Oil and Natural Gas Sector: Emission Standards for New and Modified Sources, 56593-56698 [2015-21023]

Agencies

• ENVIRONMENTAL PROTECTION AGENCY

[Federal Register Volume 80, Number 181 (Friday, September 18, 2015)]
[Proposed Rules]
[Pages 56593-56698]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2015-21023]



Federal Register / Vol. 80, No. 181 / Friday, September 18, 2015 / 
Proposed Rules

[[Page 56593]]


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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.

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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 both methane and VOC standards 
for several emission sources not currently covered by the NSPS and 
proposing methane standards for certain emission sources that are 
currently regulated for VOC. The proposed amendents also extend the 
current VOC standards to the remaining unregulated equipment across the 
source category and additionally establish methane standards for this 
equipment. Lastly, amendments to improve implementation of the current 
NSPS are being proposed which 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 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 November 17, 
2015. 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 November 17, 2015. The EPA will hold public 
hearings on the proposal. Details will be announced in a separate 
announcement.

ADDRESSES: Submit your comments, identified by Docket ID Number EPA-HQ-
OAR-2010-0505, to the Federal eRulemaking Portal: https://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 by a written comment. The written comment is considered 
the official comment and should include discussion of all points you 
wish to make. The EPA will generally not consider comments or comment 
contents located outside of the primary submission (i.e. on the web, 
cloud, or other file sharing system). For additional submission 
methods, the full EPA public comment policy, information about CBI or 
multimedia submissions, and general guidance on making effective 
comments, please visit https://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 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 CD-ROM 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 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, DC. The Public Reading Room is open from 8:30 a.m. to 4:30 
p.m., Monday through Friday, excluding legal holidays. The telephone 
number for the Public Reading Room is (202) 566-1744, and the telephone 
number for the EPA Docket Center is (202) 566-1742.

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
    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?

[[Page 56594]]

    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
    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 Low-Income 
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 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
HPD 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
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 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 at 
natural gas processing plants); and

[[Page 56595]]

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 category-wide 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.
    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. EPA 
acknowledges that a state may have more stringent state requirements 
(e.g., fugitives monitoring and repair program). We believe that 
affected sources already complying with more stringent state 
requirements may also be in compliance with this rule. We solicit 
comment on how to determine whether existing state requirements (i.e., 
monitoring, record keeping, and reporting) would demonstrate compliance 
with this federal rule.
    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.
    Following are brief summaries of these sources and the proposed 
standards.
    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 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.
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    \2\ During the development of the 2012 NSPS, our data indicatedd 
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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    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 gas-operated 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 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 
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 
(which include the transmission and storage segment and the gathering 
and boosting segment) conduct fugitive emissions surveys

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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 
three percent or more of their fugitive emission components during a 
survey. We recognize that subpart W already requires annual fugitives 
reporting for certain compressor stations that exceed the 25,000 Metric 
Ton CO2e threshold, and request comments on the overlap of 
these reporting requirements.
    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 and other emission sources operating under corporate fugitive 
monitoring plans 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).
    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 Sec.  60.5411(c)(3)(i)(A) for a bypass 
device that could divert an emission stream away from a control device, 
recordkeeping requirements of Sec.  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.

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\
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    \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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    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 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.
    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 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 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) 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.
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    \4\ Figures may not sum due to rounding.

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[[Page 56597]]

    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
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                                                   Examples of regulated
           Category               NAICS code \1\          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?

    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 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: https://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 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.'' 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

[[Page 56598]]

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 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 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 Sec.  60.5411(c)(3)(i)(A) for a 
bypass device that could divert an emission stream away from a control 
device, recordkeeping requirements of Sec.  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, 
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 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 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.''
    Fourth, 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. 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.

[[Page 56599]]

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 (https://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-HQ-OAR-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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 40-45 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?

    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.
---------------------------------------------------------------------------

    \6\ Sierra Club et al., Petition for Reconsideration, In the 
Matter of: Final Rule Published at 77 FR 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).
---------------------------------------------------------------------------

    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 availability of technically feasible control options and 
the costs of such control options. As we 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 
FR 54970, 54997 (Sep. 9, 2010). Our consideration of these factors are 
provided below and in more detail in sections VI and VIII.
---------------------------------------------------------------------------

    \7\ See 42 U.S.C. Sec.  7411(b)
---------------------------------------------------------------------------

    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 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 simultaneously reduce both methane and 
VOC emissions from these 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 56600]]

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 (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 
methane 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 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)

    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 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 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., 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).
---------------------------------------------------------------------------

    \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.
    \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.
---------------------------------------------------------------------------

    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

[[Page 56601]]

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 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.
---------------------------------------------------------------------------

    \12\ See additional discussion at 79 FR 1430, 1452 (Jan 8, 
2014).
---------------------------------------------------------------------------

    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 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.' Sec.  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 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 FR 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 
DC 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 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 FR 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 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 pollution which may reasonably be anticipated to 
endanger public health or welfare.
---------------------------------------------------------------------------

    \13\ For the oil industry, the listing includes production, as 
explained above in footnote 10.
---------------------------------------------------------------------------

    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

[[Page 56602]]

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 contributes 
significantly to air pollution which may reasonably be anticipated to 
endanger public health and welfare.\14\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \15\ ``Endangerment and Cause or Contribute Findings for 
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR 
66496 (Dec. 15, 2009) (``Endangerment Finding'').
---------------------------------------------------------------------------

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 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 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.
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 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, 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 disease-carriers such as mosquitoes and 
ticks.'' The most recent assessments now have greater

[[Page 56603]]

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 
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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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 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 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 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.
---------------------------------------------------------------------------

    \17\ National Research Council, Understanding Earth's Deep Past, 
p. 1.
    \18\ Id., p. 138.
---------------------------------------------------------------------------

    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 
[deg]C to 4.8 [deg]C (4.7 to 8.6 [deg]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

[[Page 56604]]

as wet areas getting wetter and dry regions 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 [deg]C (1.8 [deg]F) 
of warming. For 3 [deg]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.
    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 
[deg]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 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.
---------------------------------------------------------------------------

    \19\ NRC, 2011: National Security Implications of Climate Change 
for U.S. Naval Forces. The National Academies Press, p. 28.
    \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.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    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 [deg]C (1.5 [deg]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 
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

[[Page 56605]]

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 [deg]C (5.4 
[deg]F) in parts of Northern Alaska. Winter storm frequency and 
intensity have both increased in the Northern Hemisphere. The 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 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.
---------------------------------------------------------------------------

    \23\ Blunden, J., and D.S. Arndt, Eds., 2014: State of the 
Climate in 2013. Bull. Amer. Meteor. Soc., 95 (7), S1-S238.
    \24\ https://www.ncdc.noaa.gov/sotc/global/2014/13.
---------------------------------------------------------------------------

    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:
---------------------------------------------------------------------------

    \25\ NRC, 2011: America's Climate Choices, The National 
Academies Press.
---------------------------------------------------------------------------

     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.
     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 short-lived 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 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.
---------------------------------------------------------------------------

    \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 https://www.epa.gov/ncea/isa/.
    \27\ Myhre, G., D. Shindell, F.-M. Br[eacute]on, 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 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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2. VOC
    Tropospheric, or ground-level, ozone is formed through reactions of 
VOC and NOX in the presence of sunlight. Ozone 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 
incomes, and minorities, including Puerto Ricans, Native Americans/
Alaska Natives and African-Americans.\32\
---------------------------------------------------------------------------

    \32\ National Health Interview Survey (NHIS) Data, 2011 https://www.cdc.gov/asthma/nhis/2011/data.htm.
---------------------------------------------------------------------------

    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

[[Page 56606]]

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 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\
---------------------------------------------------------------------------

    \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/R-08/082F, 
2008.
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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
    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 tons \35\ 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. Schl[ouml]mer, C. von Stechow, T. Zwickel and J.C. 
Minx (eds.)]. Cambridge University Press, 1435 pp.
---------------------------------------------------------------------------

    Based on the Inventory of U.S. Greenhouse Gas Emissions and Sinks 
Report \37\ (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.
---------------------------------------------------------------------------

    \37\ U.S. EPA, 2014: Inventory of U.S. Greenhouse Gas Emissions 
and Sinks: 1990-2012. Available at https://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html#fullreport (Last accessed 
January 29, 2015).
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \38\ World Resources Institute (WRI) Climate Analysis Indicators 
Tool (CAIT) Data Explorer (Version 2.0). Available at https://cait.wri.org. (Last accessed October 31, 2014.)
---------------------------------------------------------------------------

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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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                      170.0              163.5              148.3
 Processing and Transmission...........................
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 Sources \40\.............................               91.4               89.5               82.9
                                                        --------------------------------------------------------

[[Page 56607]]

 
    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.
---------------------------------------------------------------------------

    \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 combustion, 
composting, and several sources emitting less than 1 MMT 
CO2-e in 2013.
---------------------------------------------------------------------------

    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 
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                         170                163                148
 Processing and Transmission (Total)...................
Natural Gas Production.................................                 59                 75                 47
Natural Gas Processing.................................                 21                 16                 23
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                       6,802              6,539              5,930
 Processing and Transmission (Total)...................
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 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,

[[Page 56608]]

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.

   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                 147                147                146                148
 Natural Gas Processing &
 Transmission GHG Emissions (MMT CO2
 Eq)................................
Share of Total U.S. GHG Inventory...              2.13%              2.18%              2.23%              2.22%
Total U.S. GHG Emissions (MMT CO2                 6,899              6,777              6,545              6,673
 Eq)................................
----------------------------------------------------------------------------------------------------------------

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
------------------------------------------------------------------------
                                                      Total U.S. oil and
                                                          natural gas
                                                        production and
                                   2010 (MMT CO2 eq)      natural gas
                                                        processing and
                                                      transmission share
                                                              (%)
------------------------------------------------------------------------
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 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 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 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

[[Page 56609]]

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 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 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 (https://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-HQ-OAR-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:

 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\
---------------------------------------------------------------------------

    \41\ Control techniques guidelines are not part of this action.
---------------------------------------------------------------------------

 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 
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, that we are expanding to include methane. 
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. 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. Some stakeholders 
have advocated that is appropriate to rely on VOC standards, as 
established in 2012, for sources in the production and processing 
segment. 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 VOC and methane 
standard in the transmission and storage segment. Some stakeholders 
have also advocated for the importance of setting methane standards in 
the production segment that go beyond the 2012 NSPS standards. We 
anticipate that these stakeholders will express their views during the 
comment period.
    Pursuant to CAA section 111(b), we are proposing to amend subpart 
OOOO and to create a new subpart OOOOa which will 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 September 18, 2015 (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 September 18, 2015 and 
would include current VOC requirements already provided in subpart OOOO 
as well as new provisions for methane and VOC across

[[Page 56610]]

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 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 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 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 low-emitting 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 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 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.
---------------------------------------------------------------------------

    \42\ Bleed rate can be documented through information provided 
by the controller manufacturer.
---------------------------------------------------------------------------

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

    We are proposing operational standards for well completions at 
hydraulically fractured (or refractured) wells, including oil wells. 
The 2012 NSPS regulated well completions to

[[Page 56611]]

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, non-delineation 
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 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 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 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 
Sec.  60.5365a(a)(1), that a well that is refractured, and for which 
the well completion operation is conducted according to the 
requirements of Sec.  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 purposes of the proposed fugitive 
emissions standards at Sec.  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 components 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, 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''

[[Page 56612]]

above: ``For the purposes of the fugitive emissions standards at Sec.  
60.5397a, a well site that only contains one or more wellheads is not 
subject to these standards.''
    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 site-affected 
facilities conduct an initial survey of ``fugitive emissions 
components,'' which we are proposing to define in Sec.  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 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 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 
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 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 three 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 three percent or more of 
the fugitive emission components at a well site during 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 three 
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 three percent and whether these 
thresholds should be specific numbers of components rather than 
percentages of components for triggering change in survey frequency

[[Page 56613]]

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 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, open-ended 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 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 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 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 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 three 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 three 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 three 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 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 three percent and whether these thresholds 
should be

[[Page 56614]]

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
    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 Sec.  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 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 Sec.  60.5365a(a)(1) a well that is 
refractured, and for which the well completion operation is conducted 
according to the requirements of Sec.  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 Sec.  60.5397a, 
regardless of whether the well itself is an affected facility.
    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 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. 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 fugitive monitoring programs 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 the reasons stated above, we are also soliciting comments on 
criteria we can use to determine whether and under what conditions all 
new or modified well sites or compressor stations operating under 
corporate fugitive monitoring programs can be deemed to be meeting the 
equivalent of the NSPS standards for well sites or compressor stations 
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 and compressor stations 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 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 ppm as in the 2012 NSPS. As 
discussed further in section VIII.H, we propose that the subpart VVa 
level of control applied plant-wide 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.

[[Page 56615]]

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, pneumatic pumps and compressors, as provided in 
Sec.  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 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 
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 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 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 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

[[Page 56616]]

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 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.
    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?

    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 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 DC Circuit has made no attempt to distinguish among 
them. For convenience, in this rulemaking, we will use reasonable to 
describe our evaluation of costs well within the boundaries established 
by this case law.
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    \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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    In evaluating 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 evaluating 
whether a given control achieves emission reduction at a reasonable 
cost. Cost-effectiveness analysis also allows comparisons of relative 
costs and outcomes (effects) of two or more options. In general, cost-
effectiveness is a measure of the benefit produced by resources spent. 
In the context of air pollution control options, cost-effectiveness 
typically refers to the annualized cost of implementing an air 
pollution control option divided by the amount of pollutant reductions 
realized annually. A cost-effectiveness 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 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

[[Page 56617]]

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 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 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 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 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.
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    \44\ See e.g. 73 FR 64079-64083 and EPA Document I.D. EPA-HQ-
OAR-2004-0022-0622, EPA-HQ-OAR-2004-0022-0447, EPA-HQ-OAR-2004-0022-
0448.
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    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 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.
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    \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.
---------------------------------------------------------------------------

    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 NSPS. \46\ First, 
we compared the capitals costs that would be incurred to comply with 
the

[[Page 56618]]

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 to evaluate the 
annualized costs as a percentage of the revenues being generated by the 
industry.
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    \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 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 Survey.\47\ 
Annual revenue data for relevant NAICS codes were obtained from the 
U.S. Census 2012 County Business Patterns and 2012 Economic Census.\48\ 
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 industry-wide 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 and 
operators within each segment. Although there is not a one-to-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.
---------------------------------------------------------------------------

    \47\ https://www.census.gov/econ/aces/xls/2013/full_report.html.
    \48\ For information on confidentiality protection, sampling 
error, and nonsampling error, see https://www.census.gov/econ/susb/methodology.html. For definitions of estimated receipts and other 
definitions, see https://www.census.gov/econ/susb/definitions.html.
---------------------------------------------------------------------------

    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

    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 sites.\49\ 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.
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    \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.
---------------------------------------------------------------------------

    Centrifugal compressors are used throughout the natural gas 
industry \50\ 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 that they 
compress to fuel the turbine. Sometimes an electric motor is used to 
turn a centrifugal compressor.
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    \50\ See previous footnote regarding centrifugal compressors at 
well sites.
---------------------------------------------------------------------------

    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) of methane,\51\ 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

[[Page 56619]]

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\
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    \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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    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 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.
---------------------------------------------------------------------------

    \53\ IBID.
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    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.
    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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 
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 control is not required because one is already 
available for use on site.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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

[[Page 56620]]

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 
operator, we believe it is worthwhile to note that overall these 
standards save a non-renewable resource.
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    \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.
---------------------------------------------------------------------------

    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, 
which is well below the percentage capital increase that courts have 
previously upheld as reasonable as 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.
    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 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 are located at well sites.\57\ 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.
---------------------------------------------------------------------------

    \57\ As discussed later in this section, the control cost for 
reciprocating compressors at well site is not reasonable.
---------------------------------------------------------------------------

    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), 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

[[Page 56621]]

conveyed to the process, it also avoids the issue of inducing 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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \60\ See footnote 56.
---------------------------------------------------------------------------

    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 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 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 is 
also 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.
    We did not identify any nonair quality health or environmental 
impacts or energy impacts associated with replacement of rod packing 
and

[[Page 56622]]

therefore, no analyses was conducted. In light of the above, we propose 
that rod packing 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 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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

D. Proposed Standards for Pneumatic Controllers

    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 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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    Not all pneumatic controllers are gas driven. These ``non-gas 
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 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

[[Page 56623]]

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 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.
---------------------------------------------------------------------------

    \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 
https://www.ecfr.gov/cgi-bin/text-idx?SID=dda4d1715e9926ee3517ac08e6258817&node=40:21.0.1.1.3.23&rgn=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.
---------------------------------------------------------------------------

    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 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 high-bleed 
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 0000. We are not reopening those standards in this 
rulemaking.
---------------------------------------------------------------------------

    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.
    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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 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 0.0001 
percent of the total revenues, which is also 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 is also 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

[[Page 56624]]

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.
    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 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 TSD \68\ for details of these calculations.
---------------------------------------------------------------------------

    \68\ Oil and Natural Gas Section: 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.
---------------------------------------------------------------------------

    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 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 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 multi-pollutant approach. As mentioned above, we did not 
identify any 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 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.

[[Page 56625]]

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 emissions, 
including the efficacy and cost of the technologies and the prevalence 
of use in the industry.
---------------------------------------------------------------------------

    \69\ GRI/EPA, 1996d.
---------------------------------------------------------------------------

    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.
    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 report \70\ 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 VOC, and a gas-driven 
diaphragm pump to be 3.46 tpy of methane and 0.96 tpy of VOC.
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    \70\ EPA/GRI. Methane Emissions from the Natural Gas Industry, 
Volume 13: Chemical Injection Pumps. June 1996 (EPA-60/R -96- 80m), 
Sections 5.1--Diaphragm Pumps and 5.2--Piston Pumps.
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    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 gas-driven 
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 gas-driven 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 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 gas-driven pumps, which involves routing the gas to a process 
\72\ 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.
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    \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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    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 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

[[Page 56626]]

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 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, 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 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 cost-effective, 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 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 
the cost is high if it is all assigned to VOC reduction, the cost is 
reasonable when assigned to methane reduction.
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    \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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    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 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

[[Page 56627]]

processing plants, we evaluated this option based on the incremental 
additional cost of routing the natural gas-driven 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 
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 $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 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 costs for complying with the proposed standards is 
0.001 percent of the total revenues, which is also 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 is also 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.
    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 Sec.  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 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 CFR part 63 HH and HHH. It is also our understanding from 
commenters that 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.
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    \75\ June 13, 2014, API comments on EPA's white paper on oil and 
natural gas sector pneumatic devices.

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[[Page 56628]]

F. Proposed Standards for Well Completions

    For the 2012 NSPS and this action, we have identified two 
subcategories of hydraulically fractured wells: (1) Non-exploratory 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 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 Non-Wildcat 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 
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 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 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.
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    \76\ Available at https://www.epa.gov/airquality/oilandgas/2014papers/20140415completions.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., Colorado \77\ and Wyoming \78\) 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.
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    \77\ Colorado Oil and Gas Conservation Commission (COGCC) 805 
Series Rules (805.b.(3)A) at: https://cogcc.state.co.us/ and the 
Colorado Code of Regulations at: https://www.sos.state.co.us/CCR/Welcome.do.
    \78\ WY BACT permitting guidance available at https://deq.state.wy.us/aqd/Oil%20and%20Gas/September%202013%20FINAL_Oil%20and%20Gas%20Revision_UGRB.pdf.
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    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 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

[[Page 56629]]

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 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 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.
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    \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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    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 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 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 well,\80\ 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 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.
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    \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.
---------------------------------------------------------------------------

    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 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

[[Page 56630]]

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 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 combustion-related 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.
---------------------------------------------------------------------------

    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 0.081 
percent of the total capital expenditures, which 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 costs for complying with the proposed standards is 
0.033 percent of the total revenues, which is also 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 is also 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 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 
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.
    The second stage is defined as the ``separation flowback stage.'' 
The point at which the separator can function

[[Page 56631]]

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 
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 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, Sec.  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 re-injected 
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.
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 hydraulically fractured oil well were 
9.72 tons of methane and 8.14 tons of VOC per 3-day completion 
event.\83\
---------------------------------------------------------------------------

    \83\ Emissions of VOC from hydraulically fractured subcategory 2 
gas wells are subject to the current NSPS and are not included in 
this action.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    \84\ Emissions of VOC from hydraulically fractured subcategory 2 
gas wells are subject to the current NSPS and are not included in 
this action.
---------------------------------------------------------------------------

    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 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

[[Page 56632]]

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 consider these costs to be 
reasonable considering the level of emissions reductions.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 subcategory 2 oil well completion\86\ 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 subcategory 2 wells is 0.002 
percent of the capital expenditures, which 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 is also 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 is also 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.
    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.
    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 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

[[Page 56633]]

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.
---------------------------------------------------------------------------

    \87\ The EPA received six peer review comments and several 
submissions of technical information and data on this paper, 
available for review at https://www.epa.gov/airquality/oilandgas/whitepapers.html.
---------------------------------------------------------------------------

    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 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).\89\ Additionally, we solicit 
comment on all aspects of our proposal to regulate methane and VOC 
emissions from hydraulically fractured oil well completions.
---------------------------------------------------------------------------

    \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.
    \89\ Many of these data are available in the DrillingInfo 
database. More information is available at: https://info.drillinginfo.com.
---------------------------------------------------------------------------

    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. 
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) \90\ 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 may be unintentional and may be 
infrequent, but production may nevertheless proceed due to 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.
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    \90\ 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).
---------------------------------------------------------------------------

    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.\91\ 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 
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.
---------------------------------------------------------------------------

    \91\ 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. https://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2014-0831-0137.
---------------------------------------------------------------------------

    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.\92\ 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.\93\ 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 apply to completions wells with hydraulic 
fracturing that have a GOR of less than 300 scf/barrel.
---------------------------------------------------------------------------

    \92\ https://www.eia.gov/todayinenergy/detail.cfm?id=13571#.
    \93\ https://petrowiki.org/Oil_fluid_characteristics.
---------------------------------------------------------------------------

    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

[[Page 56634]]

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 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.\94\ We solicit comment on 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.
---------------------------------------------------------------------------

    \94\ 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 Issuance of a Montana Air 
Quality Permit. Emission Control Requirements, 17.8.1603 Available 
at: https://www.deq.mt.gov/dir/legal/Chapters/Ch08-toc.mcpx.
---------------------------------------------------------------------------

3. Use of a Separator During Flowback
    For subcategory 1, subcategory 2 and low pressure gas wells, the 
current NSPS at Sec.  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 Sec.  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 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'' \95\ 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 
mitigation techniques (practices and technology) available to reduce 
these emissions along with the cost and effectiveness of these 
practices and technologies.
---------------------------------------------------------------------------

    \95\ Available at https://www.epa.gov/airquality/oilandgas/2014papers/20140415leaks.pdf.
---------------------------------------------------------------------------

    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 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
    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

[[Page 56635]]

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 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 temperature) are present. Work is 
ongoing to determine the lowest concentration that can be reliably 
detected using OGI.\96\
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    \96\ Draft Technical Support Document Appendices, Optical Gas 
Imaging Protocol (40 CFR part 60, Appendix K), August 11, 2015.
---------------------------------------------------------------------------

    In order to estimate fugitive methane and VOC emissions from well 
sites, we used fugitive emissions component counts from the GRI/EPA 
report \97\ 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 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.\98 \These data were used to develop an oil production well 
site model plant.
---------------------------------------------------------------------------

    \97\ 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 (EPA-600/
R-96-080h).
    \98\ API Workbook 4638, 1996.
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    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,\99\ 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 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.
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    \99\ U.S. Environmental Protection Agency, Protocol for 
Equipment Leak Emission Estimates, Table 2-4, November 1995 (EPA-
453/R-95-017).
---------------------------------------------------------------------------

    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 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 Industry (SOCMI) and Petroleum 
Refining Industry along with the emissions rates contained within the 
Technology Review for Equipment Leaks document.\100\ 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

[[Page 56636]]

emissions reduction percentage for each of the combinations of 
monitoring frequency and repair threshold.
---------------------------------------------------------------------------

    \100\ 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.
---------------------------------------------------------------------------

    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 cost-effectiveness of the various 
options.\101\ For purposes of this action, we have identified in 
section VIII.A two approaches (single and multipollutant approaches) 
for evaluating the cost-effectiveness 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 
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.
---------------------------------------------------------------------------

    \101\ See pages 68-69 of the TSD.
---------------------------------------------------------------------------

    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 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.\102\ We therefore focus our BSER 
analysis based on the use of OGI.
---------------------------------------------------------------------------

    \102\ See the 2015 TSD for full comparison.
---------------------------------------------------------------------------

    For the reasons stated below, we find that the control cost based 
on quarterly monitoring using OGI may not be cost-effective based on 
the information available. As shown in the TSD, under the single 
pollutant approach, if all costs are 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 cost-
effective, 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 semi-annual monitoring.
    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 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 is very 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 is also 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 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.

[[Page 56637]]

    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 OGI instruments. Many owners and operators, in particular small 
businesses, may not own OGI instruments or have staff who are trained 
and qualified to use such instruments; 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 number of available contractors and 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 OGI 
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 OGI 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 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 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 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 emission 
standards.\103\ 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.\104\
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    \103\ 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.
    \104\ This timelines is consistent with the timeline originally 
established in 1983 under 40 CFR part 60 subpart VV.
---------------------------------------------------------------------------

    Many recent studies have shown a skewed distribution for emissions 
related to leaks, where a majority of emissions come from a minority of 
sources.\105\ 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.''
---------------------------------------------------------------------------

    \105\
---------------------------------------------------------------------------

    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 around 700. We believe that a facility 
with proper operation would likely find one to three 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 three 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 three percent of 
total components have fugitive emissions; and quarterly if over three 
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

[[Page 56638]]

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 Sec.  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 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.
    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 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. 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 on criteria we can use to determine whether and under what 
conditions well sites operating under corporate fugitive monitoring 
programs 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.
    For the reasons stated above, we are also soliciting comments on 
criteria we can use to determine whether and under what conditions all 
new or modified well sites operating under corporate fugitive 
monitoring programs can be deemed to be meeting the equivalent of the 
NSPS standards for well sites 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 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 
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 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

[[Page 56639]]

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 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 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) 
\106\ 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. It is our understanding 
that fugitive emissions at low production well 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 
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. Further, we solicit comment on whether EPA should include low 
production well sites for fugitive emissions and if these types of well 
sites are not excluded, should they have a less frequent monitoring 
requirement.
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    \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).
---------------------------------------------------------------------------

    We are also requesting comment on whether there are well sites that 
have inherently low fugitive emissions, even when a 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 
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 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 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\
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    \107\ Draft Technical Support Document Appendices, Optical Gas 
Imaging Protocol (40 CFR part 60, Appendix K), August 11, 2015.
---------------------------------------------------------------------------

    In order to estimate fugitive emissions from compressor stations, 
we used component counts from the GRI/EPA report \108\ for each of the 
compressor station segments. Fugitive emission factors from AP-42 \109\ 
were used to estimate emissions from gathering and boosting stations in 
the production

[[Page 56640]]

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.
---------------------------------------------------------------------------

    \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 (EPA-600/
R-96-080h).
    \109\ Environmental Protection Agency, Protocol for Equipment 
Leak Emission Estimates, Table 2-4, November 1995 (EPA-453/R-95-
017).
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    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 methane and 4.6 tpy of VOC. The 
calculation of these emission estimates are explained in detail in the 
TSD available in the docket.
---------------------------------------------------------------------------

    \110\ U.S. Environmental Protection Agency, Protocol for 
Equipment Leak Emission Estimates, Table 2-4, November 1995 (EPA-
453/R-95-017).
---------------------------------------------------------------------------

    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 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 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.
---------------------------------------------------------------------------

    \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
---------------------------------------------------------------------------

    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 cost-effectiveness 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 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.
---------------------------------------------------------------------------

    \112\ See pages 68-69 of the TSD.
---------------------------------------------------------------------------

    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 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

[[Page 56641]]

frequencies.\113\ We therefore focus our BSER analysis based on the use 
of OGI.
---------------------------------------------------------------------------

    \113\ See the 2015 TSD for full comparison.
---------------------------------------------------------------------------

    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 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-annual 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 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 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 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 is very 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 is also 
very low.
    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.
    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

[[Page 56642]]

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 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 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\
---------------------------------------------------------------------------

    \114\ This timeline is consistent with the timeline originally 
established in 1983 under 40 CFR part 60 subpart VV.
---------------------------------------------------------------------------

    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 this information, we solicit comment on whether the fugitive 
emissions monitoring program should be limited to ``gross emitters.''
---------------------------------------------------------------------------

    \115\ See 2015 TSD.
---------------------------------------------------------------------------

    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 three 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 three 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 monitoring survey shows less 
than one percent of components to have fugitive emissions; semi-annual 
if one to three percent of total components have fugitive emissions; 
and quarterly if over three 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 Sec.  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 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 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

[[Page 56643]]

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 are 
also soliciting comments on criteria we can use to determine whether 
and under what conditions all new or modified compressor stations 
operating under corporate fugitive monitoring programs can be deemed to 
be meeting the equivalent of the NSPS standards for compressor stations 
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 compressor stations are achieving, and will continue 
to achieve, equal or better emission reduction than our proposed 
standards).
    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 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 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 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

    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 non-associated 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 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.

[[Page 56644]]

    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 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.
---------------------------------------------------------------------------

    \116\ Available athttps://www.epa.gov/airquality/oilandgas/2014papers/20140415leaks.pdf.
---------------------------------------------------------------------------

    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 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.
---------------------------------------------------------------------------

    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 (multipollutant 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. 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 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 better insight 
into emissions from liquids unloading. Data were provided in a study 
conducted by members of the American Petroleum

[[Page 56645]]

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 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 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 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) 
Closed-vent system joints, seams and other sealed connections (e.g., 
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 Sec.  
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 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 (https://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

[[Page 56646]]

conducted on an ongoing basis, 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

    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 Sec.  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 Sec.  60.5416. In 
order to maintain consistency with the previously amended Sec.  
60.5411, we are proposing to amend Sec.  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 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 Sec.  
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 Sec.  
60.5420(c) do not include the repair logs for control devices failing a 
visible emissions test required by Sec.  60.5413(c). We agree that 
these recordkeeping requirements should be listed and are proposing to 
add them at Sec.  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, Sec.  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 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 Sec.  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 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 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 pressure-assisted 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 Sec.  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

[[Page 56647]]

the notification of reconstruction requirements under Sec.  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 Sec.  
60.5410 and Sec.  60.5420 in lieu of the general notification 
requirement in Sec.  60.15(d). The EPA, therefore, proposes to add in 
Table 3 that Sec.  60.15(d) does not apply to affected facility 
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 Sec.  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 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 
Sec.  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 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 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 mirrors \118\ 
the definition in subpart VV but with the year revised to reflect the 
year subpart OOOO was proposed (i.e., 2011).
---------------------------------------------------------------------------

    \118\ The proposed definition does not include B values listed 
in subpart VV for other subparts because those values are irrelevant 
to subpart OOOO.
---------------------------------------------------------------------------

    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 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
    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 issue \119\ requested that EPA 
include in

[[Page 56648]]

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\
---------------------------------------------------------------------------

    \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 FR 52738 (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 FR 52738 (Aug. 23, 2011). Pp. 33.
---------------------------------------------------------------------------

    We clarify that subpart OOOO, as promulgated in 2012, already 
includes a provision similar to subpart KKK, Sec.  60.632(a), as 
requested in the comment. Specifically, Sec.  60.5400(a) requires 
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 Sec.  
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 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 trace amounts of 
VOC emissions that are difficult to control, that operators may choose 
to discontinue recycling to avoid noncompliance with the NSPS.
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    \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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    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 
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:

    (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 https://www.acus.gov/report/third-party-programs-final-report;
    (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\
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    \122\ EPA, Renewable Fuel Standards (RFS), https://www.epa.gov/OTAQ/fuels/renewablefuels/.
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    (5) Massachusetts Underground Storage Tank (UST) third-party 
inspection program: The owners/operators of most underground storage 
tanks in Massachusetts are required to have their USTs inspected by 
third-party inspectors every 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\
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    \123\ MassDEP, Third-Party Underground Storage Tank (UST) 
Inspection Program, https://www.mass.gov/eea/agencies/massdep/toxics/ust/third-party-ust-inspection-program.html.

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[[Page 56649]]

    (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\
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    \124\ https://www.mass.gov/eea/agencies/massdep/cleanup/licensed-site-professionals.html.

    We have identified one potential area for third-party verification 
under this rule.
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 
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 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 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 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 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 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

[[Page 56650]]

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 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 
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 
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 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;
    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: (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

[[Page 56651]]

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 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, 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 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 electronically 
reported to CEDRI will further enhance our ability to evaluate 
compliance with the rule.
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    \125\ See www.epa.gov/oilandgas.
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    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 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 
e-reporting, 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.
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    \126\ EPA, Policy Statement on E-Reporting in EPA Regulations 
(September 30, 2013).
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    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 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, Sec.  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

[[Page 56652]]

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 
(https://www.epa.gov/ttn/chief/cedri/). 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 Sec.  60.4 of the 
General Provisions. The owner or 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 
disclosure to pollution reductions,\128\ 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.
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    \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%).
    \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 https://www.sciencedirect.com/science/article/pii/S0095069696909559 (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 
https://web.worldbank.org/archive/website01004/WEB/IMAGES/BRAZILIN.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 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. J[eacute]r[ocirc]me Foulon et al., Incentives for 
Pollution Control: Regulation and Public Disclosure 5 (World Bank 
Pol'y Res., Working Paper No. 2291, 2000), available at https://papers.ssrn.com/sol3/papers.cfm?abstract_id=629138.
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    A 2014 study specific to the oil and natural gas industry \131\ 
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 
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).
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    \131\ Richard Liroff, D. F. (2014). Disclosing the Facts: 
Transparency and Risk in Hydraulic Fracturing.
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    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.
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 help ensure that optical gas imaging for fugitive 
emissions is being performed properly. The EPA requests

[[Page 56653]]

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.
    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 analysis 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 of 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, 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 analyses 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).

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 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 engineering compliance 
costs of about $8 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 2025 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 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

[[Page 56654]]

impacts are of particular concern and questions may arise about their 
existence and magnitude.
    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 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 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.
    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 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\
---------------------------------------------------------------------------

    \133\ Both the 2010 SC-CO2 TSD and the current TSD 
are available at: https://www.whitehouse.gov/omb/oira/social-cost-of-carbon.
---------------------------------------------------------------------------

    The SC-CO2 TSDs discuss a number of limitations to the 
SC-CO2 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 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

[[Page 56655]]

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 employed 
\134\ (EPA 2012). 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\
---------------------------------------------------------------------------

    \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. https://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf. Accessed March 30, 2015.
    \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 https://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_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 https://www.epa.gov/otaq/climate/documents/420r12016.pdf.
---------------------------------------------------------------------------

    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 GWP-weighted benefit 
estimates for methane are likely to be lower 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.
---------------------------------------------------------------------------

    \136\ See Waldhoff et al. (2011); Marten and Newbold (2012); and 
Marten et al. (2014).
---------------------------------------------------------------------------

    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.
    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.

                                   Table 6--Social Cost of CH4, 2012-2050 \a\
                           [In 2012$ per metric ton] (Source: Marten et al., 2014 \b\)
----------------------------------------------------------------------------------------------------------------
                                                                            SC-CH4
                    Year                     -------------------------------------------------------------------
                                                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), https://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 
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

[[Page 56656]]

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 $88 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 $220 
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
                                              [In millions, 2012$]
----------------------------------------------------------------------------------------------------------------
                                                                          Year
      Discount rate and statistic      -------------------------------------------------------------------------
                                                        2020                                 2025
----------------------------------------------------------------------------------------------------------------
Million metric tonnes of methane        0.15 to 0.16.......................  0.31 to 0.36.
 reduced.
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.
    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 visibility effects, ecosystem effects and 
climate effects, as well as additional product recovery.
---------------------------------------------------------------------------

    \139\ Previous studies have estimated the monetized benefits-
per-ton 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.
---------------------------------------------------------------------------

    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, 2006,\140\ U.S. EPA, 2010,\141\ and 
U.S. EPA, 2014 \142\), 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\
---------------------------------------------------------------------------

    \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 https://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 https://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 
Triangle Park, NC. December 2014. Available on the Internet at 
https://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 
https://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 https://
cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
---------------------------------------------------------------------------

    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 of 
these secondary air pollutant impacts is small relative to the

[[Page 56657]]

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 SC-
CO2 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 
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 https://www2.epa.gov/laws-regulations/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 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 Benefits \1\....  $200 to $210        $460 to $550
                                   million.            million.
Total Costs \2\.................  $150 to $170        $320 to $420
                                   million.            million.
Net Benefits \3\................  $35 to $42 million  $120 to $150
                                                       million.
                                 ---------------------------------------
Non-monetized 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 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 FR 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 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

[[Page 56658]]

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 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.
    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 November 
17, 2015. 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.
    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.
    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 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 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 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

[[Page 56659]]

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.
    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 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), 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 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.
    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.
    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.

[[Page 56660]]

    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 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 CFR 
Part 51

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 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 CFR 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, subpart OOOOa 
that includes incorporation by reference. In accordance with 
requirements of 1 CFR 51.5, the EPA is proposing to incorporate by 
reference ASME/ANSI PTC 19-10-1981 Part 10 (2010), ``Flue and Exhaust 
Gas Analyses'' 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 includes manual and instructional methods of analysis for 
carbon dioxide, carbon monoxide, hydrogen sulfide, nitrogen oxides, 
oxygen, and sulfur dioxide. 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 
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.

List of Subjects in 40 CFR Part 60

    Administrative practice and procedure, Air pollution control, 
Incorporation by reference, Intergovernmental relations, Reporting and 
recordkeeping.

    Dated: August 18, 2015.
Gina McCarthy,
Administrator.

    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

0
1. The authority citation for part 60 continues to read as follows:

    Authority:  42 U.S.C. 4701, et seq.

Subpart A--[Amended]

0
2. Section 60.17 is amended by revising paragraph (f)(14)


Sec.  60.17  Incorporations by reference.

* * * * *
    (f) * * *
    (14) ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses [Part 
10, Instruments and Apparatus], (Issued August 31, 1981), IBR approved 
for Sec. Sec.  60.56c(b), 60.63(f), 60.106(e), 60.104a(d), (h), (i), 
and (j), 60.105a(d), (f), and (g), Sec.  60.106a(a), Sec.  60.107a(a), 
(c), and (d), tables 1 and 3 to subpart EEEE, tables 2 and 4 to subpart 
FFFF, table 2 to subpart JJJJ, Sec.  60.285a(f), Sec. Sec.  60.4415(a), 
60.2145(s) and (t), 60.2710(s) (t), and (w), 60.2730(q), 60.4900(b), 
60.5220(b), tables 1 and 2 to subpart LLLL, tables 2 and 3 to subpart 
MMMM, Sec. Sec.  60.5406(c) and 60.5413(b), Sec.  60.5406a(c), Sec.  
60.5407a(g), Sec. Sec.  60.5413a(b) and 60.5413a(d).

[[Page 56661]]

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 September 18, 2015

0
3. The heading for Subpart OOOO is revised to read as set forth above.
0
4. Section 60.5360 is revised to read as follows:


Sec.  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 September 18, 2015.
0
5. Section 60.5365 is amended by:
0
a. Revising the introductory text; and
0
b. Revising paragraph (h)(4).
    The revisions read as follows:


Sec.  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 September 18, 2015.
* * * * *
    (h)* * *
    (4) A gas well facility initially constructed after August 23, 
2011, and on or before September 18, 2015 is considered an affected 
facility regardless of this provision.
0
6. Section 60.5370 is amended by adding paragraph (d) to read as 
follows:


Sec.  60.5370  When must I comply with this subpart?

* * * * *
    (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.
0
7. Section 60.5411 is amended by: revising paragraphs (a)(3)(i)(A) and 
(c)(3)(i)(A) to read as follows:


Sec.  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 of each time the alarm is activated according to 
Sec.  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 
Sec.  60.5420(c)(8).
* * * * *
0
8. Section 60.5412 is amended by:
0
a. Revising paragraphs (a)(1)(ii) and (d)(1) introductory text; and
0
b. Adding paragraph (d)(1)(iv).
    The revisions and addition read as follows:


Sec.  60.5412  What additional requirements must I meet for determining 
initial compliance with control devices used to 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 Sec.  
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 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 Sec.  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 Sec.  
60.5413.
    (C) You must operate at a minimum temperature of 760[deg]C for a 
control device that can demonstrate a uniform combustion zone 
temperature during the performance test conducted under Sec.  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.
* * * * *
0
9. Section 60.5413 is amended by revising paragraph (e)(3) to read as 
follows:


Sec.  60.5413  What are the performance testing procedures for control 
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.
* * * * *
0
10. Section 60.5415 is amended by revising paragraph (b)(2)(vii)(B) to 
read as follows:

[[Page 56662]]

Sec.  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) * * *
    (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.
* * * * *
0
11. Section 60.5416 is amended by revising paragraph (c)(3)(i) to read 
as follows:


Sec.  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, 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 
Sec.  60.5420(c)(8).
* * * * *
0
12. Section 60.5417 is amended by adding paragraph (h)(4) to read as 
follows:


Sec.  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 Sec.  
60.5413(b)(5)(ii) and conduct subsequent periodic performance tests at 
intervals no longer than 60 months following the previous periodic 
performance test.
0
13. Section 60.5420 is amended by:
0
a. Revising paragraph (c) introductory text; and
0
b. Adding paragraph (c)(14).
    The revision and addition reads as follows:


Sec.  60.5420  What are my notification, reporting, and recordkeeping 
requirements?

* * * * *
    (c) Recordkeeping requirements. You must maintain the records 
identified as specified in Sec.  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 Sec. Sec.  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.
0
14. Section 60.5430 is revised by:
0
a. Adding, in alphabetical order, a definition for the term ``capital 
expenditure;'' and
0
b. Revising the definition for ``group 2 storage vessel.''
    The addition and revision read as follows:


Sec.  60.5430  What definitions apply to this subpart?

* * * * *
    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 x 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 x (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 September 18, 2015.
* * * * *
0
15. Amend Table 3 to Subpart OOOO by revising entries ``Sec.  60.15'' 
and ``Sec.  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
----------------------------------------------------------------------------------------------------------------
 
                                                  * * * * * * *
Sec.   60.15................  Reconstruction.........  Yes.........................  Except that Sec.   60.15(d)
                                                                                      does not apply to
                                                                                      pneumatic controllers,
                                                                                      centrifugal compressors or
                                                                                      storage vessels.
 
                                                  * * * * * * *
Sec.   60.18................  General control device   Yes.........................  ...........................
                               requirements.
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------


[[Page 56663]]

0
16. 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 Reconstruction 
Commenced after September 18, 2015
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 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 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 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?
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 
SO2Emission 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 September 18, 2015


Sec.  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 September 18, 2015. 
The effective date of the rule is [date 60 days after publication of 
final rule in the Federal Register].


Sec.  60.5365a  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 (j) of this section for 
which you commence construction, modification or reconstruction after 
September 18, 2015.
    (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 
Sec.  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 Sec.  60.5375a(a)(1) through (4) are met. However, 
hydraulic refracturing of a well constitutes a modification of the well 
site for purposes of Sec.  60.5397a, regardless of affected facility 
status of the well itself.
    (2) A well completion operation following hydraulic refracturing 
not conducted pursuant to Sec.  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 September 18, 2015, 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

[[Page 56664]]

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 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 Sec.  60.5375a, including wells subject to Sec.  
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 Sec.  60.5411a(b).
    (ii) You meet the closed vent system requirements specified in 
Sec.  60.5411a(c).
    (iii) You maintain records that document compliance with paragraphs 
(e)(3)(i) and (ii) of this section.
    (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.
    (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 Sec. Sec.  
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 Sec. Sec.  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.
    (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 Sec.  60.5423a(c) but are not 
required to comply with Sec. Sec.  60.5405a through 60.5407a and 
Sec. Sec.  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 Sec. Sec.  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) Except as provided in Sec.  60.5365a(i)(1) through (i)(2), the 
collection of fugitive emissions components at a well site, as defined 
in Sec.  60.5430a, is an affected facility.
    (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 Sec.  60.5397a, a ``modification'' to a well 
site occurs when:
    (i) A new well is drilled at an existing well site;
    (ii) 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 Sec.  60.5430a, is an affected facility. For 
purposes of Sec.  60.5397a, a ``modification'' to a compressor station 
occurs when:

[[Page 56665]]

    (1) A new compressor is constructed at an existing compressor 
station; or
    (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


Sec.  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.


Sec.  60.5375a  What methane and VOC standards apply to well affected 
facilities?

    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 
Sec.  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 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.
    (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 Sec.  60.5420a(c)(1)(iii).
    (c) You must demonstrate initial compliance with the standards that 
apply to well affected facilities as required by Sec.  60.5410a.
    (d) You must demonstrate continuous compliance with the standards 
that apply to well affected facilities as required by Sec.  60.5415a.
    (e) You must perform the required notification, recordkeeping and 
reporting as required by Sec.  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.
    (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 Sec.  
60.5420a(c)(1)(iii) for wildcat, delineation and low pressure wells.


Sec.  60.5380a  What methane and VOC standards apply to centrifugal 
compressor affected facilities?

    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 Sec.  60.5411a(b). The cover must be connected through 
a closed vent system that meets the requirements of Sec.  60.5411a(a) 
and the closed vent system must be routed to a control device that 
meets the conditions specified in Sec.  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 
Sec.  60.5410a(b).
    (c) You must demonstrate continuous compliance with the standards 
that apply to centrifugal compressor affected facilities as required by 
Sec.  60.5415a(b).
    (d) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420a.


Sec.  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.

[[Page 56666]]

    (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 operates under 
negative pressure and route the rod packing emissions to a process 
through a closed vent system that meets the requirements of Sec.  
60.5411a(a).
    (b) You must demonstrate initial compliance with standards that 
apply to reciprocating compressor affected facilities as required by 
Sec.  60.5410a.
    (c) You must demonstrate continuous compliance with standards that 
apply to reciprocating compressor affected facilities as required by 
Sec.  60.5415a.
    (d) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420a.


Sec.  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 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 Sec.  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 Sec.  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 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 Sec.  60.5420a(c)(4)(iii).
    (d) You must demonstrate initial compliance with standards that 
apply to pneumatic controller affected facilities as required by Sec.  
60.5410a.
    (e) You must demonstrate continuous compliance with standards that 
apply to pneumatic controller affected facilities as required by Sec.  
60.5415a.
    (f) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420a, except that you are not 
required to submit the notifications specified in Sec.  60.5420a(a).


Sec.  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.
    (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 Sec.  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 Sec.  
60.5420(b)(8)(i).
    (ii) If you subsequently install a control device, you are no 
longer required to submit the certification in Sec.  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 Sec.  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 Sec.  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 Sec.  60.5411a(a) and route 
emissions to a control device that meets the conditions specified in 
Sec.  60.5412a(a), (b) and (c) and performance tested in accordance 
with Sec.  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 Sec.  
60.5410a.
    (d) You must demonstrate continuous compliance with standards that 
apply to pneumatic pump affected facilities as required by Sec.  
60.5415a.
    (e) You must perform the required notification, recordkeeping, and 
reporting as required by Sec.  60.5420a, except that you are not 
required to submit the notifications specified in Sec.  60.5420a(a).


Sec.  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

[[Page 56667]]

(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 Sec.  
60.5365a(e).
    (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 Sec.  
60.5375a, you must achieve the required emissions reductions within 60 
days after startup of production as defined in Sec.  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 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 Sec.  
60.5411a(b) and is connected through a closed vent system that meets 
the requirements of Sec.  60.5411a(c), and you must route emissions to 
a control device that meets the conditions specified in Sec.  
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.
    (2) If you use a floating roof to reduce emissions, you must meet 
the requirements of Sec.  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 Sec.  
60.5420a(b)(6)(v) in your next annual report, identifying each 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 Sec.  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 Sec.  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 Sec.  60.5410a(h) and (i).
    (2) You must demonstrate continuous compliance with standards as 
required by Sec.  60.5415a(e)(3).
    (3) You must perform the required notification, recordkeeping and 
reporting as required by Sec.  60.5420a.
    (e) Exemptions. This subpart does not apply to storage vessels 
subject to and controlled in accordance with the requirements for 
storage vessels in 40 CFR part 60, subpart Kb, 40 CFR part 63, subparts 
G, CC, HH, or WW.


Sec.  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 Sec.  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 Sec.  60.5411a.
    (a) You must monitor all fugitive emission components, as defined 
in 60.5430a, in accordance with paragraphs (b) through (i) of this 
section. You must repair all sources of fugitive emissions in 
accordance with paragraph (j) of this section. You must keep records in 
accordance with paragraph (k) and report in accordance with paragraph 
(l) of this section. 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 components at 
well sites and compressor stations in accordance with paragraph (c) of 
this section, and you must develop a site-specific 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

[[Page 56668]]

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 
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 concentration of <=10,000 
ppm at a flow rate of >=60 g/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.
    (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.
    (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 3.0 percent of the fugitive emissions components at a well 
site or at greater than 3.0 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 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 3.0 percent 
of the fugitive emissions components at the well site, or between 1.0 
percent and 3.0 percent of the fugitive emissions components at the 
compressor station.
    (j) For fugitive emissions components also subject to the repair 
provisions of Sec. Sec.  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 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 Sec.  60.5401a(g).
    (iii) Operators that use optical gas imaging to resurvey the 
repaired fugitive emissions components, are subject to the resurvey 
provisions specified in paragraphs (j)(2)(iii)(A) and (B).
    (A) A fugitive emissions component is repaired when the optical gas 
imaging

[[Page 56669]]

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 Sec.  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.
    (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 Sec.  60.5420a(b)(7). Multiple collection of 
fugitive emissions components at a well site or collection of fugitive 
emissions at a compressor station may be included in a single annual 
report.


Sec.  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 Sec. Sec.  60.482-
1a(a), (b), and (d), 60.482-2a, and 60.482-4a through 60.482-11a, 
except as provided in Sec.  60.5401a.
    (b) You may elect to comply with the requirements of Sec. Sec.  
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 
Sec.  60.5402a.
    (d) You must comply with the provisions of Sec.  60.485a except as 
provided in paragraph (f) of this section.
    (e) You must comply with the provisions of Sec. Sec.  60.486a and 
60.487a of this part except as provided in Sec. Sec.  60.5401a, 
60.5421a, and 60.5422a.
    (f) You must use the following provision instead of Sec.  
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 Sec.  60.17) must be 
used.


Sec.  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 Sec.  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 release to 
detect leaks by the methods specified in Sec.  60.485a(b) except as 
provided in Sec.  60.5400a(c) and in paragraph (b)(4) of this section, 
and Sec.  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 Sec.  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 Sec.  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 
Sec.  60.482-5a.
    (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 Sec. Sec.  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 Sec. Sec.  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 Sec.  60.485a(e):
    (1) Equipment is in heavy liquid service if the weight percent 
evaporated is 10 percent or less at 150 [deg]C (302 [deg]F) as 
determined by ASTM Method D86-96 (incorporated by reference as 
specified in Sec.  60.17).
    (2) Equipment is in light liquid service if the weight percent 
evaporated is greater than 10 percent at 150 [deg]C (302

[[Page 56670]]

[deg]F) as determined by ASTM Method D86-96 (incorporated by reference 
as specified in Sec.  60.17).
    (g) An owner or operator may use the following provisions instead 
of Sec.  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 Sec.  
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 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 re-monitored.


Sec.  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.
    (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.


Sec.  60.5405a  What standards apply to sweetening units at onshore 
natural gas processing plants?

    (a) During the initial performance test required by Sec.  60.8(b), 
you must achieve at a minimum, an SO2 emission reduction 
efficiency (Zi) to be determined from Table 1 of this 
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.


Sec.  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 Sec.  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 Sec.  60.8(b).
    (b) During a performance test required by Sec.  60.8, you must 
determine the minimum required reduction efficiencies (Z) of 
SO2 emissions as required in Sec.  60.5405a(a) and (b) as 
follows:
    (1) The average sulfur feed rate (X) must be computed as follows:

X = KQaY

Where:

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 x 10-3Mg/dscm, for metric units.
= (32 lb S/lb-mole)/((385.36 dscf/lb-mole) (2240 lb S/long ton)).
= 3.707 x 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 Sec.  60.5408a or a 
chromatographic procedure following ASTM E260-96 (incorporated by 
reference as specified in Sec.  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 procedure by 1.62 x 
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 Sec.  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:

R = (100S)/(S + E)

    (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:

E = CeQsd/K 1

Where:

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

[[Page 56671]]

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 cross-section if the area is less than 5 m\2\ (54 ft\2\) or at a 
point no closer to the walls than 1 m (39 in) if the cross-sectional 
area is 5 m\2\ 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 
x 10-3 to convert the results to sulfur equivalent. In place 
of Method 6 of Appendix A of this part, you may use ASME/ANSI PTC 
19.10-1981, Part 10 (manual portion only) (incorporated by reference as 
specified in Sec.  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 ft\3\/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 x 
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 ASME/ANSI PTC 19.10-1981, 
Part 10 (manual portion only) (incorporated by reference as specified 
in Sec.  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 sulfur 
as sulfur must be multiplied by 1.333 x 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.


Sec.  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 Sec.  60.5405a(a) or (b) you must install, calibrate, maintain, and 
operate monitoring devices or perform measurements 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 Sec.  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 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 Sec.  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 Sec.  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 
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 
Sec.  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 Sec.  
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 
Sec.  60.8 to demonstrate compliance with the standards under Sec.  
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 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

[[Page 56672]]

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 Sec.  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 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 Sec.  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 Sec.  
60.5406a(c)(1).
    (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:
[GRAPHIC] [TIFF OMITTED] TP18SE15.000

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).
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 Sec.  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 Sec.  60.13 of the General 
Provisions. For conducting the continuous emission monitoring system 
performance evaluation required by Sec.  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 Sec.  
60.17) may be used.


Sec.  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, 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 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 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,


[[Page 56673]]


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 starch-iodine end point is much 
less distinct, and a blank determination of end point, with 
H2S-free gas or air, is required.
[GRAPHIC] [TIFF OMITTED] TP18SE15.001


[[Page 56674]]




Sec.  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 Sec.  
60.5420a(a)(2).
    (2) You must submit the initial annual report for your well 
affected facility as required in Sec.  60.5420a(b).
    (3) You must maintain a log of records as specified in Sec.  
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 Sec.  
60.5375a(a)(1) and (3), as an alternative to retaining the records 
specified in Sec.  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 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 Sec.  60.5380a and as 
demonstrated by the requirements of Sec.  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 Sec.  60.5411a(b) that is connected through a closed 
vent system that meets the requirements of Sec.  60.5411a(a) and is 
routed to a control device that meets the conditions specified in Sec.  
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 
Sec.  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 continuous compliance 
requirements in Sec.  60.5415a(b)(1) through (3).
    (4) You must conduct the initial inspections required in Sec.  
60.5416a(a) and (b).
    (5) You must install and operate the continuous parameter 
monitoring systems in accordance with Sec.  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 Sec.  60.5420a(b) for each 
centrifugal compressor affected facility.
    (8) You must maintain the records as specified in Sec.  
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 Sec.  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.
    (2) If complying with Sec.  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 Sec.  60.5411a(a).
    (3) You must submit the initial annual report for your 
reciprocating compressor as required in Sec.  60.5420a(b).
    (4) You must maintain the records as specified in Sec.  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 Sec.  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 Sec.  
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.
    (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 Sec.  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 Sec.  
60.5420a(b).
    (6) You must maintain the records as specified in Sec.  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.
    (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

[[Page 56675]]

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 Sec.  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 Sec.  
60.5420a(b).
    (6) You must maintain the records as specified in Sec.  60.5420a(c) 
for each pneumatic pump affected facility.
    (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 Sec.  
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 Sec.  60.5405a(a), during the initial performance test as 
required by Sec.  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 Sec.  
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 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 Sec.  60.5365a(e).
    (2) You must reduce VOC emissions in accordance with Sec.  
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 Sec.  
60.5411a(b) and is connected through a closed vent system that meets 
the requirements of Sec.  60.5411a(c) to a control device that meets 
the conditions specified in Sec.  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.
    (4) You must conduct an initial performance test as required in 
Sec.  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 Sec.  60.5415a(e).
    (5) You must submit the information required for your storage 
vessel affected facility as specified in Sec.  60.5420a(b).
    (6) You must maintain the records required for your storage vessel 
affected facility, as specified in Sec.  60.5420a(c) for each storage 
vessel affected facility.
    (i) For each storage vessel affected facility, you must submit the 
notification specified in Sec.  60.5395a(b)(2) with the initial annual 
report specified in Sec.  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 site and each 
collection of fugitive emissions components at a compressor station as 
required in Sec.  60.5397a(a).
    (2) You must conduct an initial monitoring survey as required in 
Sec.  60.5397a(f).
    (3) You must maintain the records specified in Sec.  60.5420a(c).
    (4) You must repair each identified source of fugitive emissions 
for each affected facility as required in Sec.  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 Sec.  60.5420a(b).


Sec.  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 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 Sec.  60.5412a(a) through (c).
    (2) You must design and operate the closed vent system with no 
detectable emissions as demonstrated by Sec.  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 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 Sec.  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

[[Page 56676]]

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 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.
    (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 Sec.  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 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 Sec.  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.


Sec.  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, pneumatic pump affected 
facility, or storage vessel affected facility.
    (a) Each control device used to meet the emission reduction 
standard in Sec.  60.5380a(a)(1) for your centrifugal compressor 
affected facility or Sec.  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 Sec.  60.5413a(d), which meets the criteria in Sec.  
60.5413a(d)(11) and Sec.  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 Sec.  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 basis corrected to 3 percent 
oxygen as determined in accordance with the requirements of Sec.  
60.5413a.
    (iii) You must operate at a minimum temperature of 760 [deg]C for a 
control device that can demonstrate a uniform combustion zone 
temperature during the performance test conducted under Sec.  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 Sec.  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 Sec.  
60.5413a(c).
    (3) You must design and operate a flare in accordance with the 
requirements of Sec.  60.5413a(a)(1).
    (b) You must operate each control device installed on your 
centrifugal compressor or pneumatic pump affected facility in 
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 
Sec.  60.5380a(a), or from the pneumatic pump as required under Sec.  
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 Sec.  60.5417a(a) through (g), you must demonstrate 
compliance according to the requirements of Sec.  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

[[Page 56677]]

(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 longer than the carbon 
service life established according to Sec.  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 Sec.  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.
    (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 Sec.  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 Sec.  
60.5413a(d), which meets the criteria in Sec.  60.5413a(d)(11) and 
Sec.  60.5413a(e).
    (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 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 Sec.  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 Sec.  
60.5413a.
    (C) You must operate at a minimum temperature of 760 [deg]C for a 
control device that can demonstrate a uniform combustion zone 
temperature during the performance test conducted under Sec.  60.5413a.
    (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.


Sec.  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, pneumatic pump affected 
facility, or storage vessel affected facility. You must demonstrate 
that a control device achieves the performance requirements of Sec.  
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 Sec.  
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.

[[Page 56678]]

    (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 Sec.  60.8(b).
    (7) A control device whose model can be demonstrated to meet the 
performance requirements of Sec.  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 conducted to demonstrate that 
a control device meets the requirements of Sec.  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 Sec.  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 Sec.  
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 Sec.  60.5412a(a)(1)(i), (a)(2) 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:
    [GRAPHIC] [TIFF OMITTED] TP18SE15.002
    
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.
K2 = Constant, 2.494 x 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 [deg]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:
[GRAPHIC] [TIFF OMITTED] TP18SE15.003

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 Sec.  60.5412a(a)(1)(ii) or (d)(1)(iv)(B). You must 
calculate parts per million by volume 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:
[GRAPHIC] [TIFF OMITTED] TP18SE15.004

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.
    (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 ASME/

[[Page 56679]]

ANSI PTC 19.10-1981, Part 10 (manual portion only) (incorporated by 
reference as specified in Sec.  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:
[GRAPHIC] [TIFF OMITTED] TP18SE15.005

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 submit the 
performance test results as required in Sec.  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 Sec.  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 Sec.  
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.
    (c) Control device design analysis to meet the requirements of 
Sec.  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 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 (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 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 manually recorded provided that all inlet fuel data 
readings are included in the final report.

[[Page 56680]]

    (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.
    (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.
    (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.
    (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 chromatograph-thermal 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 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 ASME/ANSI PTC 19.10-1981, Part 10 (manual portion 
only) (incorporated by reference as specified in Sec.  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 points. An instrument 
range of 0-10 parts per million by volume-dry (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.
    (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:
[GRAPHIC] [TIFF OMITTED] TP18SE15.006


[[Page 56681]]


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) 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 paragraphs 
(d)(11)(i)(A) through (D) of this section must demonstrate a 
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 Sec.  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.
    (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 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 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.


Sec.  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 Sec.  
60.5420a(b) and maintaining the records for each completion operation 
specified in Sec.  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

[[Page 56682]]

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 
Sec.  60.5412a(a) using the procedures specified in paragraphs 
(b)(2)(i) through (vii) of this section. If you use a condenser as the 
control device to achieve the requirements specified in Sec.  
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 Sec.  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 
Sec.  60.5417a(f)(1).
    (ii) You must calculate the daily average of the applicable 
monitored parameter in accordance with Sec.  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 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 Sec.  60.5413a(d), 
compliance with the operating parameter limit is achieved when the 
criteria in Sec.  60.5413a(e) are met.
    (iv) You must operate the continuous monitoring system required in 
Sec.  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 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 Sec.  60.5412a(a) and you demonstrate compliance using 
the test procedures specified in Sec.  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 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 Sec.  
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 Sec.  60.5417a(f)(2).
    (B) You must calculate the daily average condenser outlet 
temperature in accordance with Sec.  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 Sec.  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 Sec.  60.5370a, you must 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

[[Page 56683]]

Sec.  60.5420a(c)(2), (6) through (11), and (16), as applicable.
    (c) For each reciprocating compressor affected facility complying 
with Sec.  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 
Sec.  60.5385a(a)(3), you must demonstrate continuous compliance 
according to paragraph (c)(4) of this section.
    (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 Sec.  
60.5420a(b) and maintain records as required in Sec.  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 Sec.  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 Sec.  60.5390a(a), (b), or (c).
    (2) You must submit the annual report as required in Sec.  
60.5420a(b).
    (3) You must maintain records as required in Sec.  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 Sec.  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 Sec.  
60.5395a(a).
    (ii) For each control device installed to meet the requirements of 
Sec.  60.5395a(a), you must demonstrate continuous compliance with the 
performance requirements of Sec.  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 Sec.  60.5416a(c) for each cover and 
closed vent system.
    (B) You must comply with Sec.  60.5417a(h) for each control device.
    (C) Each closed vent system that routes emissions to a process must 
be operated as specified in Sec.  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 Sec.  
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 Sec.  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 Sec.  
60.5406a(c)(1).
    (h) For each collection of fugitive emissions components at a well 
site and each collection of fugitive emissions components at a 
compressor station, you must demonstrate continuous compliance with the 
fugitive emission standards specified in Sec.  60.5397a according to 
paragraphs (h)(1) through (4) of this section.
    (1) You must conduct periodic monitoring surveys as required in 
Sec.  60.5397a(f) through (i).
    (2) You must repair or replace each identified source of fugitive 
emissions as required in Sec.  60.5397a(j).
    (3) You must maintain records as specified in Sec.  
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 Sec.  
60.5420a(b).


Sec.  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 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 Sec.  
60.5420a(c)(6).
    (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 Sec.  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

[[Page 56684]]

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 Sec.  
60.5420a(c)(6).
    (ii) Conduct annual inspections according to the test methods and 
procedures specified in paragraph (b) of this section to demonstrate 
that the components or connections operate with no detectable 
emissions. You must maintain records of the inspection results as 
specified in Sec.  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 Sec.  
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 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 Sec.  60.5420a(c)(7).
    (4) For each bypass device, except as provided for in Sec.  
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 device. You must maintain records of the 
inspections according to Sec.  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.
    (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 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 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 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

[[Page 56685]]

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-to-inspect 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.
    (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 Sec.  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 Sec.  60.5420a(c)(6).
    (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 Sec.  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 
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 Sec.  
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 Sec.  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 device. You must maintain records of the 
inspections and records of each time the key is checked out, if 
applicable, according to Sec.  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.
    (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-to-inspect 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.
    (ii) You have a written plan that requires inspection of the 
equipment at least once every 5 years.


Sec.  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.

[[Page 56686]]

    (a) For each control device used to comply with the emission 
reduction standard for centrifugal compressor affected facilities in 
Sec.  60.5380a(a)(1) or the emission reduction standard for pneumatic 
pumps affected facilities in Sec.  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 Sec.  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 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 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 Sec.  60.13(b).
    (v) Ongoing reporting and recordkeeping procedures in accordance 
with provisions in Sec.  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.
    (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 Sec.  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 [deg]C, or 2.5 [deg]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 locations and have a minimum accuracy 
of 1 percent of the temperature being monitored in [deg]C, 
or 2.5 [deg]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 [deg]C, or 2.5 [deg]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 [deg]C, or 2.5 [deg]C, whichever value is 
greater. You must install the temperature sensor at a location in the 
exhaust vent stream from the condenser.
    (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 [deg]C, 
or 2.5 [deg]C, whichever value is greater.
    (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 Sec.  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 
Sec.  60.5413a(d), a continuous monitoring system meeting the 
requirements of

[[Page 56687]]


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. 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 Sec.  
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 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 Sec.  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 Sec.  60.5413a(b) to demonstrate that the control 
device achieves the applicable performance requirements specified in 
Sec.  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 Sec.  60.5413a(c) to demonstrate that the control 
device achieves the applicable performance requirements specified in 
Sec.  60.5412a(a), then you must establish the minimum 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 Sec.  60.5413a(d) to demonstrate that the 
control device achieves the applicable performance requirements 
specified in Sec.  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 Sec.  60.5413a(b) to demonstrate that the condenser 
achieves the applicable performance requirements in Sec.  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.
    (ii) If you use a control device design analysis in accordance with 
the requirements of Sec.  60.5413a(c)(1) to demonstrate that the 
condenser achieves the applicable performance requirements specified in 
Sec.  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.
    (2) If you are subject to Sec.  60.5412a(a)(2), a deviation occurs 
when the 365-day average condenser efficiency calculated according to 
the requirements specified in Sec.  60.5415a(b)(2)(viii)(D) is less 
than 95.0 percent.
    (3) If you are subject to Sec.  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 Sec.  
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 Sec.  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.
    (ii) For each bypass line subject to Sec.  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 
Sec.  60.5413a(d), a deviation occurs when the conditions of paragraphs 
(g)(6)(i) or (ii) are met.

[[Page 56688]]

    (i) The inlet gas flow rate exceeds the maximum established during 
the test conducted under Sec.  60.5413a(d).
    (ii) Failure of the monthly visible emissions test conducted under 
Sec.  60.5413a(e)(3) occurs.
    (h) For each control device used to comply with the emission 
reduction standard in Sec.  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 Sec.  60.5413a(d)(2) through (10), 
which meets the criteria in Sec.  60.5413a(d)(11), the reporting 
requirement in Sec.  60.5413a(d)(12), and meet the continuous 
compliance requirement in Sec.  60.5413a(e).
    (1) For each combustion device you must conduct inspections at 
least once every calendar month according to paragraphs (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.
    (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 Sec.  60.5420a(c)(13).
    (4) Conduct a periodic performance test no later than 60 months 
after the initial performance test as specified in Sec.  
60.5413a(b)(5)(ii) and conduct subsequent periodic performance tests at 
intervals no longer than 60 months following the previous periodic 
performance test.


Sec.  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 Sec.  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 Sec.  
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 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 Sec.  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 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 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

[[Page 56689]]

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 Sec.  60.5380a(a)(2), the records 
specified in paragraphs (c)(6) through (11) of this section.
    (iv) If complying with Sec.  60.5380a(a)(1) with a control device 
tested under Sec.  60.5413a(d) which meets the criteria in Sec.  
60.5413a(d)(11) and Sec.  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.
    (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 Sec.  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.
    (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 Sec.  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 
Sec.  60.5410a(h)(2) and (3).
    (v) You must identify each storage vessel affected facility that is 
removed from service during the reporting period as specified in Sec.  
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 Sec.  
60.5395a(c)(3), including the date the storage vessel affected facility 
was returned to service.
    (vii) If complying with Sec.  60.5395a(a)(2) with a control device 
tested under Sec.  60.5413a(d) which meets the criteria in Sec.  
60.5413a(d)(11) and Sec.  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.
    (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 
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 Sec.  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.
    (iv) Records of deviations specified in paragraph (c)(16)(ii) of 
this section that occurred during the reporting period.
    (v) If complying with Sec.  60.5393a(b)(1) with a control device 
tested under Sec.  60.5413(d), which meets the criteria in Sec.  
60.5413(d)(11) and Sec.  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 Sec.  60.8) required by this subpart, except testing 
conducted by the manufacturer as specified in Sec.  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 
(https://www.epa.gov/ttn/chief/ert/) at the time of the test, 
you must submit the results of the performance test to the EPA via the

[[Page 56690]]

Compliance and Emissions Data Reporting Interface (CEDRI). (CEDRI can 
be accessed through the EPA's Central Data Exchange (CDX) (https://cdx.epa.gov/).) Performance 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 Sec.  60.4.
    (10) For combustion control devices tested by the manufacturer in 
accordance with Sec.  60.5413a(d), an electronic copy of the 
performance test results required by Sec.  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 (https://www.epa.gov/ttn/chief/cedri/). 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 Sec.  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 Sec.  60.7(f) and in paragraphs (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 Sec.  60.5375a.
    (iii) Records required in Sec.  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 Sec.  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 as required in Sec.  
60.5375a(a)(1)(ii); the date and time of each occurrence of returning 
to the initial flowback stage under Sec.  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 Sec.  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 Sec.  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 
Sec.  60.5375a(a)(1) and (3), if you are using a digital photograph in 
lieu of the records required in paragraphs (c)(1)(i) through (iv) of 
this section, you must retain the records of the digital photograph as 
specified in Sec.  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 Sec.  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 Sec.  60.5413a(d) which meets the criteria in Sec.  
60.5413a(d)(11) and Sec.  60.5413a(e) and used to comply with Sec.  
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.
    (vi) Records of continuous compliance requirements in Sec.  
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

[[Page 56691]]

latitude and longitude output of the GIS unit can be clearly read in 
the digital photograph.
    (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 
Sec.  60.5385a(a)(3).
    (iii) Records of deviations in cases where the reciprocating 
compressor was not operated in compliance with the requirements 
specified in Sec.  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.
    (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 Sec.  
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 Sec.  
60.5395a(a)(2), the records specified in Sec. Sec.  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 for each 
control device tested under Sec.  60.5413a(d) which meets the criteria 
in Sec.  60.5413a(d)(11) and Sec.  60.5413a(e) and used to comply with 
Sec.  60.5395a(a)(2) for each storage vessel.
    (ii) Records of each VOC emissions determination for each storage 
vessel affected facility made under Sec.  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 
Sec. Sec.  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 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 Sec.  60.5413a(d) which meets the criteria in Sec.  
60.5413a(d)(11) and Sec.  60.5413a(e) and used to comply with Sec.  
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 Sec.  
60.5413a(e) as specified in paragraphs (c)(5)(vi)(F)(1) through (4).
    (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 
Sec.  60.5416a(a)(1) and (a)(2) for centrifugal compressors, 
reciprocating compressors and pneumatic pumps, or Sec.  60.5416a(c)(1) 
for storage vessels.
    (7) A record of each cover inspection required under Sec.  
60.5416a(a)(3) for centrifugal or reciprocating compressors or Sec.  
60.5416a(c)(2) for storage vessels.
    (8) If you are subject to the bypass requirements of Sec.  
60.5416a(a)(4) for centrifugal compressors, reciprocating compressors 
or pneumatic pumps, or Sec.  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 Sec.  60.5416a(b) for centrifugal 
compressors, reciprocating compressors or pneumatic pumps, a record of 
the monitoring conducted in accordance with Sec.  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 Sec.  60.5413a(c)(2) or (3)) and 
records of each carbon replacement as specified in Sec.  
60.5412a(c)(1).
    (11) For each centrifugal compressor or pneumatic pump affected 
facility subject to the control device requirements of Sec.  
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

[[Page 56692]]

facilities, records of the schedule for carbon replacement (as 
determined by the design analysis requirements of Sec.  60.5412a(d)(2)) 
and records of each carbon replacement as specified in Sec.  
60.5412a(c)(1).
    (13) For each storage vessel affected facility subject to the 
control device requirements of Sec.  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 Sec.  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 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 Sec. Sec.  
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 
Sec.  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.
    (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 
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 Sec.  
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 Sec.  60.5413a(d) 
which meets the criteria in Sec.  60.5413a(d)(11) and Sec.  60.5413a(e) 
and used to comply with Sec.  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 Sec.  
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.
    (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.


Sec.  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 Sec.  60.486a.
    (b) The following recordkeeping requirements apply to pressure 
relief devices subject to the requirements of Sec.  60.5401a(b)(1) of 
this subpart.
    (1) When each leak is detected as specified in Sec.  
60.5401a(b)(2), a weatherproof and readily visible identification, 
marked with the equipment identification number, 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 Sec.  
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

[[Page 56693]]

by the methods specified in Sec.  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.
    (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 Sec.  
60.482-4a(a). The designation of equipment subject to the provisions of 
Sec.  60.482-4a(a) must be signed by the owner or operator.


Sec.  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 Sec.  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 language 
(XML) schema listed on the CEDRI Web site (https://www.epa.gov/ttn/chief/cedri/). 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 
Sec.  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 Sec.  60.487a(b)(1) through (4): Number of pressure relief devices 
subject to the requirements of Sec.  60.5401a(b) except for those 
pressure relief devices designated for no detectable emissions under 
the provisions of Sec.  60.482-4a(a) and those pressure relief devices 
complying with Sec.  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 Sec.  60.487a(c)(2)(i) through 
(vi):
    (1) Number of pressure relief devices for which leaks were detected 
as required in Sec.  60.5401a(b)(2); and
    (2) Number of pressure relief devices for which leaks were not 
repaired as required in Sec.  60.5401a(b)(3).


Sec.  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 Sec.  60.5405a(a) and (b) and Sec.  60.5407a(a) through (g) 
for at least 2 years following the date of the measurements. This 
requirement is included under Sec.  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 (https://www.epa.gov/ttn/chief/cedri/). 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 Sec.  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 Sec.  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 Sec.  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 
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 Sec.  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.


Sec.  60.5425a  What parts of the General Provisions apply to me?

    Table 3 to this subpart shows which parts of the General Provisions 
in Sec. Sec.  60.1 through 60.19 apply to you.


Sec.  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 square-mile area 
extending from the Brooks Range to the Arctic Ocean.

[[Page 56694]]

    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 guideline repair 
allowance, A, as reflected by the following equation: P = R x 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 x (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 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 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 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 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.
    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.

[[Page 56695]]

    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 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 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 Sec.  60.485a(e) or 
Sec.  60.5401a(f)(2) of this part.
    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.
    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 Joule-Thompson 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).
    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 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.

[[Page 56696]]

    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 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 Sec.  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
    (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
    (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.
    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 Sec.  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 Sec.  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 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.
    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

[[Page 56697]]

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.
    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 Sec.  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).
    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.
    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.


Sec. Sec.  60.5431a-60.5499a  [Reserved]

                          Table 1 to Subpart OOOOa of Part 60--Required Minimum Initial SO2 Emission Reduction Efficiency (Zi)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                        Sulfur feed rate (X), LT/D
         H2S content of acid gas (Y), %         --------------------------------------------------------------------------------------------------------
                                                    2.0300.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Y>50...........................................            79.0  88.51X\0.0101\Y\0.0125\ or 99.9, whichever is smaller.
                                                                ----------------------------------------------------------------------------------------
20300.0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Y>50...........................................            74.0  85.35X\0.0144\Y\0.0128\ or 99.9, whichever is smaller.
                                                                ----------------------------------------------------------------------------------------
20