) You must operate each control device used to comply 

with this subpart at all times when gases, vapors, and fumes are 

vented from the wet seal fluid degassing system affected 

facility as required under §60.5380a(a), or from the pneumatic 

pump as required under §60.5393a(b)(1), through the closed vent 

system to the control device. You may vent more than one 

affected facility to a control device used to comply with this 

subpart.

(2) For each control device monitored in accordance with 

the requirements of §60.5417a(a) through (g), you must 

demonstrate compliance according to the requirements of 

§60.5415a(b)(2), as applicable.

(c) For each carbon adsorption system used as a control 

device to meet the requirements of paragraph (a)(2) or (d)(2) of 

this section, you must manage the carbon in accordance with the 

requirements specified in paragraphs (c)(1) or (2) of this 

section.

(1) Following the initial startup of the control device, 

you must replace all carbon in the control device with fresh 

carbon on a regular, predetermined time interval that is no 
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longer than the carbon service life established according to 

§60.5413a(c)(2) or (3) or according to the design required in 

paragraph (d)(2) of this section, for the carbon adsorption 

system. You must maintain records identifying the schedule for 

replacement and records of each carbon replacement as required 

in §60.5420a(c)(10) and (12).

(2) You must either regenerate, reactivate, or burn the 

spent carbon removed from the carbon adsorption system in one of 

the units specified in paragraphs (c)(2)(i) through (vii) of 

this section.

(i) Regenerate or reactivate the spent carbon in a thermal 

treatment unit for which you have been issued a final permit 

under 40 CFR part 270 that implements the requirements of 40 CFR 

part 264, subpart X.

(ii) Regenerate or reactivate the spent carbon in a thermal 

treatment unit equipped with and operating air emission controls 

in accordance with this section.

(iii) Regenerate or reactivate the spent carbon in a 

thermal treatment unit equipped with and operating organic air 

emission controls in accordance with an emissions standard for 

VOC under another subpart in 40 CFR part 60 or this part.
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(iv) Burn the spent carbon in a hazardous waste incinerator 

for which the owner or operator has been issued a final permit 

under 40 CFR part 270 that implements the requirements of 40 CFR 

part 264, subpart O.

(v) Burn the spent carbon in a hazardous waste incinerator 

which you have designed and operated in accordance with the 

requirements of 40 CFR part 265, subpart O.

(vi) Burn the spent carbon in a boiler or industrial 

furnace for which you have been issued a final permit under 40 

CFR part 270 that implements the requirements of 40 CFR part 

266, subpart H.

(vii) Burn the spent carbon in a boiler or industrial 

furnace that you have designed and operated in accordance with 

the interim status requirements of 40 CFR part 266, subpart H.

(d) Each control device used to meet the emission reduction 

standard in §60.5395a(a) for your storage vessel affected 

facility must be installed according to paragraphs (d)(1) 

through (3) of this section, as applicable. As an alternative to 

paragraph (d)(1) of this section, you may install a control 

device model tested under §60.5413a(d), which meets the criteria 

in §60.5413a(d)(11) and §60.5413a(e).
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(1) For each enclosed combustion control device (e.g., 

thermal vapor incinerator, catalytic vapor incinerator, boiler, 

or process heater) you must meet the requirements in paragraphs 

(d)(1)(i) through (iv) of this section.

(i) Ensure that each enclosed combustion control device is 

maintained in a leak free condition.

(ii) Install and operate a continuous burning pilot flame.

(iii) Operate the combustion control device with no visible 

emissions, except for periods not to exceed a total of 1 minute 

during any 15 minute period. A visible emissions test using 

section 11 of EPA Method 22 of appendix A-7 of this part must be 

performed at least once every calendar month, separated by at 

least 15 days between each test. The observation period shall be 

15 minutes. Devices failing the visible emissions test must 

follow manufacturer's repair instructions, if available, or best 

combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant 

operation. All inspection, repair and maintenance activities for 

each unit must be recorded in a maintenance and repair log and 

must be available for inspection. Following return to operation 

from maintenance or repair activity, each device must pass a 
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Method 22 of appendix A-7 of this part visual observation as 

described in this paragraph.

(iv) Each combustion control device (e.g., thermal vapor 

incinerator, catalytic vapor incinerator, boiler, or process 

heater) must be designed and operated in accordance with one of 

the performance requirements specified in paragraphs (A) through 

(D) of this section.

(A) You must reduce the mass content of methane and VOC in 

the gases vented to the device by 95.0 percent by weight or 

greater as determined in accordance with the requirements of 

§60.5413a.

(B) You must reduce the concentration of TOC in the exhaust 

gases at the outlet to the device to a level equal to or less 

than 600 parts per million by volume as propane on a dry basis 

corrected to 3 percent oxygen as determined in accordance with 

the requirements of §60.5413a.

(C) You must operate at a minimum temperature of 760°C for 

a control device that can demonstrate a uniform combustion zone 

temperature during the performance test conducted under 

§60.5413a.
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(D) If a boiler or process heater is used as the control 

device, then you must introduce the vent stream into the flame 

zone of the boiler or process heater.

(2) Each vapor recovery device (e.g., carbon adsorption 

system or condenser) or other non-destructive control device 

must be designed and operated to reduce the mass content of 

methane and VOC in the gases vented to the device by 95.0 

percent by weight or greater. A carbon replacement schedule must 

be included in the design of the carbon adsorption system.

(3) You must operate each control device used to comply 

with this subpart at all times when gases, vapors, and fumes are 

vented from the storage vessel affected facility through the 

closed vent system to the control device. You may vent more than 

one affected facility to a control device used to comply with 

this subpart.

§60.5413a What are the performance testing procedures for 

control devices used to demonstrate compliance at my centrifugal 

compressor, pneumatic pump and storage vessel affected 

facilities?

This section applies to the performance testing of control 

devices used to demonstrate compliance with the emissions 

standards for your centrifugal compressor affected facility, 
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pneumatic pump affected facility, or storage vessel affected 

facility. You must demonstrate that a control device achieves 

the performance requirements of §60.5412a(a) or (d) using the 

performance test methods and procedures specified in this 

section. For condensers and carbon adsorbers, you may use a 

design analysis as specified in paragraph (c) of this section in 

lieu of complying with paragraph (b) of this section. In 

addition, this section contains the requirements for enclosed 

combustion control device performance tests conducted by the 

manufacturer applicable to storage vessel, centrifugal 

compressor and pneumatic pump affected facilities.

(a) Performance test exemptions. You are exempt from the 

requirements to conduct performance tests and design analyses if 

you use any of the control devices described in paragraphs 

(a)(1) through (7) of this section.

(1) A flare that is designed and operated in accordance 

with §60.18(b). You must conduct the compliance determination 

using Method 22 of appendix A-7 of this part to determine 

visible emissions.

(2) A boiler or process heater with a design heat input 

capacity of 44 megawatts or greater.
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(3) A boiler or process heater into which the vent stream 

is introduced with the primary fuel or is used as the primary 

fuel.

(4) A boiler or process heater burning hazardous waste for 

which you have either been issued a final permit under 40 CFR 

part 270 and comply with the requirements of 40 CFR part 266, 

subpart H; or you have certified compliance with the interim 

status requirements of 40 CFR part 266, subpart H.

(5) A hazardous waste incinerator for which you have been 

issued a final permit under 40 CFR part 270 and comply with the 

requirements of 40 CFR part 264, subpart O; or you have 

certified compliance with the interim status requirements of 40 

CFR part 265, subpart O.

(6) A performance test is waived in accordance with 

§60.8(b).

(7) A control device whose model can be demonstrated to 

meet the performance requirements of §60.5412a(a) or (d) through 

a performance test conducted by the manufacturer, as specified 

in paragraph (d) of this section.

(b) Test methods and procedures. You must use the test 

methods and procedures specified in paragraphs (b)(1) through 

(5) of this section, as applicable, for each performance test 
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conducted to demonstrate that a control device meets the 

requirements of §60.5412a(a) or (d). You must conduct the 

initial and periodic performance tests according to the schedule 

specified in paragraph (b)(5) of this section.

(1) You must use Method 1 or 1A of appendix A-1 of this 

part, as appropriate, to select the sampling sites specified in 

paragraphs (b)(1)(i) and (ii) of this section. Any references to 

particulate mentioned in Methods 1 and 1A do not apply to this 

section.

(i) Sampling sites must be located at the inlet of the 

first control device, and at the outlet of the final control 

device, to determine compliance with the control device percent 

reduction requirement specified in §60.5412a(a)(1)(i) or (a)(2).

(ii) The sampling site must be located at the outlet of the 

combustion device to determine compliance with the enclosed 

combustion control device total TOC concentration limit 

specified in §60.5412a(a)(1)(ii).

(2) You must determine the gas volumetric flowrate using 

Method 2, 2A, 2C, or 2D of appendix A-2 of this part, as 

appropriate.

(3) To determine compliance with the control device percent 

reduction performance requirement in §60.5412a(a)(1)(i), (a)(2)
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or (d)(1)(i)(A), you must use Method 25A of appendix A-7 of this 

part. You must use the procedures in paragraphs (b)(3)(i) 

through (iv) of this section to calculate percent reduction 

efficiency.

(i) For each run, you must take either an integrated sample 

or a minimum of four grab samples per hour. If grab sampling is 

used, then the samples must be taken at approximately equal 

intervals in time, such as 15-minute intervals during the run.

(ii) You must compute the mass rate of TOC (minus methane 

and ethane) using the equations and procedures specified in 

paragraphs (b)(3)(ii)(A) and (B) of this section.

(A) You must use the following equations:

EEii = KK2 ��CCiiiiMMiiii

nn

=1

�QQii

EEoo = KK2 ��CCoo MMoo

nn

=1

�QQoo

Where:

Ei, Eo = Mass rate of TOC (minus methane and ethane) at the inlet 

and outlet of the control device, respectively, dry basis, 

kilogram per hour.
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K2 = Constant, 2.494 × 10−6 (parts per million) (gram-mole per 

standard cubic meter) (kilogram/gram) (minute/hour), where 

standard temperature (gram-mole per standard cubic meter) is 

20°C.

Cij, Coj = Concentration of sample component j of the gas stream 

at the inlet and outlet of the control device, respectively, dry 

basis, parts per million by volume.

Mij, Moj = Molecular weight of sample component j of the gas 

stream at the inlet and outlet of the control device, 

respectively, gram/gram-mole.

Qi, Qo = Flowrate of gas stream at the inlet and outlet of the 

control device, respectively, dry standard cubic meter per 

minute.

n = Number of components in sample.

(B) When calculating the TOC mass rate, you must sum all 

organic compounds (minus methane and ethane) measured by Method 

25A of appendix A-7 of this part using the equations in 

paragraph (b)(3)(ii)(A) of this section.

(iii) You must calculate the percent reduction in TOC 

(minus methane and ethane) as follows:

RRcc = EEii − EEoo

EEii

∗ 100%
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Where:

Rcd = Control efficiency of control device, percent.

Ei = Mass rate of TOC (minus methane and ethane) at the inlet to 

the control device as calculated under paragraph (b)(3)(ii) of 

this section, kilograms TOC per hour or kilograms HAP per hour.

Eo = Mass rate of TOC (minus methane and ethane) at the outlet of 

the control device, as calculated under paragraph (b)(3)(ii) of 

this section, kilograms TOC per hour per hour.

(iv) If the vent stream entering a boiler or process heater 

with a design capacity less than 44 megawatts is introduced with 

the combustion air or as a secondary fuel, you must determine 

the weight-percent reduction of total TOC (minus methane and 

ethane) across the device by comparing the TOC (minus methane 

and ethane) in all combusted vent streams and primary and 

secondary fuels with the TOC (minus methane and ethane) exiting 

the device, respectively.

(4) You must use Method 25A of appendix A-7 of this part to 

measure TOC (minus methane and ethane) to determine compliance 

with the enclosed combustion control device total VOC 

concentration limit specified in §60.5412a(a)(1)(ii) or 

(d)(1)(iv)(B). You must calculate parts per million by volume 
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concentration and correct to 3 percent oxygen, using the 

procedures in paragraphs (b)(4)(i) through (iii) of this 

section.

(i) For each run, you must take either an integrated sample 

or a minimum of four grab samples per hour. If grab sampling is 

used, then the samples must be taken at approximately equal 

intervals in time, such as 15-minute intervals during the run.

(ii) You must calculate the TOC concentration for each run 

as follows: 

CCTTTTTT = ��∑ CC nn

=ii �

xx

xx

ii=1

Where:

CTOC = Concentration of total organic compounds minus methane and 

ethane, dry basis, parts per million by volume.

Cji = Concentration of sample component j of sample i, dry basis, 

parts per million by volume.

n = Number of components in the sample.

x = Number of samples in the sample run.

(iii) You must correct the TOC concentration to 3 percent 

oxygen as specified in paragraphs (b)(4)(iii)(A) and (B) of this 

section.
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(A) You must use the emission rate correction factor for 

excess air, integrated sampling and analysis procedures of 

Method 3A or 3B of appendix A-2 of this part, ASTM D6522-00 

(Reapproved 2005), or ANSI/ASME PTC 19.10-1981, Part 10 (manual 

portion only) (incorporated by reference as specified in §60.17) 

to determine the oxygen concentration. The samples must be taken 

during the same time that the samples are taken for determining 

TOC concentration.

(B) You must correct the TOC concentration for percent 

oxygen as follows:

CCcc = CCmm � 17.9

20.9 − %OO2

�

Where:

Cc = TOC concentration corrected to 3 percent oxygen, dry basis, 

parts per million by volume.

Cm = TOC concentration, dry basis, parts per million by volume.

%O2d = Concentration of oxygen, dry basis, percent by volume.

(5) You must conduct performance tests according to the 

schedule specified in paragraphs (b)(5)(i) and (ii) of this 

section.

(i) You must conduct an initial performance test within 180 

days after initial startup for your affected facility. You must 
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submit the performance test results as required in 

§60.5420a(b)(9).

(ii) You must conduct periodic performance tests for all 

control devices required to conduct initial performance tests 

except as specified in paragraphs (b)(5)(ii)(A) and (B) of this 

section. You must conduct the first periodic performance test no

later than 60 months after the initial performance test required 

in paragraph (b)(5)(i) of this section. You must conduct 

subsequent periodic performance tests at intervals no longer 

than 60 months following the previous periodic performance test 

or whenever you desire to establish a new operating limit. You 

must submit the periodic performance test results as specified 

in §60.5420a(b)(9). Combustion control devices meeting the 

criteria in either paragraph (b)(5)(ii)(A) or (B) of this 

section are not required to conduct periodic performance tests.

(A) A control device whose model is tested under, and meets 

the criteria of paragraph (d) of this section.

(B) A combustion control device tested under paragraph (b) 

of this section that meets the outlet TOC performance level 

specified in §60.5412a(a)(1)(ii) or (d)(1)(iv)(B) and that 

establishes a correlation between firebox or combustion chamber 

temperature and the TOC performance level.
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(c) Control device design analysis to meet the requirements 

of §60.5412a(a)(2) or (d)(2). (1) For a condenser, the design 

analysis must include an analysis of the vent stream 

composition, constituent concentrations, flowrate, relative 

humidity, and temperature, and must establish the design outlet 

organic compound concentration level, design average temperature 

of the condenser exhaust vent stream, and the design average 

temperatures of the coolant fluid at the condenser inlet and 

outlet.

(2) For a regenerable carbon adsorption system, the design 

analysis shall include the vent stream composition, constituent 

concentrations, flowrate, relative humidity, and temperature, 

and shall establish the design exhaust vent stream organic 

compound concentration level, adsorption cycle time, number and 

capacity of carbon beds, type and working capacity of activated 

carbon used for the carbon beds, design total regeneration 

stream flow over the period of each complete carbon bed 

regeneration cycle, design carbon bed temperature after 

regeneration, design carbon bed regeneration time, and design 

service life of the carbon.

(3) For a nonregenerable carbon adsorption system, such as 

a carbon canister, the design analysis shall include the vent 
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stream composition, constituent concentrations, flowrate, 

relative humidity, and temperature, and shall establish the 

design exhaust vent stream organic compound concentration level, 

capacity of the carbon bed, type and working capacity of 

activated carbon used for the carbon bed, and design carbon 

replacement interval based on the total carbon working capacity 

of the control device and source operating schedule. In 

addition, these systems shall incorporate dual carbon canisters 

in case of emission breakthrough occurring in one canister.

(4) If you and the Administrator do not agree on a 

demonstration of control device performance using a design 

analysis, then you must perform a performance test in accordance 

with the requirements of paragraph (b) of this section to 

resolve the disagreement. The Administrator may choose to have 

an authorized representative observe the performance test.

(d) Performance testing for combustion control devices—

manufacturers' performance test. (1) This paragraph applies to 

the performance testing of a combustion control device conducted 

by the device manufacturer. The manufacturer must demonstrate 

that a specific model of control device achieves the performance 

requirements in paragraph (d)(11) of this section by conducting 

a performance test as specified in paragraphs (d)(2) through 
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(10) of this section. You must submit a test report for each 

combustion control device in accordance with the requirements in 

paragraph (d)(12) of this section.

(2) Performance testing must consist of three 1-hour (or 

longer) test runs for each of the four firing rate settings 

specified in paragraphs (d)(2)(i) through (iv) of this section, 

making a total of 12 test runs per test. Propene (propylene) gas 

must be used for the testing fuel. All fuel analyses must be 

performed by an independent third-party laboratory (not 

affiliated with the control device manufacturer or fuel 

supplier).

(i) 90-100 percent of maximum design rate (fixed rate).

(ii) 70-100-70 percent (ramp up, ramp down). Begin the test 

at 70 percent of the maximum design rate. During the first 5 

minutes, incrementally ramp the firing rate to 100 percent of 

the maximum design rate. Hold at 100 percent for 5 minutes. In 

the 10-15 minute time range, incrementally ramp back down to 70 

percent of the maximum design rate. Repeat three more times for 

a total of 60 minutes of sampling.

(iii) 30-70-30 percent (ramp up, ramp down). Begin the test 

at 30 percent of the maximum design rate. During the first 5 

minutes, incrementally ramp the firing rate to 70 percent of the 
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maximum design rate. Hold at 70 percent for 5 minutes. In the 

10-15 minute time range, incrementally ramp back down to 30 

percent of the maximum design rate. Repeat three more times for 

a total of 60 minutes of sampling.

(iv) 0-30-0 percent (ramp up, ramp down). Begin the test at 

the minimum firing rate. During the first 5 minutes, 

incrementally ramp the firing rate to 30 percent of the maximum 

design rate. Hold at 30 percent for 5 minutes. In the 10-15 

minute time range, incrementally ramp back down to the minimum 

firing rate. Repeat three more times for a total of 60 minutes 

of sampling.

(3) All models employing multiple enclosures must be tested 

simultaneously and with all burners operational. Results must be 

reported for each enclosure individually and for the average of 

the emissions from all interconnected combustion 

enclosures/chambers. Control device operating data must be 

collected continuously throughout the performance test using an 

electronic Data Acquisition System. A graphic presentation or 

strip chart of the control device operating data and emissions 

test data must be included in the test report in accordance with 

paragraph (d)(12) of this section. Inlet fuel meter data may be 
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manually recorded provided that all inlet fuel data readings are 

included in the final report.

(4) Inlet testing must be conducted as specified in 

paragraphs (d)(4)(i) through (ii) of this section.

(i) The inlet gas flow metering system must be located in 

accordance with Method 2A of appendix A-1 of this part (or other 

approved procedure) to measure inlet gas flow rate at the 

control device inlet location. You must position the fitting for 

filling fuel sample containers a minimum of eight pipe diameters 

upstream of any inlet gas flow monitoring meter.

(ii) Inlet flow rate must be determined using Method 2A of 

appendix A-1 of this part. Record the start and stop reading for 

each 60-minute THC test. Record the gas pressure and temperature 

at 5-minute intervals throughout each 60-minute test.

(5) Inlet gas sampling must be conducted as specified in 

paragraphs (d)(5)(i) through (ii) of this section.

(i) At the inlet gas sampling location, securely connect a 

Silonite-coated stainless steel evacuated canister fitted with a 

flow controller sufficient to fill the canister over a 3-hour 

period. Filling must be conducted as specified in paragraphs 

(d)(5)(i)(A) through (C) of this section.
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(A) Open the canister sampling valve at the beginning of 

each test run, and close the canister at the end of each test 

run.

(B) Fill one canister across the three test runs such that 

one composite fuel sample exists for each test condition.

(C) Label the canisters individually and record sample 

information on a chain of custody form.

(ii) Analyze each inlet gas sample using the methods in 

paragraphs (d)(5)(ii)(A) through (C) of this section. You must 

include the results in the test report required by paragraph 

(d)(12) of this section.

(A) Hydrocarbon compounds containing between one and five 

atoms of carbon plus benzene using ASTM D1945-03.

(B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 

(CO2), nitrogen (N2), oxygen (O2) using ASTM D1945-03.

(C) Higher heating value using ASTM D3588-98 or ASTM D4891-

89.

(6) Outlet testing must be conducted in accordance with the 

criteria in paragraphs (d)(6)(i) through (v) of this section.

(i) Sample and flow rate must be measured in accordance 

with paragraphs (d)(6)(i)(A) through (B) of this section.
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(A) The outlet sampling location must be a minimum of four 

equivalent stack diameters downstream from the highest peak 

flame or any other flow disturbance, and a minimum of one 

equivalent stack diameter upstream of the exit or any other flow 

disturbance. A minimum of two sample ports must be used.

(B) Flow rate must be measured using Method 1 of appendix 

A-1 of this part for determining flow measurement traverse point 

location, and Method 2 of appendix A-1 of this part for 

measuring duct velocity. If low flow conditions are encountered 

(i.e., velocity pressure differentials less than 0.05 inches of 

water) during the performance test, a more sensitive manometer 

must be used to obtain an accurate flow profile.

(ii) Molecular weight and excess air must be determined as 

specified in paragraph (d)(7) of this section.

(iii) Carbon monoxide must be determined as specified in 

paragraph (d)(8) of this section.

(iv) THC must be determined as specified in paragraph 

(d)(9) of this section.

(v) Visible emissions must be determined as specified in 

paragraph (d)(10) of this section.
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(7) Molecular weight and excess air determination must be 

performed as specified in paragraphs (d)(7)(i) through (iii) of 

this section.

(i) An integrated bag sample must be collected during the 

moisture test required by Method 4 of appendix A-3 of this part 

following the procedure specified in (d)(7)(i)(A) and (B) of 

this section. Analyze the bag sample using a gas chromatographthermal conductivity detector (GC-TCD) analysis meeting the 

criteria in paragraphs (d)(7)(i)(C) and (D) of this section.

(A) Collect the integrated sample throughout the entire 

test, and collect representative volumes from each traverse 

location.

(B) Purge the sampling line with stack gas before opening 

the valve and beginning to fill the bag. Clearly label each bag 

and record sample information on a chain of custody form.

(C) The bag contents must be vigorously mixed prior to the 

gas chromatograph analysis.

(D) The GC-TCD calibration procedure in Method 3C of 

appendix A-2 of this part must be modified by using EPA Alt-045 

as follows: For the initial calibration, triplicate injections 

of any single concentration must agree within 5 percent of their 

mean to be valid. The calibration response factor for a single 
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concentration re-check must be within 10 percent of the original 

calibration response factor for that concentration. If this 

criterion is not met, repeat the initial calibration using at 

least three concentration levels.

(ii) Calculate and report the molecular weight of oxygen, 

carbon dioxide, methane, and nitrogen in the integrated bag 

sample and include in the test report specified in paragraph 

(d)(12) of this section. Moisture must be determined using 

Method 4 of appendix A-3 of this part. Traverse both ports with 

the sampling train required by Method 4 of appendix A-3 of this 

part during each test run. Ambient air must not be introduced 

into the integrated bag sample required by Method 3C of appendix 

A-2 of this part during the port change.

(iii) Excess air must be determined using resultant data 

from the EPA Method 3C tests and EPA Method 3B of appendix A-2 

of this part, equation 3B-1, or ANSI/ASME PTC 19.10-1981, Part 

10 (manual portion only) (incorporated by reference as specified 

in §60.17).

(8) Carbon monoxide must be determined using Method 10 of 

appendix A-4 of this part. Run the test simultaneously with 

Method 25A of appendix A-7 of this part using the same sampling 
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points. An instrument range of 0-10 parts per million by volumedry (ppmvd) is recommended.

(9) Total hydrocarbon determination must be performed as 

specified by in paragraphs (d)(9)(i) through (vii) of this 

section.

(i) Conduct THC sampling using Method 25A of appendix A-7 

of this part, except that the option for locating the probe in 

the center 10 percent of the stack is not allowed. The THC probe 

must be traversed to 16.7 percent, 50 percent, and 83.3 percent 

of the stack diameter during each test run.

(ii) A valid test must consist of three Method 25A tests, 

each no less than 60 minutes in duration.

(iii) A 0-10 parts per million by volume-wet (ppmvw) (as 

propane) measurement range is preferred; as an alternative a 0-

30 ppmvw (as carbon) measurement range may be used.

(iv) Calibration gases must be propane in air and be 

certified through EPA Protocol 1—“EPA Traceability Protocol for 

Assay and Certification of Gaseous Calibration Standards,” 

September 1997, as amended August 25, 1999, EPA-600/R-97/121 (or 

more recent if updated since 1999).

(v) THC measurements must be reported in terms of ppmvw as 

propane.
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(vi) THC results must be corrected to 3 percent CO2, as 

measured by Method 3C of appendix A-2 of this part. You must use 

the following equation for this diluent concentration 

correction:

Ccorr = Cmeas � 3

CO2meas

�

Where:

Cmeas = The measured concentration of the pollutant.

CO2meas = The measured concentration of the CO2 diluent.

3 = The corrected reference concentration of CO2 diluent.

Ccorr = The corrected concentration of the pollutant.

(vii) Subtraction of methane or ethane from the THC data is 

not allowed in determining results.

(10) Visible emissions must be determined using Method 22 

of appendix A-7 of this part. The test must be performed 

continuously during each test run. A digital color photograph of 

the exhaust point, taken from the position of the observer and 

annotated with date and time, must be taken once per test run 

and the 12 photos included in the test report specified in 

paragraph (d)(12) of this section.

(11) Performance test criteria. (i) The control device 

model tested must meet the criteria in paragraphs (d)(11)(i)(A) 
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through (D) of this section. These criteria must be reported in 

the test report required by paragraph (d)(12) of this section.

(A) Results from Method 22 of appendix A-7 of this part 

determined under paragraph (d)(10) of this section with no 

indication of visible emissions.

(B) Average results from Method 25A of appendix A-7 of this 

part determined under paragraph (d)(9) of this section equal to 

or less than 10.0 ppmvw THC as propane corrected to 3.0 percent 

CO2.

(C) Average CO emissions determined under paragraph (d)(8) 

of this section equal to or less than 10 parts ppmvd, corrected 

to 3.0 percent CO2.

(D) Excess air determined under paragraph (d)(7) of this 

section equal to or greater than 150 percent.

(ii) The manufacturer must determine a maximum inlet gas 

flow rate which must not be exceeded for each control device 

model to achieve the criteria in paragraph (d)(11)(iii) of this 

section. The maximum inlet gas flow rate must be included in the 

test report required by paragraph (d)(12) of this section.

(iii) A control device meeting the criteria in paragraph 

(d)(11)(i)(A) through (D) of this section must demonstrate a 
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destruction efficiency of 95 percent for methane, if applicable, 

and VOC regulated under this subpart.

(12) The owner or operator of a combustion control device 

model tested under this paragraph must submit the information 

listed in paragraphs (d)(12)(i) through (vi) in the test report 

required by this section in accordance with §60.5420a(b). Owners 

or operators who claim that any of the performance test 

information being submitted is confidential business information 

(CBI) must submit a complete file including information claimed 

to be CBI, on a compact disc, flash drive, or other commonly 

used electronic storage media to the EPA. The electronic media 

must be clearly marked as CBI and mailed to Attn: CBI Officer; 

OAQPS CBIO Room 521; 109 T.W. Alexander Drive; RTP, NC 27711. 

The same file with the CBI omitted must be submitted to 

Oil_and_Gas_PT@EPA.GOV 

(i) A full schematic of the control device and dimensions 

of the device components.

(ii) The maximum net heating value of the device.

(iii) The test fuel gas flow range (in both mass and 

volume). Include the maximum allowable inlet gas flow rate.

(iv) The air/stream injection/assist ranges, if used.
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(v) The test conditions listed in paragraphs (d)(12)(v)(A) 

through (O) of this section, as applicable for the tested model.

(A) Fuel gas delivery pressure and temperature.

(B) Fuel gas moisture range.

(C) Purge gas usage range.

(D) Condensate (liquid fuel) separation range.

(E) Combustion zone temperature range. This is required for 

all devices that measure this parameter.

(F) Excess air range.

(G) Flame arrestor(s).

(H) Burner manifold.

(I) Pilot flame indicator.

(J) Pilot flame design fuel and calculated or measured fuel 

usage.

(K) Tip velocity range.

(L) Momentum flux ratio.

(M) Exit temperature range.

(N) Exit flow rate.

(O) Wind velocity and direction.

(vi) The test report must include all calibration quality 

assurance/quality control data, calibration gas values, gas 

cylinder certification, strip charts, or other graphic 
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presentations of the data annotated with test times and 

calibration values.

(e) Continuous compliance for combustion control devices 

tested by the manufacturer in accordance with paragraph (d) of 

this section. This paragraph applies to the demonstration of 

compliance for a combustion control device tested under the 

provisions in paragraph (d) of this section. Owners or operators

must demonstrate that a control device achieves the performance 

criteria in paragraph (d)(11) of this section by installing a 

device tested under paragraph (d) of this section, complying 

with the criteria specified in paragraphs (e)(1) through (7) of 

this section, maintaining the records specified in 60.5420a(b) 

and submitting the reports specified in 60.5420a(c).

(1) The inlet gas flow rate must be equal to or less than 

the maximum specified by the manufacturer.

(2) A pilot flame must be present at all times of 

operation.

(3) Devices must be operated with no visible emissions, 

except for periods not to exceed a total of 1 minute during any 

15-minute period. A visible emissions test conducted according 

to section 11 of EPA Method 22 of appendix A-7 of this part must 

be performed at least once every calendar month, separated by at 
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least 15 days between each test. The observation period shall be 

15 minutes.

(4) Devices failing the visible emissions test must follow 

manufacturer's repair instructions, if available, or best 

combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant 

operation. All repairs and maintenance activities for each unit 

must be recorded in a maintenance and repair log and must be 

available for inspection.

(5) Following return to operation from maintenance or 

repair activity, each device must pass a visual observation 

according to EPA Method 22 of appendix A-7 of this part as 

described in paragraph (e)(3) of this section.

(6) If the owner or operator operates a combustion control 

device model tested under this section, an electronic copy of 

the performance test results required by this section shall be 

submitted via email to Oil_and_Gas_PT@EPA.GOV unless the test 

results for that model of combustion control device are posted 

at the following Web site: epa.gov/airquality/oilandgas/.

(7) Ensure that each enclosed combustion control device is 

maintained in a leak free condition.
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§60.5415a How do I demonstrate continuous compliance with the 

standards for my well, centrifugal compressor, reciprocating 

compressor, pneumatic controller, pneumatic pump, storage 

vessel, collection of fugitive emissions components at a well 

site, and collection of fugitive emissions components at a 

compressor station, and affected facilities at onshore natural 

gas processing plants?

(a) For each well affected facility, you must demonstrate 

continuous compliance by submitting the reports required by 

§60.5420a(b) and maintaining the records for each completion 

operation specified in §60.5420a(c)(1).

(b) For each centrifugal compressor affected facility and 

each pneumatic pump affected facility at a location with a 

control device on site, you must demonstrate continuous 

compliance according to paragraphs (b)(1) through (3) of this 

section.

(1) You must reduce methane and VOC emissions from the wet 

seal fluid degassing system and from the pneumatic pump by 95.0 

percent or greater.

(2) For each control device used to reduce emissions, you 

must demonstrate continuous compliance with the performance 

requirements of §60.5412a(a) using the procedures specified in 
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paragraphs (b)(2)(i) through (vii) of this section. If you use a 

condenser as the control device to achieve the requirements 

specified in §60.5412a(a)(2), you must demonstrate compliance 

according to paragraph (b)(2)(viii) of this section. You may 

switch between compliance with paragraphs (b)(2)(i) through 

(vii) of this section and compliance with paragraph (b)(2)(viii) 

of this section only after at least 1 year of operation in 

compliance with the selected approach. You must provide 

notification of such a change in the compliance method in the 

next annual report, as required in §60.5420a(b), following the 

change.

(i) You must operate below (or above) the site specific 

maximum (or minimum) parameter value established according to 

the requirements of §60.5417a(f)(1).

(ii) You must calculate the daily average of the applicable 

monitored parameter in accordance with §60.5417a(e) except that 

the inlet gas flow rate to the control device must not be 

averaged.

(iii) Compliance with the operating parameter limit is 

achieved when the daily average of the monitoring parameter 

value calculated under paragraph (b)(2)(ii) of this section is 

either equal to or greater than the minimum monitoring value or 
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equal to or less than the maximum monitoring value established 

under paragraph (b)(2)(i) of this section. When performance 

testing of a combustion control device is conducted by the 

device manufacturer as specified in §60.5413a(d), compliance 

with the operating parameter limit is achieved when the criteria 

in §60.5413a(e) are met.

(iv) You must operate the continuous monitoring system 

required in §60.5417a at all times the affected source is 

operating, except for periods of monitoring system malfunctions, 

repairs associated with monitoring system malfunctions, and 

required monitoring system quality assurance or quality control 

activities (including, as applicable, system accuracy audits and 

required zero and span adjustments). A monitoring system 

malfunction is any sudden, infrequent, not reasonably 

preventable failure of the monitoring system to provide valid 

data. Monitoring system failures that are caused in part by poor 

maintenance or careless operation are not malfunctions. You are 

required to complete monitoring system repairs in response to 

monitoring system malfunctions and to return the monitoring 

system to operation as expeditiously as practicable.

(v) You may not use data recorded during monitoring system 

malfunctions, repairs associated with monitoring system 
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malfunctions, or required monitoring system quality assurance or 

control activities in calculations used to report emissions or 

operating levels. You must use all the data collected during all 

other required data collection periods to assess the operation 

of the control device and associated control system.

(vi) Failure to collect required data is a deviation of the 

monitoring requirements, except for periods of monitoring system 

malfunctions, repairs associated with monitoring system 

malfunctions, and required quality monitoring system quality 

assurance or quality control activities (including, as 

applicable, system accuracy audits and required zero and span 

adjustments).

(vii) If you use a combustion control device to meet the 

requirements of §60.5412a(a) and you demonstrate compliance 

using the test procedures specified in §60.5413a(b), you must 

comply with paragraphs (b)(2)(vii)(A) through (D) of this 

section.

(A) A pilot flame must be present at all times of 

operation.

(B) Devices must be operated with no visible emissions, 

except for periods not to exceed a total of 1 minute during any 

15-minute period. A visible emissions test conducted according 
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to section 11 of EPA Method 22, 40 CFR part 60, appendix A, must 

be performed at least once every calendar month, separated by at 

least 15 days between each test. The observation period shall be 

15 minutes.

(C) Devices failing the visible emissions test must follow 

manufacturer's repair instructions, if available, or best 

combustion engineering practice as outlined in the unit 

inspection and maintenance plan, to return the unit to compliant 

operation. All repairs and maintenance activities for each unit 

must be recorded in a maintenance and repair log and must be 

available for inspection.

(D) Following return to operation from maintenance or 

repair activity, each device must pass a Method 22 of appendix 

A-7 of this part visual observation as described in paragraph 

(b)(2)(vii)(B) of this section.

(viii) If you use a condenser as the control device to 

achieve the percent reduction performance requirements specified 

in §60.5412a(a)(2), you must demonstrate compliance using the 

procedures in paragraphs (b)(2)(viii)(A) through (E) of this 

section.

(A) You must establish a site-specific condenser 

performance curve according to §60.5417a(f)(2).
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(B) You must calculate the daily average condenser outlet 

temperature in accordance with §60.5417a(e).

(C) You must determine the condenser efficiency for the 

current operating day using the daily average condenser outlet 

temperature calculated under paragraph (b)(2)(viii)(B) of this 

section and the condenser performance curve established under 

paragraph (b)(2)(viii)(A) of this section.

(D) Except as provided in paragraphs (b)(2)(viii)(D)(1) and 

(2) of this section, at the end of each operating day, you must 

calculate the 365-day rolling average TOC emission reduction, as 

appropriate, from the condenser efficiencies as determined in 

paragraph (b)(2)(viii)(C) of this section.

(1) After the compliance dates specified in §60.5370a, if 

you have less than 120 days of data for determining average TOC 

emission reduction, you must calculate the average TOC emission 

reduction for the first 120 days of operation after the 

compliance date. You have demonstrated compliance with the 

overall 95.0 percent reduction requirement if the 120-day 

average TOC emission reduction is equal to or greater than 95.0 

percent.

(2) After 120 days and no more than 364 days of operation 

after the compliance date specified in §60.5370a, you must 
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calculate the average TOC emission reduction as the TOC emission 

reduction averaged over the number of days between the current 

day and the applicable compliance date. You have demonstrated 

compliance with the overall 95.0 percent reduction requirement 

if the average TOC emission reduction is equal to or greater 

than 95.0 percent.

(E) If you have data for 365 days or more of operation, you 

have demonstrated compliance with the TOC emission reduction if 

the rolling 365-day average TOC emission reduction calculated in 

paragraph (b)(2)(viii)(D) of this section is equal to or greater 

than 95.0 percent.

(3) You must submit the annual report required by 

60.5420a(b) and maintain the records as specified in 

§60.5420a(c)(2), (6) through (11), and (16), as applicable.

(c) For each reciprocating compressor affected facility 

complying with §60.5385a(a)(1) or (2), you must demonstrate 

continuous compliance according to paragraphs (c)(1) through (3) 

of this section. For each reciprocating compressor affected 

facility complying with §60.5385a(a)(3), you must demonstrate 

continuous compliance according to paragraph (c)(4) of this 

section.
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(1) You must continuously monitor the number of hours of 

operation for each reciprocating compressor affected facility or 

track the number of months since initial startup, or [date 60 

days after publication of final rule in Federal Register], or 

the date of the most recent reciprocating compressor rod packing 

replacement, whichever is later.

(2) You must submit the annual report as required in 

§60.5420a(b) and maintain records as required in 

§60.5420a(c)(3).

(3) You must replace the reciprocating compressor rod 

packing before the total number of hours of operation reaches 

26,000 hours or the number of months since the most recent rod 

packing replacement reaches 36 months.

(4) You must operate the rod packing emissions collection 

system under negative pressure and continuously comply with the 

closed vent requirements in §60.5411a(a).

(d) For each pneumatic controller affected facility, you 

must demonstrate continuous compliance according to paragraphs 

(d)(1) through (3) of this section.

(1) You must continuously operate the pneumatic controllers 

as required in §60.5390a(a), (b), or (c).
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(2) You must submit the annual report as required in 

§60.5420a(b).

(3) You must maintain records as required in 

§60.5420a(c)(4).

(e) You must demonstrate continuous compliance according to 

paragraph (e)(3) of this section for each storage vessel 

affected facility, for which you are using a control device or 

routing emissions to a process to meet the requirement of 

§60.5395a(a)(2).

(1)-(2) [Reserved]

(3) For each storage vessel affected facility, you must 

comply with paragraphs (e)(3)(i) and (ii) of this section.

(i) You must reduce methane and VOC emissions as specified 

in §60.5395a(a).

(ii) For each control device installed to meet the 

requirements of §60.5395a(a), you must demonstrate continuous 

compliance with the performance requirements of §60.5412a(d) for 

each storage vessel affected facility using the procedure 

specified in paragraph (e)(3)(ii)(A) and either (e)(3)(ii)(B) or 

(e)(3)(ii)(C) of this section.

(A) You must comply with §60.5416a(c) for each cover and 

closed vent system.
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(B) You must comply with §60.5417a(h) for each control 

device.

(C) Each closed vent system that routes emissions to a 

process must be operated as specified in §60.5411a(c)(2).

(f) For affected facilities at onshore natural gas 

processing plants, continuous compliance with methane and VOC 

requirements is demonstrated if you are in compliance with the 

requirements of §60.5400a.

(g) For each sweetening unit affected facility at onshore 

natural gas processing plants, you must demonstrate continuous 

compliance with the standards for SO2 specified in §60.5405a(b) 

according to paragraphs (g)(1) and (2) of this section.

(1) The minimum required SO2 emission reduction efficiency 

(Zc) is compared to the emission reduction efficiency (R) 

achieved by the sulfur recovery technology.

(i) If R ≥ Zc, your affected facility is in compliance.

(ii) If R < Zc, your affected facility is not in compliance.

(2) The emission reduction efficiency (R) achieved by the 

sulfur reduction technology must be determined using the 

procedures in §60.5406a(c)(1).

(h) For each collection of fugitive emissions components at 

a well site and each collection of fugitive emissions components 
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at a compressor station, you must demonstrate continuous 

compliance with the fugitive emission standards specified in 

§60.5397a according to paragraphs (h)(1) through (4) of this 

section.

(1) You must conduct periodic monitoring surveys as 

required in §60.5397a(f) through (i).

(2) You must repair or replace each identified source of 

fugitive emissions as required in §60.5397a(j).

(3) You must maintain records as specified in 

§60.5420a(c)(15).

(4) You must submit annual reports for collection of 

fugitive emissions components at a well site and each collection 

of fugitive emissions components at a compressor station as 

required in §60.5420a(b).

§60.5416a What are the initial and continuous cover and closed 

vent system inspection and monitoring requirements for my 

centrifugal compressor, reciprocating compressor, pneumatic pump 

and storage vessel affected facilities?

For each closed vent system or cover at your storage 

vessel, centrifugal compressor, reciprocating compressor and 

pneumatic pump affected facilities, you must comply with the 
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applicable requirements of paragraphs (a) through (c) of this 

section.

(a) Inspections for closed vent systems and covers 

installed on each centrifugal compressor, reciprocating 

compressor or pneumatic pump affected facility. Except as 

provided in paragraphs (b)(11) and (12) of this section, you 

must inspect each closed vent system according to the procedures 

and schedule specified in paragraphs (a)(1) and (2) of this 

section, inspect each cover according to the procedures and 

schedule specified in paragraph (a)(3) of this section, and 

inspect each bypass device according to the procedures of 

paragraph (a)(4) of this section.

(1) For each closed vent system joint, seam, or other 

connection that is permanently or semi-permanently sealed (e.g., 

a welded joint between two sections of hard piping or a bolted 

and gasketed ducting flange), you must meet the requirements 

specified in paragraphs (a)(1)(i) and (ii) of this section.

(i) Conduct an initial inspection according to the test 

methods and procedures specified in paragraph (b) of this 

section to demonstrate that the closed vent system operates with 

no detectable emissions. You must maintain records of the 

inspection results as specified in §60.5420a(c)(6).
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(ii) Conduct annual visual inspections for defects that 

could result in air emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps in piping; loose 

connections; liquid leaks; or broken or missing caps or other 

closure devices. You must monitor a component or connection 

using the test methods and procedures in paragraph (b) of this 

section to demonstrate that it operates with no detectable 

emissions following any time the component is repaired or 

replaced or the connection is unsealed. You must maintain 

records of the inspection results as specified in 

§60.5420a(c)(6).

(2) For closed vent system components other than those 

specified in paragraph (a)(1) of this section, you must meet the 

requirements of paragraphs (a)(2)(i) through (iii) of this 

section.

(i) Conduct an initial inspection according to the test 

methods and procedures specified in paragraph (b) of this 

section to demonstrate that the closed vent system operates with 

no detectable emissions. You must maintain records of the 

inspection results as specified in §60.5420a(c)(6).

(ii) Conduct annual inspections according to the test 

methods and procedures specified in paragraph (b) of this 
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section to demonstrate that the components or connections 

operate with no detectable emissions. You must maintain records 

of the inspection results as specified in §60.5420a(c)(6).

(iii) Conduct annual visual inspections for defects that 

could result in air emissions. Defects include, but are not 

limited to, visible cracks, holes, or gaps in ductwork; loose 

connections; liquid leaks; or broken or missing caps or other 

closure devices. You must maintain records of the inspection 

results as specified in §60.5420a(c)(6).

(3) For each cover, you must meet the requirements in 

paragraphs (a)(3)(i) and (ii) of this section.

(i) Conduct visual inspections for defects that could 

result in air emissions. Defects include, but are not limited 

to, visible cracks, holes, or gaps in the cover, or between the 

cover and the separator wall; broken, cracked, or otherwise 

damaged seals or gaskets on closure devices; and broken or 

missing hatches, access covers, caps, or other closure devices. 

In the case where the storage vessel is buried partially or 

entirely underground, you must inspect only those portions of 

the cover that extend to or above the ground surface, and those 

connections that are on such portions of the cover (e.g., fill 
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ports, access hatches, gauge wells, etc.) and can be opened to 

the atmosphere.

(ii) You must initially conduct the inspections specified 

in paragraph (a)(3)(i) of this section following the 

installation of the cover. Thereafter, you must perform the 

inspection at least once every calendar year, except as provided 

in paragraphs (b)(11) and (12) of this section. You must 

maintain records of the inspection results as specified in 

§60.5420a(c)(7).

(4) For each bypass device, except as provided for in 

§60.5411a, you must meet the requirements of paragraphs 

(a)(4)(i) or (ii) of this section.

(i) Set the flow indicator to take a reading at least once 

every 15 minutes at the inlet to the bypass device that could 

divert the steam away from the control device to the atmosphere.

(ii) If the bypass device valve installed at the inlet to 

the bypass device is secured in the non-diverting position using 

a car-seal or a lock-and-key type configuration, visually 

inspect the seal or closure mechanism at least once every month 

to verify that the valve is maintained in the non-diverting 

position and the vent stream is not diverted through the bypass 
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device. You must maintain records of the inspections according 

to §60.5420a(c)(8).

(b) No detectable emissions test methods and procedures. If 

you are required to conduct an inspection of a closed vent 

system or cover at your centrifugal compressor, reciprocating 

compressor, or pneumatic pump affected facility as specified in 

paragraphs (a)(1), (2), or (3) of this section, you must meet 

the requirements of paragraphs (b)(1) through (13) of this 

section.

(1) You must conduct the no detectable emissions test 

procedure in accordance with Method 21 of appendix A-7 of this 

part.

(2) The detection instrument must meet the performance 

criteria of Method 21 of appendix A-7 of this part, except that 

the instrument response factor criteria in section 8.1.1 of 

Method 21 must be for the average composition of the fluid and 

not for each individual organic compound in the stream.

(3) You must calibrate the detection instrument before use 

on each day of its use by the procedures specified in Method 21 

of appendix A-7 of this part.

(4) Calibration gases must be as specified in paragraphs 

(b)(4)(i) and (ii) of this section.
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(i) Zero air (less than 10 parts per million by volume 

hydrocarbon in air).

(ii) A mixture of methane in air at a concentration less 

than 10,000 parts per million by volume.

(5) You may choose to adjust or not adjust the detection 

instrument readings to account for the background organic 

concentration level. If you choose to adjust the instrument 

readings for the background level, you must determine the 

background level value according to the procedures in Method 21 

of appendix A-7 of this part.

(6) Your detection instrument must meet the performance 

criteria specified in paragraphs (b)(6)(i) and (ii) of this 

section.

(i) Except as provided in paragraph (b)(6)(ii) of this 

section, the detection instrument must meet the performance 

criteria of Method 21 of appendix A-7 of this part, except the 

instrument response factor criteria in section 8.1.1 of Method 

21 must be for the average composition of the process fluid, not 

each individual volatile organic compound in the stream. For 

process streams that contain nitrogen, air, or other inerts that 

are not organic hazardous air pollutants or volatile organic 
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compounds, you must calculate the average stream response factor 

on an inert-free basis.

(ii) If no instrument is available that will meet the 

performance criteria specified in paragraph (b)(6)(i) of this 

section, you may adjust the instrument readings by multiplying 

by the average response factor of the process fluid, calculated 

on an inert-free basis, as described in paragraph (b)(6)(i) of 

this section.

(7) You must determine if a potential leak interface 

operates with no detectable emissions using the applicable 

procedure specified in paragraph (b)(7)(i) or (ii) of this 

section.

(i) If you choose not to adjust the detection instrument 

readings for the background organic concentration level, then 

you must directly compare the maximum organic concentration 

value measured by the detection instrument to the applicable 

value for the potential leak interface as specified in paragraph 

(b)(8) of this section.

(ii) If you choose to adjust the detection instrument 

readings for the background organic concentration level, you 

must compare the value of the arithmetic difference between the 

maximum organic concentration value measured by the instrument 
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and the background organic concentration value as determined in 

paragraph (b)(5) of this section with the applicable value for 

the potential leak interface as specified in paragraph (b)(8) of 

this section.

(8) A potential leak interface is determined to operate 

with no detectable organic emissions if the organic 

concentration value determined in paragraph (b)(7) of this 

section is less than 500 parts per million by volume.

(9) Repairs. In the event that a leak or defect is 

detected, you must repair the leak or defect as soon as 

practicable according to the requirements of paragraphs 

(b)(9)(i) and (ii) of this section, except as provided in 

paragraph (b)(10) of this section.

(i) A first attempt at repair must be made no later than 5 

calendar days after the leak is detected.

(ii) Repair must be completed no later than 15 calendar 

days after the leak is detected.

(10) Delay of repair. Delay of repair of a closed vent 

system or cover for which leaks or defects have been detected is 

allowed if the repair is technically infeasible without a 

shutdown, or if you determine that emissions resulting from 

immediate repair would be greater than the fugitive emissions 
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likely to result from delay of repair. You must complete repair 

of such equipment by the end of the next shutdown.

(11) Unsafe to inspect requirements. You may designate any 

parts of the closed vent system or cover as unsafe to inspect if 

the requirements in paragraphs (b)(11)(i) and (ii) of this 

section are met. Unsafe to inspect parts are exempt from the 

inspection requirements of paragraphs (a)(1) through (3) of this 

section.

(i) You determine that the equipment is unsafe to inspect 

because inspecting personnel would be exposed to an imminent or 

potential danger as a consequence of complying with paragraphs 

(a)(1), (2), or (3) of this section.

(ii) You have a written plan that requires inspection of 

the equipment as frequently as practicable during safe-toinspect times.

(12) Difficult to inspect requirements. You may designate 

any parts of the closed vent system or cover as difficult to 

inspect, if the requirements in paragraphs (b)(12)(i) and (ii) 

of this section are met. Difficult to inspect parts are exempt 

from the inspection requirements of paragraphs (a)(1) through 

(3) of this section.
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(i) You determine that the equipment cannot be inspected 

without elevating the inspecting personnel more than 2 meters 

above a support surface.

(ii) You have a written plan that requires inspection of 

the equipment at least once every 5 years.

(13) Records. Records shall be maintained as specified in 

this section and in §60.5420a(c)(9).

(c) Cover and closed vent system inspections for storage 

vessel affected facilities. If you install a control device or 

route emissions to a process, you must inspect each closed vent 

system according to the procedures and schedule specified in 

paragraphs (c)(1) of this section, inspect each cover according 

to the procedures and schedule specified in paragraph (c)(2) of 

this section, and inspect each bypass device according to the 

procedures of paragraph (c)(3) of this section. You must also 

comply with the requirements of (c)(4) through (7) of this 

section.

(1) For each closed vent system, you must conduct an 

inspection at least once every calendar month as specified in 

paragraphs (c)(1)(i) through (iii) of this section.

(i) You must maintain records of the inspection results as 

specified in §60.5420a(c)(6).
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(ii) Conduct olfactory, visual and auditory inspections for 

defects that could result in air emissions. Defects include, but 

are not limited to, visible cracks, holes, or gaps in piping; 

loose connections; liquid leaks; or broken or missing caps or 

other closure devices.

(iii) Monthly inspections must be separated by at least 14 

calendar days.

(2) For each cover, you must conduct inspections at least 

once every calendar month as specified in paragraphs (c)(2)(i) 

through (iii) of this section.

(i) You must maintain records of the inspection results as 

specified in §60.5420a(c)(7).

(ii) Conduct olfactory, visual and auditory inspections for 

defects that could result in air emissions. Defects include, but 

are not limited to, visible cracks, holes, or gaps in the cover, 

or between the cover and the separator wall; broken, cracked, or 

otherwise damaged seals or gaskets on closure devices; and 

broken or missing hatches, access covers, caps, or other closure 

devices. In the case where the storage vessel is buried 

partially or entirely underground, you must inspect only those 

portions of the cover that extend to or above the ground 

surface, and those connections that are on such portions of the 
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cover (e.g., fill ports, access hatches, gauge wells, etc.) and 

can be opened to the atmosphere.

(iii) Monthly inspections must be separated by at least 14 

calendar days.

(3) For each bypass device, except as provided for in 

§60.5411a(c)(3)(ii), you must meet the requirements of 

paragraphs (c)(3)(i) or (ii) of this section.

(i) You must properly install, calibrate and maintain a 

flow indicator at the inlet to the bypass device that could 

divert the stream away from the control device or process to the 

atmosphere. Set the flow indicator to trigger an audible and 

visible alarm, and initiate notification via remote alarm to the 

nearest field office, when the bypass device is open such that 

the stream is being, or could be, diverted away from the control 

device or process to the atmosphere. You must maintain records 

of each time the alarm is sounded according to §60.5420a(c)(8).

(ii) If the bypass device valve installed at the inlet to 

the bypass device is secured in the non-diverting position using 

a car-seal or a lock-and-key type configuration, visually 

inspect the seal or closure mechanism at least once every month 

to verify that the valve is maintained in the non-diverting 

position and the vent stream is not diverted through the bypass 
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device. You must maintain records of the inspections and records 

of each time the key is checked out, if applicable, according to 

§60.5420a(c)(8).

(4) Repairs. In the event that a leak or defect is 

detected, you must repair the leak or defect as soon as 

practicable according to the requirements of paragraphs 

(c)(4)(i) through (iii) of this section, except as provided in 

paragraph (c)(5) of this section.

(i) A first attempt at repair must be made no later than 5 

calendar days after the leak is detected.

(ii) Repair must be completed no later than 30 calendar 

days after the leak is detected.

(iii) Grease or another applicable substance must be 

applied to deteriorating or cracked gaskets to improve the seal 

while awaiting repair.

(5) Delay of repair. Delay of repair of a closed vent 

system or cover for which leaks or defects have been detected is 

allowed if the repair is technically infeasible without a 

shutdown, or if you determine that emissions resulting from 

immediate repair would be greater than the fugitive emissions 

likely to result from delay of repair. You must complete repair 

of such equipment by the end of the next shutdown.
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(6) Unsafe to inspect requirements. You may designate any 

parts of the closed vent system or cover as unsafe to inspect if 

the requirements in paragraphs (c)(6)(i) and (ii) of this 

section are met. Unsafe to inspect parts are exempt from the 

inspection requirements of paragraphs (c)(1) and (2) of this 

section.

(i) You determine that the equipment is unsafe to inspect 

because inspecting personnel would be exposed to an imminent or 

potential danger as a consequence of complying with paragraphs 

(c)(1) or (2) of this section.

(ii) You have a written plan that requires inspection of 

the equipment as frequently as practicable during safe-toinspect times.

(7) Difficult to inspect requirements. You may designate 

any parts of the closed vent system or cover as difficult to 

inspect, if the requirements in paragraphs (c)(7)(i) and (ii) of 

this section are met. Difficult to inspect parts are exempt from 

the inspection requirements of paragraphs (c)(1) and (2) of this 

section.

(i) You determine that the equipment cannot be inspected 

without elevating the inspecting personnel more than 2 meters 

above a support surface.
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(ii) You have a written plan that requires inspection of 

the equipment at least once every 5 years.

§60.5417a What are the continuous control device monitoring 

requirements for my centrifugal compressor, pneumatic pump, and 

storage vessel affected facilities?

You must meet the applicable requirements of this section 

to demonstrate continuous compliance for each control device 

used to meet emission standards for your storage vessel, 

centrifugal compressor or pneumatic pump affected facility.

(a) For each control device used to comply with the 

emission reduction standard for centrifugal compressor affected 

facilities in §60.5380a(a)(1) or the emission reduction standard 

for pneumatic pumps affected facilities in §60.5393a(b)(1), you 

must install and operate a continuous parameter monitoring 

system for each control device as specified in paragraphs (c) 

through (g) of this section, except as provided for in paragraph 

(b) of this section. If you install and operate a flare in 

accordance with §60.5412a(a)(3), you are exempt from the 

requirements of paragraphs (e) and (f) of this section.

(b) You are exempt from the monitoring requirements 

specified in paragraphs (c) through (g) of this section for the 
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control devices listed in paragraphs (b)(1) and (2) of this 

section.

(1) A boiler or process heater in which all vent streams 

are introduced with the primary fuel or are used as the primary 

fuel.

(2) A boiler or process heater with a design heat input 

capacity equal to or greater than 44 megawatts.

(c) If you are required to install a continuous parameter 

monitoring system, you must meet the specifications and 

requirements in paragraphs (c)(1) through (4) of this section.

(1) Each continuous parameter monitoring system must 

measure data values at least once every hour and record the 

parameters in paragraphs (c)(1)(i) or (ii) of this section.

(i) Each measured data value.

(ii) Each block average value for each 1-hour period or 

shorter periods calculated from all measured data values during 

each period. If values are measured more frequently than once 

per minute, a single value for each minute may be used to 

calculate the hourly (or shorter period) block average instead 

of all measured values.

(2) You must prepare a site-specific monitoring plan that 

addresses the monitoring system design, data collection, and the 
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quality assurance and quality control elements outlined in 

paragraphs (c)(2)(i) through (v) of this section. You must 

install, calibrate, operate, and maintain each continuous 

parameter monitoring system in accordance with the procedures in 

your approved site-specific monitoring plan.

(i) The performance criteria and design specifications for 

the monitoring system equipment, including the sample interface, 

detector signal analyzer, and data acquisition and calculations.

(ii) Sampling interface (e.g., thermocouple) location such 

that the monitoring system will provide representative 

measurements.

(iii) Equipment performance checks, system accuracy audits, 

or other audit procedures.

(iv) Ongoing operation and maintenance procedures in 

accordance with provisions in §60.13(b).

(v) Ongoing reporting and recordkeeping procedures in 

accordance with provisions in §60.7(c), (d), and (f).

(3) You must conduct the continuous parameter monitoring 

system equipment performance checks, system accuracy audits, or 

other audit procedures specified in the site-specific monitoring 

plan at least once every 12 months.
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(4) You must conduct a performance evaluation of each 

continuous parameter monitoring system in accordance with the 

site-specific monitoring plan.

(d) You must install, calibrate, operate, and maintain a 

device equipped with a continuous recorder to measure the values 

of operating parameters appropriate for the control device as 

specified in paragraph (d)(1), (2), or (3) of this section.

(1) A continuous monitoring system that measures the 

operating parameters in paragraphs (d)(1)(i) through (viii) of 

this section, as applicable.

(i) For a thermal vapor incinerator that demonstrates 

during the performance test conducted under §60.5413a that 

combustion zone temperature is an accurate indicator of 

performance, a temperature monitoring device equipped with a 

continuous recorder. The monitoring device must have a minimum 

accuracy of ±1 percent of the temperature being monitored in °C, 

or ±2.5°C, whichever value is greater. You must install the 

temperature sensor at a location representative of the 

combustion zone temperature.

(ii) For a catalytic vapor incinerator, a temperature 

monitoring device equipped with a continuous recorder. The 

device must be capable of monitoring temperature at two 
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locations and have a minimum accuracy of ±1 percent of the 

temperature being monitored in °C, or ±2.5°C, whichever value is 

greater. You must install one temperature sensor in the vent 

stream at the nearest feasible point to the catalyst bed inlet, 

and you must install a second temperature sensor in the vent 

stream at the nearest feasible point to the catalyst bed outlet.

(iii) For a flare, a heat sensing monitoring device 

equipped with a continuous recorder that indicates the 

continuous ignition of the pilot flame.

(iv) For a boiler or process heater, a temperature 

monitoring device equipped with a continuous recorder. The 

temperature monitoring device must have a minimum accuracy of ±1 

percent of the temperature being monitored in °C, or ±2.5°C, 

whichever value is greater. You must install the temperature 

sensor at a location representative of the combustion zone 

temperature.

(v) For a condenser, a temperature monitoring device 

equipped with a continuous recorder. The temperature monitoring 

device must have a minimum accuracy of ±1 percent of the 

temperature being monitored in °C, or ±2.5°C, whichever value is 

greater. You must install the temperature sensor at a location 

in the exhaust vent stream from the condenser.
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(vi) For a regenerative-type carbon adsorption system, a 

continuous monitoring system that meets the specifications in 

paragraphs (d)(1)(vi)(A) and (B) of this section.

(A) The continuous parameter monitoring system must measure 

and record the average total regeneration stream mass flow or 

volumetric flow during each carbon bed regeneration cycle. The 

flow sensor must have a measurement sensitivity of 5 percent of 

the flow rate or 10 cubic feet per minute, whichever is greater. 

You must check the mechanical connections for leakage at least 

every month, and you must perform a visual inspection at least 

every 3 months of all components of the flow continuous 

parameter monitoring system for physical and operational 

integrity and all electrical connections for oxidation and 

galvanic corrosion if your flow continuous parameter monitoring 

system is not equipped with a redundant flow sensor; and

(B) The continuous parameter monitoring system must measure 

and record the average carbon bed temperature for the duration 

of the carbon bed steaming cycle and measure the actual carbon 

bed temperature after regeneration and within 15 minutes of 

completing the cooling cycle. The temperature monitoring device 

must have a minimum accuracy of ±1 percent of the temperature 

being monitored in °C, or ±2.5°C, whichever value is greater.
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(vii) For a nonregenerative-type carbon adsorption system, 

you must monitor the design carbon replacement interval 

established using a design analysis performed as specified in 

§60.5413a(c)(3). The design carbon replacement interval must be 

based on the total carbon working capacity of the control device 

and source operating schedule.

(viii) For a combustion control device whose model is 

tested under §60.5413a(d), a continuous monitoring system 

meeting the requirements of paragraphs (d)(1)(viii)(A) and (B) 

of this section.

(A) The continuous monitoring system must measure gas flow 

rate at the inlet to the control device. The monitoring 

instrument must have an accuracy of ±2 percent or better. The 

flow rate at the inlet to the combustion device must not exceed 

the maximum or be less than the minimum flow rate determined by 

the manufacturer.

(B) A monitoring device that continuously indicates the 

presence of the pilot flame while emissions are routed to the 

control device.

(2) An organic monitoring device equipped with a continuous 

recorder that measures the concentration level of organic 

compounds in the exhaust vent stream from the control device. 
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The monitor must meet the requirements of Performance 

Specification 8 or 9 of appendix B of this part. You must 

install, calibrate, and maintain the monitor according to the 

manufacturer's specifications.

(3) A continuous monitoring system that measures operating 

parameters other than those specified in paragraph (d)(1) or (2) 

of this section, upon approval of the Administrator as specified 

in §60.13(i).

(e) You must calculate the daily average value for each 

monitored operating parameter for each operating day, using the 

data recorded by the monitoring system, except for inlet gas 

flow rate. If the emissions unit operation is continuous, the 

operating day is a 24-hour period. If the emissions unit 

operation is not continuous, the operating day is the total 

number of hours of control device operation per 24-hour period. 

Valid data points must be available for 75 percent of the 

operating hours in an operating day to compute the daily 

average.

(f) For each operating parameter monitor installed in 

accordance with the requirements of paragraph (d) of this 

section, you must comply with paragraph (f)(1) of this section 
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for all control devices. When condensers are installed, you must 

also comply with paragraph (f)(2) of this section.

(1) You must establish a minimum operating parameter value 

or a maximum operating parameter value, as appropriate for the 

control device, to define the conditions at which the control 

device must be operated to continuously achieve the applicable 

performance requirements of §60.5412a(a). You must establish 

each minimum or maximum operating parameter value as specified 

in paragraphs (f)(1)(i) through (iii) of this section.

(i) If you conduct performance tests in accordance with the 

requirements of §60.5413a(b) to demonstrate that the control 

device achieves the applicable performance requirements 

specified in §60.5412a(a), then you must establish the minimum 

operating parameter value or the maximum operating parameter 

value based on values measured during the performance test and 

supplemented, as necessary, by a condenser design analysis or 

control device manufacturer recommendations or a combination of 

both.

(ii) If you use a condenser design analysis in accordance 

with the requirements of §60.5413a(c) to demonstrate that the 

control device achieves the applicable performance requirements 

specified in §60.5412a(a), then you must establish the minimum 
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operating parameter value or the maximum operating parameter 

value based on the condenser design analysis and supplemented, 

as necessary, by the condenser manufacturer's recommendations.

(iii) If you operate a control device where the performance 

test requirement was met under §60.5413a(d) to demonstrate that 

the control device achieves the applicable performance 

requirements specified in §60.5412a(a), then your control device 

inlet gas flow rate must not exceed the maximum or be less than 

the minimum inlet gas flow rate determined by the manufacturer.

(2) If you use a condenser as specified in paragraph 

(d)(1)(v) of this section, you must establish a condenser 

performance curve showing the relationship between condenser 

outlet temperature and condenser control efficiency, according 

to the requirements of paragraphs (f)(2)(i) and (ii) of this 

section.

(i) If you conduct a performance test in accordance with 

the requirements of §60.5413a(b) to demonstrate that the 

condenser achieves the applicable performance requirements in 

§60.5412a(a), then the condenser performance curve must be based 

on values measured during the performance test and supplemented 

as necessary by control device design analysis, or control 

device manufacturer's recommendations, or a combination or both.
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(ii) If you use a control device design analysis in 

accordance with the requirements of §60.5413a(c)(1) to 

demonstrate that the condenser achieves the applicable 

performance requirements specified in §60.5412a(a), then the 

condenser performance curve must be based on the condenser 

design analysis and supplemented, as necessary, by the control 

device manufacturer's recommendations.

(g) A deviation for a given control device is determined to 

have occurred when the monitoring data or lack of monitoring 

data result in any one of the criteria specified in paragraphs 

(g)(1) through (g)(6) of this section being met. If you monitor 

multiple operating parameters for the same control device during 

the same operating day and more than one of these operating 

parameters meets a deviation criterion specified in paragraphs 

(g)(1) through (6) of this section, then a single excursion is 

determined to have occurred for the control device for that 

operating day.

(1) A deviation occurs when the daily average value of a 

monitored operating parameter is less than the minimum operating 

parameter limit (or, if applicable, greater than the maximum 

operating parameter limit) established in paragraph (f)(1) of 

this section.
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(2) If you are subject to §60.5412a(a)(2), a deviation 

occurs when the 365-day average condenser efficiency calculated 

according to the requirements specified in 

§60.5415a(b)(2)(viii)(D) is less than 95.0 percent.

(3) If you are subject to §60.5412a(a)(2) and you have less 

than 365 days of data, a deviation occurs when the average 

condenser efficiency calculated according to the procedures 

specified in §60.5415a(b)(2)(viii)(D)(1) or (2) is less than 

95.0 percent.

(4) A deviation occurs when the monitoring data are not 

available for at least 75 percent of the operating hours in a 

day.

(5) If the closed vent system contains one or more bypass 

devices that could be used to divert all or a portion of the 

gases, vapors, or fumes from entering the control device, a 

deviation occurs when the requirements of paragraph (g)(5)(i) or 

(ii) of this section are met.

(i) For each bypass line subject to §60.5411a(a)(3)(i)(A), 

the flow indicator indicates that flow has been detected and 

that the stream has been diverted away from the control device 

to the atmosphere.
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(ii) For each bypass line subject to §60.5411a(a)(3)(i)(B), 

if the seal or closure mechanism has been broken, the bypass 

line valve position has changed, the key for the lock-and-key 

type lock has been checked out, or the car-seal has broken.

(6) For a combustion control device whose model is tested 

under §60.5413a(d), a deviation occurs when the conditions of 

paragraphs (g)(6)(i) or (ii) are met.

(i) The inlet gas flow rate exceeds the maximum established 

during the test conducted under §60.5413a(d).

(ii) Failure of the monthly visible emissions test 

conducted under §60.5413a(e)(3) occurs.

(h) For each control device used to comply with the 

emission reduction standard in §60.5395a(a)(2) for your storage 

vessel affected facility, you must demonstrate continuous 

compliance according to paragraphs (h)(1) through (h)(4) of this 

section. You are exempt from the requirements of this paragraph 

if you install a control device model tested in accordance with 

§60.5413a(d)(2) through (10), which meets the criteria in 

§60.5413a(d)(11), the reporting requirement in §60.5413a(d)(12), 

and meet the continuous compliance requirement in §60.5413a(e).

(1) For each combustion device you must conduct inspections 

at least once every calendar month according to paragraphs 
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(h)(1)(i) through (iv) of this section. Monthly inspections must 

be separated by at least 14 calendar days.

(i) Conduct visual inspections to confirm that the pilot is 

lit when vapors are being routed to the combustion device and 

that the continuous burning pilot flame is operating properly.

(ii) Conduct inspections to monitor for visible emissions 

from the combustion device using section 11 of EPA Method 22 of 

appendix A of this part. The observation period shall be 15 

minutes. Devices must be operated with no visible emissions, 

except for periods not to exceed a total of 1 minute during any 

15 minute period.

(iii) Conduct olfactory, visual and auditory inspections of 

all equipment associated with the combustion device to ensure 

system integrity.

(iv) For any absence of the pilot flame, or other 

indication of smoking or improper equipment operation (e.g., 

visual, audible, or olfactory), you must ensure the equipment is 

returned to proper operation as soon as practicable after the 

event occurs. At a minimum, you must perform the procedures 

specified in paragraphs (h)(1)(iv)(A) and (B) of this section.
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(A) You must check the air vent for obstruction. If an 

obstruction is observed, you must clear the obstruction as soon 

as practicable.

(B) You must check for liquid reaching the combustor.

(2) For each vapor recovery device, you must conduct 

inspections at least once every calendar month to ensure 

physical integrity of the control device according to the 

manufacturer's instructions. Monthly inspections must be 

separated by at least 14 calendar days.

(3) Each control device must be operated following the 

manufacturer's written operating instructions, procedures and 

maintenance schedule to ensure good air pollution control 

practices for minimizing emissions. Records of the 

manufacturer's written operating instructions, procedures, and 

maintenance schedule must be available for inspection as 

specified in §60.5420a(c)(13).

(4) Conduct a periodic performance test no later than 60 

months after the initial performance test as specified in 

§60.5413a(b)(5)(ii) and conduct subsequent periodic performance 

tests at intervals no longer than 60 months following the 

previous periodic performance test.
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§60.5420a What are my notification, reporting, and recordkeeping 

requirements?

(a) You must submit the notifications according to 

paragraphs (a)(1) and (2) of this section if you own or operate 

one or more of the affected facilities specified in §60.5365a 

that was constructed, modified, or reconstructed during the 

reporting period.

(1) If you own or operate a well, centrifugal compressor, 

reciprocating compressor, pneumatic controller, pneumatic pump, 

storage vessel, or collection of fugitive emissions components 

at a well site or collection of fugitive emissions components at 

a compressor station you are not required to submit the 

notifications required in §60.7(a)(1), (3), and (4).

(2)(i) If you own or operate a well affected facility, you 

must submit a notification to the Administrator no later than 2 

days prior to the commencement of each well completion operation 

listing the anticipated date of the well completion operation. 

The notification shall include contact information for the owner 

or operator; the API well number; the latitude and longitude 

coordinates for each well in decimal degrees to an accuracy and 

precision of five (5) decimals of a degree using the North 

American Datum of 1983; and the planned date of the beginning of 
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flowback. You may submit the notification in writing or in 

electronic format.

(ii) If you are subject to state regulations that require 

advance notification of well completions and you have met those 

notification requirements, then you are considered to have met 

the advance notification requirements of paragraph (a)(2)(i) of 

this section.

(b) Reporting requirements. You must submit annual reports 

containing the information specified in paragraphs (b)(1) 

through (8) of this section and performance test reports as 

specified in paragraph (b)(9) or (10) of this section. You must 

submit annual reports following the procedure specified in 

paragraph (b)(11). The initial annual report is due no later 

than 90 days after the end of the initial compliance period as 

determined according to §60.5410a. Subsequent annual reports are 

due no later than same date each year as the initial annual 

report. If you own or operate more than one affected facility, 

you may submit one report for multiple affected facilities 

provided the report contains all of the information required as 

specified in paragraphs (b)(1) through (10) of this section. 

Annual reports may coincide with title V reports as long as all 

the required elements of the annual report are included. You may 
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arrange with the Administrator a common schedule on which 

reports required by this part may be submitted as long as the 

schedule does not extend the reporting period.

(1) The general information specified in paragraphs 

(b)(1)(i) through (iv) of this section for all reports.

(i) The company name and address of the affected facility.

(ii) An identification of each affected facility being 

included in the annual report.

(iii) Beginning and ending dates of the reporting period.

(iv) A certification by a certifying official of truth, 

accuracy, and completeness. This certification shall state that, 

based on information and belief formed after reasonable inquiry, 

the statements and information in the document are true, 

accurate, and complete.

(2) For each well affected facility, the information in 

paragraphs (b)(2)(i) and (ii) of this section.

(i) Records of each well completion operation as specified 

in paragraph (c)(1)(i) through (iv) of this section for each 

well affected facility conducted during the reporting period. In 

lieu of submitting the records specified in paragraph (c)(1)(i) 

through (iv), the owner or operator may submit a list of the 

well completions with hydraulic fracturing completed during the 
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reporting period and the records required by paragraph (c)(1)(v) 

of this section for each well completion.

(ii) Records of deviations specified in paragraph 

(c)(1)(ii) of this section that occurred during the reporting 

period.

(3) For each centrifugal compressor affected facility, the 

information specified in paragraphs (b)(3)(i) through (iv) of 

this section.

(i) An identification of each centrifugal compressor using 

a wet seal system constructed, modified or reconstructed during 

the reporting period.

(ii) Records of deviations specified in paragraph (c)(2) of 

this section that occurred during the reporting period.

(iii) If required to comply with §60.5380a(a)(2), the 

records specified in paragraphs (c)(6) through (11) of this 

section.

(iv) If complying with §60.5380a(a)(1) with a control 

device tested under §60.5413a(d) which meets the criteria in 

§60.5413a(d)(11) and §60.5413a(e), records specified in 

paragraph (c)(2)(i) through (c)(2)(vii) of this section for each 

centrifugal compressor using a wet seal system constructed, 

modified or reconstructed during the reporting period.
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(4) For each reciprocating compressor affected facility, 

the information specified in paragraphs (b)(4)(i) and (ii) of 

this section.

(i) The cumulative number of hours of operation or the 

number of months since initial startup, since [date 60 days 

after publication of final rule in the Federal Register], or 

since the previous reciprocating compressor rod packing 

replacement, whichever is later.

(ii) Records of deviations specified in paragraph 

(c)(3)(iii) of this section that occurred during the reporting 

period.

(5) For each pneumatic controller affected facility, the 

information specified in paragraphs (b)(5)(i) through (iii) of 

this section.

(i) An identification of each pneumatic controller 

constructed, modified or reconstructed during the reporting 

period, including the identification information specified in 

§60.5390a(b)(2) or (c)(2).

(ii) If applicable, documentation that the use of pneumatic 

controller affected facilities with a natural gas bleed rate 

greater than 6 standard cubic feet per hour are required and the 

reasons why.
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(iii) Records of deviations specified in paragraph 

(c)(4)(v) of this section that occurred during the reporting 

period.

(6) For each storage vessel affected facility, the 

information in paragraphs (b)(6)(i) through (vii) of this 

section.

(i) An identification, including the location, of each 

storage vessel affected facility for which construction, 

modification or reconstruction commenced during the reporting 

period. The location of the storage vessel shall be in latitude 

and longitude coordinates in decimal degrees to an accuracy and 

precision of five (5) decimals of a degree using the North 

American Datum of 1983. 

(ii) Documentation of the VOC emission rate determination 

according to §60.5365a(e) for each storage vessel that became an 

affected facility during the reporting period or is returned to 

service during the reporting period.

(iii) Records of deviations specified in paragraph 

(c)(5)(iii) of this section that occurred during the reporting 

period.

(iv) A statement that you have met the requirements 

specified in §60.5410a(h)(2) and (3).
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(v) You must identify each storage vessel affected facility 

that is removed from service during the reporting period as 

specified in §60.5395a(c)(1)(ii), including the date the storage 

vessel affected facility was removed from service.

(vi) You must identify each storage vessel affected 

facility returned to service during the reporting period as 

specified in §60.5395a(c)(3), including the date the storage 

vessel affected facility was returned to service.

(vii) If complying with §60.5395a(a)(2) with a control 

device tested under §60.5413a(d) which meets the criteria in 

§60.5413a(d)(11) and §60.5413a(e), records specified in 

paragraphs (c)(5)(vi)(A) through (G) of this section for each 

storage vessel constructed, modified, reconstructed or returned 

to service during the reporting period.

(7) For the collection of fugitive emissions components at 

a well site and the collection of fugitive emissions components 

at a compressor station, the records of each monitoring survey 

conducted during the year: 

(i) Date of the survey.

(ii) Beginning and end time of the survey.
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(iii) Name of operator(s) performing survey. If the survey 

is performed by optical gas imaging, you must note the training 

and experience of the operator.

(iv) Ambient temperature, sky conditions, and maximum wind 

speed at the time of the survey.

(v) Any deviations from the monitoring plan or a statement 

that there were no deviations from the monitoring plan.

(vi) Documentation of each fugitive emission, including the 

information specified in paragraphs (b)(7)(vi)(A) through (C) of 

this section

(A) Location.

(B) One or more digital photographs of each required 

monitoring survey being performed. The digital photograph must 

include the date the photograph was taken and the latitude and 

longitude of the collection of fugitive emissions components at 

a well site or collection of fugitive emissions components at a 

compressor station imbedded within or stored with the digital 

file. As an alternative to imbedded latitude and longitude 

within the digital photograph, the digital photograph may 

consist of a photograph of the monitoring survey being performed 

with a photograph of a separately operating GIS device within 

the same digital picture, provided the latitude and longitude 
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output of the GIS unit can be clearly read in the digital 

photograph.

(C) The date of successful repair of the fugitive emissions 

component.

 (D) Type of instrument used to resurvey a repaired fugitive 

emissions component that could not be repaired during the 

initial fugitive emissions finding.

(8) For each pneumatic pump affected facility, the 

information specified in paragraphs (b)(8)(i) through (v) of 

this section.

(i) In the initial annual report, a certification that 

there is no control device on site, if applicable.

(ii) An identification of each pneumatic pump constructed, 

modified or reconstructed during the reporting period, including 

the identification information specified in §60.5393a(a)(2) or 

(b)(2).

(iii) An identification of any sites which contain natural 

pneumatic pumps and which installed a control device during the 

reporting period, where there was no control device previously 

at the site.
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(iv) Records of deviations specified in paragraph 

(c)(16)(ii) of this section that occurred during the reporting 

period.

(v) If complying with §60.5393a(b)(1) with a control device 

tested under §60.5413(d), which meets the criteria in 

§60.5413(d)(11) and §60.5413(e), records specified in paragraphs 

(c)(16)(iv)(A) through (G) of this section for each pneumatic 

pump constructed, modified or reconstructed during the reporting 

period.

(9) Within 60 days after the date of completing each 

performance test (see §60.8) required by this subpart, except 

testing conducted by the manufacturer as specified in 

§60.5413a(d), you must submit the results of the performance 

test following the procedure specified in either paragraph 

(b)(9)(i) or (ii) of this section. 

(i) For data collected using test methods supported by the 

EPA’s Electronic Reporting Tool (ERT) as listed on the EPA’s ERT 

Web site (http://www.epa.gov/ttn/chief/ert/index.html) at the 

time of the test, you must submit the results of the performance 

test to the EPA via the Compliance and Emissions Data Reporting 

Interface (CEDRI). (CEDRI can be accessed through the EPA’s 

Central Data Exchange (CDX) (https://cdx.epa.gov/).) Performance 
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test data must be submitted in a file format generated through 

the use of the EPA’s ERT or an alternate electronic file format 

consistent with the extensible markup language (XML) schema 

listed on the EPA’s ERT Web site. If you claim that some of the 

performance test information being submitted is confidential

business information (CBI), you must submit a complete file 

generated through the use of the EPA’s ERT or an alternate 

electronic file consistent with the XML schema listed on the 

EPA’s ERT Web site, including information claimed to be CBI, on 

a compact disc, flash drive, or other commonly used electronic 

storage media to the EPA. The electronic media must be clearly 

marked as CBI and mailed to U.S. EPA/OAQPS/CORE CBI Office, 

Attention: Group Leader, Measurement Policy Group, MD C404-02, 

4930 Old Page Rd., Durham, NC 27703. The same ERT or alternate 

file with the CBI omitted must be submitted to the EPA via the 

EPA’s CDX as described earlier in this paragraph.

(ii) For data collected using test methods that are not 

supported by the EPA’s ERT as listed on the EPA’s ERT Web site 

at the time of the test, you must submit the results of the 

performance test to the Administrator at the appropriate address 

listed in §60.4.
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(10) For combustion control devices tested by the 

manufacturer in accordance with §60.5413a(d), an electronic copy 

of the performance test results required by §60.5413a(d) shall 

be submitted via email to Oil_and_Gas_PT@EPA.GOV unless the test 

results for that model of combustion control device are posted 

at the following Web site: epa.gov/airquality/oilandgas/.

(11) You must submit reports to the EPA via the CEDRI. 

(CEDRI can be accessed through the EPA’s CDX 

(https://cdx.epa.gov/).) You must use the appropriate electronic 

report in CEDRI for this subpart or an alternate electronic file 

format consistent with the extensible markup language (XML) 

schema listed on the CEDRI Web site 

(http://www.epa.gov/ttn/chief/cedri/index.html). If the 

reporting form specific to this subpart is not available in 

CEDRI at the time that the report is due, you must submit the 

report to the Administrator at the appropriate address listed in 

§60.4. You must begin submitting reports via CEDRI no later than 

90 days after the form becomes available in CEDRI. The reports 

must be submitted by the deadlines specified in this subpart, 

regardless of the method in which the reports are submitted. 

(c) Recordkeeping requirements. You must maintain the 

records identified as specified in §60.7(f) and in paragraphs 
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(c)(1) through (16) of this section. All records required by 

this subpart must be maintained either onsite or at the nearest 

local field office for at least 5 years. Any records required to 

be maintained by this subpart that are submitted electronically 

via the EPA’s CDX may be maintained in electronic format.

(1) The records for each well affected facility as 

specified in paragraphs (c)(1)(i) through (v) of this section.

(i) Records identifying each well completion operation for 

each well affected facility;

(ii) Records of deviations in cases where well completion 

operations with hydraulic fracturing were not performed in 

compliance with the requirements specified in §60.5375a.

(iii) Records required in §60.5375a(b) or (f) for each well 

completion operation conducted for each well affected facility 

that occurred during the reporting period. You must maintain the 

records specified in paragraphs (c)(1)(iii)(A) and (B) of this 

section.

(A) For each well affected facility required to comply with 

the requirements of §60.5375a(a), you must record: The location 

of the well; the API well number; the date and time of the onset 

of flowback following hydraulic fracturing or refracturing; the 

date and time of each attempt to direct flowback to a separator 
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as required in §60.5375a(a)(1)(ii); the date and time of each 

occurrence of returning to the initial flowback stage under 

§60.5375a(a)(1)(i); and the date and time that the well was shut 

in and the flowback equipment was permanently disconnected, or 

the startup of production; the duration of flowback; duration of 

recovery to the flow line; duration of combustion; duration of 

venting; and specific reasons for venting in lieu of capture or 

combustion. The duration must be specified in hours.

(B) For each well affected facility required to comply with 

the requirements of §60.5375a(f), you must maintain the records 

specified in paragraph (c)(1)(iii)(A) of this section except 

that you do not have to record the duration of recovery to the 

flow line.

(iv) For each well affected facility for which you claim an 

exception under §60.5375a(a)(3), you must record: The location 

of the well; the API well number; the specific exception 

claimed; the starting date and ending date for the period the 

well operated under the exception; and an explanation of why the 

well meets the claimed exception.

(v) For each well affected facility required to comply with 

both §60.5375a(a)(1) and (3), if you are using a digital 

photograph in lieu of the records required in paragraphs 
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(c)(1)(i) through (iv) of this section, you must retain the 

records of the digital photograph as specified in 

§60.5410a(a)(4).

(2) For each centrifugal compressor affected facility, you 

must maintain records of deviations in cases where the 

centrifugal compressor was not operated in compliance with the 

requirements specified in §60.5380a. Except as specified in 

paragraph (c)(2)(vii) of this section, you must maintain the 

records in paragraphs (c)(2)(i) through (vi) of this section for 

each control device tested under §60.5413a(d) which meets the 

criteria in §60.5413a(d)(11) and §60.5413a(e) and used to comply 

with §60.5380a(a)(1) for each centrifugal compressor. 

(i) Make, model and serial number of purchased device.

(ii) Date of purchase.

(iii) Copy of purchase order.

(iv) Location of the centrifugal compressor and control 

device in latitude and longitude coordinates in decimal degrees 

to an accuracy and precision of five (5) decimals of a degree 

using the North American Datum of 1983. 

(v) Inlet gas flow rate.
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(vi) Records of continuous compliance requirements in 

§60.5413a(e) as specified in paragraphs (c)(2)(vi)(A) through 

(D) of this section.

(A) Records that the pilot flame is present at all times of 

operation.

(B) Records that the device was operated with no visible 

emissions except for periods not to exceed a total of 2 minutes 

during any hour.

(C) Records of the maintenance and repair log.

(D) Records of the visible emissions test following return 

to operation from a maintenance or repair activity.

(vii) As an alternative to the requirements of paragraph 

(c)(2)(iv) of this section, you may maintain records of one or 

more digital photographs with the date the photograph was taken 

and the latitude and longitude of the centrifugal compressor and 

control device imbedded within or stored with the digital file. 

As an alternative to imbedded latitude and longitude within the 

digital photograph, the digital photograph may consist of a 

photograph of the centrifugal compressor and control device with 

a photograph of a separately operating GIS device within the 

same digital picture, provided the latitude and longitude output 

of the GIS unit can be clearly read in the digital photograph.
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(3) For each reciprocating compressor affected facility, 

you must maintain the records in paragraphs (c)(3)(i) through 

(iii) of this section.

(i) Records of the cumulative number of hours of operation 

or number of months since initial startup or [date 60 days after 

publication of final rule in the Federal Register], or the 

previous replacement of the reciprocating compressor rod 

packing, whichever is later.

(ii) Records of the date and time of each reciprocating 

compressor rod packing replacement, or date of installation of a 

rod packing emissions collection system and closed vent system 

as specified in §60.5385a(a)(3).

(iii) Records of deviations in cases where the 

reciprocating compressor was not operated in compliance with the 

requirements specified in §60.5385a.

(4) For each pneumatic controller affected facility, you 

must maintain the records identified in paragraphs (c)(4)(i) 

through (v) of this section, as applicable.

(i) Records of the date, location and manufacturer 

specifications for each pneumatic controller constructed, 

modified or reconstructed.
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(ii) Records of the demonstration that the use of pneumatic 

controller affected facilities with a natural gas bleed rate 

greater than the applicable standard are required and the 

reasons why.

(iii) If the pneumatic controller is not located at a 

natural gas processing plant, records of the manufacturer's 

specifications indicating that the controller is designed such 

that natural gas bleed rate is less than or equal to 6 standard 

cubic feet per hour.

(iv) If the pneumatic controller is located at a natural 

gas processing plant, records of the documentation that the 

natural gas bleed rate is zero.

(v) Records of deviations in cases where the pneumatic 

controller was not operated in compliance with the requirements 

specified in §60.5390a.

(5) For each storage vessel affected facility, you must 

maintain the records identified in paragraphs (c)(5)(i) through 

(vi) of this section.

(i) If required to reduce emissions by complying with 

§60.5395a(a)(2), the records specified in §§60.5420a(c)(6) 

through (8), 60.5416a(c)(6)(ii), and 60.5416a(c)(7)(ii). You 

must maintain the records in paragraph (c)(5)(vi) of this part 
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for each control device tested under §60.5413a(d) which meets 

the criteria in §60.5413a(d)(11) and §60.5413a(e) and used to 

comply with §60.5395a(a)(2) for each storage vessel. 

(ii) Records of each VOC emissions determination for each 

storage vessel affected facility made under §60.5365a(e) 

including identification of the model or calculation methodology 

used to calculate the VOC emission rate.

(iii) Records of deviations in cases where the storage 

vessel was not operated in compliance with the requirements 

specified in §§60.5395a, 60.5411a, 60.5412a, and 60.5413a, as 

applicable.

(iv) For storage vessels that are skid-mounted or 

permanently attached to something that is mobile (such as 

trucks, railcars, barges or ships), records indicating the 

number of consecutive days that the vessel is located at a site 

in the oil and natural gas production segment, natural gas 

processing segment or natural gas transmission and storage 

segment. If a storage vessel is removed from a site and, within 

30 days, is either returned to the site or replaced by another 

storage vessel at the site to serve the same or similar 

function, then the entire period since the original storage 

vessel was first located at the site, including the days when 
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the storage vessel was removed, will be added to the count 

towards the number of consecutive days.

(v) You must maintain records of the identification and 

location of each storage vessel affected facility.

(vi) Except as specified in paragraph (c)(5)(vi)(G) of this 

section, you must maintain the records specified in paragraphs 

(c)(5)(vi)(A) through (F) of this section for each control 

device tested under §60.5413a(d) which meets the criteria in 

§60.5413a(d)(11) and §60.5413a(e) and used to comply with 

§60.5395a(a)(2) for each storage vessel. 

(A) Make, model and serial number of purchased device.

(B) Date of purchase.

(C) Copy of purchase order.

(D) Location of the control device in latitude and 

longitude coordinates in decimal degrees to an accuracy and 

precision of five (5) decimals of a degree using the North 

American Datum of 1983. 

(E) Inlet gas flow rate.

(F) Records of continuous compliance requirements in 

§60.5413a(e) as specified in paragraphs (c)(5)(vi)(F)(1) through 

(4).
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(1) Records that the pilot flame is present at all times 

of operation.

(2) Records that the device was operated with no visible 

emissions except for periods not to exceed a total of 2 minutes 

during any hour.

(3) Records of the maintenance and repair log.

(4) Records of the visible emissions test following return 

to operation from a maintenance or repair activity.

(G) As an alternative to the requirements of paragraph 

(c)(5)(vi)(D) of this section, you may maintain records of one 

or more digital photographs with the date the photograph was 

taken and the latitude and longitude of the storage vessel and 

control device imbedded within or stored with the digital file. 

As an alternative to imbedded latitude and longitude within the 

digital photograph, the digital photograph may consist of a 

photograph of the storage vessel and control device with a 

photograph of a separately operating GIS device within the same 

digital picture, provided the latitude and longitude output of 

the GIS unit can be clearly read in the digital photograph.

(6) Records of each closed vent system inspection required 

under §60.5416a(a)(1) and (a)(2) for centrifugal compressors, 
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reciprocating compressors and pneumatic pumps, or 

§60.5416a(c)(1) for storage vessels.

(7) A record of each cover inspection required under 

§60.5416a(a)(3) for centrifugal or reciprocating compressors or 

§60.5416a(c)(2) for storage vessels.

(8) If you are subject to the bypass requirements of 

§60.5416a(a)(4) for centrifugal compressors, reciprocating 

compressors or pneumatic pumps, or §60.5416a(c)(3) for storage 

vessels, a record of each inspection or a record of each time 

the key is checked out or a record of each time the alarm is 

sounded.

(9) If you are subject to the closed vent system no 

detectable emissions requirements of §60.5416a(b) for 

centrifugal compressors, reciprocating compressors or pneumatic 

pumps, a record of the monitoring conducted in accordance with 

§60.5416a(b).

(10) For each centrifugal compressor or pneumatic pump

affected facility, records of the schedule for carbon 

replacement (as determined by the design analysis requirements 

of §60.5413a(c)(2) or (3)) and records of each carbon 

replacement as specified in §60.5412a(c)(1).
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(11) For each centrifugal compressor or pneumatic pump 

affected facility subject to the control device requirements of 

§60.5412a(a), (b), and (c), records of minimum and maximum 

operating parameter values, continuous parameter monitoring 

system data, calculated averages of continuous parameter 

monitoring system data, results of all compliance calculations, 

and results of all inspections.

(12) For each carbon adsorber installed on storage vessel 

affected facilities, records of the schedule for carbon 

replacement (as determined by the design analysis requirements 

of §60.5412a(d)(2)) and records of each carbon replacement as 

specified in §60.5412a(c)(1).

(13) For each storage vessel affected facility subject to 

the control device requirements of §60.5412a(c) and (d), you 

must maintain records of the inspections, including any 

corrective actions taken, the manufacturers' operating 

instructions, procedures and maintenance schedule as specified 

in §60.5417a(h)(3). You must maintain records of EPA Method 22 

of appendix A-7 of this part, section 11 results, which include: 

company, location, company representative (name of the person 

performing the observation), sky conditions, process unit (type 

of control device), clock start time, observation period 
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duration (in minutes and seconds), accumulated emission time (in 

minutes and seconds), and clock end time. You may create your 

own form including the above information or use Figure 22-1 in 

EPA Method 22 of appendix A-7 of this part. Manufacturer's 

operating instructions, procedures and maintenance schedule must 

be available for inspection.

(14) A log of records as specified in 

§§60.5412a(d)(1)(iii), for all inspection, repair and 

maintenance activities for each control device failing the 

visible emissions test.

(15) For each collection of fugitive emissions components 

at a well site and each collection of fugitive emissions 

components at a compressor station, the records identified in 

paragraphs (c)(15)(i) and (ii) of this section.

(i) The fugitive emissions monitoring plan for each 

collection of fugitive emissions components at a well site and 

each collection of fugitive emissions components at a compressor 

station as required in §60.5397a(a).

(ii) The records of each monitoring survey as specified in 

paragraphs (c)(15)(ii)(A) through (F) of this section.

(A) Date of the survey.

(B) Beginning and end time of the survey.
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(C) Name of operator(s) performing survey. You must note 

the training and experience of the operator.

(D) Ambient temperature, sky conditions, and maximum wind 

speed at the time of the survey.

(E) Any deviations from the monitoring plan or a statement 

that there were no deviations from the monitoring plan.

(F) Documentation of each fugitive emission, including the 

information specified in paragraphs (c)(15)(ii)(F)(1) through 

(2) of this section.

(1) Location.

(2) One or more digital photographs of each required 

monitoring survey being performed. The digital photograph must 

include the date the photograph was taken and the latitude and 

longitude of the collection of fugitive emissions components at 

a well site or collection of fugitive emissions components at a 

compressor station imbedded within or stored with the digital 

file. As an alternative to imbedded latitude and longitude 

within the digital photograph, the digital photograph may 

consist of a photograph of the monitoring survey being performed 

with a photograph of a separately operating GIS device within 

the same digital picture, provided the latitude and longitude 
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output of the GIS unit can be clearly read in the digital 

photograph.

(3) The date of successful repair of the fugitive emissions 

component.

(4) Instrumentation used to resurvey a repaired fugitive 

emissions component that could not be repaired during the 

initial fugitive emissions finding.

(16) For each pneumatic pump affected facility, you must 

maintain the records identified in paragraphs (c)(16)(i) through 

(iv) of this section.

(i) Records of the date, location and manufacturer 

specifications for each pneumatic pump constructed, modified or 

reconstructed.

(ii) Records of deviations in cases where the pneumatic 

pump was not operated in compliance with the requirements 

specified in §60.5393a.

(iii) Records of the control device installation date and 

the location of sites containing pneumatic pumps at which a 

control device was installed, where previously there was no 

control device at the site.

(iv) Except as specified in paragraph (c)(16)(iv)(G) of 

this section, records for each control device tested under 
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§60.5413a(d) which meets the criteria in §60.5413a(d)(11) and 

§60.5413a(e) and used to comply with §60.5393a(b)(1) for each 

pneumatic pump. 

(A) Make, model and serial number of purchased device.

(B) Date of purchase.

(C) Copy of purchase order.

(D) Location of the pneumatic pump and control device in 

latitude and longitude coordinates in decimal degrees to an 

accuracy and precision of five (5) decimals of a degree using 

the North American Datum of 1983. 

(E) Inlet gas flow rate.

(F) Records of continuous compliance requirements in 

§60.5413a(e) as specified in paragraphs (c)(16)(iv)(F)(1) 

through (4) of this section.

(1) Records that the pilot flame is present at all times of 

operation.

(2) Records that the device was operated with no visible 

emissions except for periods not to exceed a total of 2 minutes 

during any hour.

(3) Records of the maintenance and repair log.

(4) Records of the visible emissions test following return 

to operation from a maintenance or repair activity.
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(G) As an alternative to the requirements of paragraph 

(c)(16)(iv)(D) of this part, you may maintain records of one or 

more digital photographs with the date the photograph was taken 

and the latitude and longitude of the pneumatic pump and control 

device imbedded within or stored with the digital file. As an 

alternative to imbedded latitude and longitude within the 

digital photograph, the digital photograph may consist of a 

photograph of the pneumatic pump and control device with a 

photograph of a separately operating GIS device within the same 

digital picture, provided the latitude and longitude output of 

the GIS unit can be clearly read in the digital photograph.

§60.5421a What are my additional recordkeeping requirements for 

my affected facility subject to methane and VOC requirements for 

onshore natural gas processing plants?

(a) You must comply with the requirements of paragraph (b) 

of this section in addition to the requirements of §60.486a.

(b) The following recordkeeping requirements apply to 

pressure relief devices subject to the requirements of 

§60.5401a(b)(1) of this subpart.

(1) When each leak is detected as specified in 

§60.5401a(b)(2), a weatherproof and readily visible 

identification, marked with the equipment identification number, 
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must be attached to the leaking equipment. The identification on 

the pressure relief device may be removed after it has been 

repaired.

(2) When each leak is detected as specified in 

§60.5401a(b)(2), the information specified in paragraphs 

(b)(2)(i) through (x) of this section must be recorded in a log 

and shall be kept for 2 years in a readily accessible location:

(i) The instrument and operator identification numbers and 

the equipment identification number.

(ii) The date the leak was detected and the dates of each 

attempt to repair the leak.

(iii) Repair methods applied in each attempt to repair the 

leak.

(iv) “Above 500 ppm” if the maximum instrument reading 

measured by the methods specified in §60.5400a(d) after each 

repair attempt is 500 ppm or greater.

(v) “Repair delayed” and the reason for the delay if a leak 

is not repaired within 15 calendar days after discovery of the 

leak.

(vi) The signature of the owner or operator (or designate) 

whose decision it was that repair could not be effected without 

a process shutdown.
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(vii) The expected date of successful repair of the leak if 

a leak is not repaired within 15 days.

(viii) Dates of process unit shutdowns that occur while the 

equipment is unrepaired.

(ix) The date of successful repair of the leak.

(x) A list of identification numbers for equipment that are 

designated for no detectable emissions under the provisions of 

§60.482-4a(a). The designation of equipment subject to the 

provisions of §60.482-4a(a) must be signed by the owner or 

operator.

§60.5422a What are my additional reporting requirements for my 

affected facility subject to methane and VOC requirements for 

onshore natural gas processing plants?

(a) You must comply with the requirements of paragraphs (b) 

and (c) of this section in addition to the requirements of 

§60.487a(a), (b), (c)(2)(i) through (iv), and (c)(2)(vii) 

through (viii). You must submit semiannual reports to the EPA 

via the Compliance and Emissions Data Reporting Interface 

(CEDRI). (CEDRI can be accessed through the EPA’s Central Data 

Exchange (CDX) (https://cdx.epa.gov/).) Use the appropriate 

electronic report in CEDRI for this subpart or an alternate 

electronic file format consistent with the extensible markup 
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language (XML) schema listed on the CEDRI Web site 

(http://www.epa.gov/ttn/chief/cedri/index.html). If the 

reporting form specific to this subpart is not available in 

CEDRI at the time that the report is due, submit the report to 

the Administrator at the appropriate address listed in §60.4. 

You must begin submitting reports via CEDRI no later than 90 

days after the form becomes available in CEDRI. The report must 

be submitted by the deadline specified in this subpart, 

regardless of the method in which the report is submitted.

(b) An owner or operator must include the following 

information in the initial semiannual report in addition to the 

information required in §60.487a(b)(1) through (4): Number of 

pressure relief devices subject to the requirements of 

§60.5401a(b) except for those pressure relief devices designated 

for no detectable emissions under the provisions of §60.482-

4a(a) and those pressure relief devices complying with §60.482-

4a(c).

(c) An owner or operator must include the information 

specified in paragraphs (c)(1) and (2) of this section in all 

semiannual reports in addition to the information required in 

§60.487a(c)(2)(i) through (vi):
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(1) Number of pressure relief devices for which leaks were

detected as required in §60.5401a(b)(2); and

(2) Number of pressure relief devices for which leaks were 

not repaired as required in §60.5401a(b)(3).

§60.5423a What additional recordkeeping and reporting 

requirements apply to my sweetening unit affected facilities at 

onshore natural gas processing plants?

(a) You must retain records of the calculations and 

measurements required in §60.5405a(a) and (b) and §60.5407a(a) 

through (g) for at least 2 years following the date of the 

measurements. This requirement is included under §60.7(f) of the 

General Provisions.

(b) You must submit a report of excess emissions to the 

Administrator in your annual report if you had excess emissions 

during the reporting period. The excess emissions report must be 

submitted to the EPA via the Compliance and Emissions Data 

Reporting Interface (CEDRI). (CEDRI can be accessed through the 

EPA’s Central Data Exchange (CDX) (https://cdx.epa.gov/).) You 

must use the appropriate electronic report in CEDRI for this 

subpart or an alternate electronic file format consistent with 

the extensible markup language (XML) schema listed on the CEDRI 

Web site (http://www.epa.gov/ttn/chief/cedri/index.html). If the 
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reporting form specific to this subpart is not available in 

CEDRI at the time that the report is due, you must submit the 

report to the Administrator at the appropriate address listed in 

§60.4. You must begin submitting reports via CEDRI no later than 

90 days after the form becomes available in CEDRI. The report 

must be submitted by the deadline specified in this subpart, 

regardless of the method in which the report is submitted. For 

the purpose of these reports, excess emissions are defined as 

specified in paragraphs (b)(1) and (2) of this section.

(1) Any 24-hour period (at consistent intervals) during 

which the average sulfur emission reduction efficiency (R) is 

less than the minimum required efficiency (Z).

(2) For any affected facility electing to comply with the 

provisions of §60.5407a(b)(2), any 24-hour period during which 

the average temperature of the gases leaving the combustion zone 

of an incinerator is less than the appropriate operating 

temperature as determined during the most recent performance 

test in accordance with the provisions of §60.5407a(b)(3). Each 

24-hour period must consist of at least 96 temperature 

measurements equally spaced over the 24 hours.

(c) To certify that a facility is exempt from the control 

requirements of these standards, for each facility with a design 
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capacity less than 2 LT/D of H2S in the acid gas (expressed as 

sulfur) you must keep, for the life of the facility, an analysis 

demonstrating that the facility's design capacity is less than 2 

LT/D of H2S expressed as sulfur.

(d) If you elect to comply with §60.5407a(e) you must keep, 

for the life of the facility, a record demonstrating that the 

facility's design capacity is less than 150 LT/D of H2S expressed 

as sulfur.

(e) The requirements of paragraph (b) of this section 

remain in force until and unless the EPA, in delegating 

enforcement authority to a state under section 111(c) of the 

Act, approves reporting requirements or an alternative means of 

compliance surveillance adopted by such state. In that event, 

affected sources within the state will be relieved of obligation 

to comply with paragraph (b) of this section, provided that they 

comply with the requirements established by the state. 

Electronic reporting to the EPA cannot be waived, and as such, 

the provisions of this paragraph do not relieve owners or 

operators of affected facilities of the requirement to submit 

the electronic reports required in this section to the EPA.

§60.5425a What parts of the General Provisions apply to me?
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Table 3 to this subpart shows which parts of the General 

Provisions in §§60.1 through 60.19 apply to you.

§60.5430a What definitions apply to this subpart?

As used in this subpart, all terms not defined herein shall 

have the meaning given them in the Act, in subpart A or subpart 

VVa of part 60; and the following terms shall have the specific 

meanings given them.

Acid gas means a gas stream of hydrogen sulfide (H2S) and 

carbon dioxide (CO2) that has been separated from sour natural 

gas by a sweetening unit.

Alaskan North Slope means the approximately 69,000 squaremile area extending from the Brooks Range to the Arctic Ocean.

API Gravity means the weight per unit volume of hydrocarbon 

liquids as measured by a system recommended by the American 

Petroleum Institute (API) and is expressed in degrees.

Bleed rate means the rate in standard cubic feet per hour 

at which natural gas is continuously vented (bleeds) from a 

pneumatic controller.

Capital expenditure means, in addition to the definition in 

40 CFR 60.2, an expenditure for a physical or operational change 

to an existing facility that exceeds P, the product of the 

facility's replacement cost, R, and an adjusted annual asset 
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guideline repair allowance, A, as reflected by the following 

equation: P = R × A, where:

(1) The adjusted annual asset guideline repair allowance, 

A, is the product of the percent of the replacement cost, Y, and 

the applicable basic annual asset guideline repair allowance, B, 

divided by 100 as reflected by the following equation:

A = Y × (B ÷ 100);

(2) The percent Y is determined from the following 

equation: Y = 1.0 − 0.575 log X, where X is 2011 minus the year 

of construction; and

(3) The applicable basic annual asset guideline repair 

allowance, B, is 4.5.

Centrifugal compressor means any machine for raising the 

pressure of a natural gas by drawing in low pressure natural gas 

and discharging significantly higher pressure natural gas by 

means of mechanical rotating vanes or impellers. Screw, sliding 

vane, and liquid ring compressors are not centrifugal 

compressors for the purposes of this subpart.

Certifying official means one of the following:

(1) For a corporation: A president, secretary, treasurer, 

or vice-president of the corporation in charge of a principal 

business function, or any other person who performs similar 
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policy or decision-making functions for the corporation, or a 

duly authorized representative of such person if the 

representative is responsible for the overall operation of one 

or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either:

(i) The facilities employ more than 250 persons or have 

gross annual sales or expenditures exceeding $25 million (in 

second quarter 1980 dollars); or

(ii) The Administrator is notified of such delegation of 

authority prior to the exercise of that authority. The 

Administrator reserves the right to evaluate such delegation;

(2) For a partnership (including but not limited to general 

partnerships, limited partnerships, and limited liability 

partnerships) or sole proprietorship: A general partner or the 

proprietor, respectively. If a general partner is a corporation, 

the provisions of paragraph (1) of this definition apply;

(3) For a municipality, State, Federal, or other public 

agency: Either a principal executive officer or ranking elected 

official. For the purposes of this part, a principal executive 

officer of a Federal agency includes the chief executive officer 

having responsibility for the overall operations of a principal 
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geographic unit of the agency (e.g., a Regional Administrator of 

EPA); or

(4) For affected facilities:

(i) The designated representative in so far as actions, 

standards, requirements, or prohibitions under title IV of the 

Clean Air Act or the regulations promulgated thereunder are 

concerned; or

(ii) The designated representative for any other purposes 

under part 60.

Chemical/methanol or diaphragm pump means a gas-driven 

positive displacement pump typically used to inject precise 

amounts of chemicals into process streams or circulate glycol 

compounds for freeze protection.

City gate means the delivery point at which natural gas is 

transferred from a transmission pipeline to the local gas 

utility.

Collection system means any infrastructure that conveys gas 

or liquids from the well site to another location for treatment, 

storage, processing, recycling, disposal or other handling.

Completion combustion device means any ignition device, 

installed horizontally or vertically, used in exploration and 
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production operations to combust otherwise vented emissions from 

completions.

Compressor station site means any permanent combination of 

one or more compressors that move natural gas at increased 

pressure through gathering or transmission pipelines, or into or 

out of storage. This includes, but is not limited to, gathering 

and boosting stations and transmission compressor stations.

Condensate means hydrocarbon liquid separated from natural 

gas that condenses due to changes in the temperature, pressure, 

or both, and remains liquid at standard conditions.

Continuous bleed means a continuous flow of pneumatic 

supply natural gas to a pneumatic controller.

Crude oil and natural gas source category means: 

(1) crude oil production, which includes the well and 

extends to the point of custody transfer to the crude oil 

transmission pipeline; and 

(2) natural gas production, processing, transmission, and 

storage, which include the well and extend to, but do not 

include, the city gate.

Custody transfer means the transfer of natural gas after 

processing and/or treatment in the producing operations, or from 

storage vessels or automatic transfer facilities or other such 
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equipment, including product loading racks, to pipelines or any 

other forms of transportation.

Dehydrator means a device in which an absorbent directly 

contacts a natural gas stream and absorbs water in a contact 

tower or absorption column (absorber).

Deviation means any instance in which an affected source 

subject to this subpart, or an owner or operator of such a 

source:

(1) Fails to meet any requirement or obligation established 

by this subpart including, but not limited to, any emission 

limit, operating limit, or work practice standard;

(2) Fails to meet any term or condition that is adopted to 

implement an applicable requirement in this subpart and that is 

included in the operating permit for any affected source 

required to obtain such a permit; or

(3) Fails to meet any emission limit, operating limit, or 

work practice standard in this subpart during startup, shutdown, 

or malfunction, regardless of whether or not such failure is 

permitted by this subpart.

Delineation well means a well drilled in order to determine 

the boundary of a field or producing reservoir.
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Equipment, as used in the standards and requirements in 

this subpart relative to the equipment leaks of methane and VOC 

from onshore natural gas processing plants, means each pump, 

pressure relief device, open-ended valve or line, valve, and 

flange or other connector that is in VOC service or in wet gas 

service, and any device or system required by those same 

standards and requirements in this subpart.

Field gas means feedstock gas entering the natural gas 

processing plant.

Field gas gathering means the system used transport field 

gas from a field to the main pipeline in the area.

Flare means a thermal oxidation system using an open 

(without enclosure) flame. Completion combustion devices as 

defined in this section are not considered flares.

Flow line means a pipeline used to transport oil and/or gas 

to a processing facility, a mainline pipeline, re-injection, or 

routed to a process or other useful purpose.

Flowback means the process of allowing fluids and entrained 

solids to flow from a well following a treatment, either in 

preparation for a subsequent phase of treatment or in 

preparation for cleanup and returning the well to production. 

The term flowback also means the fluids and entrained solids 
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that emerge from a well during the flowback process. The 

flowback period begins when material introduced into the well 

during the treatment returns to the surface following hydraulic 

fracturing or refracturing. The flowback period ends when either 

the well is shut in and permanently disconnected from the 

flowback equipment or at the startup of production. The flowback 

period includes the initial flowback stage and the separation 

flowback stage.

Fugitive emissions component means any component that has 

the potential to emit fugitive emissions of methane or VOC at a 

well site or compressor station site, including but not limited 

to valves, connectors, pressure relief devices, open-ended 

lines, access doors, flanges, closed vent systems, thief hatches 

or other openings on a storage vessels, agitator seals, distance 

pieces, crankcase vents, blowdown vents, pump seals or 

diaphragms, compressors, separators, pressure vessels, 

dehydrators, heaters, instruments, and meters. Devices that vent 

as part of normal operations, such as natural gas-driven 

pneumatic controllers or natural gas-driven pumps, are not 

fugitive emissions components, insofar as the natural gas 

discharged from the device’s vent is not considered a fugitive 

emission. Emissions originating from other than the vent, such 
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as the seals around the bellows of a diaphragm pump, would be 

considered fugitive emissions.

Gas processing plant process unit means equipment assembled 

for the extraction of natural gas liquids from field gas, the 

fractionation of the liquids into natural gas products, or other 

operations associated with the processing of natural gas 

products. A process unit can operate independently if supplied 

with sufficient feed or raw materials and sufficient storage 

facilities for the products.

Hydraulic fracturing means 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.

Hydraulic refracturing means conducting a subsequent 

hydraulic fracturing operation at a well that has previously 

undergone a hydraulic fracturing operation.

In light liquid service means that the piece of equipment 

contains a liquid that meets the conditions specified in 

§60.485a(e) or §60.5401a(f)(2) of this part.
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In wet gas service means that a compressor or piece of 

equipment contains or contacts the field gas before the 

extraction step at a gas processing plant process unit.

Initial flowback stage means the period during a well 

completion operation which begins at the onset of flowback and 

ends at the separation flowback stage.

Intermediate hydrocarbon liquid means any naturally 

occurring, unrefined petroleum liquid.

Intermittent/snap-action pneumatic controller means a 

pneumatic controller that is designed to vent non-continuously.

Liquefied natural gas unit means a unit used to cool 

natural gas to the point at which it is condensed into a liquid 

which is colorless, odorless, non-corrosive and non-toxic.

Low pressure well means a well with reservoir pressure and 

vertical well depth such that 0.445 times the reservoir pressure 

(in psia) minus 0.038 times the vertical well depth (in feet) 

minus 67.578 psia is less than the flow line pressure at the 

sales meter.

Maximum average daily throughput means the earliest 

calculation of daily average throughput during the 30-day PTE 

evaluation period employing generally accepted methods.
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Natural gas-driven pneumatic controller means a pneumatic 

controller powered by pressurized natural gas.

Natural gas-driven chemical/methanol or diaphragm pump

means a chemical or methanol injection or circulation pump or a 

diaphragm pump powered by pressurized natural gas.

Natural gas liquids means the hydrocarbons, such as ethane, 

propane, butane, and pentane that are extracted from field gas.

Natural gas processing plant (gas plant) means any 

processing site engaged in the extraction of natural gas liquids 

from field gas, fractionation of mixed natural gas liquids to 

natural gas products, or both. A Joule-Thompson valve, a dew 

point depression valve, or an isolated or standalone JouleThompson skid is not a natural gas processing plant.

Natural gas transmission means the pipelines used for the 

long distance transport of natural gas (excluding processing). 

Specific equipment used in natural gas transmission includes the 

land, mains, valves, meters, boosters, regulators, storage 

vessels, dehydrators, compressors, and their driving units and 

appurtenances, and equipment used for transporting gas from a 

production plant, delivery point of purchased gas, gathering 

system, storage area, or other wholesale source of gas to one or 

more distribution area(s).
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Nonfractionating plant means any gas plant that does not 

fractionate mixed natural gas liquids into natural gas products.

Non-natural gas-driven pneumatic controller means an 

instrument that is actuated using other sources of power than 

pressurized natural gas; examples include solar, electric, and 

instrument air.

Onshore means all facilities except those that are located 

in the territorial seas or on the outer continental shelf.

Pneumatic controller means an automated instrument used for 

maintaining a process condition such as liquid level, pressure, 

delta-pressure and temperature.

Pressure vessel means a storage vessel that is used to 

store liquids or gases and is designed not to vent to the 

atmosphere as a result of compression of the vapor headspace in 

the pressure vessel during filling of the pressure vessel to its 

design capacity.

Process unit means components assembled for the extraction 

of natural gas liquids from field gas, the fractionation of the 

liquids into natural gas products, or other operations 

associated with the processing of natural gas products. A 

process unit can operate independently if supplied with 
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sufficient feed or raw materials and sufficient storage 

facilities for the products.

Produced water means water that is extracted from the earth 

from an oil or natural gas production well, or that is separated 

from crude oil, condensate, or natural gas after extraction.

Reciprocating compressor means a piece of equipment that 

increases the pressure of a process gas by positive 

displacement, employing linear movement of the driveshaft.

Reciprocating compressor rod packing means a series of 

flexible rings in machined metal cups that fit around the 

reciprocating compressor piston rod to create a seal limiting 

the amount of compressed natural gas that escapes to the 

atmosphere.

Recovered gas means gas recovered through the separation 

process during flowback.

Recovered liquids means any crude oil, condensate or 

produced water recovered through the separation process during 

flowback.

Reduced emissions completion means a well completion 

following fracturing or refracturing where gas flowback that is 

otherwise vented is captured, cleaned, and routed to the flow 

line or collection system, re-injected into the well or another 
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well, used as an on-site fuel source, or used for other useful 

purpose that a purchased fuel or raw material would serve, with 

no direct release to the atmosphere.

Reduced sulfur compounds means H2S, carbonyl sulfide (COS), 

and carbon disulfide (CS2).

Removed from service means that a storage vessel affected 

facility has been physically isolated and disconnected from the 

process for a purpose other than maintenance in accordance with 

§60.5395a(c)(1).

Responsible official means one of the following:

(1) For a corporation: A president, secretary, treasurer, 

or vice-president of the corporation in charge of a principal 

business function, or any other person who performs similar 

policy or decision-making functions for the corporation, or a 

duly authorized representative of such person if the 

representative is responsible for the overall operation of one 

or more manufacturing, production, or operating facilities 

applying for or subject to a permit and either:

(i) The facilities employ more than 250 persons or have 

gross annual sales or expenditures exceeding $25 million (in 

second quarter 1980 dollars); or
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(ii) The delegation of authority to such representatives is 

approved in advance by the permitting authority;

(2) For a partnership or sole proprietorship: A general 

partner or the proprietor, respectively;

(3) For a municipality, State, Federal, or other public 

agency: Either a principal executive officer or ranking elected 

official. For the purposes of this part, a principal executive 

officer of a Federal agency includes the chief executive officer 

having responsibility for the overall operations of a principal 

geographic unit of the agency (e.g., a Regional Administrator of 

EPA); or

(4) For affected facilities:

(i) The designated representative in so far as actions, 

standards, requirements, or prohibitions under title IV of the 

Clean Air Act or the regulations promulgated thereunder are 

concerned; or

(ii) The designated representative for any other purposes 

under part 60.

Returned to service means that a storage vessel affected 

facility that was removed from service has been:

(1) Reconnected to the original source of liquids or has 

been used to replace any storage vessel affected facility; or
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(2) Installed in any location covered by this subpart and 

introduced with crude oil, condensate, intermediate hydrocarbon 

liquids or produced water.

Routed to a process or route to a process means the 

emissions are conveyed via a closed vent system to any enclosed 

portion of a process where the emissions are predominantly 

recycled and/or consumed in the same manner as a material that 

fulfills the same function in the process and/or transformed by 

chemical reaction into materials that are not regulated 

materials and/or incorporated into a product; and/or recovered.

Salable quality gas means natural gas that meets the flow 

line or collection system operator specifications, regardless of 

whether such gas is sold.

Separation flowback stage means the period during a well 

completion operation when it is technically feasible for a 

separator to function. The separation flowback stage ends either 

at the startup of production, or when the well is shut in and 

permanently disconnected from the flowback equipment.

Startup of production means the beginning of initial flow 

following the end of flowback when there is continuous recovery 

of salable quality gas and separation and recovery of any crude 

oil, condensate or produced water.
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Storage vessel means a tank or other vessel that contains 

an accumulation of crude oil, condensate, intermediate 

hydrocarbon liquids, or produced water, and that is constructed 

primarily of nonearthen materials (such as wood, concrete, 

steel, fiberglass, or plastic) which provide structural support. 

A well completion vessel that receives recovered liquids from a 

well after startup of production following flowback for a period 

which exceeds 60 days is considered a storage vessel under this 

subpart. A tank or other vessel shall not be considered a 

storage vessel if it has been removed from service in accordance 

with the requirements of §60.5395a(c) until such time as such 

tank or other vessel has been returned to service. For the 

purposes of this subpart, the following are not considered 

storage vessels:

(1) Vessels that are skid-mounted or permanently attached 

to something that is mobile (such as trucks, railcars, barges or 

ships), and are intended to be located at a site for less than 

180 consecutive days. If you do not keep or are not able to 

produce records, as required by §60.5420a(c)(5)(iv), showing 

that the vessel has been located at a site for less than 180 

consecutive days, the vessel described herein is considered to 

be a storage vessel from the date the original vessel was first 
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located at the site. This exclusion does not apply to a well 

completion vessel as described above.

(2) Process vessels such as surge control vessels, bottoms 

receivers or knockout vessels.

(3) Pressure vessels designed to operate in excess of 204.9 

kilopascals and without emissions to the atmosphere.

Sulfur production rate means the rate of liquid sulfur 

accumulation from the sulfur recovery unit.

Sulfur recovery unit means a process device that recovers 

element sulfur from acid gas.

Surface site means any combination of one or more graded 

pad sites, gravel pad sites, foundations, platforms, or the 

immediate physical location upon which equipment is physically 

affixed.

Sweetening unit means a process device that removes 

hydrogen sulfide and/or carbon dioxide from the sour natural gas 

stream.

Total Reduced Sulfur (TRS) means the sum of the sulfur 

compounds hydrogen sulfide, methyl mercaptan, dimethyl sulfide, 

and dimethyl disulfide as measured by Method 16 of appendix A-6 

of this part.
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Total SO2 equivalents means the sum of volumetric or mass 

concentrations of the sulfur compounds obtained by adding the 

quantity existing as SO2 to the quantity of SO2 that would be 

obtained if all reduced sulfur compounds were converted to SO2

(ppmv or kg/dscm (lb/dscf)).

Underground storage vessel means a storage vessel stored 

below ground.

Well means a hole drilled for the purpose of producing oil 

or natural gas, or a well into which fluids are injected.

Well completion means the process that allows for the 

flowback of petroleum or natural gas from newly drilled wells to 

expel drilling and reservoir fluids and tests the reservoir flow 

characteristics, which may vent produced hydrocarbons to the 

atmosphere via an open pit or tank.

Well completion operation means any well completion with 

hydraulic fracturing or refracturing occurring at a well 

affected facility.

Well completion vessel means a vessel that contains 

flowback during a well completion operation following hydraulic 

fracturing or refracturing. A well completion vessel may be a 

lined earthen pit, a tank or other vessel that is skid-mounted 

or portable. A well completion vessel that receives recovered 
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liquids from a well after startup of production following 

flowback for a period which exceeds 60 days is considered a 

storage vessel under this subpart.

Well site means one or more areas that are directly 

disturbed during the drilling and subsequent operation of, or 

affected by, production facilities directly associated with any 

oil well, natural gas well, or injection well and its associated 

well pad. For the purposes of the fugitive emissions standards 

at §60.5397a, well site also includes tank batteries collecting 

crude oil, condensate, intermediate hydrocarbon liquids, or 

produced water from wells not located at the well site (e.g.,

centralized tank batteries). For the purposes of the fugitive 

emissions standards at §60.5397a, a well site that only contains 

one or more wellheads is not subject to these standards. 

Wellhead means the piping, casing, tubing and connected 

valves protruding above the earth's surface for an oil and/or 

natural gas well. The wellhead ends where the flow line connects 

to a wellhead valve. The wellhead does not include other 

equipment at the well site except for any conveyance through 

which gas is vented to the atmosphere.
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Wildcat well means a well outside known fields or the first 

well drilled in an oil or gas field where no other oil and gas 

production exists.

§§60.5431a – 60.5499a [Reserved]

Table 1 to Subpart OOOOa of Part 60 – Required Minimum Initial 

SO2 Emission Reduction Efficiency (Zi)

H2S 

content of 

acid gas 

(Y), %

Sulfur feed rate (X), LT/D

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0

Y>50 79.0 88.51X0.0101Y0.0125 or 99.9, whichever is 

smaller

20<Y<50 79.0 88.51X0.0101Y0.0125 or 97.9, whichever 

is smaller

97.9

10<Y<20 79.0 88.51X0.0101Y0.0125

or 93.5, whichever 

is smaller

93.5 93.5

Y<10 79.0 79.0 79.0 79.0

Table 2 to Subpart OOOOa of Part 60 – Required Minimum SO2

Emission Reduction Efficiency (Zc)
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H2S 

content of 

acid gas 

(Y), %

Sulfur feed rate (X), LT/D

2.0<X<5.0 5.0<X<15.0 15.0<X<300.0 X>300.0

Y>50 74.0 85.35X0.0144Y0.0128 or 99.9, whichever is 

smaller

20<Y<50 74.0 85.35X0.0144Y0.0128 or 97.5, whichever 

is smaller

97.5

10<Y<20 74.0 85.35X0.0144Y0.0128

or 90.8, whichever 

is smaller

90.8 90.8

Y<10 74.0 74.0 74.0 74.0

X = The sulfur feed rate from the sweetening unit (i.e., the H2S 

in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to 

one decimal place.

Y = The sulfur content of the acid gas from the sweetening unit, 

expressed as mole percent H2S (dry basis) rounded to one decimal 

place.

Z = The minimum required sulfur dioxide (SO2) emission reduction 

efficiency, expressed as percent carried to one decimal place. Zi
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Page 609 of 612

refers to the reduction efficiency required at the initial 

performance test. Zc refers to the reduction efficiency required 

on a continuous basis after compliance with Zi has been 

demonstrated.

Table 3 to Subpart OOOOa of Part 60 – Applicability of General 

Provisions to Subpart OOOOa

As stated in §60.5425a, you must comply with the following 

applicable General Provisions:

General 

Provisions 

Citation

Subject of 

Citation

Applies 

to 

subpart? Explanation

§60.1

General 

applicability of 

the General 

Provisions

Yes

§60.2 Definitions Yes Additional terms 

defined in 

§60.5430a

§60.3 Units and 

abbreviations

Yes
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§60.4 Address Yes

§60.5 Determination of 

construction or 

modification

Yes

§60.6 Review of plans Yes

§60.7 Notification and 

record keeping

Yes Except that §60.7 

only applies as 

specified in 

§60.5420a(a).

§60.8 Performance tests Yes Performance testing 

is required for 

control devices 

used on storage 

vessels, 

centrifugal 

compressors and 

pneumatic pumps.

§60.9 Availability of 

information

Yes

§60.10 State authority Yes 
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§60.11 Compliance with 

standards and 

maintenance 

requirements

No Requirements are 

specified in 

subpart OOOOa.

§60.12 Circumvention Yes

§60.13 Monitoring 

requirements

Yes Continuous monitors 

are required for 

storage vessels

§60.14 Modification Yes To the extent any 

provision in §60.14 

conflicts with 

specific provisions 

in subpart OOOOa, 

it is superseded by 

subpart OOOOa 

provisions.
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§60.15 Reconstruction Yes Except that 

§60.15(d) does not 

apply to pneumatic 

controllers, 

pneumatic pumps, 

centrifugal 

compressors or 

storage vessels.

§60.16 Priority list Yes

§60.17 Incorporations by 

reference

Yes

§60.18 General control 

device and work 

practice 

requirements

Yes

§60.19 General 

notification and 

reporting 

requirement

Yes