[Federal Register Volume 81, Number 107 (Friday, June 3, 2016)]
[Rules and Regulations]
[Pages 35824-35942]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2016-11971]



[[Page 35823]]

Vol. 81

Friday,

No. 107

June 3, 2016

Part II





Environmental Protection Agency





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40 CFR Part 60





Oil and Natural Gas Sector: Emission Standards for New, Reconstructed, 
and Modified Sources; Final Rule

  Federal Register / Vol. 81 , No. 107 / Friday, June 3, 2016 / Rules 
and Regulations  

[[Page 35824]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 60

[EPA-HQ-OAR-2010-0505; FRL-9944-75-OAR]
RIN 2060-AS30


Oil and Natural Gas Sector: Emission Standards for New, 
Reconstructed, and Modified Sources

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: This action finalizes amendments to the current new source 
performance standards (NSPS) and establishes new standards. Amendments 
to the current standards will improve implementation of the current 
NSPS. The new standards for the oil and natural gas source category set 
standards for both greenhouse gases (GHGs) and volatile organic 
compounds (VOC). Except for the implementation improvements, and the 
new standards for GHGs, these requirements do not change the 
requirements for operations covered by the current standards.

DATES: This final rule is effective on August 2, 2016.
    The incorporation by reference (IBR) of certain publications listed 
in the regulations is approved by the Director of the Federal Register 
as of August 2, 2016.

ADDRESSES: The Environmental Protection Agency (EPA) has established a 
docket for this action under Docket ID No. EPA-HQ-OAR-2010-0505. All 
documents in the docket are listed on the http://www.regulations.gov 
Web site. Although listed in the index, some information is not 
publicly available, e.g., confidential business information (CBI) or 
other information whose disclosure is restricted by statute. Certain 
other material, such as copyrighted material, is not placed on the 
Internet and will be publicly available only in hard copy form. 
Publicly available docket materials are available electronically 
through http://www.regulations.gov.

FOR FURTHER INFORMATION CONTACT: For further information concerning 
this action, contact Ms. Amy Hambrick, 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) 541-0964; facsimile number: (919) 541-
3470; email address: [email protected] or Ms. Lisa Thompson, 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) 541-9775; 
facsimile number: (919) 541-3470; email address: [email protected]. 
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: [email protected].

SUPPLEMENTARY INFORMATION: Outline. The information presented in this 
preamble is presented as follows:

I. Preamble Acronyms and Abbreviations
II. General Information
    A. Executive Summary
    B. Does this action apply to me?
    C. Where can I get a copy of this document?
    D. Judicial Review
III. Background
    A. Statutory Background
    B. Regulatory Background
    C. Other Notable Events
    D. Stakeholder Outreach and Public Hearings
    E. Related State and Federal Regulatory Actions
IV. Regulatory Authority
    A. The Oil and Natural Gas Source Category Listing Under CAA 
Section 111(b)(1)(A)
    B. Impacts of GHGs, VOC and SO2 Emissions on Public 
Health and Welfare
    C. GHGs, VOC and SO2 Emissions From the Oil and 
Natural Gas Source Category
    D. Establishing GHG Standards in the Form of Limitations on 
Methane Emissions
V. Summary of Final Standards
    A. Control of GHG and VOC Emissions in the Oil and Natural Gas 
Source Category--Overview
    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
    K. Reconsideration Issues Being Addressed
    L. Technical Corrections and Clarifications
    M. Prevention of Significant Deterioration and Title V 
Permitting
    N. Final Standards Reflecting Next Generation Compliance and 
Rule Effectiveness
VI. Significant Changes Since Proposal
    A. Centrifugal Compressors
    B. Reciprocating Compressors
    C. Pneumatic Controllers
    D. Pneumatic Pumps
    E. Well Completions
    F. Fugitive Emissions From Well Sites and Compressor Stations
    G. Equipment Leaks at Natural Gas Processing Plants
    H. Reconsideration Issues Being Addressed
    I. Technical Corrections and Clarifications
    J. Final Standards Reflecting Next Generation Compliance and 
Rule Effectiveness
    K. Provision for Equivalency Determinations
VII. Prevention of Significant Deterioration and Title V Permitting
    A. Overview
    B. Applicability of Tailoring Rule Thresholds Under the PSD 
Program
    C. Implications for Title V Program
VIII. Summary of Significant Comments and Responses
    A. Major Comments Concerning Listing of the Oil and Natural Gas 
Source Category
    B. Major Comments Concerning EPA's Authority To Establish GHG 
Standards in the Form of Limitations on Methane Emissions
    C. Major Comments Concerning Compressors
    D. Major Comments Concerning Pneumatic Controllers
    E. Major Comments Concerning Pneumatic Pumps
    F. Major Comments Concerning Well Completions
    G. Major Comments Concerning Fugitive Emissions From Well Sites 
and Compressor Stations
    H. Major Comments Concerning Final Standards Reflecting Next 
Generation Compliance and Rule Effectiveness Strategies
IX. Impacts of the Final Amendments
    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 final standards?
X. 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

[[Page 35825]]

    K. Congressional Review Act (CRA)

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:

API American Petroleum Institute
bbl Barrel
boe Barrels of Oil Equivalent
BSER Best System of Emissions Reduction
BTEX Benzene, Toluene, Ethylbenzene and Xylenes
CAA Clean Air Act
CBI Confidential Business Information
CFR Code of Federal Regulations
CO2 Eq. Carbon dioxide equivalent
DCO Document Control Officer
EIA Energy Information Administration
EPA Environmental Protection Agency
GHG Greenhouse Gases
GHGRP Greenhouse Gas Reporting Program
GOR Gas to Oil Ratio
HAP Hazardous Air Pollutants
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
PRA Paperwork Reduction Act
PTE Potential to Emit
REC Reduced Emissions Completion
RFA Regulatory Flexibility Act
RIA Regulatory Impact Analysis
scf Standard Cubic Feet
scfh Standard Cubic Feet per Hour
scfm Standard Cubic Feet per Minute
SO2 Sulfur Dioxide
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. General Information

A. Executive Summary

1. Purpose of This Regulatory Action
    The Environmental Protection Agency (EPA) proposed amendments to 
the New Source Performance Standards (NSPS) at subpart OOOO and 
proposed new standards at subpart OOOOa on September 18, 2015 (80 FR 
56593). The purpose of this action is to finalize both the amendments 
and the new standards with appropriate adjustments after full 
consideration of the comments received on the proposal. Prior to 
proposal, we pursued a structured engagement process with states and 
stakeholders. Prior to that process, we issued draft white papers 
addressing a range of technical issues and then solicited comments on 
the white papers from expert reviewers and the public.
    These rules are designed to complement other federal actions as 
well as state regulations. In particular, the EPA worked closely with 
the Department of Interior's Bureau of Land Management (BLM) during 
development of this rulemaking in order to avoid conflicts in 
requirements between the NSPS and BLM's proposed rulemaking.\1\ 
Additionally, we evaluated existing state and local programs when 
developing these federal standards and attempted, where possible, to 
limit potential conflicts with existing state and local requirements.
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    \1\ 81 FR 6616, February 8, 2016, Waste Prevention, Production 
Subject to Royalties, and Resource Conservation, Proposed Rule.
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    As discussed at proposal, prior to this final rule, the EPA had 
established standards for emissions of VOC and sulfur dioxide 
(SO2) for several sources in the source category. In this 
action, the EPA finalizes standards at subpart OOOOa, based on our 
determination of the best system of emissions reduction (BSER) for 
reducing emissions of greenhouse gases (GHGs), specifically methane, as 
well as VOC across a variety of additional emission sources in the oil 
and natural gas source category (i.e., production, processing, 
transmission, and storage). The EPA includes requirements for methane 
emissions in this action because methane is one of the six well-mixed 
gases in the definition of GHGs and the oil and natural gas source 
category is one of the country's largest industrial 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.
    In addition to finalizing standards for VOC and GHGs, the EPA is 
finalizing amendments to improve several aspects of the existing 
standards at 40 CFR part 60, subpart OOOO related to implementation. 
These improvements and the setting of standards for GHGs in the form of 
limitations on methane result from 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). These implementation 
improvements do not change the requirements for operations and 
equipment covered by the current standards at subpart OOOO.
2. Summary of 40 CFR Part 60, Subpart OOOOa Major Provisions
    The final requirements include standards for GHG emissions (in the 
form of methane emission limitations) and standards for VOC emissions. 
The NSPS includes both VOC and GHG emission standards for certain new, 
modified, and reconstructed equipment, processes, and activities across 
the oil and natural gas source category. These emission sources include 
the following:
     Sources that are unregulated under the current NSPS at 
subpart OOOO (hydraulically fractured oil well completions, pneumatic 
pumps, and fugitive emissions from well sites and compressor stations);
     Sources that are currently regulated at subpart OOOO for 
VOC, but not for GHGs (hydraulically fractured gas well completions and 
equipment leaks at natural gas processing plants);
     Certain equipment that is used across the source category, 
for which the current NSPS at subpart OOOO regulates emissions of VOC 
from only a subset (pneumatic controllers, centrifugal compressors, and 
reciprocating compressors), with the exception of compressors located 
at well sites.
    Table 1 below summarizes these sources and the final standards for 
GHGs (in the form of methane limitations) and VOC emissions. See 
sections V and VI of this preamble for further discussion.

[[Page 35826]]



 Table 1--Summary of BSER and Final Subpart OOOOa Standards for Emission
                                 Sources
------------------------------------------------------------------------
                                                     Final standards of
           Source                     BSER          performance for GHGs
                                                           and VOC
------------------------------------------------------------------------
Wet seal centrifugal          Capture and route to  95 percent
 compressors (except for       a control device.     reduction.
 those located at well
 sites) \2\.
Reciprocating compressors     Regular replacement   Replace the rod
 (except for those located     of rod packing        packing on or
 at well sites) \2\.           (i.e.,                before 26,000 hours
                               approximately every   of operation or 36
                               3 years).             calendar months or
                                                     route emissions
                                                     from the rod
                                                     packing to a
                                                     process through a
                                                     closed vent system
                                                     under negative
                                                     pressure.
Pneumatic controllers at      Instrument air        Zero natural gas
 natural gas processing        systems.              bleed rate.
 plants.
Pneumatic controllers at      Installation of low-  Natural gas bleed
 locations other than          bleed pneumatic       rate no greater
 natural gas processing        controllers.          than 6 standard
 plants.                                             cubic feet per hour
                                                     (scfh).
Pneumatic pumps at natural    Instrument air        Zero natural gas
 gas processing plants.        systems in place of   emissions.
                               natural gas driven
                               pumps.
Pneumatic pumps at well       Route to existing     95 percent control
 sites.                        control device or     if there is an
                               process.              existing control or
                                                     process on site. 95
                                                     percent control not
                                                     required if
                                                    (1) routed to an
                                                     existing control
                                                     that achieves less
                                                     than 95 percent or
                                                    (2) it is
                                                     technically
                                                     infeasible to route
                                                     to the existing
                                                     control device or
                                                     process (non-
                                                     greenfield sites
                                                     only).
Well completions              Combination of        REC in combination
 (subcategory 1: Non-wildcat   Reduced Emission      with a completion
 and non-delineation wells).   Completion (REC)      combustion device;
                               and the use of a      venting in lieu of
                               completion            combustion where
                               combustion device.    combustion would
                                                     present safety
                                                     hazards.
                                                    Initial flowback
                                                     stage: Route to a
                                                     storage vessel or
                                                     completion vessel
                                                     (frac tank, lined
                                                     pit, or other
                                                     vessel) and
                                                     separator.
                                                    Separation flowback
                                                     stage: Route all
                                                     salable 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
                                                     onsite fuel source
                                                     or use for another
                                                     useful purpose that
                                                     a purchased fuel or
                                                     raw material would
                                                     serve. If
                                                     technically
                                                     infeasible to route
                                                     recovered gas as
                                                     specified above,
                                                     recovered gas must
                                                     be combusted. All
                                                     liquids must be
                                                     routed to a storage
                                                     vessel or well
                                                     completion vessel,
                                                     collection system,
                                                     or be re-injected
                                                     into the well or
                                                     another well.
                                                    The operator is
                                                     required to have a
                                                     separator onsite
                                                     during the entire
                                                     flowback period.
Well completions              Use of a completion   The operator is not
 (subcategory 2: Exploratory   combustion device.    required to have a
 and delineation wells and                           separator onsite.
 low pressure wells).                                Either: (1) Route
                                                     all flowback to a
                                                     completion
                                                     combustion device
                                                     with a continuous
                                                     pilot flame; or (2)
                                                     Route all 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.
                                                     Capture and direct
                                                     recovered gas to a
                                                     completion
                                                     combustion device
                                                     with a continuous
                                                     pilot flame.
                                                    For both options (1)
                                                     and (2), combustion
                                                     is not required 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.
Fugitive emissions from well  For well sites:       Monitoring and
 sites and compressor          Monitoring and        repair of fugitive
 stations.                     repair based on       emission components
                               semiannual            using OGI with
                               monitoring using      Method 21 as an
                               optical gas imaging   alternative at 500
                               (OGI) \3\.            parts per million
                                                     (ppm).
                              For compressor        A monitoring plan
                               stations:             must be developed
                               Monitoring and        and implemented and
                               repair based on       repair of the
                               quarterly             sources of fugitive
                               monitoring using      emissions must be
                               OGI.                  completed within 30
                                                     days of finding
                                                     fugitive emissions.

[[Page 35827]]

 
Equipment leaks at natural    Leak detection and    Follow requirements
 gas processing plants.        repair at 40 CFR      at NSPS part 60,
                               part 60, subpart      subpart VVa level
                               VVa level of          of control as in
                               control.              the 2012 NSPS.
------------------------------------------------------------------------

    Reconsiderationissues being addressed. As fully detailed in 
sections V and VI of this preamble and the Response to Comment (RTC) 
document, the EPA granted reconsideration of several issues raised in 
the administrative reconsideration petitions submitted on the 2012 NSPS 
and subsequent amendments (subpart OOOO). In this final rule, in 
addition to the new standards described above, the EPA includes certain 
amendments to the 2012 NSPS at subpart OOOO based on reconsideration of 
those issues. The amendments to the subpart OOOO requirements are 
effective on August 2, 2016 and, therefore, do not affect compliance 
activities completed prior to that date.
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    \2\ See sections VI and VIII of this preamble for detailed 
discussion on emission sources.
    \3\ The final fugitive standards apply to low production wells. 
For the reasons discussed in section VI of the preamble, we are not 
finalizing the proposed exemption of low production wells from these 
requirements.
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    These provisions are: Requirements for storage vessel control 
device monitoring and testing; initial compliance requirements for a 
bypass device that could divert an emission stream away from a control 
device; recordkeeping requirements for repair logs for control devices 
failing a visible emissions test; clarification of the due date for the 
initial annual report; flare design and operation standards; leak 
detection and repair (LDAR) for open-ended valves or lines; the 
compliance period for LDAR for newly affected units; exemption to the 
notification requirement for reconstruction; disposal of carbon from 
control devices; the definition of capital expenditure; and continuous 
control device monitoring requirements for storage vessels and 
centrifugal compressor affected facilities. We are finalizing changes 
to address these issues to clarify the current NSPS requirements, 
improve implementation, and update procedures.
3. Costs and Benefits
    The EPA has carefully reviewed the comments and additional data 
submitted on the costs and benefits associated with this rule. Our 
conclusion and responses are summarized in section IX of the preamble 
and addressed in greater detail in the Regulatory Impact Analysis (RIA) 
and RTC. The measures finalized in this action achieve reductions of 
GHG and VOC emissions through direct regulation and reduction of 
hazardous air pollutant (HAP) emissions as a co-benefit of reducing VOC 
emissions. The data show that these are cost-effective measures to 
reduce emissions and the rule's benefits outweigh these costs.
    The EPA has estimated emissions reductions, benefits, and costs for 
2 years of analysis: 2020 and 2025. Therefore, the emissions 
reductions, benefits, and costs by 2020 and 2025 (i.e., including all 
emissions reductions, costs, and benefits in all years from 2016 to 
2025) would be potentially significantly greater than the estimated 
emissions reductions, benefits, and costs provided within this rule. 
Actions taken to comply with the final NSPS are anticipated to prevent 
significant new emissions in 2020, including 300,000 tons of methane; 
150,000 tons of VOC; and 1,900 tons of HAP. The emission reductions 
anticipated in 2025 are 510,000 tons of methane; 210,000 tons of VOC; 
and 3,900 tons of HAP. Using a 100-year global warming potential (GWP) 
of 25, the carbon dioxide-equivalent (CO2 Eq.) methane 
emission reductions are estimated to be 6.9 million metric tons 
CO2 Eq. in 2020 and 11 million metric tons CO2 
Eq. in 2025. The methane-related monetized climate benefits are 
estimated to be $360 million in 2020 and $690 million in 2025 using a 
3-percent discount rate (model average).\4\
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    \4\ We estimate methane benefits associated with four different 
values of a 1 ton methane 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 a 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 IX and in the 
RIA.
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    While the only benefits monetized for this rule are GHG-related 
climate benefits from methane reductions, the rule will also yield 
benefits from reductions in VOC and HAP emissions and from reductions 
in methane as a precursor to global background concentrations of 
tropospheric ozone. The EPA was unable to monetize the benefits of VOC 
reductions due to the difficulties in modeling the impacts with the 
current data available. A detailed discussion of these unquantified 
benefits appears in section IX of this preamble, as well as in the RIA 
available in the docket.
    Several VOC that are commonly emitted in the oil and natural gas 
source category are HAP 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 
finalized in this action, are controlled to the same degree. The co-
benefit HAP reductions for the final measures are discussed in the RIA 
and in the technical support document (TSD), which are included in the 
public docket for this action.
    The HAP reductions from these standards will be meaningful in local 
communities, as members of these communities and other stakeholders 
across the country have reported significant concerns to the EPA 
regarding potential adverse health effects resulting from exposure to 
HAP emitted from oil and natural gas operations. Importantly, these 
communities include disadvantaged populations.
    The EPA estimates the total capital cost of the final NSPS will be 
$250 million in 2020 and $360 million in 2025. The estimate of total 
annualized engineering costs of the final NSPS is $390 million in 2020 
and $640 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 final NSPS are estimated to be $320 
million in 2020 and $530 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 16 billion cubic feet in 2020 and 27 billion cubic 
feet in 2025 of natural gas will be recovered by implementing the NSPS.
    Considering all the costs and benefits of this rule, including the 
revenues from

[[Page 35828]]

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 
million in 2020 and $170 million in 2025 using a 3-percent discount 
rate (model average) for climate benefits in both years.\5\ All dollar 
amounts are in 2012 dollars.
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    \5\ Figures may not sum due to rounding.
---------------------------------------------------------------------------

B. Does this action apply to me?

    Categories and entities potentially affected by this action 
include:

      Table 2--Industrial Source Categories Affected by This Action
------------------------------------------------------------------------
                                                  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 provides a 
guide for readers regarding entities likely to be regulated by this 
action. This table lists the types of entities that the EPA is now 
aware could potentially be affected by this action. Other types of 
entities not listed in the table could also be regulated. To determine 
whether your entity is regulated by this action, you should carefully 
examine the applicability criteria found in the final rule. If you have 
questions regarding the applicability of this action to a particular 
entity, consult the person listed in the FOR FURTHER INFORMATION 
CONTACT section, your air permitting authority, or your EPA Regional 
representative listed in 40 CFR 60.4 (General Provisions).

C. Where can I get a copy of this document?

    In addition to being available in the docket, an electronic copy of 
the final action is available on the Internet through the Technology 
Transfer Network (TTN) Web site. Following signature by the 
Administrator, the EPA will post a copy of this final action at http://www3.epa.gov/airquality/oilandgas/actions.html. The TTN provides 
information and technology exchange in various areas of air pollution 
control. Additional information is also available at the same Web site.

D. Judicial Review

    Under section 307(b)(1) of the CAA, judicial review of this final 
rule is available only by filing a petition for review in the United 
States Court of Appeals for the District of Columbia Circuit by August 
2, 2016. Moreover, under section 307(b)(2) of the CAA, the requirements 
established by this final rule may not be challenged separately in any 
civil or criminal proceedings brought by the EPA to enforce these 
requirements. Section 307(d)(7)(B) of the CAA further provides that 
``[o]nly an objection to a rule or procedure which was raised with 
reasonable specificity during the period for public comment (including 
any public hearing) may be raised during judicial review.'' This 
section also provides a mechanism for the EPA to convene a proceeding 
for reconsideration, ``[i]f the person raising an objection can 
demonstrate to the EPA that it was impracticable to raise such 
objection within [the period for public comment] or if the grounds for 
such objection arose after the period for public comment (but within 
the time specified for judicial review) and if such objection is of 
central relevance to the outcome of the rule.'' Any person seeking to 
make such a demonstration to us should submit a Petition for 
Reconsideration to the Office of the Administrator, U.S. EPA, Room 
3000, EPA WJC, 1200 Pennsylvania Ave. NW., Washington, DC 20460, with a 
copy to both the person(s) listed in the preceding FOR FURTHER 
INFORMATION CONTACT section, and the Associate General Counsel for the 
Air and Radiation Law Office, Office of General Counsel (Mail Code 
2344A), U.S. EPA, 1200 Pennsylvania Ave. NW., Washington, DC 20460.

III. Background

A. Statutory Background

    The EPA's authority for this rule is CAA section 111, which 
requires the EPA to first establish a list of source categories to be 
regulated under that section and then establish emission standards for 
new sources in that source category. Specifically, CAA section 
111(b)(1)(A) requires that a source category be included on the list 
if, ``in [the EPA Administrator's] judgment it causes, or contributes 
significantly to, air pollution which may reasonably be anticipated to 
endanger public health or welfare.'' This determination is commonly 
referred to as an ``endangerment finding'' and that phrase encompasses 
both of the ``causes or contributes significantly to'' component and 
the ``endanger public health or welfare'' component of the 
determination. Once a source category is listed, CAA section 
111(b)(1)(B) requires that the EPA propose and then promulgate 
``standards of performance'' for new sources in such source category. 
Other than the endangerment finding for listing the source category, 
CAA section 111(b) gives no direction or enumerated criteria concerning 
what constitutes a source category or what emission sources or 
pollutants from a given source category should be the subject of 
standards. Therefore, as long as the EPA makes the requisite 
endangerment finding for the source category to be listed, CAA section 
111 leaves the EPA with the authority and discretion to define the 
source category, determine the pollutants for which standards should be 
developed, and identify the emission sources within the source category 
for which standards of performance should 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 non-air quality health and 
environmental impact and energy requirement) the Administrator 
determines has been adequately demonstrated.'' This definition makes

[[Page 35829]]

clear that the standard of performance must be based on controls that 
constitute ``the best system of emission reduction . . . adequately 
demonstrated.''
    In determining whether a given system of emission reduction 
qualifies as a BSER, CAA section 111(a)(1) requires that the EPA take 
into account, among other factors, ``the cost of achieving such 
reduction.'' As described in section VIII.A of the proposal 
preamble,\6\ in several cases the DC Circuit has elaborated on this 
cost factor and formulated the cost standard in various ways, stating 
that the EPA may not adopt a standard the cost of which would be 
``exorbitant,'' \7\ ``greater than the industry could bear and 
survive,'' \8\ ``excessive,'' \9\ or ``unreasonable.'' \10\ For 
convenience, in this rulemaking, we use ``reasonableness'' to describe 
costs, which is well within the bounds established by this 
jurisprudence.
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    \6\ 80 FR 56593, 56616 (September 18, 2015).
    \7\ Lignite Energy Council v. EPA, 198 F.3d 930, 933 (D.C. Cir. 
1999).
    \8\ Portland Cement Ass'n v. EPA, 513 F.2d 506, 508 (D.C. Cir. 
1975).
    \9\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
    \10\ Sierra Club v. Costle, 657 F.2d 298, 343 (D.C. Cir. 1981).
---------------------------------------------------------------------------

    CAA Section 111(a) does not provide specific direction regarding 
what metric or metrics to use in considering costs, again affording the 
EPA considerable discretion in choosing a means of cost 
consideration.\11\ In this rulemaking, we evaluated whether a control 
cost is reasonable under a number of approaches that we find 
appropriate for assessing the types of controls at issue. Specifically, 
we considered a control's cost effectiveness under a ``single pollutant 
cost-effectiveness'' approach and a ``multipollutant cost-
effectiveness'' approach.\12\ We also evaluated costs on an industry 
basis by assessing the new capital expenditures (compared to overall 
capital expenditures) and the annual compliance costs (compared to 
overall annual revenue) if the rule were to require such control. For a 
detailed discussion of these cost approaches, please see section VIII.A 
of the proposal preamble.
---------------------------------------------------------------------------

    \11\ See, e.g., Husqvarna AB v. EPA, 254 F.3d 195, 200 (D.C. 
Cir. 2001) (where CAA section 213 does not mandate a specific method 
of cost analysis, the EPA may make a reasoned choice as to how to 
analyze costs).
    \12\ As discussed in the proposed rule preamble, we believe that 
both the single and multipollutant approaches are appropriate for 
assessing the reasonableness of the multipollutant controls 
considered in this action. The EPA has considered similar approaches 
in the past when considering multiple pollutants that are controlled 
by a given control option. See e.g., 73 FR 64079-64083 and EPA 
Document ID Nos. EPA-HQ-OAR-2004-0022-0622, EPA-HQ-OAR-2004-0022-
0447, EPA-HQ-OAR-2004-0022-0448.
---------------------------------------------------------------------------

    The standard that the EPA develops, based on the BSER, is commonly 
a numerical emissions limit, expressed as a performance level (in other 
words, a rate-based standard). As provided in CAA section 111(b)(5), 
the EPA does not prescribe a particular technological system that must 
be used to comply with a standard of performance. Rather, sources can 
select any measure or combination of measures that will achieve the 
emissions level of the standard.
    CAA section 111(h)(1) authorizes the Administrator to promulgate 
``a design, equipment, work practice, or operational standard, or 
combination thereof'' if in his or her judgment, ``it is not feasible 
to prescribe or enforce a standard of performance.'' CAA section 
111(h)(2) provides the circumstances under which prescribing or 
enforcing a standard of performance is ``not feasible'': Such as, when 
the pollutant cannot be emitted through a conveyance designed to emit 
or capture the pollutant, or when there is no practicable measurement 
methodology for the particular class of sources.
    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. As mentioned above, once the EPA lists a source category 
under CAA section 111(b)(1)(A), CAA section 111(b)(1)(B) provides the 
EPA discretion to determine the pollutants and sources to be regulated. 
In addition, concurrent with the 8-year review (and though not a 
mandatory part of the 8-year review), EPA may examine whether to add 
standards for pollutants or emission sources not currently regulated 
for that source category.

B. Regulatory Background

    In 1979, the EPA published a list of source categories, which 
include ``crude oil and natural gas production,'' for which the EPA 
would promulgate standards of performance under CAA 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 CAA 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, August 21, 1979; see also, 49 FR 2636-
37, January 20, 1984.
    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 SO2 emissions from natural 
gas processing plants (40 CFR part 60, subpart LLL). In 2012, pursuant 
to its duty under CAA 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 SO2 standards for sweetening units and 
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 40 CFR part 60, subparts 
KKK and LLL, 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, September 23, 2013, and 79 FR 79018, December 31, 2014). 
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.\13\
---------------------------------------------------------------------------

    \13\ In 2015, the EPA made further amendments to provisions 
relative to storage vessels and well completions (in particular low 
pressure wells). No judicial review or administrative 
reconsideration was sought for the 2015 amendments.
---------------------------------------------------------------------------

    In this rulemaking, the EPA is addressing a number of issues raised 
in the administrative reconsideration petitions.\14\ In addition to 
addressing the petitions requesting we reconsider our decision to defer 
regulation of GHGs, these topics, which mostly address implementation 
in 40 CFR part 60, subpart OOOO, are: Storage vessel control device 
monitoring and testing provisions; initial compliance requirements for 
a bypass device that

[[Page 35830]]

could divert an emission stream away from a control device; 
recordkeeping requirements for repair logs for control devices failing 
a visible emissions test; clarification of the due date for the initial 
annual report; 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.
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    \14\ The EPA intends to complete its reconsideration process in 
a subsequent notice.
---------------------------------------------------------------------------

C. Other Notable Events

    To provide relevant context to this final rule, EPA will discuss 
several notable events. First, in 2009 the EPA found that six well-
mixed GHGs--carbon dioxide (CO2), methane (CH4), 
nitrous oxide (N2O), hydrofluorocarbons (HFCs), 
perfluorocarbons (PFCs), and sulfur hexafluoride (SF6)--
endanger both the public health and the public welfare of current and 
future generations by causing or contributing to climate change. Oil 
and natural gas operations are significant emitters of methane. 
According to data from the Greenhouse Gas Reporting Program (GHGRP), 
oil and natural gas operations are the second largest stationary source 
of GHG emissions in the United States (when including both methane 
emissions and combustion-related GHG emissions at oil and natural gas 
facilities), second only to fossil fuel electricity generation. See 
section IV of this preamble which discusses, among other issues, this 
endangerment finding in more detail.
    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. Using information 
available at the time, the EPA also evaluated methane emissions and 
reductions during the 2012 NSPS rulemaking as a potential co-benefit of 
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 GHG emissions; the EPA 
noted the impending collection of a large amount of GHG emissions 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 was the subject of a number of petitions for judicial review 
and administrative reconsideration. Litigation is currently stayed 
pending the EPA's reconsideration process. Controlling methane 
emissions 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 included direction to 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.
    Fourth, as a follow-up to the 2013 Climate Action Plan, the 
Administration issued the Climate Action Plan: Strategy to Reduce 
Methane Emissions (the Methane Strategy) in March 2014. The focus on 
reducing methane emissions reflects the fact that methane is a potent 
GHG with a 100-year GWP that is 28-36 times greater than that of carbon 
dioxide.\15\ The GWP is a measure of how much additional energy the 
earth will absorb over 100 years as a result of emissions of a given 
gas, in relation to carbon dioxide. 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 white papers were released in April 2014 and are discussed 
in more detail in section III.D of this preamble.16 17
---------------------------------------------------------------------------

    \15\ 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. For the analysis supporting this regulation, we used the 
methane 100-year GWP of 25 to be consistent with and comparable to 
key Agency emission quantification programs such as the Inventory of 
Greenhouse Gas Emissions and Sinks (GHG Inventory), and the 
Greenhouse Gas Reporting Program (GHGRP). For more information see 
Preamble section Methane Emissions in the United States and from the 
Oil and Natural Gas Industry.
    \16\ http://www.epa.gov/airquality/oilandgas/methane.html.
    \17\ Public comments on the white papers are available in the 
EPA's nonregulatory docket at http://www.regulations.gov, Docket ID 
No. EPA-HQ-OAR-2014-0557.
---------------------------------------------------------------------------

    Finally, following the Climate Action Plan and the Methane 
Strategy, in January 2015, the Administration announced a new goal to 
cut methane emissions from the oil and gas sector by 40 to 45 percent 
from 2012 levels by 2025 and steps to put the United States 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 
the EPA to address, and if appropriate, propose and set standards for 
methane and ozone-forming emissions from new and modified sources and 
to issue Control Technique Guidelines (CTG) to assist states in 
reducing ozone-forming pollutants from existing oil and natural gas 
systems in areas that do not meet the health-based standard for ozone.

D. Stakeholder Outreach and Public Hearings

1. White Papers
    As mentioned, the Methane Strategy was released in March 2014, as a 
follow-up to the 2013 Climate Action Plan, and directed 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 
the peer review process was completed on June 16, 2014.
    The peer review, consisting of 26 sets of comments and more than 
43,000 public comment submissions on the white papers, included 
additional technical information that further clarified our 
understanding of the emission sources and emission control options.\18\ 
The comments also provided additional data on emissions and the 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 that are presented in the TSD to this final 
rule.
---------------------------------------------------------------------------

    \18\ The comments received from the peer reviewers are available 
on the EPA's oil and natural gas white paper Web site (http://www.epa.gov/airquality/oilandgas/methane.html). Public comments on 
the white papers are available in the EPA's nonregulatory docket at 
www.regulations.gov, docket ID #EPA-HQ-OAR-2014-0557.
---------------------------------------------------------------------------

2. Outreach to State, Local and Tribal Governments
    Throughout the rulemaking process, the EPA collaborated with state, 
local, and tribal governments to hear how they have managed regulatory 
issues and to receive feedback that would help us develop the rule. As 
discussed in the

[[Page 35831]]

proposal, 12 states, three tribes, and several local air districts 
participated in several teleconferences in March and April 2015. The 
EPA hosted additional teleconferences in September 2015 with the same 
group of states, tribes, and air districts that the EPA spoke with 
earlier in the year. In September 2015, the EPA also hosted a webinar 
series with states, tribes, and interested communities to provide an 
overview of the proposed rule and an opportunity to ask clarifying 
questions on the proposal.\19\
---------------------------------------------------------------------------

    \19\ See 80 FR 56609, September 18, 2015.
---------------------------------------------------------------------------

    The EPA specifically 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 spoke with tribal stakeholders 
throughout the rulemaking process and updated the National Tribal Air 
Association on the Methane Strategy. Consistent with previous actions 
affecting the oil and natural gas sector, significant tribal interest 
exists because of the growth of oil and natural gas production in 
Indian country.
3. Public Hearings
    The EPA hosted three public hearings on the proposed rule in 
September 2015.\20\ The public hearings addressed this rule's proposal 
and two related actions.\21\ All combined, approximately 329 people 
gave verbal testimony. The transcripts and written comments collected 
at the hearings are in the public docket for this final rule.\22\
---------------------------------------------------------------------------

    \20\ See 80 FR 51991, August 27, 2015.
    \21\ Source Determination for Certain Emission Units in the Oil 
and Natural Gas Sector; Review of New Sources and Modifications in 
Indian Country: Federal Implementation Plan for Managing Air 
Emissions from True Minor Sources Engaged in Oil and Natural Gas 
Production in Indian Country.
    \22\ See EPA Docket ID No. EPA-HQ-OAR-2010-0505.
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E. Related State and Federal Regulatory Actions

    As mentioned, these rules are designed to complement current state 
and other federal regulations. We carefully evaluated existing state 
and local programs when developing these federal standards and 
attempted, where possible, to limit potential conflicts with existing 
state and local requirements. We recognize that, in some cases, these 
federal rules may be more stringent than existing programs and, in 
other cases, may be less stringent than existing programs. We received 
over 900,000 comments on the proposed rule. After careful consideration 
of the comments, we are finalizing the standards with revisions where 
appropriate to reduce emissions of harmful air pollutants, promote gas 
capture and beneficial use, and provide opportunity for flexibility and 
expanded transparency in order to yield a consistent and accountable 
national program that provides a clear path for states and other 
federal agencies to further align their programs.
    During development of these NSPS requirements, we were mindful that 
some facilities that will be subject to the 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.\23\ To minimize confusion and unnecessary 
burden on the part of owners and operators, the EPA and the BLM have 
maintained an ongoing dialogue during development of this action to 
identify opportunities for aligning requirements and will continue to 
coordinate through BLM's final rulemaking and through the agencies' 
implementation of their respective rules. While we intend for our rule 
to complement the BLM's action, it is important to recognize that the 
EPA and the BLM are each operating under different statutory 
authorities and mandates in developing and implementing their 
respective rules.
---------------------------------------------------------------------------

    \23\ See 81 FR 6616, February 8, 2016.
---------------------------------------------------------------------------

    In addition to this final rule, the EPA is working to finalize 
other related actions. The EPA will finalize the Source Determination 
for Certain Emissions Units in the Oil and Natural Gas Sector rule, 
which will clarify the EPA's air permitting rules as they apply to the 
oil and natural gas industry. Additionally, the EPA plans to finalize 
the federal implementation plan for the EPA's Indian Country Minor New 
Source Review (NSR) program for oil and natural gas production sources 
and natural gas processing sources, which will require compliance with 
various federal regulations and streamline the permitting process for 
this rapidly growing industry in Indian country. Lastly, the EPA will 
also issue Control Techniques Guidelines (CTG) for reducing VOC 
emissions from existing oil and gas sources in certain ozone 
nonattainment areas and states in the Ozone Transport Region. This 
suite of requirements together will help combat climate change, reduce 
air pollution that harms public health, and provide greater certainty 
about CAA permitting requirements for the oil and natural gas industry.
    Other related programs include the EPA's GHGRP, which requires 
annual reporting of GHG data and other relevant information from large 
sources and suppliers in the United States. On October 30, 2009, the 
EPA published 40 CFR part 98 for collecting information regarding GHG 
emissions from a broad range of industry sectors (74 FR 56260). 
Although reporting requirements for petroleum and natural gas systems 
(40 CFR part 98, subpart W) were originally proposed to be part of 40 
CFR part 98 (75 FR 16448, April 10, 2009), the final October 2009 rule 
did not include the petroleum and natural gas systems source category 
as one of the 29 source categories for which reporting requirements 
were finalized. The EPA reproposed subpart W in 2010 (79 FR 18608, 
April 12, 2010), and a subsequent final rule was published on November 
30, 2010, with the requirements for the petroleum and natural gas 
systems source category at 40 CFR part 98, subpart W (75 FR 74458). 
Following promulgation, the EPA finalized actions revising subpart W 
(76 FR 22825, April 25, 2011; 76 FR 59533, September 27, 2011; 76 FR 
80554, December 23, 2011; 77 FR 51477, August 24, 2012; 78 FR 25392, 
May 1, 2013; 78 FR 71904, November 29, 2013; 79 FR 63750, October 24, 
2014; 79 FR 70352, November 25, 2014; 80 FR 64262, October 22, 2015).
    40 CFR part 98, subpart W includes a wide range of operations and 
equipment, from wells to processing facilities, to transmission and 
storage and through to distribution pipelines. Subpart W consists of 
emission sources in the following segments of the petroleum and natural 
gas industry: Onshore petroleum and natural gas production, offshore 
petroleum and natural gas production, onshore petroleum and natural gas 
gathering and boosting, onshore natural gas processing plants, onshore 
natural gas transmission compression, onshore natural gas transmission 
pipeline, underground natural gas storage, liquefied natural gas 
storage, liquefied natural gas import and export equipment, and natural 
gas distribution.
    On March 10, 2016, the EPA announced the next step in reducing 
emissions of GHGs, specifically methane, from the oil and natural gas 
industry: Moving to regulate emissions from existing sources. The 
Agency will begin with a formal process to require companies operating 
existing oil and gas sources to provide information to assist in the 
development of comprehensive

[[Page 35832]]

regulations to reduce GHG emissions.\24\ An Information Collection 
Request (ICR) will enable the EPA to gather important information on 
existing sources of GHG emissions, technologies to reduce those 
emissions, and the costs of those technologies in the production, 
gathering, processing, and transmission and storage segments of the oil 
and natural gas sector. There are hundreds of thousands of existing oil 
and natural gas sources across the country; some emit small amounts of 
GHGs, but others emit very large quantities. Through the ICR, the EPA 
will be seeking a broad range of information that will help us 
determine how to effectively reduce emissions, including information 
such as how equipment and emissions controls are, or can be, 
configured, and what installing those controls entails. The EPA will 
also be seeking information that will help the Agency identify sources 
with high emissions and the factors that contribute to those emissions. 
The ICR will likely apply to the same types of sources covered by the 
40 CFR part 60, subparts OOOO and OOOOa, as well as additional sources.
---------------------------------------------------------------------------

    \24\ https://www3.epa.gov/airquality/oilandgas/pdfs/20160310fs.pdf.
---------------------------------------------------------------------------

IV. Regulatory Authority

    In this section, we describe our authority under CAA section 111(b) 
to regulate emissions from operations and equipment used across the oil 
and natural gas industry.

A. The Oil and Natural Gas Source Category Listing Under CAA Section 
111(b)(1)(A)

    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''). The 
EPA published the 1979 Priority List as directed by a then new section 
111(f) under the CAA amendments of 1977. Clean Air Act section 111(f) 
set a schedule for the EPA to promulgate regulations under CAA section 
111(b)(1)(A); listing ``categories of major stationary sources'' and 
establishing standards of performance for the listed source categories 
in the order of priority as determined by the criteria set forth in CAA 
section 111(f). The 1979 Priority List included, in the order of 
priority for promulgating standards, source categories that the EPA 
Administrator had determined, pursuant to CAA 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, 
August 21, 1979; see also 49 FR 2636-37, January 20, 1984. In 
developing the 1979 Priority List, the EPA first analyzed the data to 
identify ``major source categories'' and then ranked them in the order 
of priority for setting standards. Id. Although the EPA defined a 
``major source category'' in that listing action as ``those categories 
for which an average size plant has the potential to emit 100 tons or 
more per year of any one pollutant,'' \25\ the EPA provided notice in 
that action that ``certain new sources of smaller than average size 
within these categories may have less than a 100 ton per year emission 
potential.'' 43 FR 38872, 38873 (August 31, 1978). The EPA thus made 
clear that sources included within the listed source categories in the 
1979 Priority List were not limited to sources that emit at or above 
the 100 ton level. The EPA's decision to not exclude smaller sources in 
the 1979 Priority List was consistent with CAA section 111(b), the 
statutory authority for that listing action and the required standard 
setting to follow. In requiring that the EPA list source categories and 
establish standards for the new sources within the listed source 
categories, CAA section 111(b) does not distinguish between ``major'' 
or other sources. Similarly, as an example, CAA section 111(e), which 
prohibits violation of an applicable standard upon its effective date, 
applies to ``any new source,'' not just major new sources.
---------------------------------------------------------------------------

    \25\ 44 FR 49222, August 21, 1979.
---------------------------------------------------------------------------

    As mentioned above, one of the source categories listed in that 
1979 Priority List generally covers the oil and natural gas industry. 
Specifically, with respect to the natural gas industry, it includes 
production, processing, transmission, and storage. The 1979 Priority 
List broadly covered the natural gas industry,\26\ which was evident in 
the EPA's analysis at the time of listing.\27\ For example, the 
priority list analysis indicated that the EPA evaluated emissions from 
various segments of the natural gas industry, such as production and 
processing. 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 scope of the 1979 Priority 
List is further demonstrated 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 2637, January 20, 1984. In addition, the EPA identified emission 
points not covered by that rulemaking, such as ``well systems field oil 
and gas separators, wash tanks, settling tanks and other sources.'' Id. 
The EPA explained in that action that it could not regulate these 
emissions at that time because ``best demonstrated control technology 
has not been identified.'' Id.
---------------------------------------------------------------------------

    \26\ 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.
    \27\ 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).
---------------------------------------------------------------------------

    The inclusion of various segments of the natural gas industry into 
the source category listed in 1979 is consistent with this industry's 
operations and equipment. 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.\28\ 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, 
pneumatic pumps, 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 1979 Priority List broadly 
includes the various segments of the natural gas

[[Page 35833]]

industry (production, processing, transmission, and storage).
---------------------------------------------------------------------------

    \28\ 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 issuing the 1979 Priority List, which broadly covers the oil 
and natural gas industry as explained above, the EPA has promulgated 
performance standards to regulate SO2 emissions from natural 
gas processing and VOC emissions from certain operations and equipment 
in this industry. In this action, the EPA is regulating an additional 
pollutant (i.e., GHGs) as well as additional sources from this 
industry.
    As explained above, the EPA, in 1979, determined under section 
111(b)(1)(A) that the listed oil and natural gas source category 
contributes significantly to air pollution that may reasonably be 
anticipated to endanger public health or welfare. Therefore, the 1979 
listing of this source category provides sufficient authority for this 
action. The listed oil and natural gas source category includes oil 
\29\ and natural gas production, processing, transmission, and storage. 
For the reasons stated above, the EPA believes that the 1979 listing of 
this source category provides sufficient authority for this action. 
However, to the extent that there is any ambiguity in the prior 
listing, the EPA hereby finalizes, as an alternative, its proposed 
revision of the category listing to broadly include the oil and natural 
gas industry. As revised, the listed oil and natural gas source 
category includes oil \30\ and natural gas production, processing, 
transmission, and storage. In support, the EPA has included in this 
action the requisite finding under section 111(b)(1)(A) that, in the 
Administrator's judgment, this source category, as defined above, 
contributes significantly to air pollution which may reasonably be 
anticipated to endanger public health or welfare.
---------------------------------------------------------------------------

    \29\ For the oil industry, the listing includes production, as 
explained above in footnote 27.
    \30\ For the oil industry, the listing includes production, as 
explained above in footnote 27.
---------------------------------------------------------------------------

    To be clear, the EPA's view is that no revision is required for the 
standards established in this final rule. But even assuming it is, for 
the reason stated below, there is ample evidence that this source 
category as a whole (oil and natural gas production, processing, 
transmission, and storage) contributes significantly to air pollution 
that may reasonably be anticipated to endanger public health and 
welfare.
    First, through the 1979 Priority List, the EPA determined that the 
oil and natural gas industry contributes significantly to air pollution 
which may reasonably be anticipated to endanger public health or 
welfare. To the extent that the EPA's 1979 determination looked only at 
certain emissions sources in the industry, clearly the much greater 
emissions from the broader source category, as defined under a revised 
listing, would provide even more support for a conclusion that 
emissions from this category endanger public health or welfare. In 
addition, the EPA has included immediately below information and 
analyses regarding public health and welfare impacts from GHGs, 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 and welfare. 
Therefore, to the extent such a finding were necessary, pursuant to 
section 111(b)(1)(A), the Administrator hereby determines that, in her 
judgment, this source category, as defined above, contributes 
significantly to air pollution which may reasonably be anticipated to 
endanger public health or welfare.
    Provided below are the supporting information and analyses 
referenced above. Specifically, section IV.B of this preamble describes 
the public health and welfare impacts from GHGs, VOC and 
SO2. Section IV.C of this preamble analyzes the emission 
contribution of these three pollutants by the oil and natural gas 
industry.

B. Impacts of GHGs, 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, nitrogen oxides (NOX), hydrogen sulfide 
(H2S), carbon disulfide (CS2) and carbonyl 
sulfide (COS). See 49 FR 2636, 2637 (January 20, 1984). Although all of 
these pollutants have significant impacts on public health and welfare, 
an analysis of every one of these pollutants is not necessary for the 
Administrator to make a determination under CAA section 111(b)(1)(A); 
as shown below, the EPA's analysis of GHGs, VOC, and SO2, 
three of the primary emissions from the oil and natural gas source 
category, is sufficient for the Administrator to determine under CAA 
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.\31\
---------------------------------------------------------------------------

    \31\ We note that the 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 in the future that such 
action is appropriate.
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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).\32\ In the 2009 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 the 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.
---------------------------------------------------------------------------

    \32\ ``Endangerment and Cause or Contribute Findings for 
Greenhouse Gases Under Section 202(a) of the Clean Air Act,'' 74 FR 
66496 (December 15, 2009) (``2009 Endangerment Finding'').
---------------------------------------------------------------------------

a. Public Health Impacts Detailed in the 2009 Endangerment Finding
    Climate change caused by manmade 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 United States, 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 manmade emissions of GHGs, climate 
changes are

[[Page 35834]]

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 
United States ecosystems over the 21st century. Though some benefits 
may help 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 United States food production, agriculture, 
and forest productivity as temperatures continue to rise. These impacts 
are global and may exacerbate problems outside the United States that 
raise humanitarian, trade, and national security issues for the United 
States.
c. New Scientific Assessments and Observations
    Since the administrative record concerning the 2009 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, methane and other GHG 
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), 
United States Global Change Research Program (USGCRP), and National 
Research Council (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 United 
States 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 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 increased temperature lengthens the 
allergenic pollen season for ragweed and that increased CO2 
by itself elevates 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.'' \33\ In addition, 
increasing temperatures and loss of Arctic sea ice increases the risk 
of drowning for those engaged in traditional hunting and fishing.
---------------------------------------------------------------------------

    \33\ 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 also finds 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 that the elderly will face. Older people are at 
much higher risk of mortality during extreme heat events. Pre-existing 
health conditions also make older adults more susceptible to cardiac 
and respiratory impacts of air pollution and to more severe 
consequences from infectious

[[Page 35835]]

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, 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.'' \34\ 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, ``[a]s 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 to 4 meters (m) of 
potential sea level rise) as an abrupt climate impact with unknown but 
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 weather 
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.
---------------------------------------------------------------------------

    \34\ National Research Council, Understanding Earth's Deep Past, 
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[emsp14][deg]Celsius to 4.8[emsp14][deg]Celsius (4.7[deg] to 
8.6[emsp14][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 the amount of rainfall may not change significantly when 
looked at from the standpoint of global and annual averages, there are 
expected to be substantial shifts in where and when that precipitation 
falls. According to the NCA3, regions closer to the poles will see more 
precipitation while the dry subtropics are expected to expand 
(colloquially, this has been summarized as wet areas getting wetter and 
dry regions getting drier). In particular, the NCA3 notes that the 
western United States, 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 NCA3, 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[emsp14][deg]Celsius 
(1.8[emsp14][deg]Fahrenheit) of warming. For 3[emsp14][deg]Celsius of 
warming, the assessment found that nine 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 NCA3 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. This is 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. 
An 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,'' \35\ and the NRC 
Climate Stabilization Targets assessment states that an increase of 
3[emsp14][deg]Celsius 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: It 
is possible that the ice sheets could melt more quickly than expected, 
leading to more sea level rise than currently projected. Additionally, 
local sea level rise can differ from the global total depending on 
various factors: The east coast of the United States 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

[[Page 35836]]

storm surges.'' \36\ Also, because of the inertia of the oceans, sea 
level rise will continue for centuries after GHG concentrations have 
stabilized (though reducing GHG emissions will slow the rate of sea 
level rise and, therefore, reduce the associated risks and impacts). 
Additionally, there is a threshold temperature above which the 
Greenland ice sheet will be committed to inevitable melting: According 
to the NCA3, some recent research has suggested that even present day 
CO2 levels could be sufficient to exceed that threshold.
---------------------------------------------------------------------------

    \35\ NRC, 2011: National Security Implications of Climate Change 
for U.S. Naval Forces. The National Academies Press, p. 28.
    \36\ 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. United States 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.'' \37\ 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.'' \38\
---------------------------------------------------------------------------

    \37\ 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. United States Global Change 
Research Program, p. 17.
    \38\ 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.
---------------------------------------------------------------------------

    The impacts of climate change outside the United States, as also 
pointed out in the 2009 Endangerment Finding, will also have relevant 
consequences on the United States and our citizens. 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 manmade emissions of GHGs is already happening now and 
that it is currently having effects 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[emsp14][deg]Celsius (1.5[emsp14][deg]Fahrenheit) from 1880 to 
2012. It is extremely likely (greater than 95-percent probability) that 
human influence was the dominant cause of the observed warming since 
the mid-20th century, and likely (greater than 66-percent 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 
1,400 years. United States average temperatures have similarly 
increased by 1.3[deg] to 1.9[emsp14][deg]F since 1895, with most of 
that increase occurring since 1970. Global sea levels rose 0.19 meters 
(7.5 inches) from 1901 to 2010. Contributing to this rise was the 
warming of the oceans and melting of land ice. It is likely that 275 
gigatons per year of ice melted from land glaciers (not including ice 
sheets) since 1993, and that the rate of loss of ice from the Greenland 
and Antarctic ice sheets increased substantially in recent years, to 
215 gigatons per year and 147 gigatons per year, respectively, since 
2002. For context, 360 gigatons of ice melt is sufficient to cause 
global sea levels to rise 1 millimeter (mm). Annual mean Arctic sea ice 
has been declining at 3.5 to 4.1 percent per decade, and Northern 
Hemisphere snow cover extent has decreased at about 1.6 percent per 
decade for March and 11.7 percent per decade for June. Permafrost 
temperatures have increased in most regions since the 1980s by up to 
3[emsp14][deg]Celsius (5.4[emsp14][deg]Fahrenheit) 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 
National Oceanic and Atmospheric Administration (NOAA), atmospheric 
methane concentrations in 2014 were about 1,823 parts per billion, 150 
percent higher than methane concentrations were in the year 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 to 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.\39\ Also, 2015 
was the warmest year globally in the modern global surface temperature 
record, going back to 1880, breaking the record previously held by 
2014; this now means that the last 15 years have been 15 of the 16 
warmest years on record.\40\
---------------------------------------------------------------------------

    \39\ Blunden, J., and D.S. Arndt, Eds., 2015: State of the 
Climate in 2014. Bull. Amer. Meteor. Soc., 96 (7), S1-S267.
    \40\ http://www.ncdc.noaa.gov/sotc/global/201513.
---------------------------------------------------------------------------

    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.'' \41\ For 
example:
---------------------------------------------------------------------------

    \41\ 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

[[Page 35837]]

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 manifested, 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, which can cause 
a number of harmful effects on health and the environment (see section 
IV.B.2 of this preamble). 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.\42\ Approximately 
50 percent of the global annual mean ozone increase since preindustrial 
times is believed to be due to anthropogenic methane.\43\ Projections 
of future emissions also indicate that methane is likely to be a key 
contributor to ozone concentrations in the future.\44\ Unlike 
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.\45\ Reducing methane emissions, therefore, will contribute 
to efforts to reduce global background ozone concentrations that 
contribute to the incidence of ozone-related health 
effects.46 47 48 The benefits of such reductions are global 
and occur in both urban and rural areas.
---------------------------------------------------------------------------

    \42\ U.S. EPA. 2013. ``Integrated Science Assessment for Ozone 
and Related Photochemical Oxidants (Final Report).'' EPA-600-R-10-
076F. National Center for Environmental Assessment--RTP Division. 
Available at http://www.epa.gov/ncea/isa/.
    \43\ 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.
    \44\ Ibid.
    \45\ Ibid.
    \46\ West, J.J., Fiore, A.M. 2005. ``Management of tropospheric 
ozone by reducing methane emissions.'' Environ. Sci. Technol. 
39:4685-4691.
    \47\ Anenberg, S.C., et al. 2009. ``Intercontinental impacts of 
ozone pollution on human mortality,'' Environ. Sci. & Technol. 43: 
6482-6487.
    \48\ Sarofim, M.C., Waldhoff, S.T., Anenberg, S.C. 2015. 
``Valuing the Ozone-Related Health Benefits of Methane Emission 
Controls,'' Environ. Resource Econ. DOI 10.1007/s10640-015-9937-6.
---------------------------------------------------------------------------

2. VOC
    Many VOC can be classified as HAP (e.g., benzene \49\) which can 
lead to a variety of health concerns such as cancer and noncancer 
illnesses (e.g., respiratory, neurological). Further, VOC are one of 
the key precursors in the formation of ozone. 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 precursors 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 United States, 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.\50\
---------------------------------------------------------------------------

    \49\ Benzene IRIS Assessment: https://cfpub.epa.gov/ncea/iris2/chemicalLanding.cfm?substance_nmbr=276.
    \50\ National Health Interview Survey (NHIS) Data, 2011. http://www.cdc.gov/asthma/nhis/2011/data.htm.
---------------------------------------------------------------------------

    Scientific evidence also shows that repeated exposure to ozone can 
reduce growth and have other harmful effects on sensitive plants and 
trees. These types of effects have the potential to impact ecosystems 
and the benefits they provide.
3. SO2
    Current scientific evidence links short-term exposures to 
SO2, ranging from 5 minutes to 24 hours, with an array of 
adverse respiratory effects including bronchoconstriction and increased 
asthma symptoms. These effects are particularly important for 
asthmatics at elevated ventilation rates (e.g., while exercising or 
playing).
    Studies also show an association between short-term exposure and 
increased visits to emergency departments and hospital admissions for 
respiratory illnesses, particularly in at-risk populations including 
children, the elderly, and asthmatics.
    SO2 in the air can also damage the leaves of plants, 
decrease their ability to produce food--photosynthesis--and 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.\51\
---------------------------------------------------------------------------

    \51\ U.S. EPA. Intergrated Science Assessment (ISA) for Oxides 
of Nitrogen and Sulfur Ecological Criteria (2008 Final Report). U.S. 
Envieronmental Protection Agency, Washington, DC, EPA/600/R-08/082F, 
2008.
---------------------------------------------------------------------------

C. GHGs, VOC and SO2 Emissions From the Oil and Natural Gas 
Source Category

    The previous section explains how GHGs, VOCs, and SO2 
emissions are ``air pollution'' that may reasonably be anticipated to 
endanger public health and welfare. This section provides estimated 
emissions of these substances from the oil and natural gas source 
category.
1. 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. For the analysis supporting this 
regulation, we used the methane 100-year GWP of 25 to be consistent 
with and comparable to key Agency emission quantification programs such 
as the Inventory of United States Greenhouse Gas Emissions and Sinks 
(GHG Inventory), and the GHGRP.\52\ The use of the 100-year GWP of 25 
for methane value is currently required by the United Nations Framework 
Convention on Climate Change (UNFCCC) for reporting of national 
inventories, such as the United States GHG Inventory.

[[Page 35838]]

Updated estimates for methane GWP have been developed by IPCC 
(2013).\53\ The most recent 100-year GWP estimates for methane range 
from 28 to 36. In discussing the science and impacts of methane 
emissions generally, here we use the GWP range of 28 to 36. When 
presenting emissions estimates, we use the GWP of 25 for consistency 
and comparability with other emissions estimates in the United States 
and internationally. Methane has an atmospheric life of about 12 years.
---------------------------------------------------------------------------

    \52\ See, for example, Table A-1 to subpart A of 40 CFR part 98.
    \53\ 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, 
1535pp.
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    Official United States estimates of national level GHG emissions 
and sinks are developed by the EPA for the United States GHG Inventory 
to comply with commitments under the UNFCCC. The United States GHG 
Inventory, which includes recent trends, is organized by industrial 
sectors. Natural gas and petroleum systems are the largest emitters of 
methane in the United States. These systems emit 32 percent of United 
States anthropogenic methane.
    Table 3 below presents total United States anthropogenic methane 
emissions for the years 1990, 2005, and 2014.

                               Table 3--United States Methane Emissions by Sector
                          [Million metric ton carbon dioxide equivalent (MMT CO2 Eq.)]
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2005            2014
----------------------------------------------------------------------------------------------------------------
Oil and Natural Gas Production, and Natural Gas Processing and               201             203             232
 Transmission...................................................
Landfills.......................................................             180             154             148
Enteric Fermentation............................................             164             169             164
Coal Mining.....................................................              96              64              68
Manure Management...............................................              37              56              61
Other Methane Sources \54\......................................              95              71              57
                                                                 -----------------------------------------------
    Total Methane Emissions.....................................             774             717             731
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15,
  2016), calculated using GWP of 25. Note: Totals may not sum due to rounding.

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

    \54\ 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 Eq. 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.
    Tables 4 (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 2014, in MMT CO2 Eq. 
(Table 4 (a)) and kilotons (or thousand metric tons) of methane (Table 
4 (b)).

               Table 4(a)--United States Methane Emissions From Natural Gas and Petroleum Systems
                                                    [MMT CO2]
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2005            2014
----------------------------------------------------------------------------------------------------------------
Oil and Natural Gas Production and Natural Gas Processing and                201             203             232
 Transmission (Total)...........................................
Natural Gas Production..........................................              83             108             109
Natural Gas Processing..........................................              21              16              24
Natural Gas Transmission and Storage............................              59              31              32
Petroleum Production............................................              38              48              67
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15,
  2016), calculated using GWP of 25. Note: Totals may not sum due to rounding.


[[Page 35839]]


               Table 4(b)--United States Methane Emissions From Natural Gas and Petroleum Systems
                                                    [kt CH4]
----------------------------------------------------------------------------------------------------------------
                             Sector                                    1990            2005            2014
----------------------------------------------------------------------------------------------------------------
Oil and Natural Gas Production and Natural Gas Processing and              8,049           8,131           9,295
 Transmission (Total)...........................................
Natural Gas Production..........................................           3,335           4,326           4,359
Natural Gas Processing..........................................             852             655             960
Natural Gas Transmission and Storage............................           2,343           1,230           1,282
Petroleum Production............................................           1,519           1,921           2,694
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15,
  2016), in kt (1,000 tons) of CH4. Note: Totals may not sum due to rounding.

2. United States Oil and Natural Gas Production and Natural Gas 
Processing and Transmission GHG Emissions Relative to Total United 
States GHG Emissions
    Relying on data from the United States GHG Inventory, we compared 
United States oil and natural gas production and natural gas processing 
and transmission GHG emissions to total United States 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 
2014, total United States GHG emissions from all sources were 6,871 MMT 
CO2 Eq.

Table 5--Comparisons of United States Oil and Natural Gas Production and Natural Gas Processing and Transmission
                               CH4 Emissions to Total United States GHG Emissions
----------------------------------------------------------------------------------------------------------------
                                                         2010        2011        2012        2013        2014
----------------------------------------------------------------------------------------------------------------
Total U.S. Oil & Gas Production and Natural Gas            207.0       214.3       218.8       228.0       232.4
 Processing & Transmission methane Emissions (MMT
 CO2 Eq.)...........................................
Share of Total U.S. GHG Inventory...................        3.0%        3.1%        3.3%        3.4%        3.4%
Total U.S. GHG Emissions (MMT CO2 Eq.)..............       6,985       6,865       6,643       6,800       6,870
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15,
  2016), calculated using CH4 GWP of 25. Note: Totals may not sum due to rounding.

    In 2014, emissions from oil and natural gas production sources and 
natural gas processing and transmission sources accounted for 232.4 MMT 
CO2 Eq. methane emissions (using a GWP of 25 for methane), 
accounting for 3.4 percent of total United States domestic GHG 
emissions. The natural gas and petroleum systems source is the largest 
emitter of methane in the United States. The sector also emitted 43 MMT 
of CO2, mainly from acid gas removal during natural gas 
processing (24 MMT) and flaring in oil and natural gas production (18 
MMT). In total, these emissions (CH4 and CO2) 
account for 4.0 percent of total United States domestic GHG emissions.
    Methane is emitted in significant quantities from the oil and 
natural gas production sources and natural gas processing and 
transmission sources that are being addressed within this rule.
3. United States Oil and Natural Gas Production and Natural Gas 
Processing and Transmission GHG Emissions Relative to Total Global GHG 
Emissions

Table 6--Comparisons of United States Oil and Natural Gas Production and Natural Gas Processing and Transmission
                                   CH4 Emissions to Total Global GHG Emissions
----------------------------------------------------------------------------------------------------------------
                                                         2010        2011        2012        2013        2014
----------------------------------------------------------------------------------------------------------------
Total U.S. Oil & Gas Production and Natural Gas            207.0       214.3       218.8       228.0       232.4
 Processing & Transmission methane Emissions (MMT
 CO2 Eq.)...........................................
Share of Total U.S. GHG Inventory...................        3.0%        3.1%        3.3%        3.4%        3.4%
Total U.S. GHG Emissions (MMT CO2 Eq.)..............       6,985       6,865       6,643       6,800       6,870
----------------------------------------------------------------------------------------------------------------
Emissions from the Inventory of United States Greenhouse Gas Emissions and Sinks: 1990-2014 (published April 15,
  2016), calculated using CH4 GWP of 25.

    For additional background information and context, we used 2012 
World Resources Institute/Climate Analysis Indicators Tool (WRI/CAIT) 
and International Energy Agency (IEA) data to make comparisons between 
United States oil and natural gas production and natural gas processing 
and transmission emissions and the emissions inventories of entire 
countries and regions. Though the United States methane emissions from 
oil and natural gas production and natural gas processing and 
transmission are a seemingly small fraction (0.5 percent) of total 
global emissions of all GHG from all sources, ranking United States 
emissions of methane from oil and natural gas production and natural 
gas processing and transmission against total GHG emissions for entire 
countries (using 2012 WRI/CAIT data), shows that these emissions are 
comparatively large as they exceed the national-level emissions totals 
for all GHG and all anthropogenic sources for Greece, the Czech 
Republic, Chile, Belgium, and

[[Page 35840]]

about 150 other countries.\55\ Furthermore, United States emissions of 
methane from oil and natural gas production and natural gas processing 
and transmission are greater than the sum of total emissions of 54 of 
the lowest-emitting countries, using the 2012 WRI/CAIT data set.\56\
---------------------------------------------------------------------------

    \55\ WRI CAIT Climate Data Explorer. http://cait.wri.org/. 
Accessed March 30, 2016.
    \56\ Ibid.
---------------------------------------------------------------------------

4. Global GHG Emissions

Table 7--Comparisons of United States Oil and Natural Gas Production and
  Natural Gas Processing and Transmission CH4 Emissions to Total Global
                    Greenhouse Gas Emissions in 2012
------------------------------------------------------------------------
                                                   Total U.S. oil and
                                                 natural gas production
                                2012 (MMT CO2        and natural gas
                                     Eq.)            processing and
                                                 transmission share  (%)
------------------------------------------------------------------------
Total Global GHG Emissions...          44,816                       0.5
------------------------------------------------------------------------

    As illustrated by the domestic and global GHG comparison data 
summarized above, the collective GHG emissions from the oil and natural 
gas source category are significant, whether the comparison is domestic 
(where this sector is the largest source of methane emissions, 
accounting for 32 percent of United States methane and 3.4 percent of 
total United States emissions of all GHG), global (where this sector, 
while accounting for 0.5 percent of all global GHG emissions, emits 
more than the total national emissions of over 150 countries, and 
combined emissions of over 50 countries), or when both the domestic and 
global GHG emissions comparisons are viewed in combination. 
Consideration of the global context is important. GHG emissions from 
United States 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 United States regional climate, as well 
as the global climate as a whole for years and indeed many decades to 
come.
    As was the case in 2009, no single GHG source category dominates on 
the global scale. While the oil and natural gas source category, like 
many (if not all) individual GHG source categories, could appear small 
in comparison to total emissions, in fact, it is a very important 
contributor in terms of both absolute emissions, and in comparison to 
other source categories globally or within the United States.
5. VOC Emissions
    The EPA National Emissions Inventory (NEI) estimated total VOC 
emissions from the oil and natural gas sector to be 2,729,942 tons in 
2011. This ranks second of all the sectors estimated by the NEI and 
first of all the anthropogenic sectors in the NEI. These facts only 
serve to further the notion that emissions from the oil and natural gas 
sector contribute significantly to harmful air pollution.
6. SO2 Emissions
    The NEI estimated total SO2 emissions from the oil and 
natural gas sector to be 74,266 tons in 2011. This ranks 13th of the 
sectors estimated by the NEI. Again, it is clear that emissions from 
the oil and natural gas sector contribute significantly to dangerous 
air pollution.
7. Conclusion
    In summary, the 1979 Priority List broadly covers the oil and 
natural gas industry, including the production, processing, 
transmission, and storage of natural gas. As such, the 1979 Priority 
List covers all segments that we are regulating in this rule. To the 
extent that there is any ambiguity in the prior listing, the EPA hereby 
finalizes as an alternative its proposed revision of the category 
listing to broadly include the oil and natural gas industry. As 
revised, the listed oil and natural gas source category includes oil 
\57\ and natural gas production, processing, transmission, and storage. 
Pursuant to CAA section 111(b)(1)(A), the Administrator has determined 
that, in her judgment, this source category, as defined above, 
contributes significantly to air pollution that may reasonably be 
anticipated to endanger public health or welfare. In support, the EPA 
notes its previous determination under CAA section 111(b)(1)(A) for the 
oil and natural gas source category. In addition, the EPA provides in 
this section information and analyses detailing the public health and 
welfare impacts of GHG, VOC and SO2 emissions and the amount 
of these emission from the oil and natural gas source category (in 
particular from the various segments of the natural gas industry). 
Although the EPA does not believe the revision to the category listing 
is required for the standards we are promulgating in this action, even 
assuming it is, the revision is well justified.
---------------------------------------------------------------------------

    \57\ For the oil industry, the listing includes production, as 
explained above in footnote 27.
---------------------------------------------------------------------------

D. Establishing GHG Standards in the Form of Limitations on Methane 
Emissions

    A petition for reconsideration of the 2012 NSPS urged that ``EPA 
must reconsider its failure to adopt standards for the methane 
pollution released by the oil and gas sector.'' \58\ Upon reconsidering 
the issue, and with the benefit of additional information now available 
to us, the EPA is establishing GHG standards, in the form of 
limitations on methane emissions, throughout the oil and natural gas 
source category.
---------------------------------------------------------------------------

    \58\ Sierra Club et al., Petition for Reconsideration, In the 
Matter of: Final Rule Published at 77 FR 49490 (August 16, 2012), 
titled ``Oil and Gas Sector: New Source Performance Standards and 
National Emission Standards for Hazardous Air Pollutants Reviews; 
Final Rule,'' Docket ID No. EPA-HQ-OAR-2010-0505, RIN 2060-AP76 
(2012).
---------------------------------------------------------------------------

    During the 2012 oil and natural gas NSPS rulemaking, we had a 
considerable amount of data and a good understanding of VOC emissions 
from the oil and natural gas industry and the available control 
options, but data on methane emissions were just emerging at that time. 
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, while indicating in the 2012 
rulemaking an intent to revisit methane at a later date when additional 
information was available from the GHGRP.
    We have since received and evaluated considerable additional data, 
which confirms that the oil and natural gas industry is one of the 
largest emitters of methane in the United States. As

[[Page 35841]]

discussed in more detail in section IV.C of this preamble above, the 
current methane emissions from this industry contribute substantially 
to nationwide GHG emissions. And these emissions are expected to 
increase as a result of the rapid growth of this industry.
    While the controls used to meet the VOC standards in the 2012 NSPS 
also reduce methane emissions incidentally, in light of the current and 
projected future GHG emissions from the oil and natural gas industry, 
reducing GHG emissions from this source category should not be treated 
simply as an incidental benefit to VOC reduction; rather, it is 
something that should be directly addressed through GHG standards in 
the form of limits on methane emissions under CAA section 111(b) based 
on direct evaluation of the extent and impact of GHG emissions from 
this source category and the emission reductions that can be achieved 
through the best system for their reduction. The standards detailed in 
this final action will achieve meaningful GHG reductions and will 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) that emit both VOCs and methane, 
the VOC standards established in the 2012 NSPS apply only to the 
equipment located in the production and processing segments. As 
explained in the 2012 final rule, while our analysis suggested that the 
remaining pieces of equipment (i.e., those in the transmission and 
storage segments) are also important to regulate, given the large 
number of these pieces of equipment and the relatively low level of VOC 
from individual equipment, the EPA decided that further evaluation is 
appropriate before taking final action. 77 FR 49490, 49521-2 (August 
16, 2012). Based on its analyses in the current rulemaking, the EPA is 
taking final action to regulate VOC emitted from these remaining pieces 
of equipment. In addition, the EPA is setting GHG standards (by setting 
limitations on methane) for these pieces of equipment across the 
industry. As shown in the TSD, there are cost-effective controls that 
can simultaneously reduce both methane and VOC emissions from these 
equipment across the industry, and in many instances, they are cost 
effective even if all the costs are attributed to methane 
reduction.\59\ Moreover, in addition to the reductions to be achieved, 
establishing both GHG and VOC standards for equipment across the 
industry will also promote consistency by providing the same regulatory 
regime for this equipment throughout the oil and natural gas source 
category for both VOC and GHG, thereby facilitating implementation and 
enforcement.\60\ Therefore, based on the EPA's evaluation of methane 
reduction to address the impact of GHGs on climate change in 
conjunction with VOC reduction, the oil and gas NSPS, as finalized in 
this action, includes both VOC and GHG standards (in the form of 
limitations on methane) for a number of equipment across the oil and 
natural gas industry. It also includes VOC and GHG standards for a 
number of previously unregulated sources (i.e., oil well completions, 
fugitive emissions at well sites and compressor stations, and pneumatic 
pumps).
---------------------------------------------------------------------------

    \59\ In this action, we evaluated the controls under different 
approaches, including a single pollutant approach and a multi-
pollutant approach, which are described in detail in the preamble to 
the proposed rule and the final TSD. Under a single pollutant 
approach, we attribute all costs to one pollutant and zero to the 
other.
    \60\ While this final rule will result in additional reductions, 
as specified in sections II and IX of this preamble, 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 40 
CFR part 60 subpart BB published at 70 FR 18952 (April 4, 2014) to 
align the NSPS standards with the National Emission Standards for 
Hazardous Air Pollutants (NESHAP) standards for those sources in 40 
CFR 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 aligning the 
NSPS with the NEHSAP eased the compliance burden for the sources.
---------------------------------------------------------------------------

    With respect to the GHG standards contained in this final rule, the 
EPA identifies the air pollutant as the pollutant GHGs. However, the 
standards in this rule that are specific to GHGs are expressed in the 
form of limits on emissions of methane, and not the other constituent 
gases of the air pollutant GHGs.\61\ In this action, we are not 
establishing a limit on aggregate GHGs or separate emission limits for 
other GHGs that are not methane. This rule focuses on methane because, 
among other reasons, it is a GHG that is emitted in large quantities 
from the oil and gas industry, as explained above in section IV.C of 
this preamble. Notwithstanding this form of the standard, consistent 
with other EPA regulations addressing GHGs, the air pollutant regulated 
in this rule is GHGs; methane is limited as a constituent of the 
regulated pollutant, GHGs, not as a separate pollutant. This approach 
is consistent with the approach EPA followed in setting limits for new 
electric generating units.\62\ Additional regulatory language has been 
added to 40 CFR 60.5360a to clarify and confirm that GHGs is the 
regulated pollutant.
---------------------------------------------------------------------------

    \61\ In the 2009 GHG Endangerment Finding, the EPA defined the 
relevant ``air pollution'' as the atmospheric mix of six long-lived 
and directly emitted GHGs: CO2, CH4, 
N2O, HFCs, PFCs, and SF6. 74 FR 66497, 
December 15, 2009.
    \62\ See 80 FR 64510 (October 23, 2015).
---------------------------------------------------------------------------

    The EPA's authority for regulating GHGs in this rule is CAA section 
111(b)(1). As discussed above, under the statutory structure of CAA 
section 111(b), the Administrator first lists source categories 
pursuant to CAA section 111(b)(1)(A), and then promulgates, under CAA 
section 111(b)(1)(B), ``standards of performance for new sources within 
such category.''
    In this rule, the EPA is establishing standards under CAA section 
111(b)(1)(B) for a source category that it has previously listed and 
regulated for other pollutants and which now is being regulated for an 
additional pollutant.\63\ Because of this, there are two aspects of CAA 
section 111(b)(1) that warrant particular discussion.
---------------------------------------------------------------------------

    \63\ As explained in more detail in section IV.A of this 
preamble, the EPA interprets the 1979 category listing to broadly 
cover the oil and natural gas industry. Thus, this discussion 
focuses on EPA's authority to regulate an additional pollutant 
(specifically GHG) emitted from a previously listed source category. 
However, to the extent that any ambiguity exists in the 1979 
listing, and as also explained above, EPA is finalizing its 
alternative proposal to revise the category listing to broadly cover 
the oil and natural gas industry. In support, the Administrator has 
determined in this action, pursuant to CAA section 111(b)(1)(A), 
that the listed source category, as defined in the revision, 
contributes significantly to air pollution which may reasonably be 
anticipated to endanger public health or welfare. Therefore, the 
category listing and the Administrator's determination (to the 
extent they are necessary) provide authority for standards we are 
promulgating in this final rule, including the standards for GHG.
---------------------------------------------------------------------------

    First, because the EPA is not listing a new source category in this 
rule,\64\ the EPA is not required to make a new endangerment finding 
with regard to the oil and natural gas source category in order to 
establish standards of performance for an additional pollutant 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. 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

[[Page 35842]]

finding is made with respect to the source category; CAA 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).
---------------------------------------------------------------------------

    \64\ See section IV.A of this preamble.
---------------------------------------------------------------------------

    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 CAA 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 standards, it is appropriate for the 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).\65\
---------------------------------------------------------------------------

    \65\ In Chevron, the United States Supreme Court held that an 
agency must, at Step 1, determine whether Congress's intent as to 
the specific matter at issue is clear, and, if so, the agency must 
give effect to that intent. If Congressional intent is not clear, 
then, at Step 2, the agency has discretion to fashion an 
interpretation that is a reasonable construction of the statute.
---------------------------------------------------------------------------

    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 
(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 CAA section 111(b)(1)(B), Congress 
provided that the Administrator should take comment and then finalize 
the standards with such modifications ``as [s]he deems appropriate.'' 
The D.C. Circuit has considered similar statutory phrasing from CAA 
section 231(a)(3) and concluded that ``[t]his delegation of authority 
is both explicit and extraordinarily broad.'' National Assoc. of Clean 
Air Agencies v. EPA, 489 F.3d 1221, 1229 (D.C. Cir. 2007).
    In exercising its discretion with respect to which pollutants are 
appropriate for regulation under CAA 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 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. The EPA took this approach 
in setting limits for new electric generating units.\66\ The EPA 
interprets CAA section 111(b)(1)(B) 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. In making such determination, we have generally 
considered a number of factors to help inform our decision. These 
include the amount of the pollutant that is being emitted from the 
source category, the availability of technically feasible control 
options, and the costs of those control options.\67\
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    \66\ 80 FR 64510, 64529-30, October 23, 2015.
    \67\ See 80 FR 56593, 56600-09, (section VI of the proposed 
rule) and 56616-45, September 18, 2015 (section VIII of the proposed 
rule).
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    In this rulemaking, the EPA has a rational basis for concluding 
that GHGs from the oil and natural gas source category, which is a 
large category of sources of GHG emissions, merit regulation under CAA 
section 111. In making this determination, the EPA focuses on methane 
emissions from this category. The information summarized here and 
discussed in other sections of this preamble provides the rational 
basis for the GHG standards, expressed as limitations on methane, 
established in this action.\68\
---------------------------------------------------------------------------

    \68\ Specifically, Sections IV.B and C, V, and VI of this final 
rule.
---------------------------------------------------------------------------

    In 2009, the EPA made a finding that GHG air pollution may 
reasonably be anticipated to endanger public health or welfare under 
section 202(a) of the CAA \69\ and, in 2010, the EPA denied petitions 
to reconsider that finding. The EPA extensively reviewed the available 
science concerning GHG pollution and its impacts in taking those 
actions. In 2012, the United States Court of Appeals for the District 
of Columbia Circuit upheld the finding and the denial of petitions to 
reconsider.\70\ In addition, assessments released by the 
Intergovernmental Panel on Climate Change (IPCC), the USGCRP, and the 
NRC, and other organizations published after 2010 lend further credence 
to the validity of the 2009 Endangerment Finding. No information that 
commenters have presented or that the EPA has reviewed provides a basis 
for reaching a different conclusion for purposes of this action. 
Indeed, current and evolving science discussed in detail in sections 
IV.B and C of this preamble is confirming and enhancing our 
understanding of the near- and longer-term impacts that elevated 
concentrations of GHGs, including methane, are having on Earth's 
climate and the adverse public health, welfare, and economic 
consequences that are occurring and are projected to occur as a result.
---------------------------------------------------------------------------

    \69\ 74 FR 66496 (December 15, 2009).
    \70\ Coalition for Responsible Regulation v. EPA, 684 F.3d 102, 
119-126 (D.C. Circuit 2012).
---------------------------------------------------------------------------

    Moreover, the high quantities of methane emissions from the oil and 
natural gas source category demonstrate that it is rational for the EPA 
to set methane limitations to regulate GHG emissions from this sector. 
The oil and natural gas source category is the largest emitter of 
methane in the United States, contributing about 29 percent of total 
United States methane emissions. The methane that this source category 
emits accounts for 3 percent of all United States GHG emissions. As 
shown in Tables 4 and 5 in this preamble, oil and gas sources are very 
large emitters of methane: In fact, GWP-weighted emissions of methane 
from these sources are larger than emissions of all GHGs from about 150 
countries. Methane is a GHG with a global warming potential 28 to 36 
times greater than that of CO2.\71\ When considered in

[[Page 35843]]

total, the facts presented in sections IV.B and C of this preamble, 
along with prior EPA analysis, including that found in the 2009 
Endangerment Finding, provide a rational basis for regulating GHG 
emissions from affected oil and gas sources by expressing GHG 
limitations in the form of limits on methane emissions.
---------------------------------------------------------------------------

    \71\ 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. For the purposes 
of calculating GHG emissions, the GWP value published on Table A-1 
to subpart A of 40 CFR part 98 should still be used.
---------------------------------------------------------------------------

    To reiterate, the ``air pollution'' defined in the 2009 
Endangerment Finding is the atmospheric mix of six long-lived and 
directly emitted GHGs: CO2, CH4, N2O, 
HFCs, PFCs, and SF6.\72\ This is the same pollutant that is 
regulated by this rule. However, the standards of performance adopted 
in the present rulemaking address only one constituent gas of this air 
pollution: Methane. This is reasonable, given that methane is the 
constituent gas emitted in the largest volume by the source category 
and for which there are available controls that are technically 
feasible and cost effective. There is no requirement that standards of 
performance address each component of an air pollutant. Clean Air Act 
section 111(b)(1)(B) requires the EPA to establish ``standards of 
performance'' for listed source categories, and the definition of 
``standard of performance'' in CAA section 111(a)(1) does not specify 
which air pollutants must be controlled. So, while the limitations in 
this rule are expressed as limits on methane, the pollutant regulated 
is GHGs.
---------------------------------------------------------------------------

    \72\ See 74 FR 66496, 66497 (December 15, 2009).
---------------------------------------------------------------------------

    Some commenters have argued that the EPA is required to make a new 
endangerment finding before it may set limitations for methane from the 
oil and natural gas source category. We disagree, for the reasons 
discussed above. Moreover, even if CAA section 111 required the EPA to 
make an endangerment finding as a prerequisite for this rulemaking, 
then, the information and conclusions described above in sections IV.B 
and C of this preamble should be considered to constitute the requisite 
finding (which includes a finding of endangerment as well as a cause-
or-contribute significantly finding). The same facts that support our 
rational basis determination would support such a finding. The EPA's 
rational basis for regulating GHGs, by setting methane limitations, 
under CAA section 111 is based primarily on the analysis and 
conclusions in the EPA's 2009 Endangerment Finding and 2010 denial of 
petitions to reconsider that Finding, coupled with the subsequent 
assessments from the IPCC, USGCRP, and NRC that describe scientific 
developments since those EPA actions and other facts contained herein.
    More specifically, our approach here--reflected in the information 
and conclusions described above--is substantially similar to that 
reflected in the 2009 Endangerment Finding and the 2010 denial of 
petitions to reconsider. The D.C. Circuit upheld that approach in 
Coalition for Responsible Regulation v. EPA, 684 F.3d 102, 117-123 
(D.C. Cir. 2012) (noting, among other things, the ``substantial . . . 
body of scientific evidence marshaled by EPA in support of the 
Endangerment Finding'' (id. at 120); the ``substantial record evidence 
that anthropogenic emissions of greenhouse gases very likely caused 
warming of the climate over the last several decades'' (id. at 121); 
``substantial scientific evidence . . . that anthropogenically induced 
climate change threatens both public health and public welfare . . . 
[through] extreme weather events, changes in air quality, increases in 
food- and water-borne pathogens, and increases in temperatures'' (id.); 
and ``substantial evidence . . . that the warming resulting from the 
greenhouse gas emissions could be expected to create risks to water 
resources and in general to coastal areas. . . .'' (id.)). The facts, 
unfortunately, have only grown stronger and the potential adverse 
consequences of GHG to public health and the environment more dire in 
the interim.\73 \The facts also demonstrate that the current methane 
emissions from oil and natural gas production sources and natural gas 
processing and transmission sources contribute substantially to 
nationwide GHG emissions.
---------------------------------------------------------------------------

    \73 \ Nor does the EPA consider the cost of potential standards 
of performance in making this finding. Like the endangerment finding 
under section 202(a) at issue in State of Massachusetts v. EPA, 549 
U.S. 497 (2007), the pertinent issue is a scientific inquiry as to 
whether an endangerment to public health or welfare from the 
relevant air pollution may reasonably be anticipated. Where, as 
here, the scientific inquiry conducted by the EPA indicates that 
these statutory criteria are met, the Administrator does not have 
discretion to decline to make a positive endangerment finding to 
serve other policy grounds. Id. at 532-35. In this regard, an 
endangerment finding is analogous to setting national ambient air 
quality standards under CAA section 109(b), which similarly call on 
the Administrator to set standards that in her ``judgment'' are 
``requisite to protect the public health''. The EPA is not permitted 
to consider potential costs of implementation in setting these 
standards. Whitman v. American Trucking Assn's, 531 U.S. 457, 466 
(2001); see also Michigan v. EPA, U.S. (no. 14-46, June 29, 2015) 
slip op. pp. 10-11 (reiterating Whitman holding). The EPA notes 
further that section 111(b)(1) contains no terms such as ``necessary 
and appropriate'' which could suggest (or, in some contexts, 
require) that costs may be considered as part of the finding. 
Compare CAA section 112(n)(1)(A); see State of Michigan, slip op. 
pp. 7-8. The EPA, of course, must consider costs in determining 
whether a best system of emission reduction is adequately 
demonstrated and so can form the basis for a section 111(b) standard 
of performance, and the EPA has carefully considered costs here and 
found them to be reasonable. See sections V and VI below. The EPA 
also has found that the rule's quantifiable benefits exceed 
regulatory costs under a range of assumptions were new capacity to 
be built. See RIA. Accordingly, this endangerment finding would be 
justified if (against our view) it is both required, and (again, 
against our view) costs are to be considered as part of the finding.
---------------------------------------------------------------------------

    The EPA also reviewed comments presenting other scientific 
information to determine whether that information has any meaningful 
impact on our analysis and conclusions. For both the rational basis 
analysis and for any endangerment finding, assuming for the sake of 
argument that one would be necessary for this final rule, the EPA 
focused on public health and welfare impacts within the United States, 
as it did in the 2009 Endangerment Finding. The impacts in other world 
regions strengthen the case because impacts in other world regions can 
in turn adversely affect the United States and its citizens.\74\
---------------------------------------------------------------------------

    \74\ See 74 FR 66514 and 66535, December 15, 2009.
---------------------------------------------------------------------------

    Lastly, EPA identified technically feasible and cost effective 
controls that can be applied nationally to reduce methane emissions 
and, thus, GHG emissions, from the oil and natural gas source category.
    The EPA considered whether the costs (e.g., capital costs, 
operating costs) are reasonable considering the emission reductions 
achieved through application of the controls required. For a detailed 
discussion on how we evaluated control costs and our cost analysis for 
individual emission sources, please see the proposal and the final TSD 
in the public docket.

V. Summary of Final Standards

    This section presents a summary of the specific standards we are 
finalizing for various types of equipment and emission points. More 
details of the rationale for these standards and requirements, 
including alternative compliance options and exemptions to the 
standards, are provided in sections VI, VII, and VIII of this preamble, 
the TSD, and the RTC document in the public docket.

A. Control of GHG and VOC Emissions in the Oil and Natural Gas Source 
Category--Overview

    In this action, the EPA is finalizing emission standards for GHG, 
in the form of limitations on methane, and VOC

[[Page 35844]]

emissions, for certain new, modified and reconstructed emission sources 
across the oil and natural gas source category at subpart OOOOa. For 
some of these sources, there are VOC requirements currently in place 
that were established in the 2012 NSPS, and we are now establishing GHG 
limitations for those emission points. For others, for which there are 
no current requirements, we are finalizing both GHG and VOC standards. 
We are also finalizing improvements to enhance implementation of the 
current standards at subpart OOOO. For the reasons explained in the 
previous section, the EPA believes that GHG standards, in the form of 
limitations on methane, are warranted, even for those already subject 
to VOC standards under the 2012 NSPS. Further, as shown in the final 
TSD, there are cost effective controls that achieve simultaneous 
reductions of GHG and VOC emissions.
    Pursuant to CAA section 111(b), we are both amending subpart OOOO 
and adding a new subpart, OOOOa. We are amending subpart OOOO, which 
applies to facilities constructed, modified or reconstructed after 
August 23, 2011, (i.e., the original proposal date of subpart OOOO) and 
on or before September 18, 2015 (i.e., the proposal date of the new 
subpart OOOOa), and is amended only to include the revisions reflecting 
implementation improvements in response to issues raised in petitions 
for reconsideration. We are adding subpart OOOOa, which will apply to 
facilities constructed, modified or reconstructed after September 18, 
2015, to include current VOC requirements already provided in subpart 
OOOO (as updated) as well as new provisions for GHGs and VOCs across 
the oil and natural gas source category as highlighted below in this 
section.
    As the purpose of this action is to control and limit emissions of 
GHG and VOC, EPA seeks to confirm that all regulatory standards are 
met. Any owner or operator claiming technical infeasibility, 
nonapplicability, or exemption from the regulation has the burden to 
demonstrate the claim is reasonable based on the relevant information. 
In any subsequent review of a technical infeasibility or 
nonapplicability determination, or a claimed exemption, EPA will 
independently assess the basis for the claim to ensure flaring is 
limited and emissions are minimized, in compliance with the rule. Well-
designed rules ensure fairness among industry competitors and are 
essential to the success of future enforcement efforts.

B. Centrifugal Compressors

    We are finalizing amendments to the 2012 NSPS, and adding new 
requirements to establish both VOC and GHG standards (in the form of 
limitations on methane emissions) for new, modified or reconstructed 
wet seal centrifugal compressors located across the oil and natural gas 
source category. Specifically, the final rule adds GHG standards to the 
current VOC standards for wet seal centrifugal compressors, as well as 
establishing GHG and VOC standards for those that are currently 
unregulated, with one exception. We are not establishing requirements 
for centrifugal compressors at well sites. As finalized, the standards 
require a 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, using a cover and closed vent 
system, to a control device that achieves an emission reduction of 95 
percent, or routing to a process.

C. Reciprocating Compressors

    We are finalizing amendments to the 2012 NSPS and adding new 
requirements to establish both VOC and GHG standards (in the form of 
limitations on methane emissions) for new, modified, or reconstructed 
reciprocating compressors located across the oil and natural gas source 
category. Specifically, the final rule adds GHG standards to the 
current VOC standards for reciprocating compressors, as well as 
establishing GHG and VOC standards for those that are currently 
unregulated, with one exception. We are not establishing requirements 
for reciprocating compressors at well sites. The standards, which are 
operational standards, require 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 is 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. On or before 26,000 hours of operation, the owner or operator 
is required to 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.

D. Pneumatic Controllers

    We are finalizing amendments to the 2012 NSPS and adding new 
requirements to establish both VOC and GHG standards (in the form of 
limitations on methane emissions) for new, modified, or reconstructed 
pneumatic controllers located across the oil and natural gas source 
category. Specifically, the final rule adds GHG standards to the 
current VOC standards for pneumatic controllers and establishes GHG and 
VOC standards for those that are currently unregulated. We are 
finalizing GHG (in the form of limitations on methane emissions) and 
VOC standards to control emissions by requiring use of low-bleed 
controllers in place of high-bleed controllers (i.e., natural gas bleed 
rate not to exceed 6 standard cubic feet per hour (scfh)) at all 
locations within the source category except for natural gas processing 
plants. For natural gas processing plants, we are finalizing standards 
to control GHG and VOC emissions by requiring that pneumatic 
controllers have a zero natural gas bleed rate (i.e., they are operated 
by means other than natural gas, such as being driven by compressed 
instrument air). These standards apply to each newly installed, 
modified or reconstructed pneumatic controller (including replacement 
of an existing controller). The finalized standards provide exemptions 
for certain critical applications based on functional considerations.

E. Pneumatic Pumps

    We are finalizing standards for natural gas-driven diaphragm 
pumps.\75\ The standards require that GHGs (in the form of limitations 
on methane emissions) and VOC emissions from new, modified and 
reconstructed natural gas-driven diaphragm pumps located at well sites 
be reduced by 95 percent if either a control device or the ability to 
route to a process is already available onsite, unless it is 
technically infeasible at sites other than new developments (i.e., 
greenfield sites). In setting this requirement, the EPA recognizes that 
there may not be a control device or process available onsite. Our 
analysis shows that it is not cost-effective to require the owner or 
operator of a pneumatic pump affected facility to install a new control 
device or process onsite to capture emissions. If a control device or 
ability to route to a process is not available onsite, the pneumatic 
pump affected facility is not

[[Page 35845]]

subject to the emission reduction provisions of the final rule. In 
other instances, there may be a control device available onsite, but it 
may not be capable of achieving a 95 percent reduction. In those cases, 
we are not requiring the owner or operator to install a new control 
device onsite or to retrofit the existing control device, however, we 
are requiring the owner or operator of a pneumatic pump affected 
facility at a well site to route the emissions to an existing control 
device even it if achieves a level of emissions reduction less than 95 
percent. In those instances, the owner or operator must maintain 
records demonstrating the percentage reduction that the control device 
is designed to achieve. In this way, the final rule will achieve 
emission reductions with regard to pneumatic pump affected facilities 
even if the only available control device cannot achieve a 95 percent 
reduction. For pneumatic pumps located at natural gas processing 
plants, the standards require that GHG and VOC emissions from natural 
gas-driven diaphragm pumps be zero.
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    \75\ A lean glycol circulation pump that relies on energy 
exchange with the rich glycol from the contactor is not considered a 
diaphragm pump. For more details, please see section VI.
---------------------------------------------------------------------------

F. Well Completions

    We are finalizing GHG standards (in the form of limiting methane 
emissions) for well completions of hydraulically fractured (or 
refractured) gas wells as well as GHG and VOC standards for well 
completions of hydraulically fractured (or refractured) oil wells. As 
explained in the proposal preamble, the BSER for these emission 
reductions are the same as the BSER for reducing VOC emissions from 
hydraulically fractured gas wells. Therefore, the operational standards 
finalized in this action are essentially the same as the VOC standards 
for hydraulically fractured gas wells promulgated in the 2012 NSPS. For 
the reason stated above, the well completion standards in this final 
rule apply to both gas and oil well completions.
    As with gas wells, for well completions of hydraulically fractured 
(or refractured) oil wells, we identified two subcategories of 
hydraulically fractured wells for which well completions are conducted: 
(1) Non-wildcat and non-delineation wells (subcategory 1 wells); and 
(2) wildcat and delineation wells (subcategory 2 wells). A wildcat 
well, also referred to as an exploratory well, is a well drilled 
outside known fields or is 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.
    We are finalizing operational standards for subcategory 1 wells 
that require a combination of reduced emissions completion (REC) and 
combustion. Compared to combustion alone, the combination of REC and 
combustion will maximize gas recovery and minimize venting to the 
atmosphere. The finalized standards for subcategory 2 wells require 
combustion.
    For subcategory 1 wells, we define the flowback period of a 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 flowback is 
routed to a separator. Routing of the flowback to a separator is 
required as soon as a separator is able to function (i.e., the operator 
must route the flowback to a separator unless it is technically 
infeasible for a separator to function). Any gas in the flowback prior 
to the point at which a separator begins functioning is not subject to 
control. The point at which the separator can function marks the 
beginning of the separation flowback stage. During this stage, the 
operator must do the following, unless technically infeasible to do so 
as discussed below: (1) Route all salable quality gas from the 
separator to a gas flow line or collection system; (2) re-inject the 
gas into the well or another well; (3) use the gas as an onsite fuel 
source; or (4) use the gas for another useful purpose that a purchased 
fuel or raw material would serve. If the operator assesses all four 
options for use of recovered gas, and still finds it technically 
infeasible to route the gas as described, the operator must route the 
gas to a completion combustion device with a continuous pilot flame and 
document the technical infeasibility assessment according to Sec.  
60.5420a(c) of this final rule, which describes the specific types of 
information required to document that the operator has exercised due 
diligence in making the assessment. No direct venting of gas is allowed 
during the separation flowback stage unless combustion creates a fire 
or safety hazard or can damage tundra, permafrost or waterways. The 
separation flowback stage ends 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 and minimize releases to the atmosphere over the duration of 
the flowback period. For subcategory 1 wells (except for low gas to oil 
ratio (GOR) and low pressure wells discussed below), the operator is 
required to have a separator onsite during the entirety 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) the 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. Because the 
BSER for oil wells and gas wells are the same, the final rule applies 
these requirements to both oil and gas wells.
    For subcategory 2 wells, we are finalizing an operational standard 
that requires either (1) routing all flowback directly to a completion 
combustion device with a continuous pilot flame (which can include a 
pit flare) or, at the option of the operator, (2) routing the flowback 
to a well completion vessel and sending the flowback to a separator as 
soon as a separator will function and then directing the separated gas 
to a completion combustion device with a continuous pilot flame. For 
option 2, any gas in the flowback prior to the point when the separator 
will function is not subject to control. In either case, combustion is 
not required if combustion creates a fire or safety hazard or can 
damage tundra, permafrost or waterways. Operators are required to 
maintain the same records described above for category 1 wells.
    As with gas wells, we similarly recognize the limitation of ``low 
pressure'' oil wells from conducting REC. Therefore, consistent with 
the 2012 NSPS, low pressure wells are affected facilities and have the 
same requirements as subcategory 2 wells (wildcat and delineation 
wells). We have revised the definition of a ``low pressure'' well in 
response to comment.
    Further, wells with a GOR of less than 300 scf of gas per stock 
tank barrel of oil produced are affected facilities, but have no well 
completion requirements, providing the owner or operator maintains 
records of the low GOR certification and a claim signed by the 
certifying official.
    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

[[Page 35846]]

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 for purposes of the well completion standards. 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 fugitive emissions standards at Sec.  
60.5397a.

G. Fugitive Emissions From Well Sites and Compressor Stations

    We are finalizing standards to control GHGs (in the form of 
limitations on methane emissions) and VOC emissions from fugitive 
emission components at well sites and compressor stations. 
Specifically, we are finalizing semiannual monitoring and repair of 
fugitive emission components at well sites and quarterly monitoring and 
repair at compressor stations. Monitoring of the components must be 
conducted using optical gas imaging (OGI), and repairs must be made if 
any visible emissions are observed. Method 21 may be used as an 
alternative monitoring method at a repair threshold level at 500 parts 
per million (ppm). Repairs must be made within 30 days of finding 
fugitive emissions and a resurvey of the repaired component must be 
made within 30 days of the repair using OGI or Method 21 at a repair 
threshold of 500 ppm. A monitoring plan that covers the collection of 
fugitive emissions components at well sites or compressor stations 
within a company-defined area must be developed and implemented.

H. Equipment Leaks at Natural Gas Processing Plants

    We are finalizing standards to control GHGs (in the form of 
limitations on methane emissions) from equipment leaks at new, modified 
or reconstructed natural gas processing plants. These requirements are 
the same as the VOCs equipment leak requirements in the 2012 NSPS and 
require the level of control established in NSPS part 60, subpart VVa, 
including a detection level of 500 ppm for certain pieces of equipment, 
as in the 2012 NSPS. As with VOC reduction, we believe that subpart VVa 
level of control reflects the best system of emission reductions for 
reducing methane emissions.

I. Liquids Unloading Operations

    The EPA stated in the proposal that we did not have sufficient 
information to propose a national standard for liquids unloading.\76\ 
However, the EPA requested comment on nationally applicable 
technologies and techniques that reduce GHG and VOC emissions from 
these events. Although the EPA received valuable information from the 
public comment process, the information was not sufficient to finalize 
a national standard representing BSER for liquids unloading.
---------------------------------------------------------------------------

    \76\ See 80 FR 56614 and 80 FR 56644, September 18, 2015.
---------------------------------------------------------------------------

    Specifically, we requested data and information on the level of GHG 
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 requested 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.
    The EPA received some information pertaining to our request for 
information. Specifically, the EPA received information on the 
frequency of unloading and on techniques to reduce emissions through 
capture or flaring and learned of some operators that have been able to 
achieve capture in practice. While we have gained better understanding 
of the practice of liquids unloading, the EPA did not receive the 
necessary information to identify an emission reduction technology that 
can be applied across the category of sources. We also considered the 
possibility of subcategorization. However, according to the information 
received, the differences in liquids unloading events (with respect to 
both frequency and emission level) are not due to differences in well 
size or type of wells at which liquids unloading is performed, but 
rather the specific conditions of a given well at the time the operator 
determines that well production is impaired such that unloading must be 
done. Operators select the technique to perform liquids unloading 
operations based on the conditions of the well each time production is 
impaired. Because well conditions change over time, each iteration of 
unloading may require repeating a single technique or attempting a 
different technique that may not have been appropriate under prior 
conditions. Given the differences in conditions at different wells when 
liquids unloading must be performed, the EPA did not receive 
information about techniques, individually or as a group, that helped 
us to identify a BSER under our CAA section 111(b) authority. The EPA 
continues to search for better means to address emissions associated 
with liquids unloading and is including this emissions source in the 
upcoming information gathering effort.\77\ Please refer to the RTC for 
additional discussion on liquids unloading.\78\
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    \77\ See section III.E of this preamble for a discussion of the 
upcoming information gathering effort.
    \78\ See RTC document in EPA Docket ID No. EPA-HQ-OAR-2010-0505.
---------------------------------------------------------------------------

J. Recordkeeping and Reporting

    We are finalizing recordkeeping and reporting requirements that are 
consistent with those in the current NSPS. The final rule requires 
owners or operators to submit initial notifications and annual reports, 
in addition to retaining 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 are not required to submit an initial notification for 
each piece of equipment; rather, they must report the installation of 
these affected facilities in their 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) are required to submit an initial 
notification no later than two days prior to the commencement of each 
well completion operation. This notification must include contact 
information for the owner or operator, the United States Well Number 
(formerly 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, initial annual reports are due no later than 90 days 
after the end of the initial compliance period, which is established in 
the rule. Subsequent annual reports are due no later than the same date 
each year as the initial annual report. The annual reports include 
information on all affected facilities that were constructed, modified 
or reconstructed during the previous year. A single report may be 
submitted covering multiple affected facilities,

[[Page 35847]]

provided that the report contains all the information required by Sec.  
60.5420a(b). This information includes general information on the 
company (e.g., company name), as well as information specific to 
individual affected facilities, such as the well ID associated with the 
affected facility (e.g., storage vessels) and the facility site name 
(e.g., ``Compressor Station XYZ'' or ``Tank Battery 123'') and the 
address of the affected facility.
    For well affected facilities, the information required in the 
annual report includes the location of the well, the United States 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 the recovery of 
gas for another useful purpose, duration of combustion, duration of 
venting, and specific reasons for venting in lieu of capture or 
combustion. For each well for which a technical infeasibility exemption 
is claimed, to route the recovered gas to any of the four options 
specified in Sec.  60.5375a(a)(1)(ii), the report includes the reasons 
for the claim of technical infeasibility with respect to all four 
options provided in that subparagraph.
    For each well for which an exemption is claimed the owner or 
operator must maintain records of the low GOR certification and submit 
a claim signed by the certifying official in the annual report. For 
each 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 should include the location 
of the well, the United States 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 must 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 must 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 
must 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 includes location and documentation of manufacturer 
specifications of the natural gas bleed rate of each pneumatic 
controller installed during the reporting period. For pneumatic 
controllers for which the owner is claiming an exemption from the 
standards, the annual report includes 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 also includes 
records of deviations from the applicable standards.
    For pneumatic pump affected facilities, information in the annual 
report includes an identification of each pneumatic pump constructed, 
modified or reconstructed during the compliance period; if applicable, 
a certification that no control was available onsite and that there is 
no ability to route to a process; an identification of any sites that 
contain pneumatic pumps and installed a control device during the 
reporting period, where there was previously no control device or 
ability to route to a process at a site; and records of deviations in 
cases where the pneumatic pump was not operated in compliance with the 
applicable standards.
    The final rule includes new requirements for monitoring and 
repairing sources of fugitive emissions at well sites and compressor 
stations. An owner or operator must submit an annual report, which 
covers the collection of fugitive emissions components at well sites 
and compressor stations within an area defined by the company. The 
report must include the date and time of the surveys completed during 
the reporting year, the name of the operator performing the survey; the 
ambient temperature, sky conditions, and maximum wind during the 
survey; the type of monitoring instrument used; the number and type of 
components that were found to have fugitive emissions; the number and 
type of components that were not repaired during the monitoring survey; 
the number and type of difficult-to-monitor and unsafe-to-monitor 
components that were monitored; the date of the successful repair of 
the fugitive emissions component if it was not repaired during the 
survey; the number and type of fugitive emission components that were 
placed on delay of repair and the explanation of why the component 
could not be repaired and was placed on delay of repair; and the type 
of monitoring instrument used to resurvey a repaired component that 
could not be repaired during the initial monitoring survey. If an owner 
or operator chooses to use Method 21 to conduct the monitoring survey, 
they are required to keep records that include the type of monitoring 
instrument used and the fugitive emissions component identification. 
The owner or operator is required to keep a log for each affected 
facility. The log must include the date the monitoring survey was 
performed, the technology used to perform the survey, the number and 
types of equipment found to have fugitive emissions, a digital 
photograph or video of the monitoring survey when an OGI instrument is 
used to perform the monitoring survey, the date or dates of first 
attempt to repair the source of fugitive emissions, the date of repair 
of each source of fugitive emissions that could not be repaired during 
the initial monitoring survey, any source of fugitive emissions found 
to be technically infeasible or unsafe to repair and an explanation of 
why the component was placed on delay of repair, a list of the fugitive 
emissions components that were tagged as a result of not being repaired 
during the initial monitoring survey, and a digital photograph or video 
of each untagged fugitive emissions component that could not be 
repaired during the monitoring survey when the fugitive emissions were 
initially found. These digital photographs and logs must be available 
at the affected facility or the field office.
    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.

K. Reconsideration Issues Being Addressed

    The EPA is finalizing numerous items in subpart OOOO on which we 
granted reconsideration and proposed changes with some further 
adjustments as a

[[Page 35848]]

result of public comment. To the extent that these items relate to 
subpart OOOOa, we are also finalizing the same provisions for purposes 
of consistency between the two rules. First, we are finalizing 
corrections to the storage vessel control device monitoring and testing 
provisions related to in-field performance testing of enclosed 
combustors, initial and ongoing performance testing for any enclosed 
combustors used to comply with the emissions standard for an affected 
facility, and consistent requirements for monitoring of visible 
emissions for all enclosed combustion units. We are also finalizing 
clarified applicability requirements for storage vessel affected 
facilities. Next, we are finalizing amendments to include initial 
compliance requirements for bypass devices and certain closed vent 
systems and provide an alternative in subpart OOOO. Specifically, the 
rule allows for either an alarm at the bypass device or a remote alarm. 
The EPA is not finalizing our proposal to require both forms of alarm 
under subpart OOOO to avoid retroactive requirements.
    Additionally, the EPA is finalizing recordkeeping requirements for 
repair logs for control devices failing a visible emissions test. We 
are clarifying the due date for the initial annual report and 
finalizing that flares used to comply with subpart OOOO are subject to 
the design and operation requirements in the general provisions. Next, 
we clarify that the monitoring provisions of subpart VVa applicable to 
affected units of subpart OOOO do not extend to open-ended valves or 
lines. We are finalizing clarification to the initial compliance 
requirement specifically to identify that the 2012 rule already 
includes a provision similar to subpart KKK. The EPA is finalizing the 
exemption from the notification required for reconstruction to affected 
facility pneumatic controllers, centrifugal compressors, and storage 
vessels in subpart OOOOa. The EPA is finalizing provisions for 
management of waste from spent carbon canisters. The EPA is finalizing 
a definition of the term ``capital expenditure'' in subpart OOOO. The 
EPA is finalizing an exemption for certain water recycling vessels that 
EPA did not intend to be affected facility storage vessels under 
subparts OOOO or OOOOa. By exempting such vessels, EPA will address a 
disincentive for recycling of water for hydraulic fracturing. Lastly, 
the EPA is not finalizing continuous control device monitoring 
requirements for storage vessels and centrifugal compressor affected 
facilities in subpart OOOO. For additional discussion of these issues, 
please refer to section VI of this preamble and the RTC.

L. Technical Corrections and Clarifications

    We discovered 22 drafting errors in the proposal and have corrected 
these errors in the final rule. Please see section VI for a complete 
list of technical corrections and clarifications.

M. Prevention of Significant Deterioration and Title V Permitting

    In the proposed rule, we stated that the pollutant we were 
proposing to regulate was GHGs, not methane as a separately regulated 
pollutant. 80 FR 56593, 56600-01 (Sept. 18, 2015). As explained in 
section VII of this preamble, we are adding provisions to the final 
rule, analogous to what was included in Standards of Performance for 
Greenhouse Gas Emissions from New, Modified, and Reconstructed 
Stationary Sources: Electric Utility Generating Units, 80 FR 64509 
(Oct. 23 2015), to make clear in the regulatory text that the pollutant 
regulated by this rule is GHGs.

N. Final Standards Reflecting Next Generation Compliance and Rule 
Effectiveness

    In making decisions on the final requirements for this rule, we 
have emphasized the value of requirements that reflect principles of 
Next Generation Compliance and Rule Effectiveness. EPA's Next 
Generation Compliance strategy includes designing rules that promote 
improved compliance and better environmental outcomes. Specifically, we 
are finalizing standards with the following Next Generation Compliance 
strategies: (1) Electronic reporting via the EPA's Central Data 
Exchange (CDX), (2) clear applicability criteria (e.g., modification 
criteria), (3) incentives for intrinsically lower emitting equipment 
(e.g., solar pumps at gas plants are not affected facilities), (4) OGI 
technology for monitoring fugitive emissions, (5) digital picture 
reporting as an alternative for well completions (``REC PIX'') and 
manufacturer installed control devices, (6) qualified professional 
engineer certification of technical infeasibility to connect a 
pneumatic pump to an existing control device, and (7) qualified 
professional engineer certification of closed vent system design. These 
requirements, or options for compliance, provide opportunities for 
owners and operators to reduce obligations by making particular 
choices, reduce the burden for both the regulated industry and the 
agencies providing oversight, and provide greater transparency for all 
parties, including the public.

VI. Significant Changes Since Proposal

    This section identifies significant changes in this rule from the 
proposed rule. These changes reflect the EPA's consideration of over 
900,000 comments submitted on the proposal and other information 
received since the proposal, while preserving the aims underlying the 
proposal. The final rule protects human health and the environment by 
improving the existing NSPS and adding emission reduction standards for 
additional significant sources of GHGs and VOCs, consistent with the 
CAA. The EPA sought to achieve this important goal by endeavoring, 
where possible, to consistently expand the 2012 NSPS requirements 
across the oil and natural gas sector while also accounting for the 
unique characteristics of each type of source in setting emission 
reduction requirements. In this section, we discuss the significant 
changes since proposal by source category and the broad background for 
those changes. More specific information regarding comments and our 
responses appears in section VIII and in materials available in the 
docket.

A. Centrifugal Compressors

    For centrifugal compressors, comments and information available led 
us to finalize the standards as proposed. In the proposed rule, we 
proposed to require 95 percent reduction of emissions from each 
centrifugal compressor affected facility. The standard can be achieved 
by capturing and routing the emissions using a cover and closed vent 
system to a control device (i.e., combustion control device) that 
achieves an emission reduction of 95 percent, or by routing the 
captured emissions to a process. For additional details, please refer 
to section VIII, the TSD, and the RTC supporting documentation in the 
public docket.

B. Reciprocating Compressors

    For the reciprocating compressors requirements, we are finalizing 
the standards as proposed, except with a slight modification to the 
definition of reciprocating compressor rod packing. In the proposed 
rule, we proposed to require replacement of rod packing on or before 
26,000 hours or 3 years of operation, or alternatively to route 
emissions via a closed vent system under negative pressure. To account 
for segments of the industry in which reciprocating compressors operate 
in a pressurized mode for a fraction of the

[[Page 35849]]

calendar year, the standard is based on the determination that 26,000 
hours of operation are comparable to 3 years of continuous operation.
    In the final rule, we revised the definition of reciprocating 
compressor rod packing. The EPA received comment that the definition of 
rod packing should be included in the rule to clarify the intent to 
replace any component of the rod packing that was contributing to 
emissions from the rod packing assembly. Because we agree that this 
clarification is useful, we have revised the definition of 
reciprocating compressor rod packing in the final rule to mean 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 from the compressor, or 
any other mechanism that provides the same function of limiting the 
amount of compressed natural gas that escapes from the compressor. For 
additional details, please refer to section VIII, the TSD, and the RTC 
supporting documentation in the public docket.

C. Pneumatic Controllers

    For pneumatic controllers, comments and information available led 
us to finalize the standards as proposed. We proposed to require the 
use of low-bleed controllers in place of high-bleed controllers (i.e., 
natural gas bleed rate not to exceed 6 scfh) \79\ at all locations 
within the source category, except for natural gas processing plants. 
For natural gas processing plants, the standards require control of GHG 
and VOC emissions by requiring that pneumatic controllers have a zero 
natural gas bleed rate (i.e., they are operated by means other than 
natural gas, such as being driven by compressed instrument air).
---------------------------------------------------------------------------

    \79\ Low-bleed controllers are not affected facilities under 
this final rule.
---------------------------------------------------------------------------

    The final rule provides that certain pneumatic controllers, 
reflecting the particular functions they perform, have only tagging and 
recordkeeping and reporting requirements. As discussed in the proposal, 
the EPA identified situations where high-bleed controllers (i.e., 
controllers with a natural gas bleed rate greater than 6 scfh) are 
necessary because of 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 
compressor stations. The 2012 NSPS accounts for this by providing an 
exemption to pneumatic controllers for which compliance would pose a 
functional limitation due to their actuation response time or other 
operating characteristics. The EPA is finalizing the same exemption for 
all pneumatic controllers across the source category. For additional 
details, please refer to section VIII, the TSD, and the RTC supporting 
documentation in the public docket.

D. Pneumatic Pumps

    In the final rule, the EPA is finalizing requirements for pneumatic 
pumps that use control devices or processes that are already available 
onsite. At natural gas processing plants, the EPA proposed to require 
reductions of 100 percent of GHG (in the form of methane) and VOC 
emissions from all diaphragm pneumatic pumps. For locations other than 
natural gas processing plants, the EPA proposed to require reductions 
of 95 percent of GHG (in the form of methane) and VOC emissions from 
all natural gas-driven diaphragm pumps, if an existing control or 
process was available.
    The public comment process helped us to identify aspects of the 
proposed requirements that may not be practical or feasible in all 
cases, and commenters submitted additional information for us to 
analyze. In this final rule, based on our consideration of the comments 
received and other relevant information, we have made certain changes 
to the proposed standards for pneumatic pumps. The final standards 
require the GHG (in the form of a limitation on methane) and VOC 
emissions from new, modified, or reconstructed natural gas-driven 
diaphragm pumps located at well sites to be routed to an available 
control device or process onsite, unless such routing is technically 
infeasible at non-greenfield sites. We are not finalizing a technical 
infeasibility exemption at greenfield sites, where circumstances that 
could otherwise make control of a pneumatic pump technically infeasible 
at an existing location can be addressed in the site's design and 
construction. For pneumatic pumps located at a natural gas processing 
plant, the final rule requires the GHG (in the form of a limitation on 
methane) and VOC emissions from natural gas-driven diaphragm pumps to 
be zero.
    While we acknowledge that solar-powered, electrically-powered, and 
air-driven pumps cannot be employed in all applications, we encourage 
operators to use pumps other than natural gas-driven pneumatic pumps 
where their use is technically feasible. To incentivize the use of 
these alternatives, the final rule's definition of ``pneumatic pump 
affected facility'' described in Sec.  60.5365a(h) only includes 
natural gas-driven pumps. Pumps that are driven by means other than 
natural gas are not affected facilities subject to the pneumatic pump 
provisions of the NSPS and are not subject to any requirements under 
the final rule.
    Provided below are the significant changes since proposal that 
result from the information in the record and the comments that we 
received and our rationale for these changes. For additional details, 
please refer to section VIII, the TSD, and the RTC supporting 
documentation in the public docket.
1. Piston Pumps
    The EPA received several comments concerning the level of GHG and 
VOC emissions from natural gas-driven pneumatic piston pumps. The 
comments focused on the small volume of gas discharged by these pumps 
and the intermittent nature of their use. Other commenters suggested 
that the EPA treat pneumatic pumps consistently with pneumatic 
controllers. The commenters state that the same bleed rate 
considerations should be applied to pneumatic pumps because they are 
similar devices. Other commenters discussed the technical infeasibility 
of controlling emissions from piston pumps due to the inability to move 
such a small and intermittent gas flow through a duct or pipe to a 
control device.
    We agree with commenters that pneumatic controller bleed rate 
considerations can serve as a useful guide in considering emission 
reduction requirements for pneumatic pumps. In response to these 
comments, we further evaluated the natural gas flow rate of pneumatic 
pumps and agree that piston pumps are inherently low-emitting because 
of their small size, design, and usage patterns. As discussed in the 
TSD to the proposed rule, we used natural gas emission rates between 
2.2 to 2.5 scf/hr during operation of piston pumps. We determined these 
emission rates based on a joint report from the EPA and the Gas 
Research Institute on methane emissions from the natural gas industry. 
Our analysis of the currently available data, the information in the 
record, and consideration of public comments lead us to the conclusion 
that we should exclude piston pumps from coverage under the NSPS based 
on their inherently low emission rates. This approach is consistent 
with the manner in which we addressed low-bleed pneumatic controllers. 
After considering the inherently low emission rates of low-bleed 
pneumatic controllers, we determined that they should not be subject to 
the final rule requirements. Similarly, based upon the information

[[Page 35850]]

that we have on the low emission rates of piston pumps, we are not 
establishing requirements for them in this final rule.
    We note that our best available emissions data for diaphragm pumps, 
as discussed in the TSD, indicates that the emission rate ranges from 
about 20 to 22 scf/hr during operation of a diaphragm pump. Based on 
our analysis of this data, we do not believe exclusion of diaphragm 
pumps from the definition of a pneumatic pump affected facility is 
warranted. As a result, we are retaining requirements for diaphragm 
pumps in the final rule.
2. Pneumatic Pumps Located in the Gathering and Boosting and 
Transmission and Storage Segments
    We received comment that pneumatic pumps located in the 
transmission and storage segment generally have very low emissions. 
Similar to the arguments presented above for piston pumps, commenters 
contend that these low emission rate pumps should not be subjected to 
the final rule. In response to these comments, we reviewed our 
available information used in the proposed rule TSD to estimate the 
number of pneumatic pumps and the emission rates of these pumps in all 
segments of the oil and natural gas sector. In the TSD for the final 
rule, we noted that neither the GHGRP nor the GHG Inventory include 
data about pneumatic pumps or their emission rates in the natural gas 
transmission and storage segment. Because we currently have no reliable 
source of information indicating the prevalence of use of pneumatic 
pumps in this segment, nor what their emission rates would be if they 
are used, we are not finalizing pneumatic pump requirements for the 
transmission and storage segment at this time.
    We also reviewed the available GHGRP and GHG Inventory data for 
pneumatic pumps, which was limited to the production segment. We 
consider the production segment to include both well sites and the 
gathering and boosting segment. Our available data indicate that 
pneumatic pumps are used at well sites as well as emission data for 
those pumps, but are silent on the prevalence of use of pneumatic pumps 
in the gathering and boosting segment, and what their emission rates 
would be if they are used. As with pneumatic pumps in the transmission 
and storage segment, we are not finalizing pneumatic pump requirements 
for the gathering and boosting segments at this time because of the 
lack of information in the record to support finalizing requirements 
for these pumps.
    We note that the EPA is currently conducting a formal process to 
gather additional data on existing sources in the oil and natural gas 
sector. We believe that this data collection effort will provide 
additional information on the use and emissions of pneumatic pumps in 
the transmission and storage segment and gathering and boosting 
segment. Once we have obtained and analyzed these data, we will be 
better equipped to determine whether regulation of pneumatic pumps in 
the transmission and storage segment and gathering and boosting segment 
is warranted. See section III.E for more detail regarding the EPA's 
information collection request for existing sources.
3. Technical Infeasibility
    We agree with comments that there may be circumstances, such as 
insufficient pressure or control device capacity, where it is 
technically infeasible to capture and route pneumatic pump emissions to 
a control device or process, and we have made changes in the final rule 
to include an exemption for these instances. The owner or operator must 
maintain records of an engineering evaluation and certification 
providing the basis for the determination that it is technically 
infeasible to meet the rule requirements. The rule does not allow the 
operator to claim the technical infeasibility exemption for a pneumatic 
pump affected facility at a greenfield site (defined as a site, other 
than a natural gas processing plant, which is entirely new 
construction), where circumstances that could otherwise make control of 
a pneumatic pump technically infeasible at an existing location can be 
addressed in the site's design and construction.
4. Efficiency of Existing Control Devices
    As noted above, we are finalizing emission standards for new, 
modified, and reconstructed natural gas-driven diaphragm pumps located 
at well sites requiring emissions be reduced by 95 percent if either a 
control device or the ability to route to a process is already 
available onsite. In setting this requirement, the EPA recognizes that 
there may not be a control device or process available onsite. Our 
analysis shows that it is not cost-effective to require the owner or 
operator of a pneumatic pump affected facility to install a new control 
device or process onsite to capture emissions. In those instances, the 
pneumatic pump affected facility is not subject to the emission 
reduction provisions of the final rule.
    Commenters have also raised concerns, and we agree, that the 
control device available onsite may not be able to achieve a 95 percent 
emission reduction. We evaluated whether this requirement should only 
be triggered when a NSPS subpart OOOO or OOOOa compliant control device 
was onsite, which would alleviate the control efficiency concern raised 
by commenters. However, the EPA is concerned that significant emissions 
reductions would be lost as a result of limiting the required type of 
equipment that must be used to control pneumatic pump emissions to only 
those that are designed to achieve 95 percent emission reductions. We 
are not requiring the owner or operator to install a new control device 
on site that is capable of meeting a 95 percent reduction nor are we 
requiring that the existing control device be retrofitted to enable it 
to meet the 95 percent reduction requirement. However, we are requiring 
that the owner or operator of a pneumatic pump affected facility at 
well sites to route the emissions to an existing control device even if 
it achieves a level of emissions reduction less than 95 percent. In 
those instances, the owner or operator must maintain records 
demonstrating the percentage reduction that the control device is 
designed to achieve. In this way, the final rule will achieve emission 
reductions with regard to pneumatic pump affected facilities even if 
the only available control device on site cannot achieve a 95 percent 
reduction.
5. Compliance Requirements
    In response to concerns about applicability of subpart OOOO or 
OOOOa compliance requirements, the EPA has clarified our intent in the 
final rule that existing control devices that are not already subject 
to subparts OOOO or OOOOa compliance requirements (i.e., control 
devices that are subject to other federal or state compliance 
requirements) are not subject to the performance specifications, 
performance testing, and monitoring requirements in this rule solely 
because they are controlling pneumatic pump emissions. We believe that 
control devices covered by other federal, state, or other regulations 
would be subject to compliance requirements under those provisions and, 
therefore, we have reasonable assurance that the devices will perform 
adequately, and we do not need to include existing controls that are 
not already covered by subparts OOOO and OOOOa under the compliance 
requirements for these subparts.
6. Cost Analysis
    In response to commenters' concerns that the costs were 
underestimated for compliance with the pneumatic pump

[[Page 35851]]

requirements, we revised the cost analysis using the average of our 
annualized costs and two additional annualized cost estimates provided 
by commenters.\80\ Commenters' cost estimate methodologies and inputs 
varied from EPA's cost estimate which prevented us from conducting a 
side-by-side comparison with our cost estimate, nor could we directly 
compare the commenters' estimates with one another. However, in order 
to take into account the cost estimates provided by the commenters, we 
revised our cost analysis using the average of our annualized costs and 
the two additional annualized cost estimates provided by commenters. 
This is the same approach we would have taken had we obtained cost 
quotes from three separate vendors to install the closed vent system, 
and which we believe is the most equitable procedure when there is 
insufficient information to distinguish between the three cost 
estimates. One commenter gave an estimated capital cost of $5,800 which 
is annualized to be $826. A second commenter gave an estimated capital 
cost of $8,500 which annualized to be $1,210. The proposed capital cost 
to route emissions through a closed vent system was $2,000 which when 
annualized is $285. Based on our revised cost analysis, the capital 
cost for routing the emissions to an existing control device or process 
is $5,433, and the annualized cost is $774. We more fully discuss our 
cost estimate analysis in the TSD.
---------------------------------------------------------------------------

    \80\ See EPA docket ID No. EPA-HQ-OAR-2010-0505.
---------------------------------------------------------------------------

    We evaluated the cost of control for routing emissions to an 
existing combustion device or process where we assign the cost equally 
to methane and VOC. For diaphragm pumps at well sites, the cost of 
reducing methane emissions is $235 per ton and the cost of reducing VOC 
emissions is $847 per ton, using the single-pollutant approach. Based 
on this revised cost analysis using additional cost information, we 
find that the cost of control for reducing methane emissions remains 
reasonable.
7. Affected Facility Definition
    The EPA received comment that there was contradictory language in 
the proposal preamble and regulatory text regarding recordkeeping 
requirements for pneumatic pumps where no control device was on site. 
This lack of clarity was the result of the affected facility definition 
for pneumatic pumps. In the final rule, we have revised the definition 
to clarify that coverage under this rule is independent of availability 
of a control device on site. Specifically, all natural gas-driven 
diaphragm pumps at natural gas processing plants or well sites are 
affected facilities, except for pumps at well sites that operate less 
than 90 days per calendar year. The EPA has revised the final 
regulatory text to make clear that all pneumatic pumps affected 
facilities must be reported on the annual report and records maintained 
as applicable to control status of the pump.
8. Timing of Initial Compliance
    The EPA is also finalizing requirements for pneumatic pump affected 
facilities at natural gas processing plants. The EPA is finalizing GHG 
and VOC emissions control requirements for pneumatic pump affected 
facilities at well sites if there is a control device or ability to 
route to a process available on site or subsequently installed on site. 
We are also finalizing a technical infeasibility exception when it is 
infeasible to route the pneumatic pump to the control device (or route 
to a process) at non-greenfield sites. An owner or operator applying 
this exemption must obtain a professional engineering assessment 
demonstrating the reasons for the exemption.
    As pointed out by commenters, the technical infeasibility exemption 
may be based on safety concerns that could arise when a control device 
is not designed to handle the additional stream from the pneumatic 
pump. Commenters also expressed concern about safety issues related to 
increased pressure on the rest of the closed vent system connected to 
the control device. In light of these comments, we believe that the 
proposed 60-day compliance period may be insufficient to identify a 
qualified professional engineer, obtain the necessary design documents 
for the existing control device and associated ductwork, evaluate the 
design documents in light of the increased flow from the pneumatic 
pump, make an assessment of the technical feasibility of routing the 
pneumatic pump to the control device, and issue the required 
certification. Therefore, we are finalizing the compliance period to 
begin on November 30, 2016 to allow sufficient time for these necessary 
tasks to be completed.

E. Well Completions

    For the well completion requirements, we proposed to require RECs, 
when technically feasible and in combination with a completion 
combustion device, for subcategory 1 wells. For subcategory 2 wells, we 
proposed an operational standard 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. The proposed rule identified challenging issues 
for which we solicited comment in order to obtain additional 
information.
    The public comment process helped us to identify aspects of the 
proposed requirements that in practice may not be practical in all 
cases, and commenters submitted additional information for us to 
analyze. In this final rule, based on our consideration of the comments 
received and other relevant information, we have made certain changes 
to the proposed standards for well completions. The final rule refines 
the well completion requirements to reduce emissions and provide 
clarity for both operators and regulators. The EPA is finalizing well 
completion standards for hydraulically fractured or refractured 
wells.\81\ The final standards require a combination of REC and 
combustion at subcategory 1 wells and combustion at subcategory 2 wells 
and low pressure wells. Provided below are the significant changes 
since proposal that result from the comments we received and our 
rationale for these changes. For additional details, please refer to 
section VIII, the TSD, and the RTC supporting documentation in the 
public docket.
---------------------------------------------------------------------------

    \81\ As noted earlier in section IV, in 2012 EPA promulgated VOC 
standards for completions of hydraulically fractured or refractured 
gas wells. Today's action establishes GHG standards for gas well 
completions, as well as GHG and VOC standards for hydraulically 
fractured and refractured oil well completions.
---------------------------------------------------------------------------

1. Separator Function
    The EPA solicited comment on the use of a separator during flowback 
and whether a separator can be employed for every well completion. We 
received several comments identifying situations where a separator 
cannot function. Specifically, commenters noted instances where a 
separator cannot function due to very low gas flow from the well, 
contaminated gas flow, or low reservoir pressure requiring artificial 
lift techniques. Commenters indicate that because of these scenarios 
there can be a complete absence of a separation flowback stage during 
the well completion (which, according to the commenters, can be 
particularly common in some basins and fields). Commenters asserted 
that many of these circumstances can be anticipated prior to the onset 
of flowback. Furthermore, commenters stated that the requirement to 
have a separator onsite would likely

[[Page 35852]]

cause the operator to incur a cost with no environmental benefit 
derived.
    We believe that commenters have presented legitimate situations 
where it would be technically infeasible to use a separator, which is 
required for performing a REC. The challenge is, however, that the 
factors that lead to technical infeasibility of a separator to function 
may not be apparent until the time the well completion occurs, at which 
time it is too late to provide the equipment and, as a result, the well 
completion will go forward without controls. Further, the commenters 
did not provide data, and we do not have sufficient data to 
consistently and accurately identify the subcategory or types of wells 
for which these circumstances occur regularly or what criteria would be 
used as the basis for an exemption to the REC requirement such that a 
separator would not be required to be onsite for these specific well 
completions. In order to accommodate these concerns raised by 
commenters, the final rule requires a separator to be onsite during the 
entire flowback period for subcategory 1 wells (i.e., non-exploratory 
or non-delineation wells, also known as development wells), but does 
not require performance of REC where a separator cannot function. We 
anticipate a subcategory 1 well to be producing or near other producing 
wells. We therefore anticipate REC equipment (including separators) to 
be onsite or nearby, or that any separator brought onsite or nearby can 
be put to use. For the reason stated above, we do not believe that 
requiring a separator onsite would incur cost with no environmental 
benefit.
    However, unlike subcategory 1 wells, subcategory 2 wells are in 
areas where gas composition is likely unknown and, therefore, there is 
less certainty that a separator can work at these wells. If the 
separator does not work, there are unlikely subcategory 1 wells nearby 
that can put the separator to use. For the reasons stated above, we are 
not requiring that a separator be onsite for the well completion of 
subcategory 2 wells.
    The EPA had proposed that, for subcategory 2 wells and low pressure 
wells, operators would be required to route flowback to a completion 
combustion device as soon as the separator was able to function. We had 
based the proposed requirement for these wells on our determination 
that BSER was combustion, and efficient combustion using traditional 
combustion devices could be achieved through separation of the gas from 
the liquid and solid flowback materials prior to routing to the 
completion combustion device.
    As discussed in the 2015 proposal, traditional combustion devices 
(e.g., flares or enclosed combustors) cannot work initially because the 
flowback following hydraulic fracturing consists for liquids, gases and 
sand in high-volume, multiphase slug flow. As a result, these devices 
can work only after a separator can function. While pit flares can be 
installed and used from the start, considering the makeup of the 
initial flowback, we believe there is little gas to be burned, and so 
we assume there is not an appreciable difference between the amount of 
emissions reductions between a traditional combustion device and a pit 
flare. In addition, we believe that pit flares have increased potential 
for secondary impacts compared to traditional flares, due to the 
potential for the incomplete combustion of natural gas across the pit 
flare plume.
    Although not required, some owners and operators may choose to 
separate the gas from the other flowback materials for water management 
or other purposes. If a separator is used, any separated gas can be 
routed to combustion. In light of all of the above, we are providing in 
the final rule two options for completions of subcategory 2 wells: (1) 
Route all flowback directly to a completion combustion device (in that 
case a pit flare); or (2) should an owner or operator choose to use a 
separator, route the separated gas to a completion combustion device as 
soon as a separator is able to operate.
    We are providing the same two options for low pressure wells. We 
believe that 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, and low pressure gas could 
prevent proper operation of the separator. Alternatively, when 
feasible, some owners and operators may choose to separate the gas from 
the other flowback materials for water management or other purposes. If 
a separator is used, any separated gas must be routed to combustion.
2. REC Feasibility
    The second instance for potential technical infeasibility occurs 
during the separation flowback stage, where operators cannot perform a 
REC and, therefore, must combust. The EPA received comment that 
additional requirements are necessary to ensure that flaring of the 
recovered gas during the separation flowback stage is limited to 
scenarios where all options included in our definition for REC--(1) 
route the recovered gas from the separator into a gas flow line or 
collection system, (2) re-inject the recovered gas into the well or 
another well, (3) use the recovered gas as an onsite fuel source, or 
(4) use the recovered gas for another useful purpose that a purchased 
fuel or raw material would serve--have been pursued and their technical 
infeasibility documented.\82\ Commenters identified factors such as the 
availability and capacity of gathering lines, right of way issues, the 
quality of gas, and ownership issues that could impact the ability of 
operators to capture and use gas. Commenters stated that the provision 
for technical infeasibility for operators to use the recovered gas is 
vague and runs counter to the improvements the EPA seeks to establish 
within the oil and gas industry. Other commenters urged the EPA to 
allow flaring only as a last resort by requiring advanced notification 
and detailed documentation of the technical infeasibility of capturing 
and using salable quality gas. Commenters further stated that flaring 
should be very rarely necessary, as the EPA has identified four 
separate options for using recovered gas. The commenter recommends that 
EPA add additional notification and reporting requirements to ensure 
that all four options have been pursued and their technical 
infeasibility documented. The EPA agrees that the exemption from REC 
due to technical infeasibility should be limited. However, as 
illustrated by the comments received, the circumstances under which a 
REC is technically infeasible are varied. It is, therefore, difficult 
to provide one definition that can address all scenarios.
---------------------------------------------------------------------------

    \82\ This definition is the same as the definition for REC in 
subpart OOOO which, in response to public comment, included options 
in addition to routing to a gas line.
---------------------------------------------------------------------------

    The EPA considered, but declined to require, advanced notification 
for the following reasons. Technical infeasibility can be an after-the-
fact occurrence (i.e., gas was contaminated and not of salable quality 
or had characteristics prohibiting other beneficial use and, therefore, 
the gas was combusted); therefore, advanced notification may not always 
be possible. A case-by-case advance evaluation by a regulatory agency 
is also not feasible considering the large number of completions, the 
wide geographic dispersion of the completions and the remote location 
of many well sites. For these reasons, we are not requiring prior 
notification of the claim of the technical infeasibility exemption.
    Rather we have expanded recordkeeping requirements in the final

[[Page 35853]]

rule to include: (1) Detailed documentation of the reasons for the 
claim of technical infeasibility with respect to all four options 
provided in section 60.5375a(a)(1)(ii), including but not limited to, 
names and locations of the nearest gathering line; capture, re-
injection, and reuse technologies considered; aspects of gas or 
equipment prohibiting use of recovered gas as a fuel onsite; and (2) 
technical considerations prohibiting any other beneficial use of 
recovered gas onsite. We emphasize that the exemption is limited to 
``technical'' infeasibility (e.g., lack of infrastructure, engineering 
issues, safety concerns).
    In addition to the detailed documentation and recordkeeping 
requirement, the final rule requires that a separator be onsite during 
the entirety of the flowback period at subcategory 1 (developmental) 
wells, as described earlier. We believe these additional provisions 
will support a more diligent and transparent application of the intent 
of the technical infeasibility exemption from the REC requirement in 
the final rule. This information must be included in the annual report 
made available to the public 30 days after submission through the 
Compliance and Emissions Data Reporting Interface (CEDRI), allowing for 
public review of best practices and periodic auditing to ensure flaring 
is limited and emissions are minimized.
3. Gas to Oil Ratio (GOR) Exclusion
    We are not finalizing the proposed exclusion of wells with low GOR 
from the definition of a well affected facility. However, in the final 
rule, low GOR wells are not subject to REC or combustion requirements. 
In order to ensure that low GOR claims are not being made without 
sufficient analysis and oversight, the final rule requires that records 
used to make the GOR determination must be retained and a certifying 
official must sign the low GOR determination.
    The EPA proposed that wells with a 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.\83\ 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, in reality this is not practical given the design and operating 
parameters of separation units operating in the field.
---------------------------------------------------------------------------

    \83\ On February 24, 2015, API submitted a comment to the EPA 
stating that oil wells with GOR values less than 300 do not have 
sufficient gas to operate a separator. http://www.regulations.gov/#!documentDetail;D=EPA-HQ-OAR-2014-0831-0137.
---------------------------------------------------------------------------

    The EPA also solicited comment on how operators could identify low 
GOR wells (i.e., those with a GOR of less than 300 scf of gas per stock 
tank barrel of oil produced) prior to well completion, specifically the 
question of whether the GOR of nearby wells would be a reliable 
indicator in determining the GOR of a new or modified well. The EPA 
received comment stating that wells in the same area or reservoir could 
be used to indicate GOR prior to well completion. In light of the 
comments received and, upon further consideration, the EPA concludes 
that GOR of a well can be determined in advance. The EPA, therefore, 
does not believe that it is appropriate to prescribe in the final rule 
any specific way to determine the GOR for purposes of exempting low GOR 
wells from performing REC or combustion. However, to ensure that only 
those that, in fact, have GOR of less than 300 are exempt from the REC 
or combustion requirement; these wells remain affected facilities under 
the final rule. To ensure that their GORs are accurately determined, 
the final rule requires detailed documentation of their GOR 
determination as well as annual reporting and recordkeeping 
requirements. However, they are not subject to the REC or combustion 
requirement.
4. Low Pressure Wells
    We have revised the low pressure well definition in the final rule. 
In the 2012 NSPS, the EPA recognized that certain wells, which the EPA 
called ``low pressure gas wells,'' cannot implement a REC because of a 
lack of necessary reservoir pressure to flow gas at rates appropriate 
for the transportation of solids and liquids from a hydraulically 
fractured gas well against additional back pressure that would be 
caused by the REC equipment, thereby making a REC infeasible. The 2012 
NSPS exempts these wells from REC and instead requires combustion of 
the recovered gas.
    In the EPA's proposed rule (80 FR 56611, September 18, 2015), in 
which we proposed to also regulate VOC and GHG emissions from oil 
wells, we proposed to amend the current requirements for low pressure 
gas wells to apply to all low pressure wells. We proposed to change the 
term ``low pressure gas well'' to ``low pressure well'' but keep the 
definition the same. The substance of the definition at proposal for 
``low pressure well'' is the same as the currently codified definition 
for ``low pressure gas well'' in the 2012 NSPS. We solicited comment on 
whether this definition appropriately defined hydraulically fractured 
wells for which conducting a REC would be technologically infeasible or 
whether the definition should be revised to better characterize the 
criteria for all low pressure wells.
    In our proposed definition, the pressure of the flowback fluid 
(oil, gas, and water) immediately before it enters the flow line is 
calculated by equation (1) below:

PL (psia) = 0.445 [middot] PR (psia) - 0.038 [middot] L(ft) + 67.578 
Equation (1)

Where:

PL (psia) is the pressure of flowback fluid immediately before it 
enters the flow line;
PR (psia) is the pressure of the reservoir containing oil, gas, and 
water; and
L(ft) is the depth of the well.

    The EPA proposed that if the pressure of flowback fluid immediately 
before it enters the flow line, PL, calculated using the above equation 
is less than the available line pressure, the well would be considered 
a low pressure well. Such a well would not be required to do a REC 
during flowback (i.e., collect and send the associated gas to the flow 
line). Instead, such a well would only be required to combust the gas 
in a completion combustion device.
    Commenters asked the EPA to provide a new definition of ``low 
pressure oil well'' to differentiate oil wells from gas wells. They 
stated that the definition of ``low pressure well'' set out in proposed 
section 60.5430a and taken from the definition of ``low pressure gas 
well'' in subpart OOOO (section 60.5430) is not appropriate for a low 
pressure oil well, because the surface and back pressure for oil wells 
is higher than that for gas wells. They further state that ``. . . once 
the hydraulic fracture load stops coming back, a gas well will 
typically have much less liquids in the production tubing, making the 
surface pressure actually higher for the gas well vs. an oil well. This 
difference would be reflected in the 0.038 number which represents the 
gas gradient in the well, which would impart a back pressure. For oil 
wells this back pressure would be higher . . .'' In response to these 
comments, the EPA modified the existing low pressure gas well equation 
(equation (1) above) to add pressure drop resulting from flow of oil 
and water in a well.
    The EPA's evaluation of the steady flow of petroleum fluid (gas and 
oil) during flowback in wells resulted in the following modified 
equation, hereafter

[[Page 35854]]

referred to as the low pressure well equation (equation 2 below):
[GRAPHIC] [TIFF OMITTED] TR03JN16.000

Where:

PL is the pressure of flowback fluid immediately before it enters 
the flow line, expressed in psia;
PR is the pressure of the reservoir containing oil, gas, and water, 
expressed in psia;
L is the true vertical depth of the well, expressed in feet;
qo, qg, qw are the flow rates of oil, gas, and water, respectively, 
in the well, expressed in cubic feet/second; and
[rho]o is the density of oil in the well, expressed in pounds per 
cubic feet.

    EPA's low pressure well equation is used to predict the pressure of 
the flowback fluid (oil, gas, and water) immediately before it enters 
the flow line. The low pressure well equation uses inputs similar to 
those required for the gas well definition and for which information is 
understood to be available before well completion activity starts at a 
well site. These inputs include reservoir (or formation) pressure; true 
vertical depth of the well; flow rates of oil, gas, and water in the 
well; and the density of oil in the well.
    As oil-gas-water mixture flows upwards in a well to a lower 
pressure location, oil and gas volumes change and some of the dissolved 
gas evolves out of solution in oil. These phenomena result in oil and 
gas densities and volumetric flows changing with well depth. Therefore, 
oil density, [rho]o, and volumetric flow rate, qo, for use in equation 
(2) are calculated using the known value of oil API gravity at a well 
site and the widely used correlations provided in Vasquez and Beggs 
(1980).\84\ The gas volumetric flow, qg, is calculated using widely 
used correlations provided in Guo and Ghalambor (2005).\85\ Details on 
using equation (2) to calculate the pressure of flowback fluid 
immediately before it enters the flow line, PL, can be found in the TSD 
in the public docket.
---------------------------------------------------------------------------

    \84\ Vasquez, M. and Beggs, H.D., ``Correlations for fluid 
physical property prediction,'' JPT, 1980.
    \85\ Guo, B. and Ghalambor, A., ``Natural Gas Engineering 
Handbook,'' Gulf Publishing Company, 2005.
---------------------------------------------------------------------------

    As noted above, equation (2) is the low pressure well equation for 
all wells in the final rule. This equation predicts the pressure, PL, 
of the flowback fluid (oil, gas, and water) immediately before it 
enters the flow line during the separation flowback period. In response 
to comments, the EPA's final regulations require that this pressure be 
compared to the actual flow line pressure available at the well site. 
Wells with insufficient predicted pressure to produce into the flow 
line are required to combust the gas in a control device. Wells with 
sufficient pressure to produce into the flow line are required to 
capture the gas and produce it into the flow line.
    EPA further notes that equation (2) is a modification of equation 
(1) and adds pressure drop resulting from flows of oil and water. When 
characterizing a well with conditions of gas flow only (i.e., 
qo = qw = 0), equation (2) reduces to equation 
(1), the equation for gas wells. Also note that equation (2) for line 
pressure is derived using a vertical well. It is known that inclined 
wells exist in the field, which will experience a somewhat higher 
frictional drop due to longer flow length. Nonetheless, it is expected 
that equation (2) would be able to account for minor increases in 
pressure drop due to increased frictional drop at inclined wells 
because the frictional pressure drop component contributes a small 
amount to the total pressure drop (about 1 percent on average) and 
conservative assumptions were used in deriving equation (2)--notably, 
bottom hole pressure equals one-half of formation pressure.
    In addition to the revised low pressure well equation, we are 
providing, in the final definition of low pressure well, other 
characteristics of the well that would indicate that a well is a low 
pressure well. We believe that if the static pressure (i.e., pressure 
with the well shut in and not flowing) at the wellhead following 
hydraulic fracturing, and prior to the onset of flowback, is less than 
the flow line pressure at the sales meter, the well is a low pressure 
well without having to demonstrate that it is such by using the low 
pressure well equation in the final rule.
    Instead of using the equation, under the final rule, operators who 
suspect that a well may be a low pressure well have the option, for 
screening purposes, of performing a wellhead static pressure (i.e., 
pressure with the well shut in and not flowing) check following 
fracturing and prior to the onset of flowback. If the static pressure 
at the wellhead was less than the flow line pressure at the sales 
meter, then the well would be a low pressure well. We believe that such 
a comparison would be conservative because, for a given well, the 
static pressure (i.e., with no fluid movement through the well) would 
be higher than the dynamic pressure (i.e., with the well flowing) 
because there would be no pressure losses brought about by friction 
caused by material movement in the tubing string. For some wells, use 
of this method could eliminate the need for the detailed calculations 
provided in the low pressure well equation discussed above. For other 
wells (i.e., those wells where the static pressure was greater than the 
flow line pressure), it would be necessary for the operator to use the 
low pressure well equation.
    Commenters asserted that many oil reservoirs have pressure that is 
insufficient for wells to naturally flow even after hydraulic 
fracturing. The commenters stated that this can be evidenced by the 
prevalence of artificial lift equipment such as rod pumps visible 
across the landscape of many oil producing areas. The commenters cited 
examples of reservoirs such as the Permian Basin, where horizontal 
drilling is used to extend the life of existing producing formations. 
The commenters explained that many oil wells that are hydraulically 
fractured do not have sufficient reservoir pressure to flowback 
fracture fluids. One company estimated that 30 percent of its 
hydraulically fractured horizontal wells and 80 percent of its 
hydraulically fractured vertical wells in the Permian Basin require 
artificial lift to flowback. In these cases, the commenter explained, 
rod pumps are installed on the wells to artificially lift the fracture 
fluids to the surface. In light of the comments received, the EPA 
believes that wells that require artificial lift equipment for flowback 
of fracture fluids should be classified as low pressure wells, as we 
believe that

[[Page 35855]]

performing a REC is technically infeasible for these wells.
    To meet the definition of low pressure well, the well must satisfy 
any of the criteria above. We have revised the definition in the 
regulatory text to reflect this change. Section VIII, the RTC document, 
the TSD, and other materials available in the docket provide more 
discussion of these topics.
5. Timing of Initial Compliance
    The EPA proposed the well completion requirements that, if 
finalized, would apply to both oil and gas well completions using 
hydraulic fracturing. In the 2012 NSPS, we provided a phase-in approach 
in the gas well completion requirements due to the concern with 
insufficient REC and trained personnel if REC were required immediately 
for all gas well completions. However, we did not provide the same in 
this proposal on the assumption that the supplies of REC equipment and 
trained personnel have caught up with the demand and, therefore, are no 
longer an issue. While some commenters agreed, other commenters 
indicated that the proposed rule, which would dramatically increase the 
number of well completions subject to the NSPS, would lead to REC 
equipment shortages. One commenter estimated that it would take at 
least 6 months to obtain the necessary equipment, while another 
commenter estimated that it would take 24 months. One commenter noted 
that owners and operators have been drilling wells, but delaying 
completion, due to the current economic conditions affecting the 
industry, causing a suppressed equipment demand. Finally, one state 
regulatory agency recommended extending the compliance period to 120 
days to allow sufficient time to contract for the necessary completion 
equipment.
    After reviewing the comments, we agree that some owners and 
operators may have difficulty complying with the REC requirements in 
the final rule in the near term due to the unavailability of REC 
equipment. Although REC equipment suppliers have increased production 
to meet the demand for gas well completions under subpart OOOO, the 
affected facility under subpart OOOOa includes both gas and oil wells 
and will more than double the number of wells requiring REC equipment 
over subpart OOOO. We believe this demand will likely lead to a short-
term shortage of REC equipment. However, based on the prior experience, 
we believe that suppliers have both the capability and incentive to 
catch up with the demand quickly, as opposed to the longer terms 
suggested by the commenters; they likely already stepped up production 
since this rule was proposed last year in anticipation of the impending 
increase in demand. In light of the above, the final rule provides a 
phase-in approach that would allow a quick build-up of the REC supplies 
in the near term. Specifically, for subcategory 1 oil wells, the final 
rule requires combustion for well completions conducted before November 
30, 2016 and REC if technically feasible for well completions conducted 
thereafter. For subcategory 2 and low pressure oil wells, the final 
rule requires combustion during well completion, which is the same as 
that required for completion of subcategory 2 and low pressure gas well 
in the 2012 NSPS. For gas well completions, which are already subject 
to well completion requirements in the 2012 NSPS, the requirements 
remain the same.

F. Fugitive Emissions From Well Sites and Compressor Stations

    For fugitive emissions requirements for the source category, three 
principles or aims directed our efforts. The first aim was to produce a 
consistent and accountable program for a source to use to identify and 
repair fugitive emissions at well sites and compressor stations. A 
second aim was to provide an opportunity for companies to design and 
implement their own fugitive emissions monitoring and repair programs. 
The third aim was to focus the fugitive emissions monitoring and repair 
program on components from which we expected the greatest emissions, 
with consideration of appropriate exemptions. The fourth aim was to 
establish a program that would complement other programs currently in 
place. With these principles in mind, we proposed a detailed monitoring 
plan; semiannual requirements using OGI technology for monitoring to 
find and repair sources of fugitive emissions, which we had identified 
as the BSER; a shifting monitoring schedule based on performance; a 15-
day timeframe for repairing and resurveying leaks; and an exemption for 
low production wells.
    The public comment process helped us to identify additional 
information to consider and provided an opportunity to refine the 
standards proposed. Commenters specifically identified concerns with 
the definition of modification for well sites and compressor stations, 
the monitoring plan, the fluctuating survey frequency, the overlap with 
state and federal requirements, use of emerging monitoring 
technologies, the initial compliance timeframe, and the relationship 
between production level and fugitive emissions.
    In this final rule, based on our consideration of the comments 
received and other relevant information, we have made changes to the 
proposed standards for fugitive emissions from well sites and 
compressor stations. The final rule refines the monitoring program 
requirements while still achieving the main goals. Below we describe 
the significant changes since proposal for specific topics related to 
fugitive emissions and our rationale for these changes. For additional 
details, please refer to section VIII, the TSD, and the RTC supporting 
documentation in the public docket.
1. Fugitive Emissions From Well Sites
a. Monitoring Frequency
    In conjunction with semiannual monitoring, the EPA co-proposed 
annual monitoring and solicited comment on the availability of trained 
OGI contractors and OGI instrumentation. 80 FR 56637, September 18, 
2015. Commenters provided numerous comments and data regarding annual, 
semiannual and quarterly monitoring surveys. These comments largely 
focused on the cost, effectiveness, and feasibility of the different 
program frequencies. The EPA evaluated these comments and information, 
as well as certain production segment equipment counts from the 2016 
public review draft GHG Inventory, which were developed from the data 
reported to the GHGRP. Based on the above information, the EPA updated 
its proposal assumptions on equipment counts per well site to use data 
from the 2016 public review draft update. This resulted in changes to 
the well site model plant. Specifically, the equipment count for 
meters/piping at a gas well site increased from 1 to 3, which tripled 
the component counts from meters/piping at these sites. In addition, 
the EPA developed a third model plant to represent associated gas well 
sites. This category includes wells with GOR between 300 and 100,000 
standard cubic feet per barrel (scf/bbl), and the model plant is 
assumed to have the same component counts as the model oil well site, 
as well as components associated with meters/piping. The EPA used this 
information to re-evaluate the control options for annual, semiannual 
and quarterly monitoring. As shown in the TSD, the control cost, using 
OGI, based on quarterly monitoring is not cost-effective, while both 
semiannual and annual monitoring remain cost-effective for reducing GHG 
(in the form of

[[Page 35856]]

methane) and VOC emissions. Because control costs for both semiannual 
and annual monitoring are cost-effective, we evaluated the difference 
in emissions reductions between the two monitoring frequencies and 
concluded that semiannual monitoring would achieve greater emissions 
reductions. Therefore, the EPA is finalizing the proposed semiannual 
monitoring frequency. Please see the RTC document in the public docket 
for further discussion.\86\ Even though the EPA has determined that 
semi-annual surveys for well sites is the BSER under this NSPS, this 
does not preclude the EPA from taking a different approach in the 
future, including requiring more frequent monitoring (e.g., quarterly).
---------------------------------------------------------------------------

    \86\ See EPA docket ID No. EPA-HQ-OAR-2010-0505.
---------------------------------------------------------------------------

b. Low Production Well Sites
    The EPA proposed to exclude low production well sites (i.e., well 
sites where the average combined oil and natural gas production is less 
than 15 barrels of oil equivalent (boe) per day averaged over the first 
30 days of production) from the fugitive emissions monitoring and 
repair requirements for well sites. As we explained in the preamble to 
the proposed rule, we believed that these wells are mostly owned by 
small businesses and that fugitive emissions associated with these 
wells are generally low. 80 FR 56639, September 18, 2015. We were 
concerned about the burden on small businesses, in particular, where 
there may be little emission reduction to be achieved. Id. We 
specifically requested comment on the proposed exclusion and the 
appropriateness of the 15 boe per day threshold. We also requested data 
that would confirm that low production sites have low GHG and VOC 
fugitive emissions.
    Several commenters indicated that low production well sites should 
be exempt from fugitive emissions monitoring and that the 15 boe per 
day threshold averaged over the first 30 days of production is 
appropriate for the exemption, however, commenters did not provide 
data. Other commenters indicated that the low production well sites 
exemption would not benefit small businesses since these types of wells 
would not be economical to operate and few operators, if any, would 
operate new well sites that average 15 boe per day.
    Several commenters stated that the EPA should not exempt low 
production well sites because they are still a part of the cumulative 
emissions that would impact the environment. One commenter indicated 
that low production well sites have the potential to emit high fugitive 
emissions. Another commenter stated that low production well sites 
should be required to perform fugitive emissions monitoring at a 
quarterly or monthly frequency. One commenter provided an estimate of 
low producing gas and oil wells that indicated that a significant 
number of wells would be excluded from fugitive emissions monitoring.
    Based on the data from DrillingInfo, 30 percent of natural gas 
wells are low production wells, and 43 percent of all oil wells are low 
production wells. The EPA believes that low production well sites have 
the same type of equipment (e.g., separators, storage vessels) and 
components (e.g., valves, flanges) as production well sites with 
production greater than 15 boe per day. Because we did not receive 
additional data on equipment or component counts for low production 
wells, we believe that a low production well model plant would have the 
same equipment and component counts as a non-low production well site. 
This would indicate that the emissions from low production well sites 
could be similar to that of non-low production well sites. We also 
believe that this type of well may be developed for leasing purposes 
but is typically unmanned and not visited as often as other well sites 
that would allow fugitive emissions to go undetected. We did not 
receive data showing that low production well sites have lower GHG 
(principally as methane) or VOC emissions other than non-low production 
well sites. In fact, the data that were provided indicated that the 
potential emissions from these well sites could be as significant as 
the emissions from non-low production well sites because the type of 
equipment and the well pressures are more than likely the same. In 
discussions with us, stakeholders indicated that well site fugitive 
emissions are not correlated with levels of production, but rather 
based on the number of pieces of equipment and components. Therefore, 
we believe that the fugitive emissions from low production and non-low 
production well sites are comparable.
    Based on these considerations and, in particular, the large number 
of low production wells and the similarities between well sites with 
production greater than 15 boe per day and low production well sites in 
terms of the components that could leak and the associated emissions, 
we are not exempting low production well sites from the fugitive 
emissions monitoring program. Therefore, the collection of fugitive 
emissions components at all new, modified or reconstructed well sites 
is an affected facility and must meet the requirements of the fugitive 
emissions monitoring program.
c. Monitoring Using Method 21
    The EPA's analysis for the proposed rule found OGI to be more cost-
effective at detecting fugitive emissions than the traditional protocol 
for that purpose, Method 21, and the EPA, therefore, identified OGI as 
the BSER for monitoring fugitive emissions at well sites. See 80 FR 
56636, September 18, 2015. The EPA solicited comment on whether to 
allow Method 21 as an alternative fugitive emissions monitoring method 
to OGI. 80 FR 56638, September 18, 2015. We also solicited comment on 
the repair threshold for components that are found to have fugitive 
emissions using Method 21. Id.
    Numerous industry, state, and environmental commenters indicated 
that Method 21 is preferred or should be allowed as an alternative to 
OGI, citing availability, costs, and training associated with OGI.
    Several commenters indicated that the EPA should set the Method 21 
fugitive emissions repair threshold at 10,000 ppm, the level at which 
our recent work indicates that fugitive emissions are generally 
detectable using OGI instrumentation provided that the right operating 
conditions (e.g., wind speed and background temperature) are present. 
80 FR 56635, September 18, 2015. Some commenters stated that the repair 
threshold should be 500 ppm to achieve a high level of fugitive 
emission reductions while other commenters state that a 500 ppm repair 
threshold would target fugitive emissions that would not provide 
meaningful reductions.
    The issue of the repair threshold when Method 21 is used is a 
critical decision. As discussed in the preamble to the proposed rule, 
Method 21, at an appropriate repair threshold, is capable of achieving 
the same or better emission reductions as OGI. However, at proposal, we 
determined that Method 21 was not cost-effective at a semiannual 
monitoring frequency with a repair threshold of 500 ppm.
    While we agree with the importance of allowing the use of Method 21 
as an alternative, we need to ensure that its use does not result in 
fewer emissions reductions than what would otherwise be achieved using 
OGI, which is the BSER based on our analysis. Available data show that 
OGI can detect fugitive emissions at a concentration of at least 10,000 
ppm when restricting its use during certain environmental conditions

[[Page 35857]]

such as high wind speeds. Due to the dynamic nature for the OGI 
detection capabilities, OGI may also image emissions at a lower 
concentration when environmental conditions are ideal. Because an OGI 
instrument can only visualize emissions and not the corresponding 
concentration, any components with visible emissions, including those 
emissions that are less than 10,000 ppm, would be repaired. Method 21 
is capable of detecting fugitive emissions at concentrations well below 
10,000 ppm. However, if the repair threshold was set at 10,000 ppm, an 
owner or operator would not have to repair any leaks that are less than 
10,000 ppm, thereby foregoing the reductions that would otherwise be 
achieved by using the OGI. For the reason outlined in this section, 
10,000 ppm is not an appropriate repair threshold for Method 21.
    Using information provided by commenters, we evaluated the methane 
and VOC emission reductions associated with the use of Method 21 at 
repair thresholds of 10,000 ppm and 500 ppm, the two levels recommended 
by the various commenters. We used AP-42 emission factors to determine 
the emissions from fugitive emissions components that were found to be 
leaking using a Method 21 instrument and concluded that emissions 
reductions are lower than when OGI is used to survey the same 
components. The lower emission reductions are due to fugitive emissions 
with a concentration lower than 10,000 ppm not being found using the 
Method 21 instrument when it is calibrated to detect emissions at a 
threshold of 10,000 ppm or greater.
    We then calculated the emission reductions that result from using a 
Method 21 instrument to conduct a monitoring survey at a repair 
threshold of 500 ppm. At this threshold, the operator would have to 
repair every component found to have fugitive emissions over 500 ppm 
threshold. This results in emission reductions greater than the 
emissions reductions that would be achieved if OGI were used instead. 
For the reasons stated in this section, using Method 21 to conduct 
monitoring surveys at a repair threshold of 500 ppm is better than, or 
at least equivalent to, using OGI to conduct the same survey; we are 
allowing it in the final rule as an alternative to the use of OGI. We 
acknowledge that the cost of conducting a survey using Method 21 may be 
more expensive than using OGI; however, some owners or operators may 
still chose to use Method 21 for convenience or due to the lack of 
availability of OGI instruments or trained personnel. Therefore, to 
ensure that it achieves at least the level of emission reduction to be 
achieved using the OGI, the final rule allows the use of Method 21 with 
a repair threshold of 500 ppm.
    Based on interest in having Method 21 as an approved alternative, 
we are finalizing it as an alternative to OGI. Allowing Method 21 as an 
alternative will address some of the uncertainty expressed by small 
entities that indicated a concern with needing to purchase an OGI 
instrument or hire trained OGI contractors to perform their monitoring 
surveys. We are finalizing Method 21 as an alternative to OGI for 
monitoring fugitive emissions components at a repair threshold of an 
instrument reading of 500 ppm or greater. We are also finalizing 
specific recordkeeping and reporting requirements when Method 21 is 
used to perform a monitoring survey.
d. Shifting of Monitoring Frequency Based on Performance
    The EPA proposed shifting monitoring frequencies (ranging from 
annual to quarterly monitoring) based on the percentage of components 
that are found to have fugitive emissions during a monitoring survey. 
We solicited comment on the proposed monitoring approach, including the 
proposed metrics of one percent and three percent to determine 
monitoring frequency or whether the monitoring frequency thresholds 
should be based on a specific number of components that are found to 
have fugitive emissions. In addition, the EPA solicited comment on 
whether a performance-based frequency or a fixed-frequency program was 
more appropriate.
    Most commenters opposed performance-based monitoring frequency. 
They raised specific concerns that performance-based monitoring and 
shifting monitoring frequencies would be costly, time-consuming, and 
impose a complex administrative burden for the industry and states. For 
example, commenters pointed out that an owner may have hundreds or even 
thousands of well sites and a potentially ever-changing survey schedule 
for each of those sites would present an untenable logistical hurdle. 
Most of the commenters stated that the EPA should finalize a fixed 
monitoring frequency to provide a level of certainty to owners and 
operators for planning future schedules of survey crews.
    The EPA considered these comments and agrees that imposing a 
performance-based monitoring schedule would require operators to 
develop an extensive administrative program to ensure compliance. Under 
the performance-based monitoring, owners and operators would need to 
count all of the components at the well sites, affix identification 
tags on each component or develop detailed piping and instrument 
diagram. During each monitoring survey, owners and operators would need 
to calculate the percentage of leaking fugitive emissions components to 
determine the next monitoring frequency schedule.
    We also agree that the shifting monitoring frequencies could cause 
regulated entities additional administrative burden to determine 
compliance since the monitoring frequencies could change each year, but 
the correct frequency may not be reflected in the operating permit. 
This could also result in fugitive emissions being undetected longer 
due to less frequent monitoring. We believe that the potential for a 
performance-based approach to encourage greater compliance is 
outweighed in this case by these additional burdens and the complexity 
it would add. Therefore, the EPA is finalizing a fixed-frequency 
monitoring instead of performance-based monitoring.
e. Fugitive Emissions Components Repair and Resurvey
    The EPA proposed that components that are a source of fugitive 
emissions must be repaired or replaced as soon as practicable and, in 
any case, no later than 15 calendar days after detection of the 
fugitive emissions. For sources of fugitive emissions that cannot be 
repaired within 15 days of finding the emissions, due to technical 
infeasibility or unsafe conditions, the EPA proposed that the 
components could be placed on a delay of repair until the next 
scheduled shutdown or within six months, whichever is earlier. We also 
proposed that a repaired fugitive emissions component be resurveyed 
within 15 days of the repair. The EPA solicited comment on all three 
aspects.
    Commenters voiced various opinions regarding the requirements. Many 
commenters shared concerns that the 15-day window for repairs is too 
short, due to factors such as remoteness of equipment locations, 
unsuccessful repair attempts, and multiple components needing repair. 
Other commenters preferred the 15-day window, in the interest of 
achieving immediate mitigation of health and safety risks and alignment 
with standards in several states.
    Multiple commenters provided comments on the proposed delay of

[[Page 35858]]

repair standards, including concerns about delays lasting longer than 
six months due to availability of supplies needed to complete repairs 
and information regarding the frequency of delayed repairs. Some 
commenters also indicated that in some cases, requiring prompt repairs 
could lead to more emissions than if repairs were able to be delayed, 
for example if a well shut-in or vent blow-down is required.
    Regarding the 15-day window to resurvey repairs to fugitive 
emissions components, multiple commenters stated that the final rule 
should allow 30 days for the resurvey, due to the potential need for 
specialized personnel for the resurvey, while others considered 15 days 
to be adequate. Regarding performance of the resurvey, many commenters 
also suggested that soap bubbles, as specified in section 8.3.3 of 
Method 21, be allowed to determine if the components have been 
repaired.
    After considering the comments above, the EPA agrees that repairs 
for some sources of fugitive emissions at a well site may take multiple 
attempts or require additional equipment that is not readily available 
and may take longer than 15 days to repair. Well sites, unlike chemical 
plants or refineries, may be located in remote areas and it is unlikely 
that they would have warehouses or maintenance shops nearby where spare 
equipment or tools are kept that would be needed to perform repairs 
within 15 days. We also recognize that fugitive emissions must be 
alleviated as soon as practicable. We believe that allowing an 
additional 15 days for repair would give owners and operators enough 
time to get the parts or the personnel needed to repair or replace the 
components that could not be repaired during the initial monitoring 
survey. Therefore, we are finalizing 30 days for the repair of fugitive 
emissions sources. However, we do recognize that some state LDAR 
programs require repairs to be made within 5 to 15 days of finding a 
leak. We encourage operators to continue to fix leaks within that 
timeframe, since the majority of leaks are fixed when they are found. 
We do expect that the majority of components will not need the 
additional 15 days for repair.
    The EPA agrees, based on our review of the comments, that only a 
small percentage of components would not be able to be repaired during 
that 30 day period. We also agree that a complete well shutdown or a 
well shut-in may be necessary to repair certain components, such as 
components on the wellhead, and this could result in greater emissions 
than what would be emitted by the leaking component. The EPA does not 
agree that unavailability of supplies or custom parts is a 
justification for delaying repair (i.e., beyond the 30 days for repair 
provided in this final rule) since the operator can plan for repair of 
fugitive emission components by having stock readily accessible or 
obtaining the parts within 30 days after finding the fugitive 
emissions.
    Based on available information, it may be two years before a well 
is shut-in or shutdown. Therefore, to avoid the excess emissions (and 
cost) of prematurely forcing a shutdown, we are amending the rule to 
allow 2 years to fix a leak where it is determined to be technically 
infeasible to repair within 30 days; however, if an unscheduled or 
emergency vent blowdown, compressor station shutdown, well shutdown, or 
well shut-in occurs during the delay of repair period, the fugitive 
emissions components would need to be fixed at that time. The owner or 
operator will have to record the number and types of components that 
are placed on delay of repair and record an explanation for each delay 
of repair.
    Method 21 allows a user to spray a soap solution on components that 
are operating under certain conditions (e.g., no continuous moving 
parts or no surface temperatures above the boiling point or below the 
freezing point of the soap solution) to determine if any soap bubbles 
form. If no bubbles form, the components are deemed to be operating 
with no detected emissions. We note that spraying soap solution to 
confirm whether a component has been repaired may not work for all 
fugitive emissions components, such as a leak found under the hood of 
the thief hatch because it would be difficult to apply the soap 
solution or observe bubbles. However, we believe that this alternative 
will provide some owners and operators a simple, low cost way to 
confirm that a fugitive emissions component has been repaired. This 
would also allow the resurveys to be performed by the same personnel 
that completed the repairs instead of other certified monitoring 
personnel or hired contractors that would have to come back to verify 
the repairs. Therefore, we are finalizing the use of the alternative 
screening procedures specified in Section 8.3.3 of Method 21 for 
resurveying repaired fugitive emissions components, where appropriate.
    For owners or operators that cannot use soap spray to verify 
repairs, we are allowing an additional 30 days for resurvey of the 
repaired fugitive emissions components, to allow time for contractors 
or designated OGI personnel to perform the resurvey because they are 
not typically the same personnel that would perform the repairs.
f. Definition of ``Fugitive Emission Component''
    As just discussed, we proposed monitoring, repair, and resurvey of 
``fugitive emission components.'' The EPA solicited comment on the 
proposed definition of fugitive emissions components. Commenters 
indicated that, as proposed, the fugitive emissions component 
definition is too broad and vague, because it contains both equipment 
and component types, and suggested that the EPA modify the definition 
to be more targeted and easier for states and other regulatory 
authorities to determine compliance, and recommended other definitions, 
such as that used by the state of Colorado.
    The EPA agrees with commenters that, as proposed, the fugitive 
emissions component definition may cause confusion due to inclusion of 
equipment types, such as uncontrolled storage vessels that are 
potential sources of vented emissions (as opposed to fugitive 
emissions), in the definition.
    Therefore, we are finalizing changes to the definition to remove 
equipment types and identify specific components, such as valves and 
flanges, that have the potential to be sources of fugitive emissions 
and that, when surveyed and repaired, would significantly reduce GHG 
and VOC emissions. This targeted list will remove the ambiguity of the 
proposed definition and will allow owners and operators to consistently 
identify fugitive emissions at well sites. We are finalizing the 
definition for fugitive emissions components in Sec.  60.4530a of this 
final rule.
    As finalized, the definition also aligns closely with other states' 
and federal agencies' definitions of fugitive emissions components by 
targeting similar components to the components in those definitions. 
Owners and operators can therefore monitor one set of components while 
complying with the requirements of this final rule and other state or 
federal fugitive emissions monitoring programs.
g. Timing of the Initial Monitoring Survey
    The EPA proposed that the initial monitoring be conducted within 30 
days after the initial startup of the first well completion or 
modification of a well site. EPA solicited comment on whether the 
proposal provides an appropriate amount of time to begin conducting 
fugitive emissions monitoring. We received a wide variety of comments

[[Page 35859]]

and suggestions for the appropriate time for fugitive emissions 
monitoring to begin.
    Several commenters indicated that initial monitoring should begin 
after production starts, because time is needed to close out the 
drilling activities. The commenters further stated that completion 
activities and the transition from completion to production at well 
sites is unpredictable and temporary completion equipment may still be 
onsite 30 days after the ``initial startup of the first well 
completion.'' One commenter indicated that production may not begin 
immediately after a well completion, so initial monitoring should not 
begin until after production starts.
    The EPA acknowledges that at the time of a well completion all of 
the associated permanent equipment may not be present and conducting 
the initial monitoring survey may not capture all of the fugitive 
emissions components that would be in operation during production. In 
addition, we believe it is important to conduct the initial survey soon 
after the permanent equipment is in place to catch any improperly 
installed or defective equipment that may have substantial fugitive 
emissions immediately after installation. We believe that the permanent 
equipment will be in place at the startup of production (i.e., the 
initial flow following the end of the flowback when there is continuous 
recovery of saleable quality gas). Therefore, the startup of production 
more accurately reflects the start of normal operations and would 
capture any fugitive emissions from the newly constructed or modified 
components at the well site. Therefore, we are finalizing that the 
startup of production marks the beginning of the initial monitoring 
survey period for the collection of fugitive emissions components.
    Furthermore, based on the comments received, we are concerned that 
the tasks required prior to conducting an initial survey would take 
more than the 30 days we had proposed. Because each new or modified 
well site must be covered by a monitoring plan for a company-defined 
area, owners and operators must visit and assess each new or modified 
well site in order to incorporate it into a newly developed or modified 
monitoring plan for that area. They also need to secure certified 
monitoring survey contractors or monitoring instruments. In addition, 
they need to ensure that other compliance requirements will be met, 
such as recordkeeping and reporting. In light of the activities 
described above, the EPA is requiring in the final rule that the 
initial survey be conducted within 60 days from the startup of 
production.
    While 60 days from startup of production is sufficient time to 
conduct the initial survey once the underlying program infrastructure 
is established, we recognize that the initial establishment of the 
required program's infrastructure and the initial round of monitoring 
surveys will require additional time. Most importantly, additional time 
is needed to secure the necessary equipment or trained personnel, 
according to one OGI instrument manufacturer, which commented that they 
would need to increase production of key components for the OGI 
instrument to meet demand. The OGI manufacturer also indicated that 
they would need to scale up the number of personnel needed to provide 
OGI training and service of the equipment. We are concerned that 
currently there is not sufficient equipment and trained personnel to 
meet the demand imposed by this final rule in the near term. 
Accordingly, it will be necessary to have a window of time for trained 
personnel to work through this backlog. Furthermore, as previously 
mentioned, an owner or operator will need to develop a monitoring plan 
that would apply to each well site located within the company-defined 
area, which requires an assessment of each well site. Therefore, before 
a plan can be developed or modified, the owner or operator would need 
time to visit each well site within the company-defined area. Based on 
the information that we used to develop the model well site plants, 
each company-defined area may consist of up to 22 well sites within a 
70-mile radius of a central or district office. In light of the above, 
the initial site visits and development of the monitoring plan would 
require a significant amount of time. Time is also needed to secure 
certified monitoring survey contractors or monitoring instruments. In 
addition, owners and operators will need to plan the logistics of the 
initial activities in order to comply with the requirements. This 
includes time to set up recordkeeping systems and to train personnel to 
manage the fugitive emissions monitoring program. These corporate 
systems are critical for submitting the notification of initial and 
subsequent annual compliance status.
    As noted above, once programs are established and equipment 
supplies have caught up, well owners will be able to add additional 
affected facilities to existing programs and, thus, this longer 
timeline will not be needed. Therefore, in order to provide time for 
owners and operators to establish the initial groundwork of their 
fugitives program, we are requiring that the initial monitoring survey 
must take place by June 3, 2017 or within 60 days of the startup of 
production, whichever is later.\87\ We anticipate that sources will 
begin to phase in these requirements as additional devices and trained 
personnel become available. For additional discussion, please refer to 
the materials in the docket.
---------------------------------------------------------------------------

    \87\ For well site activities, such as the installation of a new 
well, a hydraulically fractured or refractured well, which commenced 
on or after September 18, 2015 are subject to this rule once it is 
finalized.
---------------------------------------------------------------------------

h. Monitoring Plan
    The EPA proposed that owners or operators develop a corporate-wide 
fugitive emissions monitoring plan that specifies the measures for 
locating sources and the detection technology to be used. We also 
proposed that, in addition to the corporate-wide monitoring plan, 
owners or operators develop a site-specific fugitive emissions 
monitoring plan that specifies information such as the number of 
fugitive emission components that pertains to that single site.\88\ The 
EPA solicited comment on the required elements of the proposed 
corporate-wide monitoring plan; specifically, the EPA asked for comment 
on whether other techniques, such as visual inspections to help 
identify indicators of potential leaks, should be included within the 
monitoring plan.
---------------------------------------------------------------------------

    \88\ See 80 FR 56612 (September 18, 2015).
---------------------------------------------------------------------------

    Some commenters agreed with the EPA's proposal to require a 
corporate-wide fugitive monitoring plan but expressed concerns about 
the elements of the plan, while others objected that the proposed plan 
is overly prescriptive and costly, with particular concerns about 
including requirements for a walking path and for digital photographs. 
Other commenters suggested changing the scope of monitoring plans to 
accommodate variations in locations of contractors and equipment.
    We considered these comments, and we have made the following 
changes to the proposal in the final rule.
    First, the final rule requires owners or operators to develop a 
fugitive emission monitoring plan for well sites within a company-
defined area instead of corporate-wide and site-specific monitoring 
plans. This will give companies the flexibility to group well sites 
that are located within close proximity, under common control within a 
field or district, or that are

[[Page 35860]]

managed by a single group of personnel. This would also afford owners 
and operators of well sites within different basins the ability to 
tailor their plans for the specific elements within each basin (i.e., 
geography, well site characterization, emission profile). Information 
we received indicates that, in many cases, several sites within a 
specific geographic area may have similar equipment and would use the 
same contractors, company-owned monitoring instruments, or company 
personnel to perform the monitoring surveys. Based on a study conducted 
for the city of Fort Worth, Texas, we estimate that, on average, there 
are 22 well sites within a company's specific geographic region.\89\ In 
this study, a total of 375 well pads were identified in the Fort Worth 
area, and these well pads were owned and operated by 17 different 
companies, or an average of 22 well pads per company. We believe these 
data provide a reasonable estimate of the number of well sites operated 
by a company in a specific geographic region. Therefore, we are 
removing the proposed corporate-wide and site-specific monitoring plan 
requirements and finalizing requirements that owners and operators 
develop a fugitive emissions monitoring plan for each of the company-
defined areas that covers the collection of fugitive emissions 
components at well sites. As a result, the final rule requires owners 
and operators to develop a plan that describes the sites generally, 
including descriptions of equipment, plans for how they will monitor, 
etc., that apply to all similar sites. This will allow owners and 
operators to develop a monitoring plan for groups of similar well sites 
within an area for ease of implementation and compliance.
---------------------------------------------------------------------------

    \89\ ERG and Sage Environmental Consulting, LP. City of Fort 
Worth Natural Gas Air Quality Study, Final Report. Prepared for the 
City of Fort Worth, Texas. July 13, 2011. Available at http://fortworthtexas.gov/gaswells/default.aspx?id=87074.
---------------------------------------------------------------------------

    Second, we have made changes in the final rule to the proposed 
digital photograph requirements. We believe concerns regarding the 
burden of printing or transmitting digital pictures within the annual 
report are the result of unclear language in the proposed rule. Our 
intent was to require the owner or operator to include one or more 
digital photographs of the survey being performed. However, we 
inadvertently included that text within the requirement for each 
fugitive emission. It was not our intent to require a digital 
photograph of each fugitive emission in the annual report; instead we 
wanted to ensure, through pictorial documentation, that the monitoring 
survey had been performed. After consideration of the comments 
received, we believe we can further streamline this requirement. 
Because a source with fugitive emissions during the reporting period is 
subject to other recordkeeping and reporting requirements, this 
provides sufficient documentation that the survey was performed. 
Therefore, we have removed the proposed requirement to provide a 
digital photograph in the annual report for each required monitoring 
survey. We are requiring owners and operators to retain a record of 
each monitoring survey performed with optical gas imaging by keeping 
one or more digital photographs or videos captured with the OGI 
instrument. The photograph or video must either include the latitude 
and longitude of the collection of fugitive emissions components 
imbedded within the photograph or video or must consist of an image of 
the monitoring survey being performed with a separately operating GPS 
device within the same digital picture or video, provided that the 
latitude and longitude output of the GPS unit can be clearly read in 
the image.
    Third, with the allowance for Method 21 monitoring as an 
alternative to OGI instrument monitoring, we are finalizing a 
requirement that sources of fugitive emissions (e.g., a leaking 
fugitive emissions component) that cannot be repaired during the 
initial monitoring survey either be temporarily tagged for 
identification for repair or be digitally photographed or video 
recorded in a way that identifies the location of the fugitive 
emissions component needing repair. If an owner or operator chooses to 
digitally photograph the leaking component(s) instead of using 
identification tags, the photograph will meet the requirement to take a 
digital photograph during a monitoring survey, as long as the digital 
photograph is taken with the OGI instrument and includes the latitude 
and longitude either imbedded in the photograph or visible in the 
picture.
    Fourth, we are finalizing the walking path requirement with minor 
changes. We are revising the walking path terminology to observation 
path in order to clarify that our intent is focused on the field of 
view of the OGI instrument, not the physical location of the OGI 
operator. We believe this terminology change will alleviate commenters' 
concerns regarding the potentially overly prescriptive nature of the 
defined walking path with transient interferences, environmental 
obstructions, weather conditions and safety issues. This revision also 
clarifies our intent to allow for the use of all types of OGI 
instruments (e.g., mounted, handheld or remote controlled).
    The purpose of the observation path is to ensure that the OGI 
operator visualizes all of the components that must be monitored, just 
as a Method 21 operator in a traditional leak detection program surveys 
all of the components. In the traditional scenario, the owner or 
operator tags all of the equipment that must be monitored, and when the 
Method 21 operator subsequently inspects the affected facility, the 
operator scans each component's tag and notes the component's 
instrument reading. The EPA realizes that this is a time-consuming 
practice. Additionally, while the Method 21 operator must contact each 
component with the probe of the Method 21 instrument and monitor it 
individually, we recognize that with OGI, the operator can be away from 
the components and still monitor several components simultaneously.
    Recognizing these aspects of traditional and OGI leak detection 
methods, we want to offer owners and operators an alternative to the 
traditional tagging approach. However, because we are no longer 
requiring a traditional log of instrument readings, the rule must 
provide another way to ensure that the compliance obligation to monitor 
all equipment is met. We believe that the observation path requirement 
effectively ensures that an operator looks at all of the required 
components but reduces the burden of tagging and logging associated 
with traditional Method 21 programs. Unlike the tagging and logging 
requirement associated with traditional Method 21 programs, the 
requirement to develop an observation path is a one-time requirement 
(as long as the path does not need to change due to the addition of 
components). We do not expect facilities to create overly detailed 
process and instrumentation diagrams to describe the observation path. 
The observation path description could be a simple schematic diagram of 
the facility site or an aerial photograph of the facility site, as long 
as such a photograph clearly shows locations of the components and the 
OGI operator's walking path. As a result, we do not believe that the 
requirement to document the observation path is burdensome.
i. Provision for Emerging Technology
    As the EPA noted in the 2015 proposal, fugitive emissions 
monitoring is a field of emerging technology, and major advances are 
expected in the near future. 80 FR at 56639. We are seeing a rapidly 
growing push to develop and

[[Page 35861]]

produce low-cost monitoring technologies to find fugitive and direct 
methane and VOC emissions sooner and at lower levels than current 
technology allows, thus enhancing the ability of operators to detect 
fugitive emissions. During the development of the proposed rule, the 
EPA solicited comments and information on emerging technologies that 
could potentially be used to detect fugitive emissions at well sites or 
compressor stations and how these technologies could be used (e.g., as 
standalone monitors or in conjunction with OGI). Several commenters 
indicated that methane and VOC leak detection technology is undergoing 
continuous and rapid development and innovation, potentially yielding, 
for example, continuous emissions monitoring technologies, and urged 
the EPA to allow emerging technology to be used for fugitive emissions 
monitoring. The EPA agrees that continued development of these cost 
effective technologies is important and that the final rule should 
encourage and accommodate it to the extent possible.
    Fugitive emissions monitoring and repair is a work practice 
standard, as allowed under section 111(h)(1) of the CAA. A work 
practice standard is an emission limitation that is not necessarily in 
a numeric format, such as the visualization of fugitive emissions using 
OGI. As described in section 111(h)(3), the Administrator may approve 
an alternative means of emission limitation for a work practice 
standard if it can be proven that an equal reduction in emissions will 
be achieved. To that end, pursuant to CAA section 111(h)(3), we are 
establishing in the final rule a process for the agency to permit the 
use of innovative technology for reducing fugitive emissions at well 
sites and/or compressor stations. Specifically, under the final rule, 
owners or operators may submit a request to the EPA for ``an 
alternative means of emission limitation'' where a technology has been 
demonstrated to achieve a reduction in emissions at least equivalent to 
the reduction in emissions achieved under the work practice or 
operational requirements for reducing fugitive emissions at well sites 
and/or compressor stations in subpart OOOOa.
    To facilitate the application and review process, the final rule 
includes information to be provided in the application that would be 
needed for us to expeditiously evaluate the emerging technology. Such 
information must include a description of the emerging technology and 
the associated monitoring instrument or measurement technology; a 
description of the method and data quality used to ensure the 
effectiveness of the technology; a description of the method detection 
limit of the technology and the action level at which fugitive 
emissions would be detected; a description of the quality assurance and 
control measures employed by the technology; field data that verify the 
feasibility and detection capabilities of the technology; and any 
restrictions for using the technology.
    This process will allow for the use of any currently emerging 
technology or any technology that is developed in the future that is 
capable of achieving methane and VOC emission reductions at levels that 
are at least equivalent to reductions achieved when using OGI or Method 
21 for fugitive emissions monitoring. This process will also allow for 
the use of alternative fugitive emissions monitoring approaches such as 
periodic, continuous, fixed, mobile, or a hybrid approach. Consistent 
with section 111(h)(3), any application will be publicly noticed in the 
Federal Register, which the EPA intends to provide within six months 
after receiving a complete application, including all required 
information for evaluation. The EPA will provide an opportunity for 
public hearing and comment on the application and on intended action 
the EPA might take. The EPA intends to make a final determination 
within six months after the close of the public comment period. The EPA 
will also publish its final determination in the Federal Register. If 
final determination is a denial, the EPA will provide reasoning for 
denial and recommendations for further development and evaluation of 
the emerging technology, if appropriate.
j. Definition of Well Site
    In the proposed rule, we had defined ``well site,'' for purposes of 
the fugitive emissions standards at Sec.  60.5397a, to include 
separately located, centralized tank batteries. We received comments 
that the definition was unclear and that there was concern that the 
affected facility status of centralized tank batteries could 
inadvertently pull into affected facility status those well sites that 
only contain one or more wellheads, which were proposed to be excluded 
from affected facility status. We agree that the proposed definition of 
well site was somewhat unclear, and we have revised the definition in 
the final rule. With regard to the affected facility status of 
centralized tank batteries and its effect on well sites that only 
contain one or more wellheads, our intent is not to have well sites 
that only contain one or more wellheads subject to fugitive emissions 
standards. To make this intent more explicit, we have added language to 
Sec.  60.5365a(i)(2) to this effect.
2. Fugitive Emissions From Compressor Stations
    Based on our consideration of the comments received and other 
relevant information, we have made several changes to the proposed 
fugitive emissions standards for the compressor stations in this final 
rule. The finalized fugitive emissions monitoring and repair 
requirements for compressor stations are similar to the requirements 
for well sites, so we streamlined this section by referencing our well 
site discussion, where appropriate. Below we provide the significant 
changes since proposal and our rationales for these changes.
a. Monitoring Frequency
    In conjunction with semiannual monitoring, the EPA co-proposed 
annual monitoring, solicited comment on conducting monitoring surveys 
on a quarterly basis, and solicited comment on the availability of 
trained OGI contractors and OGI instrumentation. 80 FR at 56639.
    Some commenters supported quarterly monitoring on the belief that 
it is more accurate and cost-effective than the monitoring frequencies 
proposed by the EPA. Other commenters opposed quarterly monitoring, 
alleging that it is not cost-effective and may be infeasible due to 
weather or shortages associated with OGI, necessary for the surveys. 
Also citing factors such as cost-effectiveness and questioning data 
underlying the EPA's analysis, some commenters supported annual 
monitoring or generally opposed semiannual monitoring.
    Based on the comments received, the EPA reviewed the type of 
equipment and the associated components that were included in the model 
plant used to determine emission reductions and costs for compressor 
stations at proposal. The storage and transmission model plants 
developed for the proposed rule had inadvertently included site 
blowdown open-ended lines, which are not sources of fugitive emissions 
but are vents. Therefore, the transmission and storage model plants 
were revised for the final rule to remove these components from the 
total component count.
    The EPA used information provided by commenters to re-evaluate the 
control options for annual, semiannual and quarterly monitoring. As 
shown in the TSD, the control costs for quarterly, semiannual, and 
annual monitoring remain cost-effective for reducing GHG

[[Page 35862]]

(in the form of methane) and VOC emissions. Semiannual and quarterly 
monitoring would provide greater emissions reductions than would annual 
monitoring. However, as explained in the proposed rule, we were 
concerned with compliance burden, in particular for small businesses, 
associated with quarterly monitoring even though it was cost effective. 
80 FR at 56641. Specifically, we were concerned that the limited 
supplies of trained personnel for performing surveys might lead to 
disadvantages for small businesses, which are more likely to hire 
trained personnel. Id. However, certain changes we have made in the 
final rule will help alleviate the concern. For example, the final rule 
requires that the initial monitoring survey must take place by June 3, 
2017 or within 60 days of the startup of production, whichever is 
later. This allows additional time for owners and operators to 
establish the requirement program's infrastructure at the initial 
stage. Another example, in light of comments urging EPA to allow Method 
21 as an alternative, and the fact that we know many companies already 
own Method 21 instruments, offering Method 21 at a repair threshold of 
500 ppm, as an alternative to conduct the monitoring surveys, will 
alleviate some of the demand for OGI instruments and personnel. 
Therefore, the EPA is finalizing quarterly monitoring frequency for the 
collection of fugitive emissions components at compressor stations to 
ensure the maximum amount of emission reductions. Please see the RTC 
document in the public docket for further discussion.\90\
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    \90\ See EPA docket ID No. EPA-HQ-OAR-2010-0505.
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    Some commenters requested that fugitive emissions monitoring 
exemptions be given to well sites and compressor stations that are 
located in areas of the country that routinely experience extreme 
weather. The commenters noted that these areas experience several 
months of average temperatures below 0 [deg]F and long periods of snow 
cover. The commenter also provided information from one of the OGI 
instrument manufacturers which indicates that the instrument cannot 
operate at temperatures below -4 [deg]F. The commenter also expressed 
concerns about monitoring survey personnel's safety if they were to 
attempt to conduct surveys in these weather conditions.
    We agree that there are areas within the United States that 
regularly have extreme weather conditions such as three or more 
consecutive months of average temperatures below 0 [deg]F. We also 
obtained information from two OGI instrument manufacturers that confirm 
that the minimum operating temperature of the OGI instruments is -4 
[deg]F. As such, these prolonged subzero temperature conditions would 
make performing fugitive emissions monitoring surveys impossible during 
several months of the year. Additionally, while we believe that company 
personnel may be accessing these sites for maintenance activities, it 
may be difficult to transport OGI contractors to unmanned sites within 
these areas during these periods, as outside access for OGI contractors 
usually requires air travel to access these production sites.
    Based on these considerations, we are waiving quarterly fugitive 
emissions monitoring surveys at compressor stations if, based on three 
years of historical climatic data, two of the three consecutive months 
within the quarter has an average temperature below 0 [deg]F. The 
average temperatures must be determined by historical climatic data 
from the National Oceanic and Atmospheric Administration or a source 
approved by the EPA Administrator. This waiver may not be used for two 
consecutive quarters and is not extended to well sites because we do 
not believe that there will be any locations that have average monthly 
temperatures below 0 [deg]F for six consecutive months. Owners and 
operators will have to keep records of the waiver period, including the 
three months within the quarterly monitoring period, the average 
monthly temperatures and the source of the temperature information. 
Owners and operators will also have to report this information in their 
annual report.
b. Monitoring Using Method 21
    In performing analysis for the proposed rule, the EPA found OGI to 
be more cost-effective than Method 21 and, therefore, identified OGI as 
the BSER for monitoring fugitive emissions at compressor stations. See 
80 FR 56641, September 18, 2015. As with well sites, discussed 
previously in section VI.F.1.c, the EPA solicited comment on whether to 
allow Method 21 as an alternative fugitive emissions monitoring method 
to OGI and solicited comment on the repair threshold for components 
that are found to have fugitive emissions using Method 21.
    The EPA received the same types of comments regarding allowing 
Method 21 as an alternative to OGI for monitoring fugitive emissions at 
compressor stations as for well sites, as discussed in section 
VI.F.1.c. Likewise, for the same reasons as discussed earlier, we are 
finalizing Method 21 as an alternative to OGI for monitoring fugitive 
emissions components at compressor stations at a repair threshold of an 
instrument reading of 500 ppm or greater. We are also finalizing 
specific recordkeeping and reporting requirements when Method 21 is 
used to perform a monitoring survey. See section V.J for more details 
on the recordkeeping and reporting requirements.
c. Shifting of Monitoring Frequency Based on Performance
    The EPA proposed shifting monitoring frequencies (ranging from 
annual to quarterly monitoring) based on the percentage of components 
that are found to have fugitive emissions during a monitoring survey. 
We solicited comment on the proposed monitoring scheme, including the 
proposed metrics of one percent and three percent to determine 
monitoring frequency or whether the monitoring frequency thresholds 
should be based on a specific number of components that are found to 
have fugitive emissions. In addition, the EPA solicited comment on 
whether a performance-based frequency or a fixed-frequency was more 
appropriate.
    The EPA received the same comments regarding frequency of 
monitoring for compressor stations as for well sites, discussed in 
section VI.F.1.d. Likewise, for the same reasons as discussed earlier, 
the EPA is finalizing a fixed monitoring frequency instead of 
performance based monitoring.
d. Fugitive Emissions Components Repair and Resurvey
    The EPA proposed that a source of fugitive emissions at compressor 
stations must be repaired or replaced as soon as practicable, and, in 
any case, no later than 15 calendar days after detection of the 
fugitive emissions. The EPA solicited comment on whether 15 days is the 
appropriate amount of time for repair of sources of fugitive emissions 
from compressor stations. We also solicited comment on whether 15 days 
is the appropriate amount of time needed to resurvey a component after 
it has been repaired.
    The EPA received the same comments regarding the timeframe for 
repairs, delay of repair, and resurveys for compressor stations as for 
well sites, discussed in section VI.F.1.e. Likewise, for the same 
reasons as discussed earlier, we are finalizing 30 days for the repair 
of fugitive emissions sources and an additional 30 days for resurvey of 
the repaired fugitive emissions components.

[[Page 35863]]

We also are finalizing revisions to the delay of repair requirements. 
If a repair cannot be made due to a technical infeasibility that would 
require a blowdown or shutdown of the compressor station, or would be 
unsafe to repair by exposing personnel to immediate danger, the repair 
can be delayed until the next scheduled or emergency blowdown or 
station shutdown or within 2 years of finding the fugitive source of 
emissions, whichever is earlier. We believe that the likelihood of an 
emergency blowdown or a compressor station shutdown occurring within 
six months of finding fugitive emissions from a component may be low; 
however, it would be feasible to repair the component within a two-year 
timeframe, since one of above described events is likely to occur 
within that two-year timeframe. The owner or operator will also have to 
record the number and types of components that are placed on delay of 
repair and record an explanation for each delay of repair.
    Similarly with respect to well sites, and as discussed in section 
VI.F.1.e, we are finalizing the use of the alternative screening 
procedures specified in Section 8.3.3 of Method 21 for resurveying 
repaired fugitive emissions components. Please see the RTC document in 
the public docket for further discussion.
e. Definition of ``Fugitive Emission Component''
    As discussed earlier, we proposed monitoring, repair and resurvey 
of ``fugitive emission components,'' that apply to both well sites and 
compressor stations because the type of components are identical. We 
solicited comment on the proposed definition. The EPA received the same 
comments regarding the fugitive emissions component definition for 
compressor stations as for well sites, discussed in section VI.F.1.f. 
Likewise, for the same reasons as discussed earlier, we are finalizing 
changes to the definition to identify specific components, such as 
valves and flanges, that have the potential to be sources of fugitive 
emissions and that, when surveyed and repaired, would significantly 
reduce GHG and VOC emissions. This targeted list will remove the 
ambiguity of the proposed definition and will allow owners and 
operators to consistently identify fugitive emissions at compressor 
stations.
f. Timing of the Initial Monitoring Survey
    The EPA proposed that the initial monitoring be conducted within 30 
days after the initial startup of a new compressor station or 
modification of an existing compressor station. The EPA solicited 
comment on whether 30 days is an appropriate amount of time to begin 
conducting fugitive emissions monitoring.
    Many commenters supported a longer timeframe for commencing 
monitoring, citing time needed to complete well ties into a compressor 
station that collects field gas, safety, and the relationship with 
other regulations, while some commenters supported the timeframe 
proposed. The EPA recognizes that at the time of startup of a 
compressor station, additional gathering lines or well tie-ins may be 
required. However, we also believe that, at the time of startup, the 
associated collection of fugitive emissions components is operational 
and initial monitoring can begin, even if the gathering lines or well 
tie-ins are incomplete, which could take several months or longer. 
Sources of fugitive emissions could go undetected for months if we were 
to allow monitoring to begin after all of the gathering lines and tie-
ins were completed. Therefore, we are finalizing the proposed 
requirement that initial monitoring will begin after the initial 
startup of a compressor station instead of allowing all of the 
gathering lines or tie-ins to be completed before monitoring begins.
    However, based on the comments received, we are concerned that the 
tasks required prior to conducting an initial survey would take more 
than the 30 days we had proposed. Because each new or modified 
compressor station must be covered by a monitoring plan for a company-
defined area, owners and operators must visit and assess each new or 
modified compressor station in order to incorporate it into a newly 
developed or modified monitoring plan for that area. They also need to 
secure certified monitoring survey contractors or monitoring 
instruments. In addition, they need to ensure that other compliance 
requirements will be met, such as recordkeeping and reporting. In light 
of the activities described above, the EPA is requiring in the final 
rule that the initial survey be conducted within 60 days from startup 
or modification of a compressor station.
    While 60 days from startup or modification of a compressor station 
is sufficient time to conduct the initial survey once the underlying 
program infrastructure is established, we recognize that the initial 
establishment of the required program's infrastructure and the initial 
round of monitoring surveys will require additional time. Most 
importantly, additional time is needed to secure the necessary 
equipment or trained personnel according to one OGI instrument 
manufacturer, which commented that they would need to increase 
production of key components for the OGI instrument to meet demand. The 
OGI manufacturer also indicated that they would need to scale up the 
number of personnel needed to provide OGI training and service of the 
equipment. We are concerned that currently there is not sufficient 
equipment and trained personnel to meet the demand imposed by this 
final rule in the near term. Accordingly, it will be necessary to have 
a window of time for trained personnel to work through this backlog. 
Furthermore, as previously mentioned, an owner or operator will need to 
develop a monitoring plan that would apply to each compressor station 
located within the company-defined area, which requires an assessment 
of each compressor station. Therefore, before a plan can be developed 
or modified, the owner or operator would need time to visit each 
compressor station within the company-defined area. In light of the 
above, the initial site visits and development of the monitoring plan 
would require a significant amount of time. Time is also needed to 
secure certified monitoring survey contractors or monitoring 
instruments. In addition, owners and operators will need to plan the 
logistics of the initial activities in order to comply with the 
requirements. This includes time to set up recordkeeping systems and to 
train personnel to manage the fugitive emissions monitoring program. 
These corporate systems are critical for submitting the notification of 
initial and subsequent annual compliance status.
    As noted above, once programs are established and equipment 
supplies have caught up, well owners will be able to add additional 
affected facilities to existing programs and, thus, this longer 
timeline will not be needed. Therefore, in order to provide time for 
owners and operators to establish the initial groundwork of their 
fugitives program, we are requiring that the initial monitoring survey 
must take place by June 3, 2017 or within 60 days of the startup or 
modification of a compressor station, whichever is later. We anticipate 
that sources will begin to phase in these requirements as additional 
devices and trained personnel become available. For additional 
discussion, please refer to the materials in the docket.
g. Monitoring Plan
    The EPA proposed that owners or operators develop a corporate-wide

[[Page 35864]]

emissions monitoring plan that specifies the measures for locating 
sources and the detection technology to be used. The EPA also proposed 
that owners or operators develop a separate site-specific fugitive 
emissions monitoring plan that specifies information, such as the 
number of fugitive emission components for that site and for each 
affected facility. The EPA solicited comment on the required elements 
of the proposed corporate-wide monitoring plan and specifically asked 
for comment regarding whether the monitoring plan should include other 
techniques, such as visual inspections to help identify indicators of 
potential leaks.
    As with this topic in the context of well sites, and as discussed 
in section VI.F.1.h, some commenters agreed with the EPA's proposal to 
require a corporate fugitive monitoring plan, but expressed concerns 
about the elements of the plan, while others objected that the proposed 
plan is overly prescriptive and costly, with particular concerns about 
including requirements for a walking path and for digital photographs. 
Other commenters suggested changing the scope of monitoring plans to 
accommodate variations in locations of contractors and equipment.
    Based on the comments that we received, we are revising the 
fugitive emissions monitoring plan for compressor stations. We 
acknowledge that developing and implementing a corporate-wide 
monitoring plan that would be applicable to all compressor stations 
within a company could be problematic because compressor station 
configurations may differ across areas (i.e., basins, fields, or 
districts) and what may be applicable in one area may not be relevant 
in another area. This would mean that a company could have to design 
and implement a site-specific plan for each compressor station.
    We also agree that developing a site-specific plan may be overly 
burdensome because several gathering and boosting or transmission 
compressor stations may exist in a specific geographic area and have 
similar equipment. Using information from the Interstate Natural Gas 
Association of America (INGAA) and the Energy Information 
Administration (EIA), we estimated that, on average, compressor 
stations are located 70 miles apart. We also assumed that a company 
could monitor emissions from gathering and boosting or transmission 
compressor stations within a 210-mile radius of a central location. 
Using these assumptions, we estimated that a company could monitor 
seven gathering and boosting or transmission compressor stations within 
that company's specific geographic region. In such cases, companies 
would benefit from having a plan to cover all of the compressor 
stations within that area, as the monitoring will likely require use of 
the same contractors, the same company-owned monitoring instruments, or 
the same company personnel to perform the monitoring surveys. Allowing 
companies to develop one fugitive emissions monitoring plan for all of 
the compressors within a company-defined area would alleviate burden 
and provide efficiency for owners and operators.
    Therefore, we are replacing the proposed corporate-wide and site-
specific monitoring plan requirements with a requirement for owners or 
operators to develop a corporate monitoring plan for each of the 
company-defined areas that would cover the collection of fugitive 
emissions components at the compressor stations located within that 
company-defined area. This will allow owners and operators flexibility 
in developing monitoring plans for compressor stations by allowing 
owners and operators to determine which company-defined area can be 
covered under the specifications outlined in one monitoring plan, for 
ease of implementation and compliance. See section VI.F.1.h of this 
preamble for further discussion.
h. Modifications for Compressor Stations
    The EPA proposed that, for the purposes of the collection of 
fugitive emissions monitoring and repair requirements, a compressor 
station is modified when a new compressor is constructed at an existing 
compressor station or when a physical change is made that causes an 
increase in the compression capacity of an existing compressor station. 
We received numerous comments on the compressor modification 
definition.
    Several commenters stated that the compressor station modification 
definition is too vague and broad because anytime a physical 
modification occurred, a regulatory modification would be triggered 
regardless of whether there were additional emissions. Commenters also 
stated if a compressor station is not operating at full capacity, 
addition of a compressor may not necessarily increase the compressor 
station capacity, nor would addition of a compressor with greater 
horsepower (thus adding capacity) necessarily increase emissions.
    At proposal, we attempted to identify distinct actions that we were 
confident would result in an emissions increase and would clearly mark 
for operators and regulators when a modification occurs. However, upon 
reviewing the comments, we agree that certain triggering events 
identified in the proposal may not result in an increase in emissions. 
Specifically, EPA agrees that an addition of a compressor does not 
result in an increase in emissions in all instances. For example, there 
is no emission increase when a new compressor is being installed as a 
replacement to an existing one. We have, therefore, made changes in the 
final rule to clarify when an addition of a new compressor would 
increase emission and therefore trigger the fugitive emission standards 
(i.e., when it is installed as an additional compressor or if it is a 
replacement that is of greater horsepower than the compressor or 
compressors that it is replacing).
    The EPA agrees that an increase in the compression capacity that is 
not due to the addition of a compressor that would result in an 
increase of the overall design capacity of the compressor station is 
not a modification. For example, a compressor station may have to 
increase the operating throughput by bringing existing compressors on-
line to meet demand during peak seasons. In such a case, the 
compressors' capacities are already accounted for in the overall design 
capacity for the compressor station, and bringing them on-line would 
not increase the overall design capacity nor would it increase the 
potential emissions of the compressor station. Therefore, we are not 
finalizing that an increase in compression capacity is a modification.
    Commenters also indicated that the addition of a new compressor at 
an existing compressor station should not trigger a fugitive emissions 
monitoring program for the entire compressor station but, should only 
apply to the new compressor and its associated components. We disagree 
that the addition of a compressor at an existing compressor station 
should not trigger a fugitive emissions monitoring program for the 
entire compressor station. We have clarified that the installation of a 
compressor will only trigger the fugitive monitoring requirements if it 
is installed as an additional compressor or if it is a replacement that 
is of greater horsepower than the compressor or compressors that it is 
replacing. In this case, the design capacity and potential emissions of 
the compressor station would increase. Unlike the affected facilities 
for purposes of standards for centrifugal and reciprocating compressors 
themselves, the affected facility for purposes of the fugitive

[[Page 35865]]

emission requirements is the collection of fugitive emissions 
components at a compressor station, not the fugitive emissions 
components associated with a single compressor. Therefore, if a 
compressor is added to an existing compressor station, the entire 
compressor station is subject to the fugitive emissions monitoring 
program.
    Therefore, we are finalizing a definition that we are confident 
identifies actions that increase emissions and achieves our original 
goal of having clearly identifiable criteria that can be easily 
recognized by operators and regulators. We are finalizing that a 
modification to a compressor station occurs when a compressor is added 
to a compressor station or if one or more compressors is replaced with 
one or more compressors with a greater total horsepower.
i. Provision for Emerging Technology
    Pursuant to CAA section 111(h)(3), we are establishing in the final 
rule a process for the Agency to permit the use of innovative 
technology for reducing fugitive emissions at well sites and/or 
compressor stations. For a detailed discussion, please see section 
VI.F.1.i.

G. Equipment Leaks at Natural Gas Processing Plants

    For equipment leaks at natural gas processing plants, the EPA 
received a total of seven comments addressing issues such as the 
definition of natural gas processing plant and whether OGI may be used 
in place of Method 21. We reviewed the comments received and determined 
to finalize the standard for equipment leaks at natural gas processing 
plants as proposed. Specifically, the final rule requires NSPS part 60, 
subpart VVa level of control, including a detection limitation of 500 
ppm for certain pieces of equipment. Please see the TSD and RTC 
documents in the public docket for further discussion.

H. Reconsideration Issues Being Addressed

    To address numerous items on which we granted reconsideration, we 
proposed amendments to subpart OOOO and solicited comment on certain 
topics that would also impact the new NSPS requirements. With some 
revisions based on our consideration of public comment, the EPA is 
finalizing certain reconsideration amendments. These amendments 
address: Storage vessel control device monitoring and testing 
provisions; initial compliance requirements for bypass devices; 
recordkeeping requirements 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; 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 continuous control device 
monitoring requirements for storage vessels and centrifugal compressor 
affected facilities. This section identifies specifically what the EPA 
proposed, identifies the regulatory text changes from proposal, and 
states how the EPA is finalizing these provisions.\91\ Please see the 
TSD and RTC documents in the public docket for further discussion.\92\
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    \91\ 80 FR 56645, September 18, 2015.
    \92\ See EPA docket ID No. EPA-HQ-OAR-2010-0505.
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1. Storage Vessel Control Device Monitoring and Testing Provisions
    The EPA proposed regulatory text changes to 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. The 
EPA specifically proposed to revise the limit for total organic carbon 
(TOC) concentration in the exhaust gases at the outlet of the control 
device from 20 ppmv to 600 ppmv as propane on a dry basis corrected to 
3 percent oxygen, a value that more appropriately reflects 95 percent 
control of VOC inflow to control devices. The EPA also proposed initial 
and ongoing performance testing for any enclosed combustors used to 
comply with the emissions standard for an affected facility and whose 
make and model are not listed on the EPA Oil and Natural Gas Web site 
(http://www.epa.gov/airquality/oilandgas/implement.html) as those 
having already met a manufacturer's performance test demonstration. The 
proposal stated that performance testing of combustors not listed at 
the above Web site would be conducted on an ongoing basis, every 60 
months of service, and monthly monitoring of visible emissions from 
each unit would also be required.
    Additionally, the EPA proposed amendments to make the requirements 
for monitoring visible emissions consistent for all enclosed combustion 
units. Specifically, the EPA proposed to amend 40 CFR 60.5413(e)(3) to 
require monthly 15-minute period observations using EPA Method 22.
    Based on information submitted through the public comment process, 
the EPA has identified four necessary revisions for the final storage 
vessel provisions. First, commenters provided information to the EPA 
concerning the use of 600 ppmv as propane as appropriately reflecting 
95 percent control of VOC inflow to control devices. After an 
evaluation of the comments, we agreed that the EPA's assumption about 
the ratio of fuel to combustion air was incorrect, making the proposed 
600 ppmv as propane value incorrect. The 600 ppmv as propane value was 
derived in the memorandum dated June 2, 2015,\93\ which discusses the 
background for the Sec.  60.5412(a)(1)(ii) TOC exhaust gas standard for 
combustion control devices to control VOC emissions from oil and gas 
affected facilities. While this analysis reflects the destruction of 
hydrocarbons compared to the concentration of hydrocarbon in the inlet 
fuel, our analysis did not take into account any in-stack dilution 
represented by the introduction of combustion air or the correction of 
that air to 3 percent oxygen. Since hydrocarbon combustion requires 
approximately a ratio of 12:1 input of combustion air to hydrocarbon, 
the outlet concentration of TOC would be adjusted downward to 275 parts 
per million by volume on a wet basis (ppmvw), as propane, at 3 percent 
O2. The final rule corrects this concentration at Sec.  
60.5412(a)(1)(ii), and the EPA has appended the memo in the public 
docket with this adjustment.
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    \93\ See Docket ID No. EPA-HQ-OAR-2010-0505-4907.
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    Second, the EPA is finalizing amendments to make the requirements 
for monitoring of visible emissions consistent for all enclosed 
combustion units. Prior to the proposal, enclosed combustors that met 
the manufacturer's performance test requirement were to conduct 
quarterly observations for visible smoke emissions employing section 11 
of EPA Method 22 for a 60-minute period. Petitioners suggested it would 
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. The 
EPA agrees with the petitioners. This revision will result in 
consistent requirements to all enclosed combustors, which will make 
compliance easier for owners and operators. Because both monitoring 
requirements ensure compliance of the enclosed combustors, and having 
the

[[Page 35866]]

same requirement would ease implementation burden, we are finalizing 
amendments to Sec. Sec.  60.5413(e)(3) and 60.5415(b)(2)(vii)(B) to 
require monthly 15-minute period observations using EPA Method 22 Test, 
as suggested by the petitioner.
    The EPA proposed requirements for determining applicability for new 
storage tanks that replace existing tanks. Commenters provided 
alternative text indicating how the meaning of the regulation was 
difficult to discern. The EPA considered the suggested text and agrees 
that amending this section will make the requirements for compliance 
easier to understand. The amended language has been finalized in Sec.  
60.5365(e)(4).
    Fourth, the EPA received comments requesting removal of the 
requirement that certain devices that route emissions to processes must 
reduce emissions by 95 percent and instead be written to be consistent 
with Sec.  60.5411a(c), which requires that process devices must 
operate 95 percent of the year or greater. Upon further reflection, the 
EPA determined that, because Sec.  60.5395a(a) clearly requires that 
affected sources (except those with uncontrolled emissions below 4 tons 
per year (tpy)) must reduce VOC emission by 95 percent, it is not 
necessary to further prescribe the level of reduction to be achieved 
when emissions are routed to a process. The EPA has therefore removed 
such specification in Sec.  60.5395a(b)(1) in the final rule. As 
finalized, this specific provision relative to control requirements is 
the same for centrifugal compressors, pneumatic pumps, and storage 
vessel affected facilities routing to a process.
2. Initial Compliance Requirements for Bypass Devices
    The EPA proposed to amend Sec.  60.5416(c)(3)(i) to include 
notification via remote alarm to the nearest field office in order to 
maintain consistency with previous amendments. The EPA proposed to 
require both an alarm at the bypass device and a remote alarm. The EPA 
proposed 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. At 
proposal to amend subpart OOOO, EPA changed ``or'' to ``and'' under 
subpart OOOO at Sec. Sec.  60.5411(a)(3)(i)(A) and 60.5411(c)(3)(i)(A), 
which would have required that both an audible and remote alarm be 
installed on a bypass device with the potential to vent to the 
atmosphere. One commenter pointed out that the requirements would be 
applied retroactively, as the EPA changed the requirements in subpart 
OOOO as well as subpart OOOOa. The EPA agrees with the commenter that 
our intent was not to create a retroactive requirement by revising 
subpart OOOO. The EPA is therefore not finalizing the changes to 
subpart OOOO, Sec.  60.5411(a)(3)(i)(A), or Sec.  60.5411(c)(3)(i)(A).
    Although we are not finalizing both audible and remote alarm 
requirements in subpart OOOO, the EPA disagrees that the requirement 
for remote notification is unreasonable and is therefore preserving the 
option as an alternative to an audible alarm. The EPA notes that either 
requirement is restricted to those bypass devices that vent to the 
atmosphere, not bypass devices (such as some pressure relief devices) 
that are required to be routed through closed vent systems to control 
devices. The EPA proposed to require both types of notification in 
subpart OOOOa because of the diverse nature of facilities that will use 
them. While an audible alarm may be sufficient at facilities that have 
personnel present on a continuous basis, not all affected facilities 
are at continuously-manned locations. An audible alarm on a bypass at a 
remote location that is visited only on a schedule by maintenance 
personnel would likely alert no one authorized to take action on the 
audible alarm until such time as the maintenance personnel arrive, 
which according to industry, may be a considerable time. The EPA agrees 
that the logistical requirements may need to be resolved in some 
instances, and is therefore finalizing the requirements in subpart 
OOOOa to be the same in substance as the requirements in subpart OOOO, 
which allow for the operator to choose one form of alarm or the other. 
Section 60.5416a(c)(3)(i) was revised to match the promulgated 
regulatory language in Sec.  60.5416(c)(3)(i) of OOOO for consistency.
3. Recordkeeping Requirements for Repair Logs for Control Devices 
Failing a Visible Emissions Test
    The EPA proposed that the recordkeeping requirements include the 
repair logs for control devices failing a visible emissions test as 
required by the rule. 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 finalizing them at Sec.  60.5420(c)(14).
4. Due Date for Initial Annual Report
    The EPA did not propose regulatory text to amend the rule; rather, 
the EPA stated in the preamble to the proposed rule that 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.
5. Flare Design and Operation Standards
    The EPA proposed 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 of subpart OOOO, 
this clarifies that flares used to comply with subpart OOOO are subject 
to the design and operation requirements in the general provisions.
    Comments on our proposal focused on support for the use of 
pressure-assisted flares. Pressure-assisted flares are designed to 
operate with 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, the EPA solicited 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. From comments to our 
proposal, the EPA understands that there may be affected facilities 
that use pressure-assisted flares (e.g., sonic flares) to control 
emissions from certain activities; however, the EPA now understands 
that an affected facility storage vessel, pneumatic pump, or 
centrifugal or reciprocating compressor would not use a pressure-
assisted flare for control. The affected facility could be routed by 
closed vent system to a low pressure flare, which can comply with the 
velocity requirements of 40 CFR 60.18. The EPA received information 
showing that certain configurations have separate flare tips that 
accommodate high pressure and low pressure. The EPA understands that a 
flare configured this way would be able to meet Sec.  60.18 on the low 
pressure side, which would be appropriate for compliance with these 
standards. Given these facts, the EPA is finalizing the rule as 
proposed, because no regulatory

[[Page 35867]]

amendment appears necessary for such flares to comply with the proposed 
requirements.
6. Leak Detection and Repair (LDAR) for Open-Ended Valves or Lines
    In the preamble to the final 2012 rule, the EPA stated that subpart 
VVa lowered the concentration limit defining a leak from 10,000 ppm to 
500 ppm. The EPA's action did not revise subpart VVa, but rather 
changed the application of leak detection and repair provisions by 
making the LDAR standards of subpart VVa applicable to affected units 
subject to LDAR under subpart OOOO if the concentration emanating from 
a leak is 500 ppm or greater. The EPA further stated that monitoring 
requirements from subpart VVa applied to pumps, pressure relief 
devices, and open-ended valves or lines at units affected by LDAR under 
subpart OOOO. Although the preamble may have obscured the issue, we 
clarify here that the monitoring provisions of subpart VVa applicable 
to affected units of subpart OOOO do not extend to open-ended valves or 
lines. Given this clarification of preamble language, the EPA can 
identify no need to modify the regulatory language in response to this 
petition.
7. Compliance Period for LDAR for Newly Affected Units
    An issue was raised in an administrative petition that the EPA did 
not adequately respond to a comment on the 2011 proposed NSPS regarding 
the compliance period for the LDAR requirements for on-shore natural 
gas processing plants. The commenter requested that the EPA include in 
subpart OOOO a provision similar to subpart KKK, 40 CFR 60.632(a), 
which allows a compliance period of up to 180 days after initial start-
up. The commenter was concerned that a modification at an existing 
facility or a subpart KKK regulated facility could subject the facility 
to subpart OOOO LDAR requirements without adequate time to bring the 
whole process unit into compliance with the new regulation. 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. 
Therefore, the EPA has determined there is no need to modify the 
current regulations.
8. Exemption to Notification Requirement for Reconstruction
    The EPA received an administrative petition that raised the issue 
that notification of reconstruction requirements under Sec.  60.15(d) 
is unnecessary for some affected facilities. After consideration, the 
EPA agrees that some notifications are unnecessary because the EPA 
specifies notification of reconstruction for affected unit pneumatic 
controllers, centrifugal compressors, reciprocating compressors, and 
storage vessels under Sec.  60.5410a and Sec.  60.5420a, in lieu of the 
general notification requirement in Sec.  60.15(d). To make this change 
effective, the EPA has noted this change in the explanatory comments in 
Table 3 reflecting that Sec.  60.15(d) does not apply to affected 
facility pneumatic controllers, centrifugal compressors, reciprocating 
compressors and storage vessels in subpart OOOO. The EPA has determined 
to finalize these amendments as proposed.
9. Disposal of Carbon From Control Devices
    The EPA re-proposed 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. The EPA received no comment to the re-
proposal. The EPA has determined to finalize these amendments as 
proposed.
10. The Definition of Capital Expenditure
    The EPA proposed to specifically define the term ``capital 
expenditure'' in subpart OOOO. In this proposed definition, the EPA 
updated the formula to reflect the calendar year that subpart OOOO was 
proposed, as well as specified that the B value for subpart OOOO is 
4.5. These updates are necessary for proper calculation of capital 
expenditure under subpart OOOO. The EPA has determined to finalize 
these amendments as proposed. Please refer to the RTC document in the 
public docket for this rulemaking for further discussion.
11. Tanks Associated With Water Recycling Operations
    The EPA solicited comment in the proposed rule to remove tanks that 
are used for water recycling from potential NSPS applicability and on 
approaches that could be taken to amend the definition of ``storage 
vessel.'' Commenters requested that the EPA remove water tanks that are 
primarily used for water recycling from subpart OOOOa applicability. 
Commenters discussed that large storage tanks encourage large scale 
water recycling and are expected to reduce fresh water usage primarily 
in the Permian Basin. After reviewing the public comments, the EPA 
agrees that certain large water recycling vessels should be exempt from 
affected facility status for storage vessels because EPA did not intend 
such vessels to be affected facility storage vessels under subpart OOOO 
or OOOOa. By exempting such vessels, EPA will not create a disincentive 
for recycling of water for hydraulic fracturing. Therefore, the final 
rule exempts water recycling vessels that receive water that has been 
through separation, and are much larger than the storage vessels 
generally intended to be regulated by subparts OOOO and OOOOa for VOC 
emissions. The EPA has included the exemption language at Sec.  
60.5365(e)(5) and Sec.  60.5365a(e)(5) in the final rule.
12. Continuous Control Device Monitoring
    The EPA proposed under Sec.  60.5417 to add continuous control 
device monitoring requirements for storage vessels and centrifugal 
compressor affected facilities. The EPA received comments indicating 
that to impose this requirement on affected facilities under subpart 
OOOO may make such requirements retroactive, given the time between the 
original proposal for subpart OOOO and the proposal of the additional 
requirements. To avoid this possibility, the EPA will not finalize the 
change proposed to subpart OOOO, Sec.  60.5417(h)(4).

I. Technical Corrections and Clarifications

    The EPA is finalizing technical corrections and clarifications 
intended to provide clarity, improve implementation, and update 
procedures. This section identifies each correction and the rationale 
for these changes. Please see the TSD and RTC documents in the public 
docket for further discussion.\94\
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    \94\ See EPA docket I.D. No. EPA-HQ-OAR-2010-0505.
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    1. The EPA discovered drafting errors in Sec.  
60.5412a(d)(1)(iv)(A), Sec.  60.5412a(d)(2) and Sec.  60.5415a(e)(3) 
that required control of methane from storage vessels. As discussed in 
the preamble and the TSD for the proposed rule, the EPA did not 
consider reduction of methane emissions from storage vessels. 
Therefore, the reference to controlling storage vessel methane 
emissions in the proposed regulatory text in the above provisions was a 
drafting error. In correction, the EPA is removing ``methane and'' from 
these three provisions because methane control is not required for 
storage vessels under subpart OOOOa.
    2. A commenter noted that EPA had omitted a clear deadline by which 
newly constructed, reconstructed, or

[[Page 35868]]

modified storage vessels that receive liquids from sources other than 
hydraulically fractured wells must make their potential to emit 
determination, in Sec.  60.5365a(e)(1). The commenter presumed, 
correctly, that the omission was inadvertent, stating that 
``Presumably, EPA intends that such tanks with potential VOC emissions 
greater than 6 tons per year would be subject to the rule.'' We have 
more clearly specified the deadline.
    3. We removed the requirement in Sec.  60.5375a(a)(2) that all 
salable gas recovered from a well completion be routed as soon as 
practicable to a gathering line. This requirement was duplicative of 
the provisions of paragraph (a)(1) of the same section.
    4. We revised Sec.  60.5420a(b)(4)(i) to include the provision that 
gas recovered from reciprocating compressors could also be routed to a 
process as an alternative to replacing rod packing no later than on or 
before 26,000 hours of operation or 36 months. We additionally 
corrected an error that identified a wrong initial startup period. This 
correction consists of removing ``since [insert date 60 days after 
publication of final rule in the Federal Register].'' This correction 
was also made in Sec.  60.5420a(c)(3)(i) and Sec.  60.5415a(c)(1).
    5. We revised the requirements in Sec.  60.5417a for heat sensing 
monitoring devices on pilot flames to clarify that these devices are 
not subject to calibration, quality assurance and quality control 
requirements. While we intended for these devices to monitor 
continuously, we did not intend to place all of the requirements for 
continuous parameter monitoring systems on these devices. We also 
revised the language in Sec.  60.5417a(e) and Sec.  60.5417a(g) to 
indicate that heat sensing is not a daily average and that a deviation 
occurs when the device fails to indicate the presence of a pilot flame.
    6. We revised the language in Sec.  60.5417a(f)(1)(iii) for 
monitoring inlet gas flow rate on control devices tested by the 
manufacturer. We did not intend for owners or operators to have to 
continuously achieve a minimum inlet gas flow rate. We have revised the 
requirement to indicate that there is only a limit on the maximum gas 
inlet flow rate to the device. We also revised the language in Sec.  
60.5417a(d)(1)(viii)(A) to indicate that the accuracy requirement is at 
the maximum flow rate.
    7. We revised the language in Sec.  60.5413a(d)(11)(iii) to 
indicate that manufacturers must demonstrate a destruction efficiency 
of 95 percent for total hydrocarbons (THC), as propane. This 
requirement previously stated that the manufacturer must demonstrate a 
destruction efficiency of 95 percent for VOC and methane. The revised 
language aligns more accurately with the testing requirements in the 
rule. Additionally, as these units are burning propene during the test, 
it would be impossible to demonstrate a destruction efficiency of 
methane. As methane is a one-carbon, single-bonded compound, it is more 
easily destructed than propene, a double-bonded compound, and thus, the 
destruction efficiency should be just as high or higher for methane 
than for the THC measured during the performance test.
    8. We revised the testing language in Sec.  60.5413a(b) in order to 
make it clearer for compliance purposes. The proposed language failed 
to clearly identify the number of runs or the length of runs expected 
for each performance test. Additionally, the calculations did not 
properly align with the specified methods. Section 60.5412a(d)(1)(i) 
has no subsections. The reference to ``percent reduction performance 
requirement'' in the referring section 60.5413a(b)(3) indicates that 
the cross reference should refer to section 60.5412a(d)(1)(iv)(A), 
which contains the percent reduction required.
    9. We revised the language in Sec.  60.5395a(a) to clarify that 
owners and operators must comply with the requirements of Sec.  
60.5395a(a)(1). The proposed language could have been interpreted to 
mean that compliance with Sec.  60.5395a(a)(1) was not required if 
owners or operators complied with Sec.  60.5395a(a)(3); however, it 
would be impossible to comply with Sec.  60.5395a(a)(3) without first 
determining the potential for VOC emissions, as required by Sec.  
60.5395a(a)(1). We also further clarified when owners and operators 
must comply with the requirements of Sec.  60.5395a(a)(2) and when they 
may comply with the requirements of Sec.  60.5395a(a)(3).
    10. We revised the language in Sec.  60.5420a(b)(9)(i), Sec.  
60.5420a(b)(11), Sec.  60.5422a(a), and 60.5423a(b) to update the Web 
site address for the Electronic Reporting Tool (ERT). We have also 
clarified that if the CEDRI form is not available at the time that a 
report is due, we do not intend for owners or operators to submit forms 
electronically through CEDRI until the form has been available for 90 
days. We are also clarifying that this only applies to subsequent 
reports; owners or operators would not be required to enter previous 
reports into CEDRI once the form is available. While similar language 
was proposed, we realize that the previous language did not fully 
capture our intent.
    11. We revised the language in Sec.  60.5412a(c)(2)(iii) to correct 
a drafting error. The proposed language lists the types of units in 
which owners or operators must regenerate or reactivate spent carbon. 
The proposed language stated the unit must be operating emission 
controls in accordance with an emissions standard for VOC under another 
subpart in 40 CFR part 60 or this part, which is redundant. The 
language has been revised to state part 63 or this part. We also 
removed Sec.  60.5412a(c)(2)(ii), as we do not believe that owners or 
operators would be able to regenerate or reactivate spent carbon in 
accordance with this section, as there are no requirements in this 
section for that activity. Finally, we removed the phrase ``thermal 
treatment'' in front of unit in Sec.  60.5412a(c)(2)(i) and (iii) as 
the phrase ``thermal treatment unit'' is not defined.
    12. We revised the language in Sec.  60.5412a(c)(2)(iv) through 
(vii) and Sec.  60.5413a(a)(4) and (5) to reconcile the fact that most 
hazardous waste combustion units are subject to the requirements of 40 
CFR part 63 subpart EEE. While our intent was to encompass all 
hazardous waste incinerators, boilers and industrial furnaces in these 
requirements, referencing only 40 CFR parts 264, 265, 266 and 270 may 
have inadvertently excluded units.
    13. We revised the language in Sec.  60.5413a(b)(5)(ii)(B) to more 
clearly identify the continuing compliance obligations for units exempt 
from periodic testing.
    14. We revised the TOC emission rate limit in Sec.  
60.5412a(a)(1)(ii) and Sec.  60.5412a(d)(1)(iv)(B) to be consistent 
with the changes to the limit in 40 CFR part 60 subpart OOOO. For more 
explanation on this topic, see the discussion on reconsideration issues 
in section VI.H of this preamble. We also revised the TOC limit to be 
on a wet basis, as these units will be tested with Method 25A, which 
provides measurement data on a wet basis. While we note that 
compressors must control both VOCs and methane to at least 95 percent, 
the calculated limit reflects 95 percent control of VOC inflow to 
control devices. Because methane is the simplest carbon compound, it is 
very easy to destroy through combustion. Ensuring 95 percent 
destruction of VOCs will guarantee greater than 95 percent destruction 
of methane.
    15. We revised the wording of Sec.  60.5365(e)(4) and 
60.5365a(e)(4) at the request of commenters seeking clearer direction 
on the applicability of standards to storage vessels returning to

[[Page 35869]]

service. Since the re-wording does not change the meaning or 
requirements of the section, the revisions have been made to both 
subparts OOOO and OOOOa for consistency.
    16. We corrected the cross reference in section 60.5415(c)(4) from 
Sec.  60.5411(a) to section 60.5416(a) and (b), and in Sec.  60.5415a 
paragraph (c)(4) from section 60.5411a(a) to Sec.  60.5416a(a) and (b).
    17. We corrected language in in Sec.  60.5420(c)(6) to include 
reciprocating compressors.
    18. We adjusted the language in Sec.  60.5412(d)(1)(iv)(C), Sec.  
60.5412a(a)(1)(iii) and Sec.  60.5412a(d)(1)(iv)(C). This language 
allowed operation of the control device at a minimum temperature of 
760[deg]Celsius, if the control device was able to demonstrate a 
uniform combustion temperature during the performance test. In our 
response to comments on the August 23, 2011 proposed rule, we agreed 
with commenters that uniform combustion profiles are difficult to 
obtain due to flame zone mixing and heat transfer. In response to that 
comment, we revised the language in 40 CFR part 63 subpart HH. We have 
now revised the language in 40 CFR part 60 subparts OOOO and OOOOa to 
mimic the language in 40 CFR part 63 subpart HH. We believe that this 
change is necessary as we do not believe that owners or operators will 
be able to demonstrate a uniform combustion zone temperature, nor have 
we defined what it means to have a uniform combustion zone temperature 
(e.g., the number of measurement points necessary, the agreement 
between points, etc.). Additionally, Sec.  60.5412(d)(1)(iv)(C), Sec.  
60.5412a(a)(1)(iii) and Sec.  60.5412a(d)(1)(iv)(C) previously 
referenced performance testing in accordance with Sec.  60.5413 and 
Sec.  60.5413a, but it was unclear what the performance testing 
obligations were. We believe the revised language will allow owners and 
operators to more easily comply with this requirement.
    19. We added language to Sec.  60.5412(d) and Sec.  60.5412a(d) to 
make our intent clear that flares are acceptable control devices for 
storage vessels and to identify the design requirements for flares. We 
also revised language in Sec.  60.5415a(b)(2)(vii) to clearly identify 
the continuing compliance requirements for flares.
    20. We adjusted the language in Sec.  60.5413a(b)(5)(ii)(A) and 
Sec.  60.5417a(d)(1)(viii) to add a second compliance option for 
control device models tested under Sec.  60.5413a(d). We are allowing 
owners and operators an option to retest these units every five years 
in lieu of continuously monitoring the gas flow rate. Owners and 
operators must still ensure they are not overwhelming the control 
device by using a control device that can handle the maximum flow rate 
at the site.
    21. We added language to Sec.  60.5417a(a) to identify the 
continuing compliance requirements for enclosed combustion devices that 
are not specifically identified in Sec.  60.5417a(d).
    22. In preparation of the final rule, EPA discovered an error in 
both subpart OOOO and the proposed subpart OOOOa. Specifically, they 
fail to include a general duty to minimize emissions. As the EPA 
clarified during the 2012 NSPS rulemaking, ``[t]he general duty is 
applicable to a source at all times.'' \95\ Therefore, the absence of 
this provision in subpart OOOO and the proposed subpart OOOOa was an 
error, which is being corrected in these final rules at Sec.  60.5370 
and Sec.  60.5370a.
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    \95\ See RTC document in EPA Docket I.D. No. EPA-HQ-OAR-2010-
0505-4546.
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J. Final Standards Reflecting Next Generation Compliance and Rule 
Effectiveness

    We are finalizing certain standards that are reflecting EPA's Next 
Generation Compliance and rule effectiveness strategies. Based on our 
consideration of the comments received, we are finalizing some aspects 
as proposed while, for others, we have made a number of changes to the 
proposed standards. We have the opportunity to expand transparency by 
making the information we have more accessible and by making new 
information, obtained from advanced emissions monitoring and electronic 
reporting, publicly available. We are finalizing an electronic 
reporting requirement, via the EPA's CDX.
    Other aspects of the final rule will maximize regulatory 
compliance, such as clear applicability of the final rule (e.g., in 
revisions to modification criteria) and provide incentives for 
inherently low-emitting equipment (e.g., solar pumps at gas plants are 
not affected facilities). Advances in technology additionally promote 
compliance by enhancing a ``visibility'' factor; this rule builds on 
such Next Generation strategies, by including measures involving the 
use of digital picture reporting and OGI technology. In lieu of 
independent third party verification for closed vent system design, we 
are finalizing a qualified professional engineer certification for 
certain issues. For example, as discussed in section VIII of this 
preamble, in response to comment, we are providing that a pneumatic 
pump that cannot be connected to an existing control device due to 
technical infeasibility does not have to meet this requirement. 
However, we will require that the source make this determination 
through use of a professional engineer certification. We are finalizing 
the use of OGI technology as a method for detecting fugitive emissions 
at well sites and compressor station sites. With the exception of 
``clear applicability'', ``incentives for inherently low-emitting 
equipment'' and ``OGI technology for monitoring fugitive emissions'', 
which are discussed elsewhere in this preamble, this section identifies 
the rationale to the regulatory text changes from proposal and states 
how the EPA is finalizing these provisions. For additional details, 
please refer to section VIII, the TSD, and the RTC supporting 
documentation in the public docket.
1. Electronic Reporting
    Through electronic reporting, 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 to the government but, also a means to 
make collected information easily accessible to the public and other 
stakeholders.
    On March 20, 2015, the EPA proposed the ``Electronic Reporting and 
Recordkeeping Requirements for New Source Performance Standards'' (80 
FR 15099, March 20, 2015). If adopted, the rule would revise the part 
60 General Provisions 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 performance test reports, performance evaluation 
reports, summary and excess emission reports and subpart specific 
reports that are similar in nature to these reports.
    Subpart OOOO is one of the rules potentially affected by this 
rulemaking. When promulgated, in addition to electronically reporting 
the results of performance tests, which is already a requirement, a 
requirement to report the annual reports required in Sec.  60.5420(b), 
the semiannual reports required in Sec.  60.5422 and the excess 
emissions reports required in Sec.  60.5423(b) would

[[Page 35870]]

be added to subpart OOOO. The owner or operator would be required to 
use the appropriate electronic form in CEDRI for the subpart or an 
alternate electronic file format consistent with the form's extensible 
markup language (XML) schema. If the reporting form specific to the 
subpart is not available 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 would begin submitting reports electronically with 
the next report that is due once the electronic form has been available 
for at least 90 days. The EPA is currently working to develop the form 
for subpart OOOO.
    In the proposal for subpart OOOOa, the EPA included the same 
electronic reporting requirements for subpart OOOOa that were included 
for subpart OOOO in the March 2015 proposal. The EPA is finalizing the 
requirement to report certain performance test reports, excess emission 
reports, annual reports and semiannual reports electronically through 
the EPA's CDX using the CEDRI. The EPA believes that the electronic 
submittal of the reports addressed in this rulemaking will increase the 
usefulness of the data contained in those reports, is in keeping with 
current trends in data availability, will further assist in the 
protection of public health and the environment, and will ultimately 
result in less burden on the regulated community. Electronic reporting 
can also eliminate paper-based, manual processes, thereby saving time 
and resources, simplifying data entry, eliminating redundancies, 
minimizing data reporting errors, and providing data quickly and 
accurately to the affected facilities, air agencies, the EPA and the 
public.
    The EPA Web site that stores the submitted electronic data, 
WebFIRE, will be easily accessible to everyone and will provide a user-
friendly interface that any stakeholder can access. By making the 
records, data and reports addressed in this rulemaking readily 
available, the EPA, the regulated community and the public will benefit 
when the EPA conducts its CAA-required reviews. As a result of having 
reports readily accessible, our ability to carry out comprehensive 
reviews will be increased and achieved within a shorter period of time.
    The EPA anticipates fewer or less substantial information 
collection requests (ICRs) in conjunction with prospective CAA-required 
reviews may be needed, resulting in a decrease in time spent by 
industry to respond to data collection requests. The EPA also expects 
the ICRs to contain less extensive stack testing provisions, as we will 
already have stack test data electronically. Reduced testing 
requirements would be a cost savings to industry. The EPA should also 
be able to conduct these required reviews more quickly. While the 
regulated community may benefit from a reduced burden of ICRs, the 
general public benefits from the Agency's ability to provide these 
required reviews more quickly, resulting in increased public health and 
environmental protection.
    Air agencies will benefit from more streamlined and automated 
review of the electronically submitted data. Having reports and 
associated data in electronic format will facilitate review through the 
use of software ``search'' options, as well as the downloading and 
analyzing of data in spreadsheet format. The ability to access and 
review air emission report information electronically will assist air 
agencies to more quickly and accurately determine compliance with the 
applicable regulations, potentially allowing a faster response to 
violations that could minimize harmful air emissions. This benefits 
both air agencies and the general public.
    For a more thorough discussion of electronic reporting, see the 
discussion in the preamble of the March 2015 proposal. In summary, in 
addition to supporting regulation development, control strategy 
development, and other air pollution control activities, having an 
electronic database populated with performance test data will save 
industry, air agencies, and the EPA significant time, money, and effort 
while improving the quality of emission inventories, air quality 
regulations, and enhancing the public's access to this important 
information.
2. Digital Picture Reporting as an Alternative for Well Completions 
(``REC PIX'') and Manufacturer Installed Control Devices
    The EPA is finalizing digital picture reporting as an alternative 
for well completions and manufacturer installed control devices as 
proposed. Specifically, the final rule allows digital picture reporting 
as an alternative for well completions (``REC PIX'') and manufacturer 
installed control devices. These alternative reporting options provide 
flexibility for owners and operators, provide enhanced ``visibility'' 
for regulators, and take advantage of the advances of the digital age 
with the ability to capture geospatial accuracy at any location.
    Digital picture reporting as an alternative for well completions 
(``REC PIX'') reflects the 2012 NSPS. As with the 2012 NSPS, we 
continue to promote an optional 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 subpart OOOOa. Although we understand that commenters 
have concerns about the amount of electronic storage capability 
necessary to store digital pictures, we believe that by allowing either 
the REC PIX or the elements required under the recordkeeping 
requirements for well completions, the owner or operator may determine 
what is most advantageous for their company. Should an owner or 
operator choose to submit the REC PIX, the REC PIX must consist of a 
digital photograph of the REC equipment in use, with the date and 
geospatial coordinates shown on the photographs. These photographs must 
be submitted with the next annual report, along with a list of well 
completions performed with identifying information for each well 
completed.
    Digital picture reporting as an alternative for manufacturer 
installed control devices provides further opportunity and flexibility 
to owners and operators to advance data capture to ensure that 
compliance practices are in effect. This alternative recordkeeping and 
reporting option is allowed specifically for centrifugal compressors 
and storage vessels routed to control devices, where the control device 
used is one tested in accordance with the manufacturer testing 
procedures in the rule and is posted to the EPA Oil and Gas page. In 
lieu of a written record with the location of the centrifugal 
compressor or storage vessel and its associated control device in 
latitude and longitude, the digital picture alternative must have the 
date the photograph was taken and the latitude and longitude of the 
centrifugal compressor and control device or storage vessel and control 
device imbedded within or stored with the digital file. As an 
alternative to imbedded latitude and longitude within the digital 
picture, the digital picture may consist of a photograph of the 
centrifugal compressor and control device with a photograph of a 
separately operating GPS device within the same digital picture, 
provided the latitude and longitude output of the GPS unit can be 
clearly read in the digital photograph. Furthermore, as discussed in 
section VI.F of this preamble, digital pictures and frame captures will 
help ensure that OGI for fugitive emissions is being performed 
properly.

[[Page 35871]]

3. Certification of Technical Infeasibility of Connecting a Pneumatic 
Pump to an Existing Control Device
    In response to comment, the final rule requires that a new, 
modified, or reconstructed pneumatic pump be routed to an existing 
control device or process onsite, unless the owner or operator obtains 
a certification that it is technically infeasible to do so. The EPA 
understands that some factors such as capacity of the existing control 
device and back pressure on the exhaust of the pneumatic pump imposed 
by the closed vent system and control device can contribute to 
infeasibility of routing a pneumatic pump to an existing control device 
onsite. Due to the various scenarios that could make routing a 
pneumatic pump to an onsite control device or process technically 
infeasible, we do not think we could prescribe a specific set of 
criteria or factors that must be considered for making such 
determination that could capture all such circumstances. However, we 
want to ensure that the owner or operator has effectively assessed 
these factors before making a claim of infeasibility. To that end, we 
have included provisions in the final rule to require certification by 
a qualified professional engineer of such technical infeasibility. In 
addition, we are requiring that the owner or operator maintain records 
of that certification for a period of five years.
4. Professional Engineer Design of Closed Vent Systems
    It is the EPA's experience, through site inspections and 
interaction with the states, that closed vent systems and control 
devices for storage vessels and other emission sources often suffer 
from improper design or inadequate capacity that results in emissions 
not reaching the control device and/or the control device being 
overwhelmed by the volume of emissions. Either of these conditions can 
seriously compromise emissions control and can render the system 
ineffective. We also discussed the issue in the September 2015 
Compliance Alert ``EPA Observes Air Emissions from Controlled Storage 
Vessels at Onshore Oil and Natural Gas Production Facilities'' (See 
https://www.epa.gov/sites/production/files/2015-09/documents/oilgascompliancealert.pdf).
    We believe it is important that owners and operators make real 
efforts to provide for proper design of these systems to ensure that 
all the emissions routed to the control device reach the control device 
and that the control device is sized and operated to result in proper 
control. As a result, we have included in the final rule provisions for 
certification by a qualified professional engineer that the closed vent 
system is properly designed to ensure that all emissions from the unit 
being controlled in fact reach the control device and allow for proper 
control.
    Although the final rule does not include requirements for specific 
criteria for proper design, the EPA believes there are certain minimum 
design criteria that should be considered to ensure that the closed 
vent and control device system are designed to meet the requirements of 
the rule; i.e., the closed vent system must be capable of routing all 
gases, vapors, and fumes emitted from the affected facility to a 
control device or to a process that meets the requirements of the rule.
    Furthermore, because other emissions may be collected into the 
closed vent system and routed to the control device, these design 
criteria include consideration of the contribution of these additional 
emissions to ensure proper sizing and operation. The minimum design 
elements include, but are not limited to, based on site-specific 
considerations:
    1. Review of the Control Technologies to be Used to Comply with 
Sec. Sec.  60.5380a and 60.5395a.
    2. Closed Vent System Considerations:
    a. Piping--
    i. Size (include all emissions, not just affected facility);
    ii. Back pressure, including low points which collect liquids;
    iii. Pressure losses; and
    iv. Bypasses and pressure release points.
    3. Affected Facility Considerations:
    a. Peak Flow from affected facility, including flash emissions, if 
applicable; and
    b. Bypasses, pressure release points.
    4. Control Device Considerations:
    a. Maximum volumetric flow rate based on peak flow, and
    b. Ability to handle future gas flow.

K. Provision for Equivalency Determinations

    In recent years, certain states have developed programs to control 
various oil and gas emission sources in their own states. Due to the 
differences in the sources covered and the requirements, determining 
equivalency through direct comparison of the various state programs 
with the NSPS has proven to be difficult. We also did not find that any 
state program as a whole would reflect what we have identified as the 
BSERs for all emissions sources covered by the NSPS. In any event, 
federal standards are necessary to ensure that emissions from the oil 
and natural gas industry are controlled nationwide.
    However, depending on the applicable state requirements, certain 
owners and operators may achieve equivalent or more emission reduction 
from their affected source(s) than the required reduction under the 
NSPS by complying with their state requirements. States may adopt and 
enforce standards or limitations that are more stringent than the NSPS. 
See CAA section 116 and the EPA's regulations at 40 CFR 60.10(a). For 
states that are being proactive in addressing emissions from the oil 
and natural gas industry, it is important that the NSPS complement such 
effort. Therefore, in the final rule, through the process described in 
section VI.F.1.i for emerging technology, owners and operators may also 
submit an application requesting that the EPA approve certain state 
requirement as ``alternative means of emission limitations'' under the 
NSPS for their affected facilities. The application would include a 
demonstration that emission reduction achieved under the state 
requirement(s) is at least equivalent to the emission reduction 
achieved under the NSPS standards for a given affected facility. 
Consistent with section 111(h)(3), any application will be publicly 
noticed, which the EPA intends to provide within six months after 
receiving a complete application, including all required information 
for evaluation. The EPA will provide an opportunity for public hearing 
on the application and on intended action the EPA might take. The EPA 
intends to make a final determination within six months after the close 
of the public comment period. The EPA will also publish its 
determination in the Federal Register.

VII. Prevention of Significant Deterioration and Title V Permitting

A. Overview

    This final rule will regulate GHGs under CAA section 111. In this 
section, the EPA is addressing how regulation of GHGs under CAA section 
111 could have implications for other EPA rules and for permits written 
under the CAA Prevention of Significant Deterioration (PSD) 
preconstruction permit program and the CAA Title V operating permit 
program. The EPA is adopting provisions in the regulations that 
explicitly address some of these potential implications based on our 
review of the proposed regulatory text and comments received on the 
proposal.
    For purposes of the PSD program, the EPA is finalizing provisions 
in part 60

[[Page 35872]]

of its regulations and explaining in this preamble that the current 
threshold for determining whether a PSD source must satisfy the best 
available control technology (BACT) requirement for GHGs continues to 
apply after promulgation of this rule. This rule does not require any 
additional revisions to state implementation plans (SIPs). With respect 
to the Title V operating permits program, we are finalizing provisions 
in part 60 and explaining in this preamble that this rule does not 
affect whether sources are subject to the requirement to obtain a Title 
V operating permit based solely on emitting or having the potential to 
emit GHGs above major source thresholds.

B. Applicability of Tailoring Rule Thresholds Under the PSD Program

    EPA received several comments asking for clarification or changes 
to make clear that this rule did not directly regulate methane as a 
separate pollutant from GHG and that it would not cause sources to 
trigger PSD or Title V permitting requirements based solely on methane 
emissions.\96\ This section discusses changes made in response to these 
comments as well as clarification as to what, if any, impact this rule 
has on PSD permitting. Section VII.C below addresses Title V-specific 
issues.
---------------------------------------------------------------------------

    \96\ As is discussed elsewhere, the EPA has made clear that the 
pollutant subject to regulation is GHG, in the form of methane. 
Additional regulatory language in 40 CFR 60.5360a has been added to 
provide additional clarity.
---------------------------------------------------------------------------

    Under the PSD program in part C of title I of the CAA, in areas 
that are classified as attainment or unclassifiable for NAAQS 
pollutants, a new or modified source that emits any air pollutant 
subject to regulation at or above specified thresholds is required to 
obtain a preconstruction permit. This permit ensures that the source 
meets specific requirements, including application of BACT to each 
pollutant subject to regulation under the CAA. Many states (and local 
districts) are authorized by the EPA to administer the PSD program and 
to issue PSD permits. If a state is not authorized, then the EPA issues 
the PSD permits for facilities in that state.
    To identify the pollutants subject to the PSD permitting program, 
EPA regulations contain a definition of the term ``regulated NSR 
pollutant.'' 40 CFR 52.21(b)(50); 40 CFR 51.166(b)(49). This definition 
contains four subparts, which cover pollutants regulated under various 
parts of the CAA. The second subpart covers pollutants regulated under 
section 111 of the CAA. The fourth subpart is a catch-all provision 
that applies to ``[a]ny pollutant that is otherwise subject to 
regulation under the Act.''
    This definition and the associated PSD permitting requirements 
applied to GHGs for the first time on January 2, 2011, by virtue of the 
EPA's regulation of GHG emissions from motor vehicles, which first took 
effect on that same date. 75 FR 17004 (Apr. 2, 2010). GHGs became 
subject to regulation under the CAA and the fourth subpart of the 
``regulated NSR pollutant'' definition became applicable to GHGs.
    On June 3, 2010, the EPA issued a final rule, known as the 
Tailoring Rule, which phased in permitting requirements for GHG 
emissions from stationary sources under the CAA PSD and Title V 
permitting programs (75 FR 31514). Under its understanding of the CAA 
at the time, the EPA believed the Tailoring Rule was necessary to avoid 
a sudden and unmanageable increase in the number of sources that would 
be required to obtain PSD and Title V permits under the CAA because the 
sources emitted GHGs in amounts over applicable major source and major 
modification thresholds. In Step 1 of the Tailoring Rule, which began 
on January 2, 2011, the EPA limited application of PSD or Title V 
requirements to sources of GHG emissions only if the sources were 
subject to PSD or Title V ``anyway'' due to their emissions of non-GHG 
pollutants. These sources are referred to as ``anyway sources.'' In 
Step 2 of the Tailoring Rule, which began on July 1, 2011, the EPA 
applied the PSD and Title V permitting requirements under the CAA to 
sources that were classified as major and, thus, required to obtain a 
permit based solely on their potential GHG emissions and to 
modifications of otherwise major sources that required a PSD permit 
because they increased only GHG emissions above applicable levels in 
the EPA regulations.
    In the PSD program, the EPA implemented the steps of the Tailoring 
Rule by adopting a definition of the term ``subject to regulation.'' 
The limitations in Step 1 of the Tailoring Rule are reflected in 40 CFR 
52.21(b)(49)(iv) and 40 CFR 51.166(b)(48)(iv). With respect to ``anyway 
sources'' covered by PSD during Step 1, this provision established that 
GHGs would not be subject to PSD requirements unless the source emitted 
GHGs in the amount of 75,000 tons per year (tpy) of CO2 Eq. or more. 
The primary practical effect of this paragraph is that the PSD BACT 
requirement does not apply to GHG emissions from an ``anyway source'' 
unless the source emits GHGs at or above this threshold. The Tailoring 
Rule Step 2 limitations are reflected in 40 CFR 52.21(b)(49)(v) and 
51.166(b)(48)(v). These provisions contain thresholds that, when 
applied through the definition of ``regulated NSR pollutant,'' function 
to limit the scope of the terms ``major stationary source'' and ``major 
modification'' that determine whether a source is required to obtain a 
PSD permit. See e.g., 40 CFR 51.166(a)(7)(i) and (iii); 40 CFR 
51.166(b)(1); 40 CFR 51.166(b)(2).
    On June 23, 2014, the United States Supreme Court, in Utility Air 
Regulatory Group v. Environmental Protection Agency, issued a decision 
addressing the application of PSD permitting requirements to GHG 
emissions. The Supreme Court held that the EPA may not treat GHGs as an 
air pollutant for purposes of determining whether a source is a major 
source (or modification thereof) for the purpose of PSD applicability. 
The Court also said that the EPA could continue to require that PSD 
permits, otherwise required based on emissions of pollutants other than 
GHGs, contain limitations on GHG emissions based on the application of 
BACT. The Supreme Court decision effectively upheld PSD permitting 
requirements for GHG emissions under Step 1 of the Tailoring Rule for 
``anyway sources'' and invalidated application of PSD permitting 
requirements to Step 2 sources based on GHG emissions. The Court also 
recognized that, although the EPA had not yet done so, it could 
``establish an appropriate de minimis threshold below which BACT is not 
required for a source's greenhouse gas emissions.'' 134 S. Ct. at 2449.
    In accordance with the Supreme Court decision, on April 10, 2015, 
the United States Court of Appeals for the District of Columbia Circuit 
(the D.C. Circuit) issued an amended judgment vacating the regulations 
that implemented Step 2 of the Tailoring Rule but not the regulations 
that implement Step 1 of the Tailoring Rule. The court specifically 
vacated 40 CFR 51.166(b)(48)(v) and 40 CFR 52.21(b)(49)(v) of the EPA's 
regulations, but did not vacate 40 CFR 51.166(b)(48)(iv) or 40 CFR 
52.21(b)(48)(iv). The court also directed the EPA to consider whether 
any further revisions to its regulations are appropriate in light of 
UARG v. EPA and, if so, to undertake such revisions.
    The practical effect of the Supreme Court's clarification of the 
reach of the CAA is that it eliminates the need for Step 2 of the 
Tailoring Rule and subsequent steps of the GHG permitting phase-in that 
the EPA had planned to consider under the Tailoring Rule. This also 
eliminates the possibility that the

[[Page 35873]]

promulgation of GHG standards under section 111 could result in 
additional sources becoming subject to PSD based solely on GHGs, 
notwithstanding the limitations the EPA adopted in the Tailoring 
Rule.\97\ However, for an interim period, the EPA and the states will 
need to continue applying parts of the PSD definition of ``subject to 
regulation'' to ensure that sources obtain PSD permits meeting the 
requirements of the CAA.
---------------------------------------------------------------------------

    \97\ As discussed in other portions of this rulemaking, GHG are 
the pollutant subject to regulation by this rule. The standards are 
specific to GHGs expressed in the form of limitations on emissions 
of methane. Changes, consistent with 40 CFR part 60, subpart TTTT as 
suggested by several of the commenters, have been made in 40 CFR 
60.5360a to make this clear.
---------------------------------------------------------------------------

    The CAA continues to require that PSD permits issued to ``anyway 
sources'' satisfy the BACT requirement for GHGs. Based on the language 
that remains applicable under 40 CFR 51.166(b)(48)(iv) and 40 CFR 
52.21(b)(49)(iv), the EPA and states may continue to limit the 
application of BACT to GHG emissions in those circumstances where a 
source emits GHGs in the amount of at least 75,000 tpy on a CO2 Eq. 
basis. The EPA's intention is for this to serve as an interim approach 
while the EPA moves forward to propose a GHG significant emission rate 
(SER) that would establish a de minimis threshold level for permitting 
GHG emissions under PSD. Under this forthcoming rule, the EPA intends 
to propose restructuring the GHG provisions in its PSD regulations so 
that the de minimis threshold for GHGs will not reside within the 
definition of ``subject to regulation.'' This restructuring will be 
designed to make the PSD regulatory provisions on GHGs universally 
applicable, without regard to the particular subparts of the definition 
of ``regulated NSR pollutant'' that may cover GHGs. Upon promulgation 
of this PSD rule, it will then provide a framework that states may use 
when updating their SIPs consistent with the Supreme Court decision.
    While the PSD rulemaking described above is pending, the EPA and 
approved state, local, and tribal permitting authorities will still 
need to implement the BACT requirement for GHGs. In order to enable 
permitting authorities to continue applying the 75,000 tpy CO2 Eq. 
threshold to determine whether BACT applies to GHG emissions from an 
``anyway source'' after GHGs are subject to regulation under CAA 
section 111, the EPA has concluded that it is appropriate to adopt 
language in 40 CFR 60.5360a, language that is substantially similar to 
language found in 40 CFR 60.5515 (subpart TTTT).
    While most of the Tailoring Rule limitations are no longer needed 
to avoid triggering the requirement to obtain a PSD permit based on 
GHGs alone, the limitation in 40 CFR 51.166(b)(48)(iv) and 40 CFR 
52.21(b)(49)(iv) will remain important to provide an interim 
applicability level for the GHG BACT requirement in ``anyway source'' 
PSD permits. Thus, there continues to be a need to ensure that the 
regulation of GHGs under CAA section 111 does not make this BACT 
applicability level for ``anyway sources'' effectively inoperable. The 
language in 40 CFR 60.5360a is necessary to avoid this result in light 
of the judicial actions described above.

C. Implications for Title V Program

    Under the Title V program, certain stationary sources, including 
``major sources'' are required to obtain an operating permit. This 
permit includes all of the CAA requirements applicable to the source, 
including adequate monitoring, recordkeeping, and reporting 
requirements to ensure sources' compliance. These permits are generally 
issued through EPA-approved state Title V programs.
    In the proposal for this rulemaking, the EPA indicated that ``the 
air pollutant that it propose[d] to regulate [was] the pollutant GHGs 
(which consist of the six well-mixed gases), consistent with other 
actions the EPA has taken under the CAA, although only methane will be 
reduced directly by the proposed standards.'' 80 FR 56600-56601 (Sept. 
18, 2015).
    Similar to the comments received on PSD permitting, the EPA 
received several comments asking for clarification to make clear that 
this rule did not directly regulate methane as a separate pollutant 
from GHG and that it would not cause sources to be considered a major 
source under the Title V permitting program based solely on having 
methane emissions above the major source threshold. Several of these 
comments suggested that this issue could be addressed by adding 
provisions similar to those that appear in 40 CFR 60.5515 (subpart 
TTTT).
    The immediately preceding section provides some general background 
about the application of the PSD and Title V permitting programs to GHG 
emissions. With respect to Title V, the definition of major source 
includes, in relevant part, a stationary source that ``directly emits 
or has the potential to emit, 100 tpy or more of any air pollutant 
subject to regulation.'' 40 CFR 70.2, 71.2 (definition of ``major 
source''). In the Tailoring Rule, a GHG threshold was incorporated into 
the definition of ``subject to regulation'' under 40 CFR 70.2 and 71.2, 
such that those definitions specify that GHGs are not subject to 
regulation, unless, as of July 1, 2011, the emissions of GHGs are from 
a source emitting or having the potential to emit 100,000 tpy of GHGs 
on a CO2 Eq. basis. 40 CFR 70.2, 71.2 (definition of ``subject to 
regulation''); see also 75 FR 31583, June 3, 2010. However, there is 
not a similar threshold for methane as a separately regulated air 
pollutant. Some comments reflected a concern that if methane were to be 
subject to regulation as a separate air pollutant, sources that emitted 
or had the potential to emit 100 tpy or more of methane would trigger 
major source status under Title V and any related requirements under 
the Title V permitting program.
    In consideration of these comments and for purposes of clarity, the 
EPA has concluded that it is appropriate to adopt language in 40 CFR 
60.5360a that is substantially similar to language found in 40 CFR 
60.5515 (subpart TTTT). Consistent with the statement quoted above from 
the proposal, that provision along with the explanation in this 
preamble clarifies that the GHG standard established in this rulemaking 
regulates the air pollutant GHGs, although the standard is expressed in 
the form of a limitation on emission of methane. Accordingly, the air 
pollutant that is subject to regulation under this standard for Title V 
purposes is GHGs.
    As noted above, on June 23, 2014, the United States Supreme Court 
issued its opinion in UARG v. EPA, 134 S.Ct. 2427 (June 23, 2014) and, 
in accordance with that decision, the D.C. Circuit subsequently issued 
an amended judgment in Coalition for Responsible Regulation, Inc. v. 
Environmental Protection Agency, Nos. 09-1322, 10-073, 10-1092 and 10-
1167 (D.C. Cir., April 10, 2015). With respect to Title V, the Supreme 
Court said in UARG v. EPA that the EPA may not treat GHGs as an air 
pollutant for purposes of determining whether a source is a major 
source required to obtain a Title V operating permit. In accordance 
with that decision, the D.C. Circuit's amended judgment in Coalition 
for Responsible Regulation, Inc. v. Environmental Protection Agency, 
vacated the Title V regulations under review in that case to the extent 
that they require a stationary source to obtain a Title V permit solely 
because the source emits or has the potential to emit GHGs above the 
applicable major source thresholds. The D.C. Circuit also directed the 
EPA to consider whether any further revisions to its regulations

[[Page 35874]]

are appropriate in light of UARG v. EPA, and, if so, to undertake to 
make such revisions. These court decisions make clear that promulgation 
of CAA section 111 requirements for GHGs will not result in the EPA 
imposing a requirement that stationary sources obtain a Title V permit 
solely because such sources emit or have the potential to emit GHGs 
above the applicable major source thresholds.\98\
---------------------------------------------------------------------------

    \98\ The EPA intends to propose revisions to the Title V 
regulations in a future rulemaking action to respond to the Supreme 
Court decision and the D.C. Circuit's amended judgment. To the 
extent there are any issues related to the potential interaction 
between the promulgation of CAA section 111 requirements for GHGs 
and Title V applicability based on emissions above major source 
thresholds, the EPA anticipates there would be an opportunity to 
consider those during that rulemaking.
---------------------------------------------------------------------------

    To be clear, however, unless exempted by the Administrator through 
regulation under CAA section 502(a), any source, including an area 
source (a ``non-major source''), subject to an NSPS is required to 
apply for, and operate pursuant to, a Title V permit that ensures 
compliance with all applicable CAA requirements for the source, 
including any GHG-related applicable requirements. This aspect of the 
Title V program is not affected by UARG v. EPA, as the EPA does not 
read that decision to affect either the grounds other than those 
described above on which a Title V permit may be required or the 
applicable requirements that must be addressed in Title V permits.\99\ 
For the source category in this rule, there is an exemption in 40 CFR 
60.5370a from the obligation to obtain a Title V permit for sources 
that are not otherwise required by law to obtain a permit under 40 CFR 
70.3(a) or 40 CFR 71.3(a). However, sources that are subject to the CAA 
section 111 standards promulgated in this rule and that are otherwise 
required to obtain a Title V permit under 40 CFR 70.3(a) or 40 CFR 
71.3(a) will be required to apply for, and operate pursuant to, a Title 
V permit that ensures compliance with all applicable CAA requirements, 
including any GHG-related applicable requirements.
---------------------------------------------------------------------------

    \99\ See Memorandum from Janet G. McCabe, Acting Assistant 
Administrator, Office of Air and Radiation, and Cynthia Giles, 
Assistant Administrator, Office of Enforcement and Compliance 
Assurance, to Regional Administrators, Regions 1-10, Next Steps and 
Preliminary Views on the Application of Clean Air Act Permitting 
Programs to Greenhouse Gases Following the Supreme Court's Decision 
in Utility Regulatory Group v. Environmental Protection Agency (July 
24, 2014) at 5.
---------------------------------------------------------------------------

VIII. Summary of Significant Comments and Responses

    This section summarizes the significant comments on our proposed 
amendments and our response to those comments.

A. Major Comments Concerning Listing of the Oil and Natural Gas Source 
Category

    As previously explained, the EPA interprets the 1979 listing of 
this source category to cover the oil and natural gas industry broadly. 
To the extent there is any uncertainty, EPA proposed, as an alternative 
in the 2015 proposal, to revise the listing of this source category to 
include oil production and natural gas production, processing, and 
transmission and storage. We received several comments regarding the 
EPA's interpretation of the 1979 category listing and its alternative 
proposal to revise that listing. Provided below is one such comment and 
the EPA's response. Other comments on this subject and the EPA's 
responses thereto can be found in the RTC.
    Comment: One commenter argues that, in the proposed rule, the EPA 
seeks to unlawfully expand the scope of the oil and natural gas sector 
source category, even beyond the expansion that the EPA undertook in 
2012 with subpart OOOO, which the commenter had also opposed as 
unlawful. The commenter asserts that the EPA's attempt here to expand 
even further the types of emissions sources that would be subject to 
the NSPS is likewise unlawful. The commenter notes that, in this 
proposal, several types of never before regulated emissions sources 
would be regulated under NSPS, specifically, hydraulically fractured 
oil well completions, pneumatic pumps and fugitive emissions from well 
sites and compressor stations, and that some source types would also be 
regulated more generally for methane and VOC emissions, as only a small 
subset are currently regulated for VOC: Pneumatic controllers, 
centrifugal compressors and reciprocating compressors (except for 
compressors at well sites).
    The commenter notes that the EPA's proposed NSPS would cover an 
even greater number of very small source types in the EPA's broadly 
defined ``oil and natural gas source category,'' which, according to 
the EPA, includes production, processing, transmission and storage. The 
commenter notes that the EPA again maintains, as it did in the original 
subpart OOOO rulemaking, that all emissions sources proposed for 
regulation are covered by its 1979 listing of the oil and natural gas 
category.
    The commenter claims that the EPA is incorrect that the 1979 
original source category determination can be read to include the 
numerous smaller emissions points covered by this proposal. According 
to the commenter, the 1979 listing was focused on major emitting 
operations and cannot be reasonably construed as encompassing small, 
discrete sources that exist separate and apart from a large facility, 
like a processing plant.
    The commenter claims that the EPA made clear in the 1979 listing 
notice that the category was listed to satisfy section 111(f) of the 
Clean Air Act. According to the commenter, that section required the 
EPA to create a list of ``categories of major stationary sources'' that 
had not been listed as of August 7, 1977, under section 111(b)(1)(A) of 
the Act, and to promulgate NSPS for the listed categories according to 
a set schedule. The commenter asserts that the EPA explained in the 
listing rule that its list included ``major source categories,'' which 
the EPA defined to include ``those categories for which an average size 
plant has the potential to emit 100 tons or more per year of any one 
pollutant.''
    Although the commenter notes that the EPA provided no further 
explanation in its original 1979 listing decision as to what facilities 
it intended to regulate under the ``crude oil and natural gas 
production'' source category, the commenter claims that ``there can be 
no doubt that the category originally included `stationary sources' 
(i.e., `plants') that typically have a potential to emit at least 100 
tons per year of a regulated pollutant.'' \100\ The commenter argues 
that this communicates two important limitations on the original 
listing decision: First, the EPA was focused on discrete ``plants'' or 
``stationary sources''; and second, the EPA was focused on large 
emitting plants or stationary sources. The commenter argues that, as a 
result, the original listing decision cannot reasonably be interpreted 
to extend to the types of sources the EPA seeks to regulate in the 
proposal and that the additional source types that the EPA seeks to 
regulate in this proposal could not plausibly be considered part and 
parcel of major emitting plants.
---------------------------------------------------------------------------

    \100\ API Comments on the Proposed Rulemaking--Standards of 
Performance for New Stationary Sources: Oil and Natural Gas 
Production and Natural Gas Transmission and Distribution, at 2 
(December 4, 2015).
---------------------------------------------------------------------------

    The commenter notes that the EPA interpreted the 1979 listing to be 
broader than the ``production source segment'' because the EPA 
evaluated equipment that is used in various segments of the natural gas 
industry, such as stationary pipeline compressor engines. 80 FR 56600, 
September 18, 2015. The commenter argues that this

[[Page 35875]]

does not evince an intent to regulate non-major source types, but only 
that the Agency evaluated equipment located at what it perceived to be 
major facilities.
    The commenter further notes that, in the preamble to the proposed 
NSPS for natural gas processing plants, the EPA described the major 
emission points of this source category to include process, storage and 
equipment leaks. However, the commenter argues that this does not 
support what the commenter claims as ``broad regulation of even the 
smallest sources in the oil and natural gas industry.'' \101\ The 
commenter notes that the emissions points regulated in that 
rulemaking--process units and compressors--were located at gas 
processing plants. The commenter argues that it is telling that the 
Agency decided to regulate only natural gas processing plants--the 
closest thing to a major emitting plant that can be found in this 
sector--in that NSPS.
---------------------------------------------------------------------------

    \101\ Id.
---------------------------------------------------------------------------

    Response: In 1979, the EPA published a list of source categories, 
including ``oil and natural gas production,'' pursuant to a new section 
111(f) in the Clean Air Act amendment of 1977, which directed the EPA 
to list under 111(b)(1)(A) ``categories of major stationary sources'' 
and establish standards of performance for the listed source 
categories. As explained in the September 2015 proposal preamble and 
earlier in section IV.A of this preamble, the EPA interprets the 1979 
listing to broadly cover the oil and natural gas industry. The 
commenter claims that the EPA's interpretation is incorrect because the 
1979 listing included only large emitting plants or stationary sources. 
However, the commenter's interpretation fails for the following 
reasons.
    The commenter's claim relies in large part on the EPA's definition 
of a ``major source category'' in the 1979 listing action, which was 
defined as ``an average size plant that has the potential to emit 100 
tons or more per year of any one pollutant,'' 44 FR 49222 (August 21, 
1979). However, despite the definition above, the EPA provided notice 
in the listing action that ``certain new sources of smaller than 
average size within these categories may have less than a 100 ton per 
year emission potential.'' 43 FR 38872, 38873 (August 31, 1978). The 
EPA thus made clear that the 1979 listing did not include only those 
meeting the major source threshold. The EPA's contemporaneous 
explanation indicates that, while the 1979 action focused on large 
emitting sources, the EPA recognized at the time that there are smaller 
sources that may warrant regulation.
    The commenter next argues that the 1979 listing included only large 
plants because it included only ``stationary sources.'' However, 
``stationary sources,'' as defined in section 111(a)(2), include not 
only buildings, structures and facilities (e.g., plants) but also 
installations, such as equipment, that emit or may emit any pollutant. 
Moreover, this definition contains no size limitation.
    The commenter cites to the EPA's initial NSPS promulgation in 1985, 
which regulated only natural gas processing plants, as evidence that 
the 1979 listing included only large emitting stationary sources and, 
in the case of the oil and natural gas source category, only natural 
gas processing plants. However, the fact that the EPA regulated only 
natural gas processing plants in the 1985 NSPS does not establish that 
the listed oil and natural gas source category consists of only large 
natural gas processing plants. On the contrary, this argument ignores 
that the category, as listed, also includes crude oil production. 
Further, such narrow view is inconsistent with the EPA's clarification 
of the 1979 listing and the statutory definition of ``stationary 
sources,'' neither of which limits a listed category of stationary 
sources under section 111 only to large plants such as natural gas 
processing plants, as explained above.
    The commenter's assertion is also refuted by the EPA's statements 
during the development of the 1985 NSPS. Specifically, in the preamble 
to the proposed rule 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, which can be 
found in various segments of the oil and natural gas industry. Further, 
as mentioned earlier, the EPA described the listed oil and natural gas 
source category to include emission points that the EPA did not 
regulate at that time, such as ``well systems field oil and gas 
separators, wash tanks, settling tanks and other sources.'' 49 FR at 
2637. The EPA explained in that action that it could not address these 
emission at that time because ``best demonstrated control technology 
has not been identified.''
    In light of the above, EPA reasonably interprets the 1979 listing 
to include the sources regulated under the 2012 oil and gas NSPS as 
well as those subject to today's action. The EPA established well 
completion performances standards for hydraulically fractured gas wells 
in the 2012 NSPS and for oil wells in today's action. These standards 
address some of the above mentioned well system emissions that the EPA 
could not regulate previously due to the lack of data. In addition, as 
mentioned above, the EPA had previously identified equipment leaks as a 
major emission point from this listed source category and established 
leaks standards for natural gas processing plants. Today's action 
further reduces emissions from equipment leaks by establishing work 
practice standards to detect and repair fugitive emissions at well 
sites and compressor stations. Emissions from equipment do not result 
only from leaks but also from normal operations that, if uncontrolled, 
are vented into the atmosphere. Therefore, both the 2012 NSPS and 
today's rule include performance standards for certain equipment used 
throughout the oil and natural gas industry, such as storage vessels, 
pneumatic controllers, pneumatic pumps, and compressors. Because these 
equipment are widely used across this industry, they contribute 
significant amount of emissions even if emissions from an individual 
piece of equipment may not be big.\102\
---------------------------------------------------------------------------

    \102\ For example, based on industry wide estimate, high-bleed 
pneumatic controllers (from production through transmission and 
storage) emit in total of 87,285 tons of VOC and 350,000 tons of 
methane (8.7 million metric tons of CO2e).
---------------------------------------------------------------------------

    The commenter's main concern appears to be with the EPA regulating 
what the commenter claims to be ``very small emission sources'' and, 
therefore, unreasonable. However, section 111(b)(1)(A) requires that 
the EPA list source categories, not emission sources. In listing a 
source category, the EPA is not required to identify specific emission 
points within that source category. However, having listed a source 
category, the EPA is then required under section 111(b)(1)(B) to 
establish through rulemaking performance standards that reflect the 
best system of emission reductions, which would entail evaluation of 
emissions, control options, and other considerations (including their 
costs) for the sources to be regulated. Therefore, specific concerns 
with regulation of certain emission sources can be addressed during the 
rulemaking to establish such performance standards, where a commenter 
can argue that controlling a specific type of source is unreasonable 
under 111(b)(1)(B).
    For the reasons stated above, the commenter fails to support its 
claim that the EPA's interpretation of the 1979 listing is unlawful. 
The commenter also fails to support its interpretation of the 1979 
listing. The EPA's interpretation of

[[Page 35876]]

the 1979 listing therefore remains unchanged.
    Comment: The commenter claims that the EPA fails to make the 
required statutory findings under section 111(b)(1)(A) to support its 
proposed revision to the 1979 listing. The commenter asserts that, 
under section 111(b)(1)(A), the EPA is authorized to regulate 
additional source types if and only if it: (1) Defines a discrete 
``category'' of stationary sources; and (2) determines that emissions 
from the source category cause or significantly contribute to 
endangerment to health or the environment.
    The commenter claims that the EPA makes no effort whatsoever to 
demonstrate that emissions from the particular additionally-regulated 
sources in subpart OOOOa cause or contribute to endangerment to health 
or the environment. Instead, the Agency simply asserts general public 
health effects associated with GHGs, VOC, and SO2 and then 
evaluates emissions from oil and natural gas sources generally. See 80 
FR 56601-08, September 18, 2015. For methane, the EPA merely breaks 
down emissions into four general ``segments'' (natural gas production, 
natural gas processing, natural gas transmission and storage, and 
petroleum production), but does not evaluate particular source type 
emissions within those segments. The EPA does nothing to break down its 
evaluation of emissions even by sector segment for SO2 and 
VOC. This failure to investigate the key statutory listing criteria is 
patently arbitrary and plainly violates the requirement in section 
307(d)(3) of the Clean Air Act to clearly set forth the basis and 
purpose of the proposal.
    The commenter claims that under the EPA's logic, as long as certain 
types of stationary sources in a category, or segment of a category, 
cause or significantly contribute to endangerment to health or the 
environment, the Agency can lump together in the defined source 
category (or segment of a source category) all manner of ancillary 
equipment and operations, even if those ancillary equipment and 
operations do not in and of themselves significantly contribute to the 
previously identified endangerment. See 80 FR 56601, September 18, 
2015. This is not a reasonable interpretation of section 111(b)(1)(A) 
because such an interpretation would bestow virtually unlimited 
regulatory authority upon the EPA, allowing the EPA to evade the 
express listing criteria by creating loose associations of nominally 
related sources in a sector.
    Response: The commenter claims that the EPA must separately list 
and make the required findings under CAA section 111(b)(1)(A) for the 
``additional source types'' from the oil and natural gas industry that 
were not covered by the 1979 listing. First of all, the EPA disagrees 
that there are such ``additional source types'' because, for the 
reasons stated in section IV.A of this preamble and the response to 
comment immediately above, the EPA interprets the 1979 listing to 
broadly cover the oil and natural gas industry. To the extent there is 
any uncertainty, the EPA rejects the commenter's claim that the 1979 
listing covers only natural gas processing plants. But, more 
importantly, the EPA rejects this comment because it is contrary to the 
law.
    CAA section 111(b)(1)(A) requires that the EPA list a category of 
sources ``if in [the Administrator's] judgment it causes, or 
contributes significantly to, air pollution which may reasonably be 
anticipated to endanger public health and welfare.'' \103\ The 
provision is clear that the listing and endangerment findings 
requirements are to be made for source categories, not specific 
emission sources within the source category. The provision also does 
not require that the EPA identify all emission points within a source 
category when listing that category.
---------------------------------------------------------------------------

    \103\ As previously mentioned, the required findings under 
section 111(b)(1)(A) is commonly referred to as the ``endangerment 
findings.''
---------------------------------------------------------------------------

    The commenter's claim that the EPA must separately list and make 
findings for particular emission source types within individual 
segments of the natural gas industry clearly contradicts with the plain 
language of section 111(b)(1)(A) which, as discussed above, is stated 
in terms of source category, not emission source types. Regardless, the 
EPA has satisfied the two criteria the commenter has identified as 
required by section 111(b)(1)(A): (1) Define a discrete category of 
stationary sources; and (2) determine that emissions from the source 
category cause or significantly contribute to endangerment to health or 
the environment. Although the EPA does not believe that revision to the 
1979 category listing to be necessary for today's action, the EPA is 
finalizing as an alternative its proposed revision of the category 
listing to broadly include the oil and natural gas industry. In support 
of the revision, the final rule includes the Administrator's 
determination under section 111(b)(1)(A) that, in her judgment, this 
source category, as defined in this revision, contributes significantly 
to air pollution which may reasonably be anticipated to endanger public 
health or welfare.
    The commenter also appears to claim that the EPA cannot revise the 
scope of a listed source category, but must instead separately list and 
make findings for what the commenter considers as ``additional source 
types'' within an already listed source category. The commenter offers 
no legal basis to support its claim because there is none. On the 
contrary, as explained below, the commenter claim impermissibly 
restricts the EPA's authority under section 111(b)(1)(A).
    Section 111(b)(1)(A) requires that the EPA revise the category 
listing from time to time; it does not limit such revision to simply 
adding new source categories. The only criteria that section 
111(b)(1)(A) states for the EPA to apply to category listing revision 
are the same as those for the initial category listing: That the 
category ``causes, or contributes significantly to, air pollution which 
may reasonably be anticipated to endanger public health and welfare.'' 
Thus, the statute leaves the EPA with the discretion to determine how 
to carry out such task, and that gives the EPA the flexibility to list 
and revise the list, including redefining the scope of a previously 
listed category, as long as long as the EPA meets the above criteria 
with the requisite endangerment findings for the source category as a 
whole. It allows the EPA to revise a category listing to include 
sources that, though not included in the initial listing (e.g., the EPA 
might now have known about it at the time), reasonably belong in a 
listed source category. The commenter provides no compelling reason 
that such emission sources need a separate category listing and 
endangerment finding. In light of the above, the commenter's claim for 
a separate category listing and endangerment finding is not only 
unsupported by the statute, it unreasonably curtails the discretion 
section 111(b)(1)(A) provides the EPA in executing its category listing 
and revision authority under that provision. For the reasons stated 
above, the EPA disagrees with this comment.

B. Major Comments Concerning EPA's Authority To Establish GHG Standards 
in the Form of Limitations on Methane Emissions

    As previously explained in section IV.D, the EPA's authority for 
regulating GHGs in this rule is CAA section 111. The standards in this 
rule that are specific to GHGs are expressed in the form of limitations 
on emissions of methane, and not the other constituent gases of the air 
pollutant GHGs. We

[[Page 35877]]

received several comments regarding the EPA's interpretation of CAA 
section 111. Provided below is a summary of such comments and the EPA's 
response. Other comments on this subject and the EPA's responses 
thereto can be found in the RTC document.
    Comment: Several commenters argued that the EPA cannot rely on the 
2009 Endangerment Finding for GHG to justify the limitations of methane 
in this rule. The commenters made several arguments.
    First, some commenters asserted that the EPA cannot regulate 
methane alone or specifically without a new Endangerment and Cause or 
Contribute Finding for the individual gas, because the original 2009 
Finding defined the pollutant as the six well-mixed greenhouse gases. 
One commenter further stated that it is unlawful for the EPA to 
regulate only methane based on an endangerment finding that is largely 
attributable to other pollutants and that, of the six greenhouse gases, 
carbon dioxide is emitted in vastly greater quantities (even on a 
carbon dioxide equivalent basis) than methane.
    Second, some commenters argue that a new endangerment finding is 
necessary for each pollutant regulated in a given source category. One 
commenter claims that section 111(b)(1)(A) of the CAA requires the EPA 
to list a category of stationary sources if, in the Administrator's 
judgment, the category causes, or contributes significantly to, air 
pollution which may reasonably be anticipated to endanger public health 
or welfare. The commenter further argues that this CAA section 
unambiguously requires the EPA to list and regulate according to 
endangerment and significant contribution findings for particular 
pollutants. The commenter goes to state that it is unreasonable for the 
EPA to use a cause-or-contribute finding made for one pollutant thirty 
years ago in order to justify controlling a different pollutant today. 
The commenter asserts that a ``rational basis test'' is insufficient 
justification, and that the term ``rational basis'' is not found in 
section 111.
    Third, some commenters argue that methane does not endanger human 
health or welfare. One commenter states that methane is naturally 
occurring and is non-toxic, that it does not accumulate in the body, 
that the only real risks that it poses are that it is flammable when 
present in high concentrations, and that inhaling high levels can cause 
oxygen deprivation. Another commenter claims that recent science 
supports a weakening of the case for human-caused global warming.
    Finally, some commenters state that the impacts of the rule will be 
very small. One commenter argues that ``the oil and gas sector do [sic] 
not significantly cause or contribute to climate change'' because 
methane emissions from that sector ``account for only 3 percent of 
total United States domestic GHG emissions, just over 2 percent of the 
total United States GHG Inventory, and 0.3 percent of Global GHG 
emissions'' and transmission and storage is only a third of that total.
    Response: As a general matter, commenters on this issue 
consistently mischaracterize the EPA's actions. The standards in this 
rule that are specific to GHGs are expressed in the form of limitations 
on emissions of methane. For these standards, GHG is the regulated 
pollutant. An endangerment finding is only required when the EPA lists 
a source category under section 111(b)(1)(A). Nothing in section 111 
requires that the EPA make further endangerment findings with respect 
to each pollutant that it regulates under section 111(b)(1)(B). By 
considering whether there is a rational basis to regulate a given 
pollutant from a listed source category, the EPA ensures that it 
regulates pollutants that warrant regulation.
    For purposes of this final rule, the EPA's rational basis is 
supported, in part, by the analysis that supported the 2009 
Endangerment Finding. If, as commenters argue, the EPA is required to 
make additional findings of endangerment and cause-or-contribute for 
this final rule, then the analysis that supported the 2009 Endangerment 
Finding, along with other facts presented herein, including the 
information in sections IV.B and C, would be sufficient to make these 
findings.
    While the 2009 Endangerment Finding defined the pollutant as the 
``aggregate group of the well-mixed greenhouse gases'' the finding was 
also clear that a given source category does not have to emit every 
single one of these gases in order to contribute to the pollution in 
question. See 74 FR 66496-99 and 66541 (December 15, 2009). 
Specifically, as we explained in the 2009 Endangerment Finding, two of 
the six pollutants (PFCs and SF6) are not emitted by motor 
vehicles, the source category in question in the 2009 Endangerment 
Finding. Moreover, while motor vehicles contribute to emissions of HFC-
134a, there are many other HFCs which are not emitted by that source. 
Just as the GHG emissions from motor vehicles do not need to contain 
all six gases in order to be regulated, the GHG emissions from the oil 
and gas sector do not need to contain all six gases. Therefore, the EPA 
does not need to make an endangerment finding for methane alone: The 
2009 Endangerment Finding that defines the aggregate group of six well-
mixed gases as the air pollution addresses emissions of any individual 
component of that aggregate group and, therefore, supports the rational 
basis for this final rule.
    Next, the assertion that methane has no risks beyond flammability 
is false. While methane is indeed produced from natural sources, the 
health and welfare risks of elevated concentrations of greenhouse gases 
(including methane) was detailed in the 2009 Endangerment Finding. 
Moreover, methane is a precursor to tropospheric ozone formation, which 
also impacts human health. As further context, according to the IPCC, 
historical methane emissions contribute the second most warming today 
of all the greenhouse gases, after carbon dioxide. This makes methane 
emission reductions an important contribution to reducing the 
atmospheric concentrations of the six well-mixed greenhouse gases.
    Lastly, the climate benefits anticipated from the implementation of 
this rule are consequential in terms of the quantity of methane 
reduced, particularly in light of the potency of methane as a GHG. The 
reductions are additionally important as the United States oil and 
natural gas sector emits about 32 percent of United States methane 
emissions and about 3.4 percent of all United States GHGs. The final 
standards are expected to reduce methane emissions annually by about 
6.9 million metric tons CO2 Eq. in 2020 and by about 11 
million metric tons CO2 Eq. in 2025. To gives a sense of the 
magnitude of these reductions, the methane reductions expected in 2020 
are equivalent to about 2.8 percent of the methane emissions for this 
sector reported in the United States GHG Inventory for 2014. Expected 
reductions in 2025 are equivalent to around 4.7 percent of 2014 
emissions. As discussed in section IX.E, the estimated monetized 
benefits of methane emission reductions resulting from this rule are 
$160 million to approximately $950 million for reduced emissions in 
2020, and $320 million to $1.8 billion for reduced emissions in 2025, 
depending on the discount rate used. The magnitude of these benefits 
estimates demonstrates that the methane reductions are consequential 
from an economic perspective, as well as physical perspective.

[[Page 35878]]

C. Major Comments Concerning Compressors

1. Wet Seal Centrifugal Compressors With Emission Rates Equal to or 
Lower Than Dry Seal Centrifugal Compressors
    Comment: The EPA received several comments asserting that there are 
many wet seal centrifugal compressors that have emissions that are 
equal to, or lower than, dry seal compressors. One commenter notes that 
the EPA cites 6 standard cubic feet per minute (scfm) as the emission 
rate for dry seals and that a wide variety of wet seal systems are in 
use with varying rates of de-gas emissions and that if wet seal system 
can meet an emissions performance specification on par with dry seals 
(i.e., 6 scfm), they should be exempt from the 95 percent reduction 
requirement. One commenter states that data indicate that a well-
maintained wet seal will have a methane emission rate comparable to or 
lesser than dry seals and that the emission rate for commenter's 
compressors is significantly lower than the average rate identified in 
the EPA's National Emissions Inventory for this kind of source.
    Response: The emissions factor used in our BSER analysis is an 
average factor calculated from available emissions information. As 
such, there are some wet seal centrifugal compressors that have a lower 
emission rate than the average emission rate. However, we have not been 
provided, nor do we have, any data indicating that there is a specific 
type or significant population of wet seal centrifugal compressors that 
have emission rates that are equal to or lower than dry seal 
compressors. We acknowledge that a well-maintained wet seal compressor 
may have lower emissions; however, as noted, the rule is based on an 
average emission factor derived from the best available information on 
a population of wet seal compressors. We have no data on which to base 
an exemption or different requirement for a subcategory of merely 
presumed low-emitting wet seal centrifugal compressors.
2. Regulation of Centrifugal and Reciprocating Compressors at Well 
Sites
    Comment: The EPA received several comments opposing the exemption 
of centrifugal and reciprocating compressors located at well heads from 
the requirements of the rule. The commenters state that there are 
thousands of well head reciprocating compressors across the nation as 
well as some centrifugal compressors at well heads, and they pose a 
significant source of emissions unless properly controlled. The 
commenters contend that the reason the EPA claims to exclude these 
compressors is based on EPA data that show no centrifugal compressors 
located at well heads and on the determination that it is not cost 
effective to regulate these reciprocating compressors. Commenters state 
that the GHGRP data shows that there are centrifugal compressors 
located at well heads and that they should be regulated under the rule. 
Further, commenters assert that the EPA's cost effectiveness 
determination for reciprocating compressors is arbitrary because it was 
based on outdated emission factors and that if updated, the revised 
emissions would render the control for the well head compressors as 
cost-effective. Commenters suggest that the EPA should have relied on 
updated emission factors to estimate emissions from well-site 
compressors as it did to estimate emissions from gathering sector 
compressors, or at least explained why it failed to rely on updated 
emissions data to estimate emissions from well-site compressors.
    Response: The emissions estimates presented in the proposal were 
based on the most robust data available at the time of their 
development. The EPA began collecting data through GHGRP on centrifugal 
compressors in the onshore petroleum and natural gas production segment 
in 2011. However, reporting of input data for compressors, including 
the count of centrifugal compressors at a facility, in onshore 
production was deferred until 2015 and published for the first time in 
October 2015. As a result, data on the number of centrifugal 
compressors were not available through GHGRP at the time of the 
development of the NSPS OOOOa proposal.
    The EPA agrees with the commenter that the newly available data 
from GHGRP show the presence of centrifugal compressors in the onshore 
production segment, but the EPA disagrees with the commenter that it 
should cover these sources under the final rule. Although GHGRP data 
shows that 15 reporters indicated 69 centrifugal compressors at 
production facilities, the data do not provide a method to determine 
the number of centrifugal compressors with wet seals in onshore 
production. The GHGRP does not collect data on seal type (wet seal and 
dry seal) for onshore production. The EPA is not aware of other data 
sets on wet seals in the onshore production segment. Based on available 
data on the number of centrifugal compressors in onshore production, it 
is unlikely that there is a large population of centrifugal compressors 
with wet seals in onshore production.
    With respect to emission factors for reciprocating compressors at 
well sites, the EPA proposed to exempt these compressors from the 
standards because we found that the cost of control for reciprocating 
compressors at well sites is not reasonable. Commenters on the 2014 Oil 
and Gas White Papers and on the subpart OOOOa proposal did not provide 
new data available for development of emission factors for 
reciprocating compressors at well sites. The EPA has not identified 
additional data sources for development of emission factors for 
reciprocating compressors at well sites and, therefore, has not updated 
its emissions estimate for this source. We continue to believe the cost 
of control for reciprocating compressors at well sites remains 
unreasonable. The final rule exempts centrifugal and reciprocating 
compressors at well sites.
3. Condition-Based Maintenance
    Comment: The EPA solicited comment on an alternative to the 
proposed requirements which consists of monitoring of rod packing 
leakage to identify when the rate of rod packing leakage indicates that 
packing replacement is needed. Under such a condition-based maintenance 
provision, rod packing would be inspected or monitored based on a 
prescribed method and frequency and rod packing replacement, or repair 
would be required once a prescribed leak rate was observed. We 
requested additional information on the technical details of this 
condition-based concept.
    Several commenters state that the rule should include an 
alternative maintenance program and allow operators flexibility to use 
a condition-based maintenance approach to reduce emissions rather than 
a prescribed maintenance schedule as currently included in the rule. In 
addition to controlling emissions, commenters assert that a condition-
based maintenance may extend the operation of functional rod packing, 
eliminate premature and wasteful rod packing maintenance/replacement 
and, possibly, where rod packing leakage increases quicker than is 
typical, condition-based maintenance can result in earlier maintenance 
than EPA's proposed prescribed maintenance schedule. Commenters note 
that condition-based maintenance has been a proven successful technique 
for reducing methane emissions through the Natural Gas STAR program, 
where rod packing leaks were periodically monitored and the value of 
the incremental leaked gas (relative to leak rates for ``new'' packing) 
was compared to the rod packing

[[Page 35879]]

maintenance cost. When the incremental lost gas value exceeded the 
maintenance/replacement cost, the rod packing maintenance was 
determined to be cost-effective.
    Other commenters noted that because operators in transmission and 
storage segment do not own the gas, a different performance metric 
could be used and recommended a metric based on a defined leak rate or 
change in leak rate over time. Commenters recommended possibly setting 
a threshold at a leak rate above 2 scfm, combined with annual 
monitoring, which would require rod packing maintenance/replacement 
within nine months or during the next unit shutdown, whichever is 
sooner and which is consistent with a draft California Air Resources 
Board (CARB) regulation for oil and gas operations.
    Response: The EPA disagrees with the commenters that the rule 
should include an alternative maintenance program and allow operators 
flexibility to use condition-based maintenance approach to reduce 
emissions rather than a prescribed maintenance schedule. While we 
received comment supporting the addition of a threshold-based or 
condition-based maintenance provision, we did not receive sufficient 
technical details to properly evaluate this alternative for inclusion 
in the rule. Although condition-based maintenance has been shown to be 
effective under the Natural Gas STAR program, the criteria on which 
rule requirements could be based would require significantly more data 
and analysis. Specifically, in order to evaluate such a provision for 
the rule, we would need to determine an appropriate leak-rate threshold 
which would trigger rod packing replacement. Commenters suggested 2 
scfm demonstrated acceptable rod packing leakage; however, the 
commenters provided no substantive data as to the reason for this 
threshold. Commenters also recommended that we model the provision 
after the California Air Resources Board proposed regulation which was 
based on input from rod packing vendors. Although some valuable 
information was provided, the level of technical data and information 
necessary to analyze all aspects of such a provision were not provided. 
Therefore, we are unable to evaluate the condition-based maintenance 
provision for inclusion in the rule at this time.

D. Major Comments Concerning Pneumatic Controllers

1. Studies That Indicate Emission Rates for Low-Bleed Pneumatic 
Controllers That Are Higher Than the EPA Estimates
    Comment: The EPA received comment that several recent studies 
report that pneumatic controllers emit more than they are designed to 
emit and that their emission rate is higher than the currently 
estimated EPA emission rate for pneumatic controllers. Specifically, 
the commenters noted that studies indicated that controllers were 
observed to have emissions inconsistent with the manufacturer's design 
and were likely operating incorrectly due to maintenance or equipment 
issues. Low-bleed pneumatic controllers were observed to have emission 
rates that were 270 percent higher than the EPA's emission factor for 
these devices, in some cases approaching the emission rate of high-
bleed controllers.
    Response: The emissions estimates presented in the proposal were 
based on the most robust data available at the time of their 
development. The EPA is familiar with the studies discussed in the 
comments summarized here and several of those studies were discussed in 
the EPA's Oil and Gas White Paper. The EPA has reviewed available data; 
because of the lack of emissions data that are straightforward to use 
in assessment of emissions from specific bleed rate categories (i.e., 
high-bleed and low-bleed), the EPA has retained the emission factors 
for pneumatic controllers used in the proposal analysis and has 
retained the requirements for pneumatic controllers.
2. Capture and Control of Emissions From Pneumatic Controllers
    Comment: The EPA received comment that pneumatic controllers should 
be required to capture emissions through a closed vent system and route 
the captured emissions to a process or a control device, similar to the 
approach the EPA has taken in its proposed standards for pneumatic 
pumps and compressors. The commenters cite recent Wyoming proposed 
rules for existing pneumatic controllers that allow operators of 
existing high-bleed controllers to route emissions to a process and the 
California Air Resources Board (CARB) proposed rules which requires 
that operators capture emissions and route to a process or control 
device. Commenters state that this approach would work for all types of 
pneumatic controllers and that this approach would be cost effective 
based on the costs identified for pneumatic pumps in the TSD.
    Response: The EPA disagrees with the commenters that capturing and 
routing emissions from pneumatic controllers to a process or control 
device is a viable control option under our BSER analysis. While the 
commenter stated that a few permits in Wyoming indicate that a facility 
is capturing emissions from controllers and routing to a control 
device, we believe that there is insufficient information and data 
available for the EPA to establish the control option as the BSER. For 
more information, please see the RTC.

E. Major Comments Concerning Pneumatic Pumps

1. Compliance Date
    Comment: Commenters stated that the EPA requires that new or 
modified pneumatic pumps at a site that currently lack an emission 
control device will become an affected facility if a control device is 
later installed; and, the facility must be in compliance within 30 days 
of installation of the new control device. One commenter states that 30 
days does not provide such sources sufficient time to come into 
compliance. The commenter suggests that the rule be revised to require 
compliance within 30 days of startup of the control device so that the 
operator can ensure that the control device is properly tested after 
installation without concern over triggering non-compliance for 
pneumatic pump controls.
    Response: We agree that additional time is appropriate for 
designing connections and testing after control device installation. 
Therefore, we have revised the compliance date in the final rule with 
respect to control devices that are installed on site after 
installation of the pneumatic pump affected facility. In the final 
rule, the compliance date for pneumatic pump affected facilities to be 
routed to a newly installed onsite control device 30 days after startup 
of the control device.
2. Subsequent Removal of Control Device
    Comment: Several commenters expressed concern that the rule did not 
provide a way to remove control equipment from a site when it is no 
longer needed for the purpose for which it was installed. Further, they 
requested that the EPA clarify that a source ceases to be an affected 
facility if the control device is no longer needed for other equipment. 
The commenters cite an example where the exiting control device onsite 
is installed for a subpart OOOO storage vessel and subsequently

[[Page 35880]]

the storage vessel's potential to emit falls below 6 tpy. If this were 
to occur, the storage vessel would no longer be subject to regulation 
and the control device would no longer be necessary.
    Response: The EPA agrees that the intent of the proposal was not to 
require existing control devices that are no longer required for their 
original purposes to remain at a site only to control pneumatic pump 
affected facility emissions. Therefore, the final rule clarifies that 
subsequent to the removal of a control device and provided that there 
is no ability to route to a process, a pneumatic pump affected facility 
is no longer required to comply with Sec.  60.5393a(b)(1) or (2). 
However, these units will continue to be affected facilities and we are 
requiring pneumatic pump affected facilities to continue following the 
relevant recordkeeping requirements of Sec.  60.5420a even after an 
existing control device is removed.
3. Limited-Use Pneumatic Pumps
    Comment: Commenters state that there are natural gas-driven 
pneumatic pumps which are used intermittently to transfer bulk liquids. 
These limited use pumps may be manually operated as needed or may be 
triggered by a level controller or other sensor. Specific examples 
provided by the commenters include engine skid sump pumps, pipeline 
sump pumps, tank bottom pumps, flare knockout drum pumps, and separator 
knockout drum pumps that are used to pump liquids from one place to 
another. The commenters contend that these pumps do not run 
continuously or even seasonally for long periods but only run 
periodically as needed. Thus, these pumps do not exhaust large volumes 
of gas in the aggregate. For this reason, the commenters requested that 
the final rule include an exemption for limited-use pneumatic pumps.
    Response: In the TSDs to the proposed and final rule, the emission 
factors we used for pneumatic pumps assumed that the pumps operated 40 
percent of the time. While we understood that pneumatic pumps typically 
do not run continuously, we did assume that the 40 percent usage was 
distributed evenly throughout the year. However, based upon the 
comments we received, the usage of some pneumatic pumps is much more 
limited than we previously determined and not spread evenly throughout 
the year. We did not intend to regulate these limited-use pneumatic 
pumps and are not including limited-use pneumatic pumps in the 
definition of pneumatic pump affected facilities that are located at 
well sites. Specifically, if a pump located at a well site operates for 
any period of time each day for less than a total of 90 days per year, 
this limited-use pneumatic pump is not an affected facility under this 
rule. We believe this requirement is sufficient to address the 
commenters' concerns for both intermittent use and temporary use 
pneumatic pumps.
    Because we believe there are multiple viable alternatives available 
at natural gas processing plants that are not available at well sites, 
we do not believe it is necessary to exclude limited-use pneumatic 
pumps located at natural gas processing plants from the definition of 
pneumatic pump affected facility. Based on our best available 
information, both instrument air and electricity are readily available 
at natural gas processing plants. We believe owners and operators will 
choose instrument air over natural gas-driven pumps since their other 
pumps will be air powered. We also believe owners and operators can 
utilize electric pumps for intermittent activities cited by the 
commenters such as sump pumps and transfer pumps where it is safe to 
use an electric pump. Given these options, we conclude that it is not 
necessary to exclude limited-use pneumatic pumps located at natural gas 
processing plants from the definition of pneumatic pump affected 
facility in the final rule.
4. Removal of Tagging Requirements
    Comment: Several commenters requested that the EPA remove the 
tagging requirement for pneumatic pump affected facilities. As written, 
the proposed rule required that operators tag pumps that are affected 
facilities and those that are not affected facilities. The commenters 
contend that the tagging requirement appears to add little value and is 
confusing. Commenters suggest operators should only be required to 
maintain a list of make, model, and serial number, rather than 
individual tags and that a list of make, model, and serial number will 
achieve the same results desired by the EPA, without presenting the 
unnecessary operational hurdles associated with individual tagging and 
recordkeeping.
    Response: The EPA has reviewed the proposed tagging requirements 
and agrees with the commenters that the recordkeeping in lieu of 
tagging for pneumatic pumps affected facilities is sufficient. 
Therefore, the EPA has removed the tagging requirements for pneumatic 
pump affected facilities in the final rule.
5. Lean Glycol Circulation Pumps
    Comment: The EPA solicited comments on the level of uncontrolled 
emissions from lean glycol circulation pumps and how they are vented 
through the dehydrator system. We received comments corroborating our 
understanding at proposal and in the white papers that emissions from 
these pumps are vented through the rich glycol separator vent or the 
reboiler still vent and are already regulated under 40 CFR part 63 
subparts HH and HHH.
    Response: The EPA's understanding during the proposal was that the 
lean glycol pumps are integral to the operation of the dehydrator, and 
as such, 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, including HAP 
emission that are being controlled to meet the standards under the 
National Emission Standards for Hazardous Air Pollutants (NESHAP) at 40 
CFR part 63 subparts HH and HHH. It is also our understanding from 
white paper 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 on the white paper stated 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 currently feasible. 
Therefore, we have clarified that lean glycol circulation pumps are not 
affected facilities under the final pneumatic pumps standards.

F. Major Comments Concerning Well Completions

1. Request for a Limited Use of Combustion
    Comment: Several commenters support the requirements for reducing 
completion emissions at oil wells; however, they express concern that 
the proposed rule does not go far enough in establishing a hierarchy of 
preference for the beneficial use options provided in the rule (i.e., 
routing the recovered gas from the separator into a gas flow line or 
collection system, re-injecting the recovered gas into the well or 
another well, use of the recovered gas as an onsite fuel source or use 
of the recovered gas for another useful purpose that a purchased fuel 
or raw material would serve) over what the commenters perceive to be 
the least-preferable option to route the emission to a combustion 
control device. Further, one commenter states that the technical

[[Page 35881]]

infeasibility exemption in the rule is vague and could detract 
significantly from the overall value of this standard if not narrowly 
limited in application. The commenter notes that because of the swiftly 
increasing production of oil (along with associated natural gas) in the 
United States which produces very high initial rates of oil and 
associated gas, it is vital that the rule's requirements apply 
rigorously.
    Response: The EPA agrees that REC should be preferred over 
combustion due to the secondary environmental impact from combustion. 
The final rule reflects such preference by requiring REC unless it is 
technically infeasible, in which event the recovered gas is to be 
routed to a completion combustion device. Further, to ensure that the 
exemption from REC due to technical infeasibility is limited to those 
situations where the operator can demonstrate that each of the options 
to capture and use gas beneficially is not feasible and why, we have 
expanded recordkeeping requirements in the final rule to include: (1) 
Detailed documentation of the reasons for the claim of technical 
infeasibility with respect to all four options provided in Sec.  
60.5375a(a)(1)(ii), including but not limited to, names and locations 
of the nearest gathering line; capture, re-injection, and reuse 
technologies considered; aspects of gas or equipment prohibiting use of 
recovered gas as a fuel onsite; and (2) technical considerations 
prohibiting any other beneficial use of recovered gas on site.
    We believe these additional provisions will support a more diligent 
and transparent application of the intent of the technical 
infeasibility exemption from the REC requirement in the final rule. 
This information must be included in the annual report made available 
to the public 30 days after submission through CEDRI and WebFIRE, 
allowing for public review of best practices and periodic auditing to 
ensure flaring is limited and emissions are minimized.

G. Major Comments Concerning Fugitive Emissions From Well Sites and 
Compressor Stations

1. Modification Definitions for Well Sites
    Comment: Several commenters assert that the definition of 
``modification'' of a well site under the proposed rule in Sec.  
60.5365a(i) is overly broad because it would bring many existing well 
sites under the Rule's requirements. The commenters believe that 
drilling a new well or hydraulically fracturing an existing well does 
not increase the probability of a leak from an individual component and 
no new components result from these activities, thus the potential 
emissions rate does not change and should not be consider a 
modification.
    Response: The EPA believes the addition of a new well or the 
hydraulically fracturing or refracturing of an existing well will 
increase emissions from the well site for the following reasons. These 
events are followed by production from these wells which generate 
additional emissions at the well sites. Some of these additional 
emissions will pass through leaking fugitive emission components at the 
well sites (in addition to the emissions already leaking from those 
components). Further, it is not uncommon that an increase in production 
would require additional equipment and, therefore, additional fugitive 
emission components at the well sites. We also believe that defining 
``modification'' to include these two events, rather than requiring 
complex case-by-case analysis to determine whether there is emission 
increase in each event, will ease implementation burden for owners and 
operators. For the reasons stated above, EPA is finalizing the 
definition of ``modification'' of a well site, as proposed.
2. Monitoring Plan
    Comment: Commenters expressed concerns about the elements of the 
proposed monitoring plans and encouraged the EPA to consult with the 
oil and gas industry and states to adopt requirements that would meet 
their specific needs. Commenters suggested that an area-wide monitoring 
plan should be allowed instead of a corporate-wide or site specific 
plan. The area plan would allow owners to write a plan that covers 
various areas for each specific region since operators may rely on 
contractors in one area due to location while company-owned monitoring 
equipment may be used within another area.
    Response: The EPA participated in numerous meetings with industry, 
environmental and state stakeholders to discuss the proposed rule. 
During these meetings industry stakeholders further explained why a 
corporate-wide monitoring plan would be difficult to develop due to 
their corporate structures, well site locations, basin characteristics 
and many other factors. They also indicated that a site-specific plan 
would be redundant since many well sites within a district or field 
office are similar and would utilize the same personnel, contractors or 
monitoring equipment. The industry stakeholders provided input on 
specific elements of the monitoring plan, such as the walking path 
requirement. Based on the comments that we received and subsequent 
stakeholder meetings, we have made changes to the monitoring plan and 
have further explained our intent for the walking path. We have also 
modified the digital photograph recordkeeping requirements for sources 
of fugitive emissions. See section VI.f.1.h of this preamble for 
further discussion.

H. Major Comments Concerning Final Standards Reflecting Next Generation 
Compliance and Rule Effectiveness Strategies

1. Electronic Reporting
    Comment: While some commenters express support, several commenters 
oppose electronic reporting of compliance-related records. Some of the 
commenters state that they have an obligation under the rule to 
maintain these records and make them available to the regulatory agency 
upon request, and this should be sufficient. Providing all the records 
requested under the proposed rule would likely cause a backlog of 
correspondence between the regulatory agency and the industry. Other 
commenters expressed concern that sensitive company information could 
be present in the records, and other parties could use a FOIA request 
to obtain the records.
    Additional commenters pointed out that the EPA should not require 
electronic reporting until CEDRI is modified to accommodate the unique 
nature of the oil and natural gas production industry. As the 
commenters understand the operational characteristics of CEDRI, the 
system links reports for each affected facility to the site at which 
they are located. Under subparts OOOO and OOOOa, there is no unique 
site identifier. This would result in owners and operators having to 
deconstruct the annual report in order to obtain the affected facility 
level data needed for CEDRI. The EPA did not account for this burden 
and cost. The commenters request that should electronic reporting be 
required, that CEDRI be revised to accept the annual reports as 
currently specified in the proposed rule as a pdf file or hardcopy 
until these issues can be resolved. Commenters also request that CEDRI 
be modified to accept area-wide reports rather than site-level reports. 
Additionally, commenters noted that the definition of ``certifying 
official'' under CEDRI is different than in the proposed rule.
    Finally, since the EPA did not propose regulatory language for 
these

[[Page 35882]]

requirements, some commenters believe that the EPA cannot finalize 
these requirements without first proposing the regulatory language.
    Response: The EPA notes that regulatory language for the electronic 
reporting requirements was available in Sec.  60.5420a, Sec.  60.5422a 
and Sec.  60.5423a of the proposed rule.
    The EPA thanks the commenters for the support for electronic 
reporting. Electronic reporting is in ever-increasing use and is 
universally considered to be faster, more efficient and more accurate 
for all parties once the initial systems have been established and 
start-up costs completed. Electronic reporting of environmental data is 
already common practice in many media offices at the EPA; programs such 
as the Toxics Release Inventory (TRI), the Greenhouse Gas Reporting 
Program, Acid Rain and NOX Budget Trading Programs and the 
Toxic Substances Control Act (TSCA) New Chemicals Program all require 
electronic submissions to the EPA. The EPA has previously implemented 
similar electronic reporting requirements in over 50 different subparts 
within parts 60 and 63. WebFIRE, the public access site for these data, 
currently houses over 5000 reports that have been submitted to the EPA 
via CEDRI.
    The EPA notes that reporting is an essential element in compliance 
assurance, and this is especially true in this sector. Because of the 
large number of sites and the remoteness of sites, it is unlikely that 
the delegated agencies will be able to visit all sites. By providing 
reports electronically in a standardized format, the system benefits 
air agencies by streamlining review of data, facilitating large scale 
data analysis, providing access to reports and providing cost savings 
through a reduction in storage costs. The narrative and upload fields 
within the CEDRI forms can even be used to provide information to 
satisfy extra reporting requirements that state and local air agencies 
may impose.
    The EPA is sensitive to the complexity of the oil and gas 
regulations and the unique challenges presented by this sector. CEDRI 
forms are designed to be consistent with the requirements of the 
underlying subparts and are unique to each regulation. The forms are 
reviewed multiple times before being finalized, and they are subjected 
to a beta testing period that allows end-users to provide feedback on 
issues with the forms prior to requiring their use. Also, if a form has 
not yet been completed by the time the rule is effective, affected 
facilities will not be required to use CEDRI until the form has been 
available for at least 90 days. The EPA notes that we have recently 
developed a bulk upload feature for several subparts within CEDRI. The 
bulk upload feature allows users to enter data for sites across the 
country in a single file instead of having to submit individual reports 
for each site. This feature should alleviate some of the commenters' 
concerns.
    The EPA is aware that facility personnel must learn the new 
reporting system, but the savings realized by simplified data entry 
outweighs the initial period of learning the system. Electronic 
reporting can eliminate paper-based, manual processes, thereby saving 
time and resources, simplifying data entry, eliminating redundancies, 
minimizing data reporting errors and providing data quickly and 
accurately. Reporting form standardization can also lead to cost 
savings by laying out the data elements specified by the regulations in 
a step-by-step process, thereby helping to ensure completeness of the 
data and allowing for accurate assessment of data quality. 
Additionally, the EPA's electronic reporting system will be able to 
access existing information in previously submitted reports and data 
stored in other EPA databases. These data can be incorporated into new 
reports, which will lead to reporting burden reduction through labor 
savings.
    In 2011, in response to Executive Order 13563, the EPA developed a 
plan to periodically review its regulations to determine if they should 
be modified, streamlined, expanded, or repealed in an effort to make 
regulations more effective and less burdensome.\104\ The plan includes 
replacing outdated paper reporting with electronic reporting. In 
keeping with this plan and the White House's Digital Government 
Strategy,\105\ in 2013 the EPA issued an agency-wide policy specifying 
that EPA will start with the assumption that reporting will be 
electronic and not paper. The EPA believes that the electronic 
submittal of the reports addressed in this rulemaking increases the 
usefulness of the data contained in those reports, is in keeping with 
current trends in data availability, further assists in the protection 
of public health and the environment and will ultimately result in less 
burden on the regulated community. Therefore, the EPA is retaining the 
requirement to report these data electronically.
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    \104\ EPA's Final Plan for Periodic Retrospective Reviews, 
August 2011. Available at: http://www.epa.gov/regdarrt/retrospective/documents/eparetroreviewplan-aug2011.pdf.
    \105\ Digital Government: Building a 21st Century Platform to 
Better Serve the American People, May 2012. Available at: https://www.whitehouse.gov/sites/default/files/omb/egov/digital-government/digital-government-strategy.pdf.
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2. Third-Party Verification for Closed Vent Systems
    Comment: Several commenters express opposition to a third-party 
verification system for the design of closed vent systems. Some of the 
commenters explain that they design their closed vent system using in-
house staff. Many of the details regarding actual flow volumes and gas 
composition are unknown at the initial design stage, so it would not be 
possible to certify the design's effectiveness prior to construction. 
Also, storage vessels are designed to have some level of losses, so it 
would also not be possible to certify that the closed vent system 
routes all emissions to the control device.
    Several of the commenters also express concern that the 
verification process discussed in the preamble to the proposed rule 
would create a complex bureaucratic scheme with no measurable benefits. 
Many of the commenters believe such a verification process would add a 
significant labor and cost burden that the EPA has not quantified. The 
EPA's contention that third-party verification ``may'' improve 
compliance is presented without any analysis or support and does not 
justify the costs of such a program.
    Concerning the impartiality requirements outlined by the EPA, some 
of the commenters believe that it would be impossible to find someone 
who is qualified to do verification that could pass those requirements 
due to the interrelationship between the production and support 
companies over decades of working with one another. Some commenters 
contend that the EPA overestimates the availability of qualified third-
party consultants, assuming that an impartial one could be found, that 
understands the industry well enough to competently review designs for 
closed vent systems.
    Some of the commenters remind the EPA of the conclusions the Agency 
reached after proposing a similar third-party verification system for 
the Greenhouse Gas Reporting Program, in which the EPA expressed 
concerns about establishing third-party verification protocols, 
developing a system to accredit third-party verifiers, and developing a 
system to ensure impartiality.
    Response: The EPA continues to believe that independent third party 
verification can furnish more, and sometimes better, data about 
regulatory compliance. With better data about compliance, regulatory 
agencies, including the EPA, would have more

[[Page 35883]]

information to determine what types of regulations are effective and 
how to spend their resources. A critical element to independent third 
party verification is to ensure third-party verifiers are truly 
independent from their clients and perform competently. We continue to 
believe that this model best limits the risk of bias or ``capture'' due 
to the third-party verifier identifying or aligning his interests too 
closely with those of the client. However, in other rulemakings, we 
have explored and implemented an alternative to the independent third 
party verification, where engineering design is the element we wish to 
ensure is examined and implemented without bias. This is the 
``qualified professional engineer'' model. In the ``Resource 
Conservation and Recovery Act (RCRA) Burden Reduction Initiative'' 
(Burden Reduction Rule) (71 FR 16826, April 4, 2006) and the ``Oil 
Pollution Prevention and Response; Non-Transportation-Related Onshore 
and Offshore Facilities rule (67 FR 47042, July 17, 2002), the Agency 
came to similar conclusions. First, that professional engineers, 
whether independent or employees of a facility, being professionals, 
will uphold the integrity of their profession and only certify 
documents that meet the prescribed regulatory requirements and that the 
integrity of both the professional engineer and the professional 
oversight of boards licensing professional engineers are sufficient to 
prevent any abuses. And second, that in-house professional engineers 
may be the persons most familiar with the design and operation of the 
facility and that a restriction on in-house professional certifications 
might place an undue and unnecessary financial burden on owners or 
operators of facilities by forcing them to hire an outside engineer. 
Also in the ``Burden Reduction Rule'' the Agency concluded that a 
professional engineer is able to give fair and technical review because 
of the oversight programs established by the state licensing boards 
that will subject the professional engineer to penalties, including the 
loss of license and potential fines if certifications are provided when 
the facts do not warrant it. A qualified professional engineer 
maintains the most important components of any certification 
requirement: (1) That the engineer be qualified to perform the task 
based on training and experience; and (2) that she or he be a 
professional engineer licensed to practice engineering under the title 
Professional Engineer which requires following a code of ethics with 
the potential of losing his/her license for negligence (see 71 FR 
16868, April 4, 2006). The personal liability of the professional 
engineer provides strong support for both the requirement that 
certifications must be performed by licensed professional engineers. 
The Agency is convinced that an employee of a facility, who is a 
qualified professional engineer and who has been licensed by a state 
licensing board, would be no more likely to be biased than a qualified 
professional engineer who is not an employee of the owner or operator. 
The EPA has concluded that the programs established by state licensing 
boards provide sufficient guarantees that a professional engineer, 
regardless of whether he/she is ``independent'' of the facility, will 
give a fair technical review. As an additional protection, the Agency 
has re-evaluated the design criteria for closed vent systems to ensure 
that the requirements are sufficiently objective and technically 
precise, while providing site specific flexibility, that a qualified 
professional engineer will be able to certify that they have been met.
    It is important to reiterate that state licensing boards can 
investigate complaints of negligence or incompetence on the part of 
professional engineers and may impose fines and other disciplinary 
actions, such as cease-and-desist orders or license revocation. (See 71 
FR 16868.) In light of the third party oversight provided by the state 
licensing boards in combination with the numerous recordkeeping and 
recording requirements established in this rule, the Agency is 
confident that abuses of the certification requirements will be minimal 
and that human health and the environment will be protected.
    In other rulemakings, which have allowed for a qualified 
professional engineer in lieu of an independent reviewer, the Agency 
has required that the professional engineer be licensed in the state in 
which the facility is located. (See ``Hazardous and Solid Waste 
Management System; Disposal of Coal Combustion Residuals from Electric 
Utilities; Final Rule'' (Coal Ash Rule) (80 FR 21302, April 17, 2015)). 
The Agency has made this decision, in that rule, for a number of 
reasons, but primarily because state licensing boards can provide the 
necessary oversight on the actions of the professional engineer and 
investigate complaints of negligence or incompetence as well as impose 
fines and other disciplinary actions such as cease-and-desist orders or 
license revocation. The Agency concluded that oversight may not be as 
rigorous if the professional engineer is operating under a license 
issued from another state. While we believe this is the appropriate 
outcome for the Coal Ash Rule, in part due to the regional and 
geological conditions specific to the landfill design, we do not 
believe that we need to provide this restriction for the closed vent 
system design under this rulemaking. Closed vent system design elements 
are not predicated on regional characteristics but instead follow 
generally and widely understood engineering analysis such as volumetric 
flow, back pressure and pressure drops. We do believe that the 
professional engineer should be licensed in a minimum of one of the 
states in which the certifying official does business.
    Whether to specify independent third-party reporting, some other 
type of third-party or self-reporting, or a Professional Engineer is a 
case-specific decision that will vary depending on the nature of the 
rule, the characteristics of the sector(s) and regulated entities, and 
the applicable regulatory requirements. Based on all relevant factors 
for this rule, the EPA has determined that a qualified Professional 
Engineer approach is appropriate and that it is unnecessary to require 
the individual making certifications under this rule to be 
``independent third parties.'' Thus the final rule does not prohibit an 
employee of the facility from making the certification, provided they 
are a professional engineer that is licensed by a state licensing 
board.
3. The EPA's Authority and Costs for Standards Reflecting Next 
Generation Compliance and Rule Effectiveness
    Comment: Several commenters believe that standards reflecting Next 
Generation Compliance and rule effectiveness strategies discussed in 
the preamble to the proposed rule are not legal and represent an 
overreach of its authority. While the EPA has authority to require 
reasonable recordkeeping, reporting and monitoring under the CAA, there 
is nothing in the CAA that can be construed to authorize the EPA to 
force the regulated community to hire a third-party contractor to do 
the EPA's work. The commenters point out that the EPA admitted in the 
preamble to the 2011 proposal of subpart OOOO that ensuring compliance 
with the well completion requirements would be very difficult and 
burdensome for regulatory agencies. The commenters believe that the EPA 
is using the requirements to relieve the regulatory agencies of some of 
this burden. One commenter stated that the requirements amount to an 
unfunded enforcement mandate on the facilities it is supposed to be 
regulating.
    The commenters also state that the compliance requirements would 
violate

[[Page 35884]]

the Anti-Deficiency Act because the third-party verification 
requirements would circumvent budget appropriations for EPA enforcement 
activities (see 31 U.S.C. 1341(a)(1)(A)).
    Some of the commenters also object to the EPA justifying increased 
monitoring, recordkeeping and reporting requirements on consent decrees 
in enforcement actions. The commenters point out that consent decrees 
impose more stringent requirements on facilities that have been found 
to be in violation of a regulatory requirement; therefore, consent 
decree requirements would be inappropriate for generally applicable 
regulations. The commenters state that the EPA has provided no 
justification for imposing heightened requirements on all facilities 
regardless of their compliance history.
    Several commenters also state that the EPA must propose the 
regulatory language for all of the compliance provisions reflecting 
Next Generation Compliance and rule effectiveness strategies before 
they can be finalized and doing otherwise would raise a notice and 
comment issue. One commenter added that the EPA's intent is to apply 
such compliance requirements to more industries than just oil and 
natural gas production. Therefore, the EPA must separately propose the 
compliance requirements in their entirety, including estimated costs 
and benefits, before using them in any specific rulemakings.
    Many commenters believe the standards reflecting Next Generation 
and rule effectiveness strategies will add significant labor and cost 
burdens over and above the compliance costs that the EPA already 
estimated for complying with the proposed rule. For example, one 
commenter calculates that their company will have to generate 270,000 
closed vent system monthly inspection reports in the first five years 
of the rule if current requirements are finalized. Another commenter 
estimates the cost of installing continuous pressure monitoring 
equipment at a single site to be $20,000, resulting in potential 
company-wide costs of about $15 million. One commenter adds, based on 
their own experience with third-party auditors, the cost of an audit 
can range from $8,000 to $15,000 per audit, per facility. In general, 
the commenters state that the compliance requirements raise technical 
and operational complexities which can only result in increased costs. 
Some of the commenters note that these costs would be untenable for 
small businesses.
    Some of the commenters also expressed concern about a lack of 
necessary IT infrastructure, such as data acquisition hardware, data 
management software, and appropriate software, at remote oil and 
natural gas production and transmission facilities. The commenters also 
point out the lack of electricity at these sites. The commenters point 
out that dealing with these issues further increase the costs 
associated with these compliance measures.
    Response: The EPA believes that the comment regarding our legal 
authority may be based upon a misunderstanding of EPA's Next Generation 
Compliance and rule effectiveness strategies. The EPA describes these 
strategies as follows:
    ``Today's pollution challenges require a modern approach to 
compliance, taking advantage of new tools and approaches while 
strengthening vigorous enforcement of environmental laws. Next 
Generation Compliance is EPA's integrated strategy to do that, designed 
to bring together the best thinking from inside and outside EPA.'' 
\106\ Among the referenced modern approaches to compliance is to 
``[d]esign regulations and permits that are easier to implement, with a 
goal of improved compliance and environmental outcomes.''
---------------------------------------------------------------------------

    \106\ USEPA; Next Generation Compliance Web page at https://www.epa.gov/compliance/next-generation-compliance.
---------------------------------------------------------------------------

    Thus EPA's Next Generation Compliance and rule effectiveness 
strategies, in and of themselves, impose no requirements or obligations 
on the regulated community. The strategies establish no regulatory 
terms for any sector or facility nor create rights or responsibilities 
in any party. Rather, the strategies describe general compliance 
assurance and regulatory design principles, approaches, and tools that 
EPA may consider in conducting rulemaking, permitting, and compliance 
assurance, and enforcement activities.
    Regarding comments that in order to avoid notice and comment issues 
the EPA must propose regulatory language before finalizing any 
regulatory language, the EPA disagrees. Section 307(d)(3) of the CAA 
states that ``notice of proposed rulemaking shall be published in the 
Federal Register, as provided under section 553(b) of title 5, United 
States Code . . . .'' There is nothing in the remainder of section 
307(d) that requires the EPA to publish the regulatory text. Similarly, 
section 553(b) of the Administrative Procedure Act (APA) does not 
require agencies to publish the actual regulatory text. See EMILY's 
List v. FEC, 362 F. Supp. 2d 43, 53 (D.D.C. 2005), where ``[t]he Court 
notes that section 553 itself does not require the Agency to publish 
the text of a proposed rule, since the Agency is permitted to publish 
'either the terms or substance of the proposed rule or a description of 
the subjects and issues involved.' ''. For this rulemaking, the EPA has 
provided notice and opportunity to comment for all of the specific 
regulatory requirements applicable to the sector and facilities covered 
by the rulemaking, either through proposed regulatory language or a 
description in the preamble.
    The EPA notes that the proposal for independent third party 
verification--replaced in the final rule with qualified Professional 
Engineer requirements--reflects the responsibility of regulated 
entities to comply with the new NSPS. 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 non-
air quality health and environmental impact and energy requirement) the 
Administrator determines has been adequately demonstrated.'' Further, 
in directing the Administrator to propose and promulgate regulations 
under section 111(b)(1)(B), Congress provided that the Administrator 
should take comment and then finalize the standards with such 
modifications ``as he deems appropriate.'' The D.C. Circuit has 
considered similar statutory phrasing from CAA section 231(a)(3) and 
concluded that ``[t]his delegation of authority is both explicit and 
extraordinarily broad.'' National Assoc. of Clean Air Agencies v. EPA, 
489 F.3d 1221, 1229 (D.C. Cir. 2007).
    In addition, 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) which provides that for ``any standard of performance 
under section 7411,'' the Administrator may require the sources to, 
among other things, ``install, use, and maintain such monitoring 
equipment, and use such audit procedures, or methods'' and submit 
compliance certifications in accordance with subsection (a)(3) of this 
section,'' as the Administrator may require. CAA section 114(a)(1)(A)-
(G).
    As discussed in section VI and in this section, the EPA has 
determined that to comply with the new NSPS and meet its

[[Page 35885]]

emissions standard, regulated entities must obtain certifications from 
qualified Professional Engineers to demonstrate technical infeasibility 
to connect a pneumatic pump to an existing control device and to ensure 
the proper closed vent system design. The EPA believes for the sources 
covered by this rule, a professional engineer can furnish more, and 
sometimes better, data about regulatory compliance, especially where 
engineering design (e.g., closed vent system design) is the element we 
want to ensure is examined and implemented without bias.
    The EPA notes that nothing in this rule relieves the EPA of any of 
its responsibilities under the CAA or implies that the EPA will not 
continue to use its enforcement authorities under the CAA or devote 
resources to monitoring and enforcing this rule. This rule simply 
ensures that regulated parties will have the tools available to assess 
and ensure their own compliance.
    The EPA wishes to explain that unfunded mandates are typically 
rules that impose significant obligations, without funding, on state, 
local, or tribal governments.\107\ Interpreting this comment as 
applying to the obligations this NSPS imposes on entities to which it 
will apply, all rules, by definition, impose some obligations and 
responsibilities on subject facilities. In this preamble, the EPA 
explains the benefits, costs, and justification for each regulatory 
requirement.
---------------------------------------------------------------------------

    \107\ See USEPA, Rulemakings by Effect: Unfunded Mandates Web 
site at https://yosemite.epa.gov/opei/rulegate.nsf/content/effectsunfunded.html?OpenDocument&Count=1000&ExpandView.
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    As discussed above, the EPA explains the emission standards in this 
NSPS apply to the subject regulated entities. The EPA remains 
responsible for ensuring and enforcing compliance with the rule. The 
EPA notes that nothing in this rule relieves the EPA of any of its 
responsibilities under the CAA to ensure and enforce regulatory 
compliance.
    The EPA agrees, that if the EPA were to seek to apply the standards 
in this rule--or any other regulatory standards, reflecting the 
Agency's Next Generation Compliance and rule effectiveness strategies 
or otherwise--to additional sectors beyond oil and natural gas 
production, the EPA would need to separately propose and justify the 
standards. As discussed above, however, the EPA's Next Generation 
Compliance and rule effectiveness strategies, in and of themselves, 
impose no requirements on the regulated community. The strategies 
prescribe no specific regulatory terms for any sector or facility nor 
do they create rights or responsibilities in any party. Rather, they 
describe compliance assurance and regulatory design strategies and 
approaches that the EPA will consider in conducting rulemaking, 
permitting, and compliance assurance, and enforcement activities that 
are inappropriate for notice and comment rulemaking. If the EPA 
believes that these strategies and approaches should be applied in 
other circumstances and to other industry sectors, the Agency will do 
this through other regulatory actions.
    The EPA agrees with the commenters that certain of the Next 
Generation and rule effectiveness strategies are the result of 
information that the Agency has gained from implementation of past 
consent decrees (e.g., closed vent system design and fugitives 
monitoring program audit). It is not unusual for the Agency to require 
additional monitoring practices, and recordkeeping and reporting 
requirements through consent, as this provides us an opportunity to 
identify the effectiveness of these standards from those companies that 
have engaged in violative conduct. Furthermore, through our enforcement 
efforts, when we see common and widespread compliance problems that can 
be addressed through improved monitoring, reporting and recordkeeping 
practices, it is our duty to include these tools in rulemaking, 
resulting in greater environmental benefit. As discussed elsewhere in 
this preamble, we are not requiring an ``independent third party'' 
verification of closed vent system design, nor are we requiring that 
the fugitive emissions monitoring program be audited. However, because 
of the widespread issues we have found with closed vent system design, 
the Agency will require a certification by a qualified professional 
engineer.
    Regarding the comment about necessary IT infrastructure, such as 
data acquisition hardware, data management software, and appropriate 
software, at remote oil and natural gas production and transmission 
facilities and the lack of electricity at these sites, the Agency does 
not believe that the next generation and rule effectiveness initiatives 
we are proposing directly require IT infrastructure beyond that already 
required by other aspects of the rule. Likewise, onsite electrical 
availability for remote well sites is not an issue for the Next 
Generation and Rule Effectiveness strategies that we are finalizing.

IX. Impacts of the Final Amendments

A. What are the air impacts?

    For this action, the EPA estimated the emission reductions that 
will occur due to the implementation of the final 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 represents 
the accumulation of new and modified sources from the first full year 
of compliance, 2016, through 2020 to illustrate the near-term impacts 
of the rule. The regulatory impact estimates for 2020 include sources 
newly affected in 2020 as well as the accumulation of affected sources 
from 2016 to 2019 that are also assumed to be in continued operation in 
2020, thus incurring compliance costs and emissions reductions in 2020. 
We also estimate impacts in 2025 to illustrate the continued compound 
effect of this rule over a longer period. The regulatory impact 
estimates for 2025 include sources newly affected in 2025 as well as 
the accumulation of affected sources from 2016 to 2024 that are also 
assumed to be in continued operation in 2025, thus incurring compliance 
costs and emissions reductions in 2025.
    In 2020, we have estimated that the final NSPS would reduce about 
300,000 tons of methane emissions and 150,000 tons of VOC emissions 
from affected facilities. In 2025, we have estimated that the proposed 
NSPS would reduce about 510,000 tons of methane emissions and 210,000 
tons of VOC emissions from affected facilities. The NSPS is also 
expected to concurrently reduce about 1,900 tons HAP in 2020 and 3,900 
tons HAP in 2025.
    As described in the TSD and RIA for this rule, the EPA projected 
affected facilities using a combination of historical data from the 
United States 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 final NSPS in projecting affected sources for 
impacts analyses supporting this rule.

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

[[Page 35886]]

controls expected to be used for compliance with the final NSPS.
    The final NSPS encourages the use of emission controls that recover 
hydrocarbon products, such as methane, that can be used onsite as fuel 
or reprocessed within the production process for sale. We estimate that 
the standards will result in a total cost of about $320 million in 2020 
and $530 million in 2025 (in 2012 dollars).

C. What are the compliance costs?

    The EPA estimates the total capital cost of the final NSPS will be 
$250 million in 2020 and $360 million in 2025. The estimate of total 
annualized engineering costs of the final NSPS is $390 million in 2020 
and $640 million in 2025. This annual cost estimate includes capital, 
operating, maintenance, 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 16 billion cubic feet in 2020 and 27 billion cubic 
feet of natural gas in 2025 will be recovered by implementing the 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 final NSPS are estimated to be $320 million in 
2020 and $530 million in 2025.\108\ 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 $16 million in 2020 
and $27 million in 2025.
---------------------------------------------------------------------------

    \108\ To the extent that NSPS affected facilities would have 
controlled emissions voluntarily through the Methane Challenge or 
other initiatives, the estimated costs and benefits of the NSPS 
would be lower than those included in the RIA analysis.
---------------------------------------------------------------------------

D. What are the economic and employment impacts?

    The EPA used the National Energy Modeling System (NEMS) to estimate 
the impacts of the final 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 EIA and is used to produce the 
AEO, a reference publication that provides detailed forecasts of the 
United States energy economy.
    The EPA estimate that natural gas and crude oil drilling levels 
decline slightly over the 2020 to 2025 period relative to the baseline 
(by about 0.17 percent for natural gas wells and about 0.02 percent for 
crude oil wells). Natural gas production decreases slightly over the 
2020 to 2025 period relative to the baseline (by about 0.03 percent), 
while crude oil production does not vary appreciably. Crude oil 
wellhead prices for onshore lower 48 production are not estimated to 
change appreciably over the 2020 to 2025 period relative to the 
baseline. However, wellhead natural gas prices for onshore lower 48 
production are estimated to increase slightly over the 2020 to 2025 
period relative to the baseline (about 0.20 percent). Net imports of 
natural gas are estimated to increase slightly over the 2020 to 2025 
period relative to the baseline (by about 0.11 percent). Crude oil net 
imports are not estimated to change appreciably over the 2020 to 2025 
period relative to the baseline.
    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) While a 
standalone analysis of employment impacts is not included in a standard 
benefit-cost analysis, such an analysis is of particular concern in the 
current economic climate given continued interest in the employment 
impact of regulations such as this final rule.
    The 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 270 FTEs in both 
2020 and 2025. The annual labor requirement to comply with final NSPS 
is estimated at about 1,100 FTEs in 2020 and 1,800 FTEs in 2025.
    We note that this type of FTE estimate cannot be used to identify 
the specific number of employees 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 final standards?

    The final rule is expected to result in significant reductions in 
emissions. In 2020, the final rule is anticipated to reduce 300,000 
short tons, or 280,000 metric tons, of methane (a GHG and a precursor 
to tropospheric ozone formation), 150,000 tons of VOC (a precursor to 
both PM (2.5 microns and less) (PM2.5) and ozone formation), 
and 1,900 tons of HAP. In 2025, the final rule is anticipated to reduce 
510,000 short tons (460,000 metric tons) of methane, 210,000 tons of 
VOC, and 3,900 tons of HAP. These pollutants are associated with 
substantial health effects, climate effects, and other welfare effects.
    The final standards are expected to reduce methane emissions 
annually by about 6.9 million metric tons CO2 Eq. in 2020 
and by about 11 million metric tons CO2 Eq. in 2025. It is 
important to note that the emission reductions are based upon predicted 
activities in 2020 and 2025; however, the EPA did not forecast sector-
level emissions in 2020 and 2025 for this rulemaking. To give a sense 
of the magnitude of the reductions, the methane reductions expected in 
2020 are equivalent to about 2.8 percent of the methane emissions for 
this sector reported in the United States GHG Inventory for 2014 (about 
232 million metric tons CO Eq. from petroleum and natural gas 
production and gas processing, transmission, and storage). Expected 
reductions in 2025 are equivalent to around 4.7 percent of 2014 
emissions. As it is expected that emissions from this sector would 
increase over time, the estimates compared against the 2014 emissions 
would likely overestimate the percent of reductions from total 
emissions in 2020 and 2025.
    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 of 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

[[Page 35887]]

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 United States anthropogenic methane emissions.
    We calculated the global social benefits of methane emission 
reductions expected from the final 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.\109\ 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.
---------------------------------------------------------------------------

    \109\ 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 the 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).\110\
---------------------------------------------------------------------------

    \110\ 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. The 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 
Office of Management and Budget (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 rule is that the IWG did 
not estimate the social costs of non-CO2 GHG emissions at 
the time the SC-CO2 estimates were developed. In addition, 
the directly modeled estimates of the social costs of non-
CO2 GHG emissions previously found in the published 
literature were few in number and varied considerably in terms of the 
models and input assumptions they employed \111\ (EPA 2012). In the 
past, EPA has sought to understand the potential importance of 
monetizing non-CO2 GHG emissions changes through sensitivity 
analysis using an estimate of the GWP of methane 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 methane.\112\
---------------------------------------------------------------------------

    \111\ U.S. EPA. 2012. Regulatory Impact Analysis Final New 
Source Performance Standards and Amendments to the National 
Emissions Standards for Hazardous Air Pollutants for the Oil and 
Natural Gas Industry. Office of Air Quality Planning and Standards, 
Health and Environmental Impacts Division. April. http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_neshap_nsps_ria.pdf. Accessed March 30, 2015.
    \112\ For example, see (1) U.S. EPA. (2012). ``Regulatory impact 
analysis supporting the 2012 U.S. Environmental Protection Agency 
final new source performance standards and amendments to the 
national emission standards for hazardous air pollutants for the oil 
and natural gas industry.'' Retrieved from http://www.epa.gov/ttn/ecas/regdata/RIAs/oil_natural_gas_final_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 http://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.\113\ 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 (300 years 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.
---------------------------------------------------------------------------

    \113\ 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.114 115

[[Page 35888]]

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

    \114\ 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.
    \115\ 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 United States 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 8. 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 8--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), http://www.tandfonline.com/doi/abs/10.1080/14693062.2015.1070550.

    The application of these directly modeled SC-CH4 
estimates from Marten et al. (2014) in a benefit-cost analysis of a 
regulatory action is analogous to the use of the SC-CO2 
estimates. In addition, the limitations for the SC-CO2 
estimates discussed above likewise apply to the SC-CH4 
estimates, given the consistency in the methodology.
    In early 2015, the EPA 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.
    The EPA also carefully considered the full range of public comments 
and associated technical issues on the Marten et al. SC-CH4 
estimates received through this rulemaking. The comments addressed the 
technical details of the SC-CO2 estimates and the Marten et 
al. SC-CH4 estimates as well as their application to this 
rulemaking analysis. The commenters also provided constructive 
recommendations to improve the SC-CO2 and SC-CH4 
estimates in the future. Based on the evaluation of the public comments 
on this rulemaking, the favorable peer review of the Marten et al. 
application, and past comments urging the EPA to value non-
CO2 GHG impacts in its rulemakings, the EPA concluded that 
the estimates represent the best scientific information on the impacts 
of climate change available in a form appropriate for incorporating the 
damages from incremental methane emissions changes into regulatory 
analysis. The EPA has included those benefits in the main benefits 
analysis. See the RTC document for the complete response to comments 
received on the SC-CH4 as part of this rulemaking.
    The methane benefits calculated using Marten et al. (2014) are 
presented in Table 9 for years 2020 and 2025. Applying this approach to 
the methane reductions estimated for the NSPS, the 2020 methane 
benefits vary by discount rate and range from about $160 million to 
approximately $960 million; the mean SC-CH4 at the 3-percent 
discount rate results in an estimate of about $360 million in 2020. The 
methane benefits increase in the 2025, ranging from $320 million to 
$1.8 billion, depending on discount rate used; the mean SC-
CH4 at the 3-percent discount rate results in an estimate of 
about $690 million in 2025.

        Table 9--Estimated Global Benefits of Methane Reductions
                          [In millions, 2012$]
------------------------------------------------------------------------
                                                       Year
       Discount rate and statistic       -------------------------------
                                               2020            2025
------------------------------------------------------------------------
Million metric tonnes of methane reduced            0.28            0.46
Million metric tonnes of CO2 Eq.........             6.9              11
    5% (average)........................            $160            $320
    3% (average)........................            $360            $690
    2.5% (average)......................            $480            $890
    3% (95th percentile)................            $960          $1,800
------------------------------------------------------------------------


[[Page 35889]]

    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.
    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.\116\ In addition to health improvements, there 
will be improvements in visibility effects, ecosystem effects and 
climate effects, as well as additional product recovery.
---------------------------------------------------------------------------

    \116\ 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 HAP 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 \117,\ U.S. EPA, 2010 \118\, and 
U.S. EPA, 2014 \119\), 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.\120\ 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.\121\
---------------------------------------------------------------------------

    \117\ U.S. EPA. RIA. National Ambient Air Quality Standards for 
Particulate Matter, Chapter 5. Office of Air Quality Planning and 
Standards, Research Triangle Park, NC. October 2006. Available on 
the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/
Chapter%205_Benefits.pdf.
    \118\ U.S. EPA. RIA. National Ambient Air Quality Standards for 
Ozone. Office of Air Quality Planning and Standards, Research 
Triangle Park, NC. January 2010. Available on the Internet at http://www.epa.gov/ttn/ecas/regdata/RIAs/s1-supplemental_analysis_full.pdf.
    \119\ 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 
http://www.epa.gov/ttnecas1/regdata/RIAs/20141125ria.pdf.
    \120\ U.S. EPA. Integrated Science Assessment for Particulate 
Matter (Final Report). EPA-600-R-08-139F. National Center for 
Environmental Assessment--RTP Division. December 2009. Available at 
http://cfpub.epa.gov/ncea/cfm/recordisplay.cfm?deid=216546.
    \121\ U.S. EPA. Air Quality Criteria for Ozone and Related 
Photochemical Oxidants (Final). EPA/600/R-05/004aF-cF. Washington, 
DC: U.S. EPA. February 2006. Available on the Internet at http://cfpub.epa.gov/ncea/CFM/recordisplay.cfm?deid=149923.
---------------------------------------------------------------------------

    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 direct 
emission reductions anticipated from this rule.
    In particular, the EPA has estimated that an increase in flaring of 
natural gas in response to this rule will produce a variety of 
emissions, including about 1.0 million short tons of CO2 in 
2020 and about 1.2 million short tons of CO2 in 2025. The 
EPA has not estimated the monetized value of the secondary emissions of 
CO2 because much of the VOCs and 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.
    For VOC emissions, the oxidization period is relatively short, on 
the order of a couple of weeks. However, for methane, the oxidization 
period is longer, on the order of a decade, and the 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 via oxidized methane from fossil-
based emissions may be less than the estimated impact of CO2 
released immediately from combustion. This would imply a small 
disbenefit associated with the earlier release of CO2 during 
combustion of the methane emissions.
    In the proposal, the EPA solicited comment on the appropriateness 
of monetizing the impact of the earlier release of CO2 due 
to combusting methane emissions from oil and gas sites and an 
illustrative analysis that described a potential approach to 
approximate this value using the SC-CO2. The EPA did not 
receive any comments regarding the appropriate methodology for 
conducting such an analysis, but did receive one comment letter that 
voiced general support for monetizing the secondary impacts. In 
consideration of this comment and recognizing the challenges and 
uncertainties related to estimation of these secondary emissions 
impacts for this rulemaking, EPA has continued to examine this issue in 
the context of this regulatory analysis (i.e., the combusting of 
fossil-based methane at oil and gas sites) and explored ways to improve 
the illustrative analysis. See RIA for details.

X. Statutory and Executive Order Reviews

    Additional information about these statutes and Executive Orders 
can be found at http://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 Office of Management and Budget (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

[[Page 35890]]

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 10 shows the results 
of the cost and benefits analysis for the final rule.

    Table 10--Summary of the Monetized Benefits, Social Costs and Net
    Benefits for the Final Oil and Natural Gas NSPS in 2020 and 2025
                           [Millions of 2012$]
------------------------------------------------------------------------
                                      2020                  2025
------------------------------------------------------------------------
Total Monetized Benefits \1\  $360 million........  $690 million.
Total Costs \2\.............  $320 million........  $530 million.
Net Benefits \3\............  $35 million.........  $170 million.
                             -------------------------------------------
Non-monetized Benefits......  Non-monetized climate benefits.
                              Health effects of PM2.5 and ozone exposure
                               from 150,000 tons of VOC in 2020 and
                               210,000 tons of VOC in 2025.
                              Health effects of HAP exposure from 1,900
                               tons of HAP in 2020 and 3,900 tons of HAP
                               in 2025.
                              Health effects of ozone exposure from
                               300,000 tons of methane in 2020 and
                               510,000 tons methane in 2025.
                              Visibility impairment.
                              Vegetation effects.
------------------------------------------------------------------------
1 We estimate methane benefits associated with four different values of
  a one ton methane 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 IX.E and in the RIA. The CO2-equivalent (CO2
  Eq.) methane emission reductions are 6.9 million metric tons in 2020
  and 11 million metric tons in 2025. Also, the specific control
  technologies for the proposed NSPS are anticipated to have minor
  secondary disbenefits.
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 the final action 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 final 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 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 2,554 owners and 
operators that are subject to the rule is 98,438 labor hours, with an 
annual average cost of $3,361,074. The annual public reporting and 
recordkeeping burden for this collection of information is estimated to 
average 20 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.

C. Regulatory Flexibility Act (RFA)

    Pursuant to sections 603 and 609(b) of the RFA, the EPA prepared an 
initial regulatory flexibility analysis (IRFA) for the proposed rule 
and convened a Small Business Advocacy Review (SBAR) Panel to obtain 
advice and recommendations from small entity representatives that 
potentially would

[[Page 35891]]

be subject to the rule's requirements. Summaries of the IRFA and Panel 
recommendations are presented in the proposed rule at 80 FR 56593.
    As required by section 604 of the RFA, the EPA prepared a final 
regulatory flexibility analysis (FRFA) for this action. The FRFA 
addresses the issues raised by public comments on the IRFA for the 
proposed rule. The complete FRFA is available for review in the RIA in 
the public docket and is summarized here.
1. Statutory Authority
    The legal authority for this rule stems from section 111 of the 
CAA, which requires the EPA to issue ``standards of performance'' for 
new sources in the list of categories of stationary sources that cause 
or contribute significantly to air pollution and which may reasonably 
be anticipated to endanger public health or welfare. See section III.A 
of this preamble for more information.
2. Significant Issues Raised and Agency Responses
    The EPA received comments on the proposed standards related to the 
potential impacts on small entities and requests for comments that were 
included based on the SBAR Panel Recommendations. See sections VI and 
VIII of this preamble and the RTC Document in Docket ID EPA-HQ-OAR-
2010-0505 for more detailed responses.
    Low production wells: Several commenters supported the proposed 
exemption of low production well sites from the fugitive monitoring 
requirements. Commenters noted that marginal wells generate relatively 
low revenue and these wells are often drilled and operated by small 
companies.
    Response: While these commenters did provide support for the 
proposed low production well exemption, other commenters indicated that 
low production well sites have the potential to emit substantial 
amounts of fugitive emissions, and that a significant number of wells 
would be excluded from fugitive emissions monitoring based on this 
exemption. We did not receive data showing that low production well 
sites have lower emissions than non-low production well sites. In fact, 
the data that were provided indicated that the potential emissions from 
these well sites could be as significant as the emissions from non-low 
production well sites since the type of equipment and the well 
pressures are more than likely the same. In discussions with 
stakeholders, they indicated that well site fugitive emissions are not 
based on production, but rather on the number of pieces of equipment 
and components. Therefore, we believe that the emissions from low 
production and non-low production well sites are comparable and we did 
not finalize the proposed exclusion of low production well sites from 
fugitive emissions monitoring.
    REC costs: Commenters stated that small operators have higher well 
completion costs, and typically conduct completions less frequently. 
Generally, small operators lack the purchasing power to get the 
discounted prices service companies offer to larger operators. However, 
small entity commenters did not provide specific cost information.
    Response: The BSER analysis is based on the averages of nationwide 
data. It is possible for a small operator to have higher than the 
nationwide average completion costs, however, the daily completion cost 
provided by the commenters is not significantly different than the 
EPA's estimate. Therefore, we do not believe that the cost of RECs 
disfavor small businesses.
    Phase-in period for RECs: Commenters stated that the EPA should 
create a compliance phase-in period of at least 6 months for the REC 
requirements, to accommodate small operators. Commenters stated that 
REC equipment is in short supply, and this will drive up REC costs. 
Commenters stated that small entities lack the purchasing power of 
larger operators, which makes it difficult to obtain the needed 
equipment before the compliance period begins.
    Response: We agree that compliance with the REC requirements in the 
final rule could be burdensome for some in the near term due to the 
unavailability of REC equipment. As discussed in section VI of the 
preamble, the final rule provides a phase-in approach that would allow 
a quick build-up of the REC supplies in the near term.
    Alternatives to OGI technology: Several commenters indicated that 
the EPA should allow alternatives to OGI technology as the cost is 
excessive for small operators.
    Response: In the final rule, the EPA is allowing Method 21 with a 
repair threshold of 500 ppm as an alternative to OGI. We believe this 
alternative will alleviate some of the burden on small entities.
    Basing monitoring frequency on the percentage of leaking 
components: Commenters indicated that using a percentage of components, 
rather than a set number of components, to determine the frequency of 
surveys is also unfair to small entities since a small site will have 
fewer fugitive emission components than a larger site. Commenters 
stated that smaller entities are much more likely to operate these 
smaller sites, and thus are more likely to have higher frequency survey 
requirements under the percentage-based system.
    Response: The EPA agrees that imposing a performance based 
monitoring schedule would require operators to develop a program that 
would require extensive administration to ensure compliance. We believe 
that the potential for a performance-based approach to encourage 
greater compliance is outweighed in this case by these additional 
burdens and the complexity it would add. Therefore, the EPA is 
finalizing a fixed monitoring frequency instead of performance based 
monitoring.
    Timing of initial fugitive monitoring periods: Commenters stated 
that the requirement to conduct surveys for affected facilities using 
OGI technology within 30 days of the well completion or within 30 days 
of modification is overly restrictive. Additionally, commenters stated 
that small operators may not be able to find vendors available to 
survey a small number of wells within the required timeframe. One 
commenter stated that contractors will be in high demand and may give 
scheduling preference to larger clients versus small business entities.
    Response: The EPA considered these and other comments and concluded 
that the proposed time of 30 days within a well completion or 
modification is not enough time to complete the necessary preparations 
for the initial monitoring survey. In addition, other commenters 
pointed out that first date of production should be the trigger, rather 
than the date of well completion. Therefore, for the collection of 
fugitive emissions components at a new or modified well site, we are 
finalizing that the initial monitoring survey must take place by June 
3, 2017 or within 60 days of the startup of production, whichever is 
later. We believe this extended timeframe for compliance will alleviate 
some of the burden on smaller operators.
    Third party compliance: Commenters believe that requiring third 
party compliance audits will be a significant burden on small entities. 
One commenter said that a third-party audit requirement will 
dramatically increase the costs of the program and have a negative 
competitive impact on smaller, less funded operators.
    Response: While the EPA continues to believe that independent third 
party verification can furnish more, and sometimes better, data about 
regulatory compliance, we have explored

[[Page 35892]]

alternatives to the independent third party verification. Specifically, 
the ``qualified professional engineer'' model was assessed to focus on 
the element of engineering design. The final rule requires a 
professional engineer certification of technical infeasibility of 
connecting a pneumatic pump to an existing control device, and a 
professional engineer design of closed vent systems. These 
certifications will ensure that the owner or operator has effectively 
assessed appropriate factors before making a claim of infeasibility and 
that the closed vent system is properly designed to verify that all 
emissions from the unit being controlled in fact reach the control 
device and allow for proper control. We believe this simplified 
approach will reduce the burden imposed on all affected facilities, 
including those owned by small businesses.
3. Affected Small Entities
    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 analysis indicates about 2,031 small entities may be subject to 
the requirements for hydraulically fractured and re-fractured oil well 
completions and fugitive emissions requirements at well sites.
4. Reporting, Recordkeeping and Other Compliance Requirements
    The information to be collected for the NSPS is based on 
notification, performance tests, recordkeeping and reporting 
requirements which will be mandatory for all operators subject to the 
final standards. 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 2,554 
owners and operators that are subject to the rule is 98,438 labor 
hours, with an annual average cost of $3,361,074. The annual public 
reporting and recordkeeping burden for this collection of information 
is estimated to average 20 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).
    The EPA summarized the potential regulatory cost impacts of the 
proposed rule and alternatives in Section 3 of the RIA. The analysis in 
the FRFA drew upon the same analysis and assumptions as the analyses 
presented in the RIA. The FRFA analysis is presented in its entirely in 
Section 6.3 of the RIA.
    The EPA based the analysis in the FRFA on impacts estimates for the 
proposed requirements for hydraulically fractured and re-fractured oil 
well completions and well site fugitive emissions, which represent 
about 98 percent of the estimated compliance costs of the NSPS in 2020 
and 2025. Not incorporating impacts from other provisions in this 
analysis 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 rule in its 
entirety. The cost of compliance for small firms is estimated to be 
about $110 million in 2020 and $190 million in 2025.
    We also estimate cost-to-sales ratios for small firms. For some 
firms, we estimate their 2012 sales levels by multiplying their 2012 
oil and natural gas production levels reported in an industry database 
by the 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 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 percent of small firms with cost-to-sales ratios greater than 1 
percent and greater than 3-percent increase from 2020 to 2025 as 
affected sources accumulate under the NSPS. Cost-to-sales ratios 
exceeding 1 percent and 3 percent. Also, cost-to-sales ratios fall as 
the oil price falls from the main scenario to the low oil price 
scenario.
    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.
5. Steps Taken To Minimize Impact on Small Entities
    The EPA considered three major options for this rule. The finalized 
option includes reduced emission completion (REC) and completion 
combustion requirements for a subset of newly completed oil wells that 
are hydraulically fractured or refractured and requirements that 
fugitive emissions survey and repair programs be performed semiannually 
at affected well sites and quarterly at affected transmission and 
storage or compressor stations. One option examined includes an 
exemption from low production well site fugitive requirements, but was 
rejected because we believe that low production well sites have similar 
equipment and components as sites that are not categorized as low 
production. Without data supporting a difference in emissions between 
low production well sites and not low production well sites, the EPA 
believes exempting low production well sites would reduce the 
effectiveness of the rule, especially considering the high proportion 
of small firms in the industry. The more stringent option required 
quarterly monitoring for all sites under the fugitive emissions 
programs, which leads to greater emissions reductions, however it also 
increases net costs and results in lower net benefits compared to the 
finalized option.
    Significant comments with regard to the small business analysis 
received by the EPA include the topics of low production well 
exemptions, well completion costs, compliance phase-in periods, 
alternatives to OGI technology, monitoring frequency and timing, and 
third party compliance.
    Though all comments were seriously considered, the EPA is unable to 
incorporate all suggestions without compromising the effectiveness of 
the final regulation. Changes to the rule from proposal that may 
benefit small entities due to comments received include allowing both 
OGI and Method 21 as acceptable monitoring technology, replacing a 
performance based monitoring schedule with a fixed frequency, 
lengthening the time of initial fugitive monitoring from within 30 days 
to the later of either June 3, 2017 or within 60 days of the startup of 
production, whichever is later, and simplifying the third party 
verification of technical infeasibility requirements. Though these are 
not monetized, we believe the flexibility and simplifications these 
changes have added to the rule result in a reduced burden on small 
entities.
    In addition, the EPA is preparing a Small Entity Compliance Guide 
to help small entities comply with this rule. The guide will be 
available on the World Wide Web 60 days after publication of the final 
rule at https://www3.epa.gov/airquality/oilandgas/implement.html.

D. Unfunded Mandates Reform Act of 1995 (UMRA)

    This action contains a federal mandate under UMRA, 2 U.S.C. 1531-
1538, that may result in expenditures of $100 million or more for 
state, local and tribal governments, in the aggregate, or the private 
sector in any one year. More

[[Page 35893]]

specifically, this action contains a federal private sector mandate 
that may result in the expenditures of $100 million or more for the 
private section in any one year. Accordingly, the EPA has prepared the 
following written statement in compliance with sections 202 and 205 of 
UMRA. This rule is not subject to the requirements of section 203 of 
UMRA because it contains no regulatory requirements that might 
significantly or uniquely affect small governments.
1. Statutory Authority
    The legal authority for this rule stems from section 111 of the 
CAA, which requires the EPA to issue ``standards of performance'' for 
new sources in the list of categories of stationary sources that cause 
or contribute significantly to air pollution and which may reasonably 
be anticipated to endanger public health or welfare. See section III.A 
of this preamble for more information.
2. Costs and Benefits
    As discussed in sections II.A.3, IX.C and IX.E of this preamble, 
this rule results in a net benefit. Including the resources from 
recovered natural gas that would otherwise be vented, the quantified 
net benefits of the regulation are estimated to be $35 million in 2020 
and $170 million in 2025 in 2012 dollars using a 3 percent discount 
rate for climate benefits. The estimated total annualized engineering 
costs of the final rule, accounting for the recovered natural gas are 
$320 million in 2020 and $530 million in 2025. The EPA estimates the 
final rule will lead to monetized benefits of about $360 million in 
2020 and $690 million in 2025, at the model average at a 3 percent 
discount rate. More in depth information on costs and benefits, 
including non-monetized or quantified benefits, of the final regulation 
can be found in the RIA.
3. Effects on National Economy
    As seen in section IX.D of this preamble, the EPA used the National 
Energy Modeling System (NEMS) to estimate the impacts of the final rule 
on the United States energy system. Estimates show slight declines in 
natural gas and crude oil drilling, and natural gas production over the 
2020 to 2025 period under the rule, while wellhead natural gas prices 
are estimated to increase slightly over the 2020 to 2025 period under 
the rule. Crude oil production and crude oil wellhead prices are not 
estimated to change appreciably over the 2020 to 2025 period under the 
rule. Net imports of natural gas are estimated to increase slightly 
over the 2020 to 2025 period, while net imports of crude oil are not 
estimated to change appreciably.
    Also discussed in section IX.D, the up-front labor requirement to 
comply with the proposed NSPS is estimated at about 270 FTEs in 2020 
and 2025. The annual labor requirement to comply with final NSPS is 
estimated at about 1,100 FTEs in 2020 and 1,800 FTEs in 2025. For more 
in depth information on both the estimated energy markets impacts and 
estimated job creation and employment impacts of this rule, see the 
RIA.
4. Regulatory Alternatives
    Alternate regulatory options examined in the RIA include decreasing 
fugitive survey requirements to annual at well sites and semiannual at 
all other affected locations (termed Option 1 in the RIA), and 
increasing fugitive survey frequency at all wells to quarterly (termed 
Option 3 in the RIA). The finalized regulation results in estimated net 
benefits of $35 million in 2020 and $170 million in 2025. Reducing 
fugitive survey requirements, Option 1, leads to lower costs as well as 
lower benefits and results in estimated net benefits of $54 million in 
2020 and $180 million in 2025. Increasing the survey frequency leads to 
an increase in capital costs with a non-commensurate increase in 
monetized benefits, resulting in estimated net benefits of -$75 million 
in 2020, and -$38 million in 2025. Both of these regulatory options 
result in lower net benefits in 2025 compared to the finalized 
regulation. For a more in depth analysis of these options, see the RIA.

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

    Subject to Executive Order 13175 (65 FR 67249; November 9, 2000), 
the EPA may not issue a regulation that has tribal implications, that 
imposes substantial direct compliance costs, and that is not required 
by statute, unless the federal government provides the funds necessary 
to pay the direct compliance costs incurred by tribal governments, or 
the EPA consults with tribal officials early in the process of 
developing the proposed regulation and develops a tribal summary impact 
statement.
    The EPA has concluded that this action has tribal implications. 
However, it will neither impose substantial direct compliance costs on 
federally recognized tribal governments, nor preempt tribal law, thus 
Executive Order 13175 does not apply to this rule. The EPA believes 
that the affected facilities 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 offered consultation with tribal officials early in the 
regulation development process to permit them an opportunity to have 
meaningful and timely input. Consultation letters were sent to the 
tribal leaders of 567 federally recognized tribes, provided information 
regarding this rule, and offered consultation. The EPA did not receive 
any requests for tribal consultation on this rulemaking. In addition, 
the EPA has conducted meaningful involvement with tribal stakeholders 
throughout the rulemaking process and provided an update on the Methane 
Strategy on the January 29, 2015 and September 10, 2015 National Tribal 
Air Association and EPA Air Policy monthly calls. 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 
solicited comment on the proposed action from tribal officials and 
considered comments received from tribal officials in the development 
of this final action. Please see the RTC document in the public docket.

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.

[[Page 35894]]

    Greenhouse gases 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 rules 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 IV.B 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.
    The EPA used the NEMS to estimate the impacts of the final 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 estimates that natural gas and crude oil drilling levels 
decline slightly over the 2020 to 2025 period under the final NSPS (by 
about 0.17 percent for natural gas wells and 0.02 percent for crude oil 
wells). Crude oil production does not vary appreciably under the rule, 
while natural gas production declines slightly over the 2020 to 2025 
period (about 0.03 percent). Crude oil wellhead prices for onshore 
lower 48 production are not estimated to change appreciably over the 
2020 to 2025 period. However, wellhead natural gas prices for onshore 
lower 48 production are estimated to increase slightly over the 2020 to 
2025 period (about 0.20 percent). Net imports of natural gas are 
estimated to increase slightly in 2020 (by about 0.12 percent) and in 
2025 (by about 0.11 percent). Crude oil net imports are not estimated 
to change in 2020, but decrease slightly in 2025 (by about 0.02 
percent). Net imports of crude oil do not change appreciably over the 
2020 to 2025 period.
    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 final rule, please see the Regulatory Impact 
Analysis, which is in the docket for this rule.

I. National Technology Transfer and Advancement Act (NTTAA) and 1 CFR 
Part 51

    This action 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, 18, 
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 and none were brought to its attention in comments. All potential 
standards were reviewed to determine the practicality of the voluntary 
consensus standards (VCS) for this rule.
    Two VCS were identified as an acceptable alternative to EPA test 
methods for the purpose of this rule. First, ANSI/ASME PTC 19-10-1981, 
Flue and Exhaust Gas Analyses (Part 10) was identified 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. Second, 
ASTM D6420-99 (2010), ``Test Method for Determination of Gaseous 
Organic Compounds by Direct Interface Gas Chromatography/Mass 
Spectrometry'' is an acceptable alternative to EPA Method 18 with the 
following caveats, only use when the target compounds are all known and 
the target compounds are all listed in ASTM D6420 as measurable. ASTM 
D6420 should never be specified as a total VOC Method. (ASTM D6420-99 
(2010) is not incorporated by reference in 40 CFR part 60.) The search 
identified 19 VCS that were potentially applicable for this rule in 
lieu of EPA reference methods. However, these have been determined to 
not be practical due to lack of equivalency, documentation, validation 
of data and other important technical and policy considerations. For 
additional information, please see the April 6, 2016, memo titled, 
``Voluntary Consensus Standard Results for Oil and Natural Gas Sector: 
Emission Standards for New and Modified Sources'' in the public docket.
    In this rule, the EPA is finalizing regulatory text for 40 CFR part 
60, subpart OOOOa that includes incorporation by reference in 
accordance with requirements of 1 CFR 51.5 as discussed below. Ten 
standards are incorporated by reference.
     ASTM D86-96, Distillation of Petroleum Products (Approved 
April 10, 1996) covers the distillation of natural gasolines, motor 
gasolines, aviation

[[Page 35895]]

gasolines, aviation turbine fuels, special boiling point spirits, 
naphthas, white spirit, kerosines, gas oils, distillate fuel oils, and 
similar petroleum products, utilizing either manual or automated 
equipment.
     ASTM D1945-03 (Reapproved 2010), Standard Test Method for 
Analysis of Natural Gas by Gas Chromatography covers the determination 
of the chemical composition of natural gases and similar gaseous 
mixtures within a certain range of composition. This test method may be 
abbreviated for the analysis of lean natural gases containing 
negligible amounts of hexanes and higher hydrocarbons, or for the 
determination of one or more components.
     ASTM D3588-98 (Reapproved 2003), Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuel covers procedures for calculating heating value, relative 
density, and compressibility factor at base conditions for natural gas 
mixtures from compositional analysis. It applies to all common types of 
utility gaseous fuels.
     ASTM D4891-89 (Reapproved 2006), Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion covers the determination of the heating value of natural 
gases and similar gaseous mixtures within a certain range of 
composition.
     ASTM D6522-00 (Reapproved December 2005), Standard Test 
Method for Determination of Nitrogen Oxides, Carbon Monoxide, and 
Oxygen Concentrations in Emissions from Natural Gas-Fired Reciprocating 
Engines, Combustion Turbines, Boilers, and Process Heaters Using 
Portable Analyzers covers the determination of nitrogen oxides, carbon 
monoxide, and oxygen concentrations in controlled and uncontrolled 
emissions from natural gas-fired reciprocating engines, combustion 
turbines, boilers, and process heaters.
     ASTM E168-92, General Techniques of Infrared Quantitative 
Analysis covers the techniques most often used in infrared quantitative 
analysis. Practices associated with the collection and analysis of data 
on a computer are included as well as practices that do not use a 
computer.
     ASTM E169-93, General Techniques of Ultraviolet 
Quantitative Analysis (Approved May 15, 1993) provide general 
information on the techniques most often used in ultraviolet and 
visible quantitative analysis. The purpose is to render unnecessary the 
repetition of these descriptions of techniques in individual methods 
for quantitative analysis.
     ASTM E260-96, General Gas Chromatography Procedures 
(Approved April 10, 1996) is a general guide to the application of gas 
chromatography with packed columns for the separation and analysis of 
vaporizable or gaseous organic and inorganic mixtures and as a 
reference for the writing and reporting of gas chromatography methods.
     ASME/ANSI PTC 19.10-1981, Flue and Exhaust Gas Analyses 
[Part 10, Instruments and Apparatus] (Issued August 31, 1981) covers 
measuring the oxygen or carbon dioxide content of the exhaust gas.
     EPA-600/R-12/531, EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards (Issued May 2012) is 
mandatory for certifying the calibration gases being used for the 
calibration and audit of ambient air quality analyzers and continuous 
emission monitors that are required by numerous parts of the CFR.
    The EPA determined that the ASTM and ASME/ANSI standards, 
notwithstanding the age of the standards, are reasonably available 
because it they are available for purchase from the following 
addresses: American Society for Testing and Materials (ASTM), 100 Barr 
Harbor Drive, Post Office Box C700, West Conshohocken, PA 19428-2959; 
or ProQuest, 300 North Zeeb Road, Ann Arbor, MI 48106 and the American 
Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 
10016-5990. The EPA determined that the EPA standard is reasonably 
available because it is publically available through the EPA's Web 
site: http://nepis.epa.gov/Adobe/PDF/P100EKJR.pdf.

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 rulemaking process 
by conducting community calls and webinars. Documentation of these 
activities can be found in the public docket for this rulemaking.

K. Congressional Review Act (CRA)

    This action is subject to the CRA, and the EPA will submit a rule 
report to each House of the Congress and to the Comptroller General of 
the United States. This action is a ``major rule'' as defined by 5 
U.S.C. 804(2).

List of Subjects in 40 CFR Part 60

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

    Dated: May 12, 2016.
Gina McCarthy,
Administrator.
    For the reasons set out in the preamble, title 40, chapter I of the 
Code of Federal Regulations is 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.


0
2. Section 60.17 is amended by:
0
a. Revising paragraph (g)(14).
0
b. Revising paragraphs (h)(19), (75), (137), (167), (184), (193), 
(196), and (199).
0
c. Adding paragraph (j)(2).
    The revisions and addition read as follows:


Sec.  60.17  Incorporations by reference.

* * * * *
    (g) * * *
    (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, 60.5406(c), 60.5406a(c), 60.5407a(g), 60.5413(b), 60.5413a(b) and 
60.5413a(d).
* * * * *
    (h) * * *

[[Page 35896]]

    (19) ASTM D86-96, Distillation of Petroleum Products, (Approved 
April 10, 1996), IBR approved for Sec. Sec.  60.562-2(d), 60.593(d), 
60.593a(d), 60.633(h), 60.5401(f), 60.5401a(f).
* * * * *
    (75) ASTM D1945-03 (Reapproved 2010), Standard Method for Analysis 
of Natural Gas by Gas Chromatography, (Approved January 1, 2010), IBR 
approved for Sec. Sec.  60.107a(d), 60.5413(d), 60.5413a(d).
* * * * *
    (137) ASTM D3588-98 (Reapproved 2003), Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels, (Approved May 10, 2003), IBR approved for Sec. Sec.  
60.107a(d), 60.5413(d), and 60.5413a(d).
* * * * *
    (167) ASTM D4891-89 (Reapproved 2006) Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion, (Approved June 1, 2006), IBR approved for Sec. Sec.  
60.107a(d), 60.5413(d), and 60.5413a(d).
* * * * *
    (184) ASTM D6522-00 (Reapproved 2005), Standard Test Method for 
Determination of Nitrogen Oxides, Carbon Monoxide, and Oxygen 
Concentrations in Emissions from Natural Gas-Fired Reciprocating 
Engines, Combustion Turbines, Boilers, and Process Heaters Using 
Portable Analyzers, (Approved October 1, 2005), IBR approved for table 
2 to subpart JJJJ, Sec. Sec.  60.5413(b) and (d), and 60.5413a(b).
* * * * *
    (193) ASTM E168-92, General Techniques of Infrared Quantitative 
Analysis, IBR approved for Sec. Sec.  60.485a(d), 60.593(b), 
60.593a(b), 60.632(f), 60.5400, 60.5400a(f).
* * * * *
    (196) ASTM E169-93, General Techniques of Ultraviolet Quantitative 
Analysis, (Approved May 15, 1993), IBR approved for Sec. Sec.  
60.485a(d), 60.593(b), 60.593a(b), 60.632(f), 60.5400(f), and 
60.5400a(f).
* * * * *
    (199) ASTM E260-96, General Gas Chromatography Procedures, 
(Approved April 10, 1996), IBR approved for Sec. Sec.  60.485a(d), 
60.593(b), 60.593a(b), 60.632(f), 60.5400(f), 60.5400a(f) 60.5406(b), 
and 60.5406a(b)(3).
* * * * *
    (j) * * *
    (2) EPA-600/R-12/531, EPA Traceability Protocol for Assay and 
Certification of Gaseous Calibration Standards, May 2012, IBR approved 
for Sec. Sec.  60.5413(d) and 60.5413a(d).
* * * * *

0
3. Part 60 is amended by revising the heading for Subpart OOOO to read 
as follows:

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
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.
0
b. Revising paragraph (e)(4).
0
c. Adding paragraph (e)(5).
0
d. Revising paragraph (h)(4).
    The revisions and addition 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.
* * * * *
    (e) * * *
    (4) The following requirements apply immediately upon startup, 
startup of production, or return to service. A storage vessel affected 
facility that is reconnected to the original source of liquids is a 
storage vessel affected facility subject to the same requirements that 
applied before being removed from service. Any storage vessel that is 
used to replace any storage vessel affected facility is subject to the 
same requirements that apply to the storage vessel affected facility 
being replaced.
    (5) A storage vessel with a capacity greater than 100,000 gallons 
used to recycle water that has been passed through two stage separation 
is not a storage vessel affected facility.
    (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 revising paragraph (b) and adding 
paragraph (d) to read as follows:


Sec.  60.5370  When must I comply with this subpart?

* * * * *
    (b) At all times, including periods of startup, shutdown, and 
malfunction, owners and operators shall maintain and operate any 
affected facility including associated air pollution control equipment 
in a manner consistent with good air pollution control practice for 
minimizing emissions. Determination of whether acceptable operating and 
maintenance procedures are being used will be based on information 
available to the Administrator which may include but is not limited to, 
monitoring results, opacity observations, review of operating and 
maintenance procedures, and inspection of the source.
* * * * *
    (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.


Sec.  60.5410  [Amended]

0
7. Section 60.5410 is amended by removing and reserving paragraph 
(b)(6).

0
8. 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 that 
is capable of taking periodic readings as specified in Sec.  
60.5416(a)(4) and either sounds an alarm, or initiates 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).
* * * * *

[[Page 35897]]

    (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 and 
that either sounds an alarm, or initiates 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
9. 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 275 parts 
per million by volume as propane on a wet 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. Each flare must be designed and operated in 
accordance with the requirements of Sec.  60.5413(a)(1). You must 
follow the requirements in paragraphs (d)(1)(i) through (iv) of this 
section.
* * * * *
    (iv) Each enclosed 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 (d)(1)(iv)(A) through (D) of this 
section.
    (A) You must reduce the mass content of 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 275 parts 
per million by volume as propane on a wet 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]Celsius, 
provided the control device has demonstrated, during the performance 
test conducted under Sec.  60.5413, that combustion zone temperature is 
an indicator of destruction efficiency.
    (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
10. Section 60.5413 is amended by revising paragraphs (d)(9)(iv) and 
(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?

* * * * *
    (d) * * *
    (9) * * *
    (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,'' (incorporated by 
reference as specified in Sec.  60.17).
* * * * *
    (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
11. Section 60.5415 is amended by revising paragraphs (b)(2)(vii)(B) 
and (c)(4) to read as follows:


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.
* * * * *
    (c) * * *
    (4) You must operate the rod packing emissions collection system 
under negative pressure and continuously comply with the closed vent 
requirements in Sec.  60.5416(a) and (b).
* * * * *

0
12. 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 facilities?

* * * * *
    (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, or 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
13. Section 60.5420 is amended by:
0
a. Revising paragraph (c) introductory text; and
0
b. Revising paragraph (c)(6); and
0
c. 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.
* * * * *
    (6) Records of each closed vent system inspection required under

[[Page 35898]]

Sec.  60.5416(a)(1) and (2) for centrifugal or reciprocating 
compressors or Sec.  60.5416(c)(1) for storage vessels.
* * * * *
    (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 device failing the visible emissions test.

0
14. Section 60.5430 is amended 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.''
0
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.
    (2) [Reserved]
* * * * *
    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 gas
                                                                                      wells, pneumatic
                                                                                      controllers, centrifugal
                                                                                      compressors, reciprocating
                                                                                      compressors or storage
                                                                                      vessels.
 
                                                  * * * * * * *
Sec.   60.18.......................  General control device  Yes...................  Except that the period of
                                      requirements.                                   visible emissions shall
                                                                                      not exceed a total of 1
                                                                                      minute during any 15-
                                                                                      minute period instead of 5
                                                                                      minutes during any 2
                                                                                      consecutive hours as
                                                                                      required in Sec.
                                                                                      60.18(c).
 
                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------

0
16. Add subpart OOOOa, consisting of sections 60.5360a through 
60.5499a, 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 GHG and VOC standards apply to well affected 
facilities?
60.5380a What GHG and VOC standards apply to centrifugal compressor 
affected facilities?
60.5385a What GHG and VOC standards apply to reciprocating 
compressor affected facilities?
60.5390a What GHG and VOC standards apply to pneumatic controller 
affected facilities?
60.5393a What GHG 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 GHG 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?
60.5398a What are the alternative means of emission limitations for 
GHG and VOC from well completions, reciprocating compressors, 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 GHG and VOC standards apply to affected 
facilities at an onshore natural gas processing plant?
60.5401a What are the exceptions to the equipment leak GHG and VOC 
standards for affected facilities at onshore natural gas processing 
plants?
60.5402a What are the alternative means of emission limitations for 
GHG and VOC 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, and storage vessel 
affected facilities?
60.5413a What are the performance testing procedures for control 
devices used to demonstrate compliance at my

[[Page 35899]]

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 GHG and VOC requirements for onshore 
natural gas processing plants?
60.5422a What are my additional reporting requirements for my 
affected facility subject to GHG 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?
60.5432a How do I determine whether a well is a low pressure well 
using the low pressure well equation?
60.5433a--60.5499a [Reserved]
Table 1 to Subpart OOOOa of Part 60 Required Minimum Initial 
SO2 Emission Reduction Efficiency (Zi)
Table 2 to Subpart OOOOa of Part 60 Required Minimum SO2 
Emission Reduction Efficiency (Zc)
Table 3 to Subpart OOOOa of Part 60 Applicability of General 
Provisions to Subpart OOOOa

Subpart OOOOa--Standards of Performance for Crude Oil and Natural 
Gas Facilities for which Construction, Modification or 
Reconstruction Commenced After September 18, 2015


Sec.  60.5360a  What is the purpose of this subpart?

    (a) This subpart establishes emission standards and compliance 
schedules for the control of the pollutant greenhouse gases (GHG). The 
greenhouse gas standard in this subpart is in the form of a limitation 
on emissions of methane from affected facilities in the crude oil and 
natural gas source category that commence construction, modification, 
or reconstruction after September 18, 2015. This subpart also 
establishes emission standards and compliance schedules for the control 
of 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 August 2, 2016.
    (b) Prevention of Significant Deterioration (PSD) and title V 
thresholds for Greenhouse Gases. (1) For the purposes of 40 CFR 
51.166(b)(49)(ii), with respect to GHG emissions from affected 
facilities, the ``pollutant that is subject to the standard promulgated 
under section 111 of the Act'' shall be considered to be the pollutant 
that otherwise is subject to regulation under the Act as defined in 40 
CFR 51.166(b)(48) and in any State Implementation Plan (SIP) approved 
by the EPA that is interpreted to incorporate, or specifically 
incorporates, Sec.  51.166(b)(48).
    (2) For the purposes of 40 CFR 52.21(b)(50)(ii), with respect to 
GHG emissions from affected facilities, the ``pollutant that is subject 
to the standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is subject to regulation 
under the Clean Air Act as defined in 40 CFR 52.21(b)(49).
    (3) For the purposes of 40 CFR 70.2, with respect to greenhouse gas 
emissions from affected facilities, the ``pollutant that is subject to 
any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 70.2.
    (4) For the purposes of 40 CFR 71.2, with respect to greenhouse gas 
emissions from affected facilities, the ``pollutant that is subject to 
any standard promulgated under section 111 of the Act'' shall be 
considered to be the pollutant that otherwise is ``subject to 
regulation'' as defined in 40 CFR 71.2.


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. 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 paragraph (i)(3)(iii) of this section, 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) Except as provided in Sec.  60.5365a(i)(3)(iii), refracturing 
of a well, by itself, 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 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) Each pneumatic controller affected facility:
    (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. The potential for 
VOC emissions must be calculated using a generally accepted model or 
calculation methodology,

[[Page 35900]]

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 subsection. 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 you must 
determine the potential for VOC emissions within 30 days after liquids 
first enter the storage vessel, except as provided in paragraph 
(e)(3)(iv) of this section. 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 of the well.
    (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) and (d).
    (iii) You must 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) The following requirements apply immediately upon startup, 
startup of production, or return to service. A storage vessel affected 
facility that is reconnected to the original source of liquids is a 
storage vessel affected facility subject to the same requirements that 
applied before being removed from service. Any storage vessel that is 
used to replace any storage vessel affected facility is subject to the 
same requirements that apply to the storage vessel affected facility 
being replaced.
    (5) A storage vessel with a capacity greater than 100,000 gallons 
used to recycle water that has been passed through two stage separation 
is not a storage vessel affected facility.
    (f) The group of all equipment 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 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.
    (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).
    (4) Sweetening facilities producing acid gas that is completely re-
injected 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.
    (h) Each pneumatic pump affected facility:
    (1) For natural gas processing plants, each pneumatic pump affected 
facility, which is a single natural gas-driven diaphragm pump.
    (2) For well sites, each pneumatic pump affected facility, which is 
a single natural gas-driven diaphragm pump. A single natural gas-driven 
diaphragm pump that is in operation less than 90 days per calendar year 
is not an affected facility under this subpart provided the owner/
operator keeps records of the days of operation each calendar year and 
submits such records to the EPA Administrator (or delegated enforcement 
authority) upon request. For the purposes of this section, any period 
of operation during a calendar day counts toward the 90 calendar day 
threshold.
    (i) Except as provided in Sec.  60.5365a(i)(2), the collection of 
fugitive emissions components at a well site, as defined in Sec.  
60.5430a, is an affected facility.
    (1) [Reserved]
    (2) A well site that only contains one or more wellheads is not an 
affected facility under this subpart. The affected facility status of a 
separate tank battery surface site has no effect on the affected 
facility status of a well site that only contains one or more 
wellheads.
    (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:
    (1) An additional compressor is installed at a compressor station; 
or
    (2) One or more compressors at a compressor station is replaced by 
one or more compressors of greater total horsepower than the 
compressor(s) being replaced. When one or more compressors is replaced 
by one or more compressors of an equal or smaller total horsepower than 
the compressor(s) being replaced, installation of the replacement 
compressor(s) does not trigger a modification of the compressor station 
for purposes of Sec.  60.5397a.


Sec.  60.5370a  When must I comply with this subpart?

    (a) You must be in compliance with the standards of this subpart no 
later

[[Page 35901]]

than August 2, 2016 or upon startup, whichever is later.
    (b) At all times, including periods of startup, shutdown, and 
malfunction, owners and operators shall maintain and operate any 
affected facility including associated air pollution control equipment 
in a manner consistent with good air pollution control practice for 
minimizing emissions. Determination of whether acceptable operating and 
maintenance procedures are being used will be based on information 
available to the Administrator which may include, but is not limited 
to, monitoring results, opacity observations, review of operating and 
maintenance procedures, and inspection of the source. 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 GHG and VOC standards apply to well affected 
facilities?

    If you are the owner or operator of a well affected facility as 
described in Sec.  60.5365a(a) that also meets the criteria for a well 
affected facility in Sec.  60.5365(a) of subpart OOOO of this part, you 
must reduce GHG (in the form of a limitation on emissions of methane) 
and VOC emissions by complying with paragraphs (a) through (g) of this 
section. If you own or operate a well affected facility as described in 
Sec.  60.5365a(a) that does not meet the criteria for a well affected 
facility in Sec.  60.5365(a) of subpart OOOO of this part, you must 
reduce GHG and VOC emissions by complying with paragraphs (f)(3), 
(f)(4) or (g) for each well completion operation with hydraulic 
fracturing prior to November 30, 2016, and you must comply with 
paragraphs (a) through (g) of this section for each well completion 
operation with hydraulic fracturing on or after November 30, 2016.
    (a) Except as provided in paragraph (f) and (g) 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) through (iii) 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 onsite 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 technically infeasible for a separator to function, you 
must comply with paragraph (a)(1)(i) of this section.
    (iii) You must have a separator onsite during the entirety of the 
flowback period, except as provided in paragraphs (a)(1)(iii)(A) 
through (C) of this section.
    (A) A well that is not hydraulically fractured or refractured with 
liquids, or that does not generate condensate, intermediate hydrocarbon 
liquids, or produced water such that there is no liquid collection 
system at the well site is not required to have a separator onsite.
    (B) If conditions allow for liquid collection, then the operator 
must immediately stop the well completion operation, install a 
separator, and restart the well completion operation in accordance with 
Sec.  60.5375a(a)(1).
    (C) The owner or operator of a well that meets the criteria of 
paragraph (a)(1)(iii)(A) or (B) of this section must submit the report 
in Sec.  60.5420a(b)(2) and maintain the records in Sec.  
60.5420a(c)(1)(iii).
    (2) [Reserved]
    (3) If it is technically infeasible to route the recovered gas as 
required in Sec.  60.5375a(a)(1)(ii), then 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 pilot flame.
    (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(a).
    (d) You must demonstrate continuous compliance with the standards 
that apply to well affected facilities as required by Sec.  
60.5415a(a).
    (e) You must perform the required notification, recordkeeping and 
reporting as required by Sec.  60.5420a(a)(2), (b)(1) and (2), and 
(c)(1).
    (f) For each well affected facility specified in paragraphs (f)(1) 
and (2) of this section, you must comply with the requirements of 
paragraphs (f)(3) and (4) of this section.
    (1) Each well completion operation with hydraulic fracturing at a 
wildcat or delineation well.
    (2) Each well completion operation with hydraulic fracturing at a 
non-wildcat low pressure well or non-delineation low pressure well.
    (3) You must comply with either paragraph (f)(3)(i) or (f)(3)(ii) 
of this section, unless you meet the requirements in paragraph (g) of 
this section. You must also comply with paragraph (b) of this section.
    (i) Route all flowback 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 pilot flame.
    (ii) Route all 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. Capture and direct recovered gas to a completion combustion 
device, except in conditions

[[Page 35902]]

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 pilot flame. (4) You must submit 
the notification as specified in Sec.  60.5420a(a)(2), submit annual 
reports as specified in Sec.  60.5420a(b)(1) and (2) and maintain 
records specified in Sec.  60.5420a(c)(1)(iii) for each wildcat and 
delineation well. You must submit the notification as specified in 
Sec.  60.5420a(a)(2), submit annual reports as specified in Sec.  
60.5420a(b)(1) and (2), and maintain records as specified in Sec.  
60.5420a(c)(1)(iii) and (vii) for each low pressure well.
    (g) For each well affected facility with less than 300 scf of gas 
per stock tank barrel of oil produced, you must comply with paragraphs 
(g)(1) and (2) of this section.
    (1) You must maintain records specified in Sec.  
60.5420a(c)(1)(vi).
    (2) You must submit reports specified in Sec.  60.5420a(b)(1) and 
(2).


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

    You must comply with the GHG 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.
    (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 (d) 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 reporting as required by Sec.  
60.5420a(b)(1) and (3), and the recordkeeping as required by Sec.  
60.5420a(c)(2), (6) through (11), and (17), as applicable.


Sec.  60.5385a  What GHG and VOC standards apply to reciprocating 
compressor affected facilities?

    You must reduce GHG (in the form of a limitation on emissions of 
methane) and VOC emissions by complying with the standards in 
paragraphs (a) through (d) of this section for each reciprocating 
compressor affected facility.
    (a) You must replace the reciprocating compressor rod packing 
according to either paragraph (a)(1) or (2) of this section, or you 
must comply with paragraph (a)(3) of this section.
    (1) On or 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 that 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) and (d).
    (b) You must demonstrate initial compliance with standards that 
apply to reciprocating compressor affected facilities as required by 
Sec.  60.5410a(c).
    (c) You must demonstrate continuous compliance with standards that 
apply to reciprocating compressor affected facilities as required by 
Sec.  60.5415a(c).
    (d) You must perform the reporting as required by Sec.  
60.5420a(b)(1) and (4) and the recordkeeping as required by Sec.  
60.5420a(c)(3), (6) through (9), and (17), as applicable.


Sec.  60.5390a  What GHG and VOC standards apply to pneumatic 
controller affected facilities?

    For each pneumatic controller affected facility you must comply 
with the GHG and VOC standards, based on natural gas as a surrogate for 
GHG 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 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(d).
    (e) You must demonstrate continuous compliance with standards that 
apply to pneumatic controller affected facilities as required by Sec.  
60.5415a(d).
    (f) You must perform the reporting as required by Sec.  
60.5420a(b)(1) and (5) and the recordkeeping as required by Sec.  
60.5420a(c)(4).


Sec.  60.5393a  What GHG and VOC standards apply to pneumatic pump 
affected facilities?

    For each pneumatic pump affected facility you must comply with the 
GHG and VOC standards, based on natural gas as a surrogate for GHG and 
VOC, in either paragraph (a) or (b) of this section, as applicable, on 
or after November 30, 2016.
    (a) Each pneumatic pump affected facility at a natural gas 
processing plant must have a natural gas emission rate of zero.
    (b) For each pneumatic pump affected facility at a well site you 
must comply with paragraph (b)(1) or (2) of this section.
    (1) If the pneumatic pump affected facility is located at a 
greenfield site as

[[Page 35903]]

defined in Sec.  60.5430a, you must reduce natural gas emissions by 
95.0 percent, except as provided in paragraphs (b)(3) and (4) of this 
section.
    (2) If the pneumatic pump affected facility is not located at a 
greenfield site as defined in Sec.  60.5430a, you must reduce natural 
gas emissions by 95.0 percent, except as provided in paragraphs (b)(3), 
(4) and (5) of this section.
    (3) You are not required to install a control device solely for the 
purpose of complying with the 95.0 percent reduction requirement of 
paragraph (b)(1) or (b)(2) of this section. If you do not have a 
control device installed on site by the compliance date and you do not 
have the ability to route to a process, then you must comply instead 
with the provisions of paragraphs (b)(3)(i) and (ii) of this section.
    (i) Submit a certification in accordance with Sec.  
60.5420a(b)(8)(i)(A) in your next annual report, certifying that there 
is no available control device or process on site and maintain the 
records in Sec.  60.5420a(c)(16)(i) and (ii).
    (ii) If you subsequently install a control device or have the 
ability to route to a process, you are no longer required to comply 
with paragraph (b)(2)(i) of this section and must submit the 
information in Sec.  60.5420a(b)(8)(ii) in your next annual report and 
maintain the records in Sec.  60.5420a(c)(16)(i), (ii), and (iii). You 
must be in compliance with the requirements of paragraph (b)(2) of this 
section within 30 days of startup of the control device or within 30 
days of the ability to route to a process.
    (4) If the control device available on site is unable to achieve a 
95 percent reduction and there is no ability to route the emissions to 
a process, you must still route the pneumatic pump affected facility's 
emissions to that existing control device. If you route the pneumatic 
pump affected facility to a control device installed on site that is 
designed to achieve less than a 95 percent reduction, you must submit 
the information specified in Sec.  60.5420a(b)(8)(i)(C) in your next 
annual report and maintain the records in Sec.  60.5420a(c)(16)(iii).
    (5) If an owner or operator at a non-greenfield site determines, 
through an engineering assessment, that routing a pneumatic pump to a 
control device or a process is technically infeasible, the requirements 
specified in paragraph (b)(5)(i) through (iv) of this section must be 
met.
    (i) The owner or operator shall conduct the assessment of technical 
infeasibility in accordance with the criteria in paragraph (b)(5)(iii) 
of this section and have it certified by a qualified professional 
engineer in accordance with paragraph (b)(5)(ii) of this section.
    (ii) The following certification, signed and dated by the qualified 
professional engineer shall state: ``I certify that the assessment of 
technical infeasibility was prepared under my direction or supervision. 
I further certify that the assessment was conducted and this report was 
prepared pursuant to the requirements of Sec.  60.5393a(b)(5)(iii). 
Based on my professional knowledge and experience, and inquiry of 
personnel involved in the assessment, the certification submitted 
herein is true, accurate, and complete. I am aware that there are 
penalties for knowingly submitting false information.''
    (iii) The assessment of technical feasibility to route emissions 
from the pneumatic pump to an existing control device onsite or to a 
process shall include, but is not limited to, safety considerations, 
distance from the control device, pressure losses and differentials in 
the closed vent system and the ability of the control device to handle 
the pneumatic pump emissions which are routed to them. The assessment 
of technical infeasibility shall be prepared under the direction or 
supervision of the qualified professional engineer who signs the 
certification in accordance with paragraph (b)(2)(ii) of this section.
    (iv) The owner or operator shall maintain the records Sec.  
60.5420a(c)(16)(iv).
    (6) If the pneumatic pump is routed to a control device or a 
process and the control device or process is subsequently removed from 
the location or is no longer available, you are no longer required to 
be in compliance with the requirements of paragraph (b)(1) or (b)(2) of 
this section, and instead must comply with paragraph (b)(3) of this 
section and report the change in next annual report in accordance with 
Sec.  60.5420a(b)(8)(ii).
    (c) If you use a control device or route to a process 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 (d).
    (d) You must demonstrate initial compliance with standards that 
apply to pneumatic pump affected facilities as required by Sec.  
60.5410a(e).
    (e) You must perform the reporting as required by Sec.  
60.5420a(b)(1) and (8) and the recordkeeping as required by Sec.  
60.5420a(c)(6) through (10), (16), and (17), as applicable.


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 the requirements of paragraphs (a)(1) and 
(2) of this section. After 12 consecutive months of compliance with 
paragraph (a)(2) of this section, you may continue to comply with 
paragraph (a)(2) of this section, or you may comply with paragraph 
(a)(3) of this section, if applicable. 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 the 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(a)(1)(i) or (ii), 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 may no longer comply with 
this paragraph and must instead 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

[[Page 35904]]

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 (d), and you must route 
emissions to a control device that meets the conditions specified in 
Sec.  60.5412a(c) or (d). As an alternative to routing the closed vent 
system to a control device, you may route the closed vent system to a 
process.
    (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 paragraphs (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 reporting as required by Sec.  
60.5420a(b)(1) and (6) and the recordkeeping as required by Sec.  
60.5420a(c)(5) through (8), (12) through (14), and (17), as applicable.
    (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, and 40 CFR part 63, 
subparts G, CC, HH, or WW.


Sec.  60.5397a  What fugitive emissions GHG 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 GHG (in the form of a limitation on emissions of methane) 
and VOC emissions by complying with the requirements of paragraphs (a) 
through (j) 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 Sec.  60.5430a, in accordance with paragraphs (b) through (g) of 
this section. You must repair all sources of fugitive emissions in 
accordance with paragraph (h) of this section. You must keep records in 
accordance with paragraph (i) of this section and report in accordance 
with paragraph (j) 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 or an instrument 
reading of 500 ppm or greater using Method 21.
    (b) You must develop an emissions monitoring plan that covers the 
collection of fugitive emissions components at well sites and 
compressor stations within each company-defined area in accordance with 
paragraphs (c) and (d) of this section.
    (c) Fugitive emissions monitoring plans must include the elements 
specified in paragraphs (c)(1) through (8) of this section, at a 
minimum.
    (1) Frequency for conducting surveys. Surveys must be conducted at 
least as frequently as required by paragraphs (f) and (g) of this 
section.
    (2) Technique for determining fugitive emissions (i.e., Method 21 
at 40 CFR part 60, appendix A-7, or optical gas imaging).
    (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 (h) 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) If you are using optical gas imaging, 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 <=60g/hr from a quarter inch diameter orifice.
    (ii) Procedure for a daily verification check.
    (iii) Procedure for determining the operator's maximum viewing 
distance from the equipment and how the operator will ensure that this 
distance is maintained.
    (iv) Procedure for determining maximum wind speed during which 
monitoring can be performed and how the operator will ensure monitoring

[[Page 35905]]

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. At a minimum, 
procedures must comply with those recommended by the manufacturer.
    (8) If you are using Method 21 of appendix A-7 of this part, your 
plan must also include the elements specified in paragraphs (c)(8)(i) 
and (ii) of this section. For the purposes of complying with the 
fugitive emissions monitoring program using Method 21 a fugitive 
emission is defined as an instrument reading of 500 ppm or greater.
    (i) Verification that your monitoring equipment meets the 
requirements specified in Section 6.0 of Method 21 at 40 CFR part 60, 
appendix A-7. For purposes of instrument capability, the fugitive 
emissions definition shall be 500 ppm or greater methane using a FID-
based instrument. If you wish to use an analyzer other than a FID-based 
instrument, you must develop a site-specific fugitive emission 
definition that would be equivalent to 500 ppm methane using a FID-
based instrument (e.g., 10.6 eV PID with a specified isobutylene 
concentration as the fugitive emission definition would provide 
equivalent response to your compound of interest).
    (ii) Procedures for conducting surveys. At a minimum, the 
procedures shall ensure that the surveys comply with the relevant 
sections of Method 21 at 40 CFR part 60, appendix A-7, including 
Section 8.3.1.
    (d) Each fugitive emissions monitoring plan must include the 
elements specified in paragraphs (d)(1) through (4) of this section, at 
a minimum, as applicable.
    (1) Sitemap.
    (2) A defined observation path that ensures that all fugitive 
emissions components are within sight of the path. The observation path 
must account for interferences.
    (3) If you are using Method 21, your plan must also include a list 
of fugitive emissions components to be monitored and method for 
determining location of fugitive emissions components to be monitored 
in the field (e.g. tagging, identification on a process and 
instrumentation diagram, etc.).
    (4) Your plan must also include the written plan developed for all 
of the fugitive emission components designated as difficult-to-monitor 
in accordance with paragraph (g)(3)(i) of this section, and the written 
plan for fugitive emission components designated as unsafe-to-monitor 
in accordance with paragraph (g)(3)(ii) of this section.
    (e) Each monitoring survey shall observe each fugitive emissions 
component, as defined in Sec.  60.5430a, for fugitive emissions.
    (f)(1) You must conduct an initial monitoring survey within 60 days 
of the startup of production, as defined in Sec.  60.5430a, for each 
collection of fugitive emissions components at a new well site or by 
June 3, 2017, whichever is later. For a modified collection of fugitive 
emissions components at a well site, the initial monitoring survey must 
be conducted within 60 days of the first day of production for each 
collection of fugitive emission components after the modification or by 
June 3, 2017, whichever is later.
    (2) You must conduct an initial monitoring survey within 60 days of 
the startup of a new compressor station for each new collection of 
fugitive emissions components at the new compressor station or by June 
3, 2017, whichever is later. For a modified collection of fugitive 
components at a compressor station, the initial monitoring survey must 
be conducted within 60 days of the modification or by June 3, 2017, 
whichever is later.
    (g) A monitoring survey of each collection of fugitive emissions 
components at a well site or at a compressor station must be performed 
at the frequencies specified in paragraphs (g)(1) and (2) of this 
section, with the exceptions noted in paragraphs (g)(3) and (4) of this 
section.
    (1) A monitoring survey of each collection of fugitive emissions 
components at a well site within a company-defined area must be 
conducted at least semiannually after the initial survey. Consecutive 
semiannual monitoring surveys must be conducted at least 4 months 
apart.
    (2) A monitoring survey of the collection of fugitive emissions 
components at a compressor station within a company-defined area must 
be conducted at least quarterly after the initial survey. Consecutive 
quarterly monitoring surveys must be conducted at least 60 days apart.
    (3) Fugitive emissions components that cannot be monitored without 
elevating the monitoring personnel more than 2 meters above the surface 
may be designated as difficult-to-monitor. Fugitive emissions 
components that are designated difficult-to-monitor must meet the 
specifications of paragraphs (g)(3)(i) through (iv) of this section.
    (i) A written plan must be developed for all of the fugitive 
emissions components designated difficult-to-monitor. This written plan 
must be incorporated into the fugitive emissions monitoring plan 
required by paragraphs (b), (c), and (d) of this section.
    (ii) The plan must include the identification and location of each 
fugitive emissions component designated as difficult-to-monitor.
    (iii) The plan must include an explanation of why each fugitive 
emissions component designated as difficult-to-monitor is difficult-to-
monitor.
    (iv) The plan must include a schedule for monitoring the difficult-
to-monitor fugitive emissions components at least once per calendar 
year.
    (4) Fugitive emissions components that cannot be monitored because 
monitoring personnel would be exposed to immediate danger while 
conducting a monitoring survey may be designated as unsafe-to-monitor. 
Fugitive emissions components that are designated unsafe-to-monitor 
must meet the specifications of paragraphs (g)(4)(i) through (iv) of 
this section.
    (i) A written plan must be developed for all of the fugitive 
emissions components designated unsafe-to-monitor. This written plan 
must be incorporated into the fugitive emissions monitoring plan 
required by paragraphs (b), (c), and (d) of this section.
    (ii) The plan must include the identification and location of each 
fugitive emissions component designated as unsafe-to-monitor.
    (iii) The plan must include an explanation of why each fugitive 
emissions component designated as unsafe-to-monitor is unsafe-to-
monitor.
    (iv) The plan must include a schedule for monitoring the fugitive 
emissions components designated as unsafe-to-monitor.
    (5) The requirements of paragraph (g)(2) of this section are waived 
for any collection of fugitive emissions components at a compressor 
station located within an area that has an average calendar month 
temperature below 0 [deg]Fahrenheit for two of three consecutive 
calendar months of a quarterly monitoring period. The calendar month 
temperature average for

[[Page 35906]]

each month within the quarterly monitoring period must be determined 
using historical monthly average temperatures over the previous three 
years as reported by a National Oceanic and Atmospheric Administration 
source or other source approved by the Administrator. The requirements 
of paragraph (g)(2) of this section shall not be waived for two 
consecutive quarterly monitoring periods.
    (h) Each identified source of fugitive emissions shall be repaired 
or replaced in accordance with paragraphs (h)(1) and (2) of this 
section. 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 (h)(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 30 calendar days 
after detection of the fugitive emissions.
    (2) If the repair or replacement is technically infeasible, would 
require a vent blowdown, a compressor station shutdown, a well shutdown 
or well shut-in, or would be unsafe to repair during operation of the 
unit, the repair or replacement must be completed during the next 
compressor station shutdown, well shutdown, well shut-in, after an 
unscheduled, planned or emergency vent blowdown or within 2 years, 
whichever is earlier.
    (3) Each repaired or replaced fugitive emissions component must be 
resurveyed as soon as practicable, but no later than 30 days after 
being repaired, to ensure that there are no fugitive emissions.
    (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 30 days of finding such fugitive 
emissions.
    (ii) For each repair that cannot be made during the monitoring 
survey when the fugitive emissions are initially found, a digital 
photograph must be taken of that component or the component must be 
tagged for identification purposes. The digital photograph must include 
the date that the photograph was taken, must clearly identify the 
component by location within the site (e.g., the latitude and longitude 
of the component or by other descriptive landmarks visible in the 
picture).
    (iii) Operators that use Method 21 to resurvey the repaired 
fugitive emissions components are subject to the resurvey provisions 
specified in paragraphs (h)(3)(iii)(A) and (B) of this section.
    (A) A fugitive emissions component is repaired when the Method 21 
instrument indicates a concentration of less than 500 ppm above 
background or when no soap bubbles are observed when the alternative 
screening procedures specified in section 8.3.3 of Method 21 are used.
    (B) Operators must use the Method 21 monitoring requirements 
specified in paragraph (c)(8)(ii) of this section or the alternative 
screening procedures specified in section 8.3.3 of Method 21.
    (iv) Operators that use optical gas imaging to resurvey the 
repaired fugitive emissions components, are subject to the resurvey 
provisions specified in paragraphs (h)(3)(iv)(A) and (B) of this 
section.
    (A) A fugitive emissions component is repaired when the optical gas 
imaging instrument shows no indication of visible emissions.
    (B) Operators must use the optical gas imaging monitoring 
requirements specified in paragraph (c)(7) of this section.
    (i) Records for each monitoring survey shall be maintained as 
specified Sec.  60.5420a(c)(15).
    (j) 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 at a compressor station 
may be included in a single annual report.


Sec.  60.5398a  What are the alternative means of emission limitations 
for GHG and VOC from well completions, reciprocating compressors, the 
collection of fugitive emissions components at a well site and the 
collection of fugitive emissions components at a compressor station?

    (a) If, in the Administrator's judgment, an alternative means of 
emission limitation will achieve a reduction in GHG (in the form of a 
limitation on emission of methane) and VOC emissions at least 
equivalent to the reduction in GHG and VOC emissions achieved under 
Sec.  60.5375a, Sec.  60.5385a, and Sec.  60.5397a, the Administrator 
will publish, in the Federal Register, a notice permitting the use of 
that alternative means for the purpose of compliance with Sec.  
60.5375a, Sec.  60.5385a, and Sec.  60.5397a. 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.
    (d) Determination of equivalence to the design, equipment, work 
practice or operational requirements of this section will be evaluated 
by the following guidelines:
    (1) The applicant must collect, verify and submit test data, 
covering a period of at least 12 months to demonstrate the equivalence 
of the alternative means of emission limitation. The application must 
include the following information:
    (i) A description of the technology or process.
    (ii) The monitoring instrument and measurement technology or 
process.
    (iii) A description of performance based procedures (i.e., method) 
and data quality indicators for precision and bias; the method 
detection limit of the technology or process.
    (iv) For affected facilities under Sec.  60.5397a, the action 
criteria and level at which a fugitive emission exists.
    (v) Any initial and ongoing quality assurance/quality control 
measures.
    (vi) Timeframes for conducting ongoing quality assurance/quality 
control.
    (vii) Field data verifying viability and detection capabilities of 
the technology or process.
    (viii) Frequency of measurements.
    (ix) Minimum data availability.
    (x) Any restrictions for using the technology or process.
    (xi) Operation and maintenance procedures and other provisions 
necessary to ensure reduction in methane and VOC emissions at least 
equivalent to the reduction in methane and VOC emissions achieved under 
Sec.  60.5397a.
    (xii) Initial and continuous compliance procedures, including 
recordkeeping and reporting.
    (2) For each determination of equivalency requested, the emission 
reduction achieved by the design, equipment, work practice or 
operational requirements shall be demonstrated.
    (3) For each affected facility for which a determination of 
equivalency is requested, the emission reduction achieved by the 
alternative means of emission limitation shall be demonstrated.
    (4) Each owner or operator applying for a determination of 
equivalence to a work practice standard shall commit in writing to work 
practice(s) that provide for emission reductions equal to or

[[Page 35907]]

greater than the emission reductions achieved by the required work 
practice.
    (e) After notice and opportunity for public hearing, the 
Administrator will determine the equivalence of a means of emission 
limitation and will publish the determination in the Federal Register.
    (f) An application submitted under this section will be evaluated 
as set forth in paragraphs (f)(1) and (2) of this section.
    (1) The Administrator will compare the demonstrated emission 
reduction for the alternative means of emission limitation to the 
demonstrated emission reduction for the design, equipment, work 
practice or operational requirements and, if applicable, will consider 
the commitment in paragraph (d) of this section.
    (2) The Administrator may condition the approval of the alternative 
means of emission limitation on requirements that may be necessary to 
ensure operation and maintenance to achieve the same emissions 
reduction as the design, equipment, work practice or operational 
requirements. (g) Any equivalent means of emission limitations approved 
under this section shall constitute a required work practice, 
equipment, design or operational standard within the meaning of section 
111(h)(1) of the CAA.


Sec.  60.5400a  What equipment leak GHG 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 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 equipment leak GHG and 
VOC 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 onsite, instead of within 5 days as specified in 
paragraph (b)(1) of this section and Sec.  60.482-4a(b)(1).
    (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]Celsius (302 
[deg]Fahrenheit) 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]Celsius (302 
[deg]Fahrenheit) 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

[[Page 35908]]

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 means of emission limitations 
for GHG 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 GHG and VOC emissions 
at least equivalent to the reduction in GHG 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) An application submitted under paragraph (c) of this section 
must meet the following criteria:
    (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) The application must include operation, maintenance and other 
provisions necessary to assure 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 in paragraph (a) of this section by including the information 
specified in paragraphs (d)(1)(i) through (x) of this section.
    (i) A description of the technology or process.
    (ii) The monitoring instrument and measurement technology or 
process.
    (iii) A description of performance based procedures (i.e. method) 
and data quality indicators for precision and bias; the method 
detection limit of the technology or process.
    (iv) The action criteria and level at which a fugitive emission 
exists.
    (v) Any initial and ongoing quality assurance/quality control 
measures.
    (vi) Timeframes for conducting ongoing quality assurance/quality 
control.
    (vii) Field data verifying viability and detection capabilities of 
the technology or process.
    (viii) Frequency of measurements.
    (ix) Minimum data availability.
    (x) Any restrictions for using the technology or process.
    (3) The application must include initial and continuous compliance 
procedures including recordkeeping and reporting.


Sec.  60.5405a   What standards apply to sweetening unit affected 
facilities 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 unit 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 
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-\3\Mg/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 (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/K1

Where:

E = emission rate of sulfur per run, kg/hr.
Ce = concentration of sulfur equivalent (SO\2+\ reduced 
sulfur), g/dscm (lb/dscf).
Qsd = volumetric flow rate of effluent gas, dscm/hr 
(dscf/hr).
K1 = conversion factor, 1000 g/kg (7000 gr/lb).

    (4) The concentration (Ce) of sulfur equivalent must be 
the sum of the SO2 and TRS concentrations, after being 
converted to sulfur equivalents. For each run and each of the test 
methods specified in this paragraph (c) of this section, you must use a 
sampling time of at least 4 hours. You must use Method 1 of appendix A-
1 of this part to select the sampling site. The sampling point in the 
duct must be at

[[Page 35909]]

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 ANSI/ASME 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 ANSI/ASME 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 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.

[[Page 35910]]

    (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] TR03JN16.001

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 that 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,

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

[[Page 35911]]

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.
BILLING CODE 6560-50-P
[GRAPHIC] [TIFF OMITTED] TR03JN16.002


[[Page 35912]]


BILLING CODE 6560-50-C


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 August 2, 
2016, 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 August 2, 2016. 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 (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)(1) and (2).
    (3) You must maintain a log of records as specified in Sec.  
60.5420a(c)(1)(i) through (iv), as applicable, for each well completion 
operation conducted during the initial compliance period. If you meet 
the exemption for wells with a GOR less than 300 scf per stock barrel 
of oil produced, you do not have to maintain the records in Sec.  
60.5420a(c)(1)(i) through (iv) and must maintain the record in Sec.  
60.5420a(c)(1)(vi).
    (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 in accordance with Sec.  60.5420a(c)(1)(v) 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 GPS device within the same digital picture, provided the 
latitude and longitude output of the GPS 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(a) 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 (d) 
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.
    (3) You must conduct an initial performance test as required in 
Sec.  60.5413a within 180 days after initial startup or by August 2, 
2016, whichever is later, and you must comply with the continuous 
compliance requirements in Sec.  60.5415a(b).
    (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) ]Reserved]
    (7) You must submit the initial annual report for your centrifugal 
compressor affected facility as required in Sec.  60.5420a(b)(1) and 
(3).
    (8) You must maintain the records as specified in Sec.  
60.5420a(c)(2), (6) through (11), and (17), as applicable.
    (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) and (d).
    (3) You must submit the initial annual report for your 
reciprocating compressor as required in Sec.  60.5420a(b)(1) and (4).
    (4) You must maintain the records as specified in Sec.  
60.5420a(c)(3) 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(b)(1) or (c)(1).
    (2) If you own or operate a pneumatic controller affected facility 
located at a natural gas processing plant, your pneumatic controller 
must be driven by a gas other than natural gas, resulting in zero 
natural gas emissions.
    (3) If you own or operate a pneumatic controller affected facility 
located other than at a natural gas processing plant, the controller 
manufacturer's design specifications for the controller must 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)(1) and (5).
    (6) You must maintain the records as specified in Sec.  
60.5420a(c)(4) 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 (7) of this section, as 
applicable.
    (1) If you own or operate a pneumatic pump affected facility 
located at a natural gas processing plant, your pneumatic pump must be 
driven by a gas other than natural gas, resulting in zero natural gas 
emissions.

[[Page 35913]]

    (2) If you own or operate a pneumatic pump affected facility not 
located at a natural gas processing plant, you must reduce emissions in 
accordance Sec.  60.5393a(b)(1) or (b)(2), and you must collect the 
pneumatic pump emissions through a closed vent system that meets the 
requirements of Sec.  60.5411a(a) and (d).
    (3) If you own or operate a pneumatic pump affected facility not 
located at a natural gas processing plant and there is no control 
device or process available on site, you must submit the certification 
in 60.5420a(b)(8)(i)(A).
    (4) If you own or operate a pneumatic pump affected facility not 
located at a natural gas processing plant or a greenfield site, and you 
are unable to route to an existing control device due to technical 
infeasibility, and you are unable to route to a process, you must 
submit the certification in Sec.  60.5420a(b)(8)(i)(B).
    (5) If you own or operate a pneumatic pump affected facility not 
located other than at a natural gas processing plant and you reduce 
emissions in accordance with Sec.  60.5393a(b)(4), you must collect the 
pneumatic pump emissions through a closed vent system that meets the 
requirements of Sec.  60.5411a(c) and (d).
    (6) You must submit the initial annual report for your pneumatic 
pump affected facility required in Sec.  60.5420a(b)(1) and (8).
    (7) You must maintain the records as specified in Sec.  
60.5420a(c)(6), (8) through (10), (16), and (17), as applicable, for 
each pneumatic pump affected facility.
    (f) For affected facilities at onshore natural gas processing 
plants, initial compliance with the methane and VOC standards 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 must submit 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 August 2, 2016, 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) and (d) 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 August 2, 2016, 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 in your initial annual report as specified in 
Sec.  60.5420a(b)(1) and (6).
    (6) You must maintain the records required for your storage vessel 
affected facility, as specified in Sec.  60.5420a(c)(5) through (8), 
(12) through (14), and (17), as applicable, for each storage vessel 
affected facility.
    (i) For each storage vessel affected facility that complies by 
using a floating roof, you must submit a statement that you are 
complying with Sec.  60.112(b)(a)(1) or (2) in accordance with 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 as 
required in Sec.  60.5397a(b)(c), and (d).
    (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)(15).
    (4) You must repair each identified source of fugitive emissions 
for each affected facility as required in Sec.  60.5397a(h).
    (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)(1) and (7).


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. For reciprocating 
and centrifugal compressors, the closed vent system must route all 
gases, vapors, and fumes to a control device 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.

[[Page 35914]]

    (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 that 
is capable of taking periodic readings as specified in Sec.  
60.5416a(a)(4)(i) and sounds an alarm, or initiates 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 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), and (d), 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.
    (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 that 
sounds an alarm, or initiates 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 lines, and safety devices are not subject to the requirements 
of paragraph (c)(3)(i) of this section.
    (d) Closed vent systems requirements for centrifugal compressor wet 
seal fluid degassing systems, reciprocating compressors, pneumatic 
pumps and storage vessels using a control device or routing emissions 
to a process.
    (1) You must conduct an assessment that the closed vent system is 
of sufficient design and capacity to ensure that all emissions from the 
storage vessel are routed to the control device and that the control 
device is of sufficient design and capacity to accommodate all 
emissions from the affected facility and have it certified by a 
qualified professional engineer in accordance with paragraphs (d)(1)(i) 
and (ii) of this section.
    (i) You must provide the following certification, signed and dated 
by the qualified professional engineer: ``I certify that the closed 
vent system design and capacity assessment was prepared under my 
direction or supervision. I further certify that the closed vent system 
design and capacity assessment was conducted and this report was 
prepared pursuant to the requirements of subpart OOOOa of 40 CFR part 
60. Based on my professional knowledge and experience, and inquiry of 
personnel involved in the assessment, the certification submitted 
herein is true, accurate, and complete. I am aware that there are 
penalties for knowingly submitting false information.''
    (ii) The assessment shall be prepared under the direction or 
supervision of the qualified professional engineer who signs the 
certification in paragraph (d)(1)(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, 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, 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 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 meet the continuous compliance 
requirements in 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(b), 
with the exceptions noted in Sec.  60.5413a(a).

[[Page 35915]]

    (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 275 parts 
per million by volume as propane on a wet basis corrected to 3 percent 
oxygen as determined in accordance with the applicable requirements of 
Sec.  60.5413a(b), with the exceptions noted in Sec.  60.5413a(a).
    (iii) You must operate at a minimum temperature of 760 
[deg]Celsius, provided the control device has demonstrated, during the 
performance test conducted under Sec.  60.5413a(b), that combustion 
zone temperature is an indicator of destruction efficiency.
    (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(b). 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.  60.18(b), and you must conduct the compliance 
determination using Method 22 of appendix A-7 of this part to determine 
visible emissions.
    (b) You must operate each control device installed on your 
centrifugal compressor 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)(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 (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 (vi) of this section.
    (i) Regenerate or reactivate the spent carbon in a 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 unit equipped 
with an operating organic air emission controls in accordance with an 
emissions standard for VOC under another subpart in 40 CFR part 63 or 
this part.
    (iii) Burn the spent carbon in a hazardous waste incinerator for 
which the owner or operator complies with the requirements of 40 CFR 
part 63, subpart EEE and has submitted a Notification of Compliance 
under 40 CFR 63.1207(j).
    (iv) Burn the spent carbon in a hazardous waste boiler or 
industrial furnace for which the owner or operator complies with the 
requirements of 40 CFR part 63, subpart EEE and has submitted a 
Notification of Compliance under 40 CFR 63.1207(j).
    (v) Burn the spent carbon in an 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.
    (vi) Burn the spent carbon in an 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)(2) for your storage vessel affected 
facility must be installed according to paragraphs (d)(1) through (4) 
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 meet the continuous compliance requirements in Sec.  60.5413a(e).
    (1) For each 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 enclosed 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 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).
    (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 275 parts 
per million by volume as propane on a wet basis corrected to 3 percent 
oxygen as determined in accordance with the applicable requirements of 
Sec.  60.5413a(b).
    (C) You must operate at a minimum temperature of 760 [deg]Celsius, 
provided the control device has demonstrated, during the performance 
test conducted under Sec.  60.5413a(b), that combustion

[[Page 35916]]

zone temperature is an indicator of destruction efficiency.
    (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 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 design and operate a flare in accordance with the 
requirements of Sec.  60.18(b), and you must conduct the compliance 
determination using Method 22 of appendix A-7 of this part to determine 
visible emissions.
    (4) 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 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 or storage vessel affected 
facility. You must demonstrate that a control device achieves the 
performance requirements of Sec.  60.5412a(a)(1) or (2) or (d)(1) or 
(2) 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 and centrifugal compressor 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.
    (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 been issued a final permit under 40 CFR part 270 and comply 
with the requirements of 40 CFR part 266, subpart H; you have certified 
compliance with the interim status requirements of 40 CFR part 266, 
subpart H; you have submitted a Notification of Compliance under 40 CFR 
63.1207(j) and comply with the requirements of 40 CFR part 63, subpart 
EEE; or you comply with 40 CFR part 63, subpart EEE and will submit a 
Notification of Compliance under 40 CFR 63.1207(j) by the date 
specified in Sec.  60.5420(b)(9) for submitting the initial performance 
test report.
    (5) A hazardous waste incinerator for which you have submitted a 
Notification of Compliance under 40 CFR 63.1207(j), or for which you 
will submit a Notification of Compliance under 40 CFR 63.1207(j) by the 
date specified in Sec.  60.5420a(b)(9) for submitting the initial 
performance test report, and you comply with the requirements of 40 CFR 
part 63, subpart EEE.
    (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)(1) or (d)(1) 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)(1) or (2) 
or (d)(1) or (2). You must conduct the initial and periodic performance 
tests according to the schedule specified in paragraph (b)(5) of this 
section. Each performance test must consist of a minimum of 3 test 
runs. Each run must be at least 1 hour long.
    (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 a control device percent reduction 
requirement.
    (ii) The sampling site must be located at the outlet of the 
combustion device to determine compliance with a TOC exhaust gas 
concentration limit.
    (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)(iv)(A), you must use Method 25A of appendix A-7 of this part. 
You must use Method 4 of appendix A-3 of this part to convert the 
Method 25A results to a dry basis. You must use the procedures in 
paragraphs (b)(3)(i) through (iii) of this section to calculate percent 
reduction efficiency.
    (i) You must compute the mass rate of TOC using the following 
equations:

Ei = K2CiMpQi
Eo = K2CoMpQo

Where:

Ei, Eo = Mass rate of TOC at the inlet and 
outlet of the control device, respectively, dry basis, kilograms 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]Celsius.
Ci, Co = Concentration of TOC, as propane, of 
the gas stream as measured by Method 25A at the inlet and outlet of 
the control device, respectively, dry basis, parts per million by 
volume.
Mp = Molecular weight of propane, 44.1 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.

    (ii) You must calculate the percent reduction in TOC as follows:
    [GRAPHIC] [TIFF OMITTED] TR03JN16.003
    
Where:

Rcd = Control efficiency of control device, percent.
Ei, = Mass rate of TOC at the inlet to the control device 
as calculated under paragraph (b)(3)(i) of this section, kilograms 
per hour.
Eo = Mass rate of TOC at the outlet of the control 
device, as calculated under paragraph (b)(3)(i) of this section, 
kilograms per hour.

    (iii) If the vent stream entering a boiler or process heater with a 
design

[[Page 35917]]

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 across the device by comparing the TOC in all combusted 
vent streams and primary and secondary fuels with the TOC exiting the 
device, respectively.
    (4) You must use Method 25A of appendix A-7 of this part to measure 
TOC, as propane, to determine compliance with the TOC exhaust gas 
concentration limit specified in Sec.  60.5412a(a)(1)(ii) or 
(d)(1)(iv)(B). You may also use Method 18 of appendix A-6 of this part 
to measure methane and ethane. You may subtract the measured 
concentration of methane and ethane from the Method 25A measurement to 
demonstrate compliance with the concentration limit. You must determine 
the concentration in parts per million by volume on a wet basis and 
correct it to 3 percent oxygen, using the procedures in paragraphs 
(b)(4)(i) through (iii) of this section.
    (i) If you use Method 18 to determine methane and ethane, 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. You must determine the average methane and ethane 
concentration per run. The samples must be taken during the same time 
as the Method 25A sample.
    (ii) You may subtract the concentration of methane and ethane from 
the Method 25A TOC, as propane, concentration for each run.
    (iii) You must correct the TOC concentration (minus methane and 
ethane, if applicable) 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 ANSI/
ASME 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] TR03JN16.004

Where:

Cc = TOC concentration, as propane, corrected to 3 
percent oxygen, parts per million by volume on a wet basis.
Cm = TOC concentration, as propane, (minus methane and 
ethane, if applicable), parts per million by volume on a wet basis.
%O2m = Concentration of oxygen, percent by volume as 
measured, wet.

    (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).
    (A) A control device whose model is tested under, and meets the 
criteria of paragraph (d) of this section. For centrifugal compressor 
affected facilities, if you do not continuously monitor the gas flow 
rate in accordance with Sec.  60.5417a(d)(1)(viii), then you must 
comply with the periodic performance testing requirements of paragraph 
(b)(5)(ii).
    (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. For centrifugal compressor affected facilities, you 
must establish a limit on temperature in accordance with Sec.  
60.5417a(f) and continuously monitor the temperature as required by 
Sec.  60.5417a(d).
    (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 (d) 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

[[Page 35918]]

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.
    (4) Inlet testing must be conducted as specified in paragraphs 
(d)(4)(i) and (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) and (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 (incorporated by reference as 
specified in Sec.  60.17).
    (B) Hydrogen (H2), carbon monoxide (CO), carbon dioxide 
(CO2), nitrogen (N2), oxygen (O2) 
using ASTM D1945-03 (incorporated by reference as specified in Sec.  
60.17).
    (C) Higher heating value using ASTM D3588-98 or ASTM D4891-89 
(incorporated by reference as specified in Sec.  60.17).
    (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) and (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

[[Page 35919]]

report specified in paragraph (d)(12) of this section. Moisture must be 
determined using Method 4 of appendix A-3 of this part. Traverse both 
ports with the sampling train required by Method 4 of appendix A-3 of 
this part during each test run. Ambient air must not be introduced into 
the integrated bag sample required by Method 3C of appendix A-2 of this 
part during the port change.
    (iii) Excess air must be determined using resultant data from the 
EPA Method 3C tests and EPA Method 3B of appendix A-2 of this part, 
equation 3B-1, or ANSI/ASME PTC 19.10-1981, Part 10 (manual portion 
only) (incorporated by reference as specified in 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,'' (incorporated by 
reference as specified in Sec.  60.17).
    (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] TR03JN16.005

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 manufacturer must demonstrate a destruction efficiency of 
at least 95 percent for THC, as propane. A control device model that 
demonstrates a destruction efficiency of 95 percent for THC, as 
propane, will meet the control requirement for 95 percent destruction 
of VOC and methane (if applicable) required 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) of this section in the test report 
required by this section in accordance with Sec.  60.5420a(b)(10). 
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 Document Control Officer; Office of Air Quality 
Planning and Standards (OAQPS) CBIO Room 521; 109 T.W. Alexander Drive; 
RTP, NC 27711. The same file with the CBI omitted must be submitted to 
[email protected].
    (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 (e) 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 (8) of this section,

[[Page 35920]]

maintaining the records specified in Sec.  60.5420a(c)(2) or (c)(5)(vi) 
and submitting the report specified in Sec.  60.5420a(b)(10).
    (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 
[email protected] 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.
    (8) Operate each control device following the manufacturer's 
written operating instructions, procedures and maintenance schedule to 
ensure good air pollution control practices for minimizing emissions.


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 
affected facilities, 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)(1) and (2) 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, you must demonstrate continuous 
compliance according to paragraph (b)(3) of this section. For each 
centrifugal compressor affected facility, you also must demonstrate 
continuous compliance according to paragraphs (b)(1) and (2) of this 
section.
    (1) You must reduce methane and VOC emissions from the wet seal 
fluid degassing system 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 may 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, 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(a) 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)(1) and you demonstrate compliance 
using the test procedures specified in Sec.  60.5413a(b), or you use a 
flare designed and operated in accordance with Sec.  60.18(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.

[[Page 35921]]

    (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(a), 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(a), 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 reports required by 60.5420a(b)(1) 
and (3) and maintain the records as specified in Sec.  60.5420a(c)(2), 
(6) through (11), and (17), 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 the date of the most recent 
reciprocating compressor rod packing replacement, whichever is later.
    (2) You must submit the annual reports as required in Sec.  
60.5420a(b)(1) and (4) and maintain records as required in Sec.  
60.5420a(c)(3).
    (3) You must replace the reciprocating compressor rod packing on or 
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 cover and 
closed vent requirements in Sec.  60.5416a(a) and (b).
    (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 reports as required in Sec.  
60.5420a(b)(1) and (5).
    (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 VOC emissions as specified in Sec.  
60.5395a(a)(2).
    (ii) For each control device installed to meet the requirements of 
Sec.  60.5395a(a)(2), 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) and (3).
    (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(g).
    (2) You must repair or replace each identified source of fugitive 
emissions as required in Sec.  60.5397a(h).

[[Page 35922]]

    (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)(1) and (7).


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 
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(c)(3)(ii), 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

[[Page 35923]]

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 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 alarm, or 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).

[[Page 35924]]

    (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 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 or centrifugal compressor 
affected facility.
    (a) For each control device used to comply with the emission 
reduction standard for centrifugal compressor affected facilities in 
Sec.  60.5380a(a)(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. If you install 
and operate an enclosed combustion device which is not specifically 
listed in paragraph (d) of this section, you must demonstrate 
continuous compliance according to paragraphs (h)(1) through (h)(4) 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. Heat 
sensing monitoring devices that indicate the continuous ignition of a 
pilot flame are exempt from the calibration, quality assurance and 
quality control requirements in this section.
    (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. Heat sensing monitoring devices that indicate the 
continuous ignition a pilot flame are exempt from the calibration, 
quality assurance and quality control requirements in this section.
    (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(b) 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]Celsius, or 2.5 
[deg]Celsius, 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.

[[Page 35925]]

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]Celsius, or 2.5 [deg]Celsius, 
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. The heat sensing monitoring device is exempt from the 
calibration requirements of this section.
    (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]Celsius, or 2.5 
[deg]Celsius, 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]Celsius, or 2.5 [deg]Celsius, 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]Celsius, or 2.5 [deg]Celsius, 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 paragraphs (d)(1)(viii)(A) and (B) of this section. If 
you comply with the periodic testing requirements of Sec.  
60.5413a(b)(5)(ii), you are not required to continuously monitor the 
gas flow rate under paragraph (d)(1)(viii)(A) 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 at the maximum expected 
flow rate. The flow rate at the inlet to the combustion device must not 
exceed the maximum 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 and data from the 
heat sensing devices that indicate the presence of a pilot flame. 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)(1) or (2). 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)(1) or (2), 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)(2), 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)(1), then your control device inlet gas 
flow rate must not exceed the maximum inlet gas flow rate determined by 
the manufacturer.

[[Page 35926]]

    (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)(2), 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)(2), 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 (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 or when the heat 
sensing device indicates that there is no pilot flame present.
    (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) of this section are met.
    (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 an affected facility that is the group of 
all equipment within a process unit at an onshore natural gas 
processing plant, or a sweetening unit at an onshore natural gas 
processing plant, you must submit

[[Page 35927]]

the notifications required in Sec.  60.7(a)(1), (3), and (4). 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 United 
States 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) 
and (12) of this section and performance test reports as specified in 
paragraph (b)(9) or (10) of this section, if applicable. You must 
submit annual reports following the procedure specified in paragraph 
(b)(11) of this section. 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 (8) 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, facility site name associated with the 
affected facility, US Well ID or US Well ID associated with the 
affected facility, if applicable, and address of the affected facility. 
If an address is not available for the site, include a description of 
the site location and provide the latitude and longitude coordinates of 
the site in decimal degrees to an accuracy and precision of five (5) 
decimals of a degree using the North American Datum of 1983.
    (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) through (iii) of this section.
    (i) Records of each well completion operation as specified in 
paragraphs (c)(1)(i) through (iv) and (vi) of this section, if 
applicable, for each well affected facility conducted during the 
reporting period. In lieu of submitting the records specified in 
paragraph (c)(1)(i) through (iv) of this section, 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.
    (iii) Records specified in paragraph (c)(1)(vii) of this section, 
if applicable, that support a determination under 60.5432a that the 
well affected facility is a low pressure well as defined in 60.5430a.
    (3) For each centrifugal compressor affected facility, the 
information specified in paragraphs (b)(3)(i) through (iv) of this 
section.
    (i) An identification of each centrifugal compressor using a wet 
seal system constructed, modified or reconstructed during the reporting 
period.
    (ii) Records of deviations specified in paragraph (c)(2) of this 
section that occurred during the reporting period.
    (iii) If required to comply with 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 or since the previous reciprocating 
compressor rod packing replacement, whichever is later. Alternatively, 
a statement that emissions from the rod packing are being routed to a 
process through a closed vent system under negative pressure.
    (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.

[[Page 35928]]

    (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 (F) 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 each 
well site and the collection of fugitive emissions components at each 
compressor station within the company-defined area, the records of each 
monitoring survey including the information specified in paragraphs 
(b)(7)(i) through (xii) of this section. For the collection of fugitive 
emissions components at a compressor station, if a monitoring survey is 
waived under Sec.  60.5397a(g)(5), you must include in your annual 
report the fact that a monitoring survey was waived and the calendar 
months that make up the quarterly monitoring period for which the 
monitoring survey was waived.
    (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) Monitoring instrument used.
    (vi) Any deviations from the monitoring plan or a statement that 
there were no deviations from the monitoring plan.
    (vii) Number and type of components for which fugitive emissions 
were detected.
    (viii) Number and type of fugitive emissions components that were 
not repaired as required in Sec.  60.5397a(h).
    (ix) Number and type of difficult-to-monitor and unsafe-to-monitor 
fugitive emission components monitored.
    (x) The date of successful repair of the fugitive emissions 
component.
    (xi) Number and type of fugitive emission components placed on 
delay of repair and explanation for each delay of repair.
    (xii) 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 (iii) of this section.
    (i) For each pneumatic pump that is constructed, modified or 
reconstructed during the reporting period, you must provide 
certification that the pneumatic pump meets one of the conditions 
described in paragraphs (b)(8)(i)(A), (B) or (C) of this section.
    (A) No control device or process is available on site.
    (B) A control device or process is available on site and the owner 
or operator has determined in accordance with Sec.  60.5393a(b)(5) that 
it is technically infeasible to capture and route the emissions to the 
control device or process.
    (C) Emissions from the pneumatic pump are routed to a control 
device or process. If the control device is designed to achieve less 
than 95 percent emissions reduction, specify the percent emissions 
reductions the control device is designed to achieve.
    (ii) For any pneumatic pump affected facility which has been 
previously reported as required under paragraph (b)(8)(i) of this 
section and for which a change in the reported condition has occurred 
during the reporting period, provide the identification of the 
pneumatic pump affected facility and the date it was previously 
reported and a certification that the pneumatic pump meets one of the 
conditions described in paragraphs (b)(8)(ii)(A), (B) or (C) or (D) of 
this section.
    (A) A control device has been added to the location and the 
pneumatic pump now reports according to paragraph (b)(8)(i)(C) of this 
section.
    (B) A control device has been added to the location and the 
pneumatic pump affected facility now reports according to paragraph 
(b)(8)(i)(B) of this section.
    (C) A control device or process has been removed from the location 
or otherwise is no longer available and the pneumatic pump affected 
facility now report according to paragraph (b)(8)(i)(A) of this 
section.
    (D) A control device or process has been removed from the location 
or is otherwise no longer available and the owner or operator has 
determined in accordance with Sec.  60.5393a(b)(5) through an 
engineering evaluation that it is technically infeasible to capture and 
route the emissions to another control device or process.
    (iii) Records of deviations specified in paragraph (c)(16)(ii) of 
this section that occurred 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://www3.epa.gov/ttn/chief/ert/ert_info.html) at the time of the 
test, you must submit the results of the performance test to the EPA 
via the Compliance and Emissions Data Reporting Interface (CEDRI). 
(CEDRI can be accessed through the EPA's Central Data Exchange (CDX) 
(https://cdx.epa.gov/).) Performance 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.

[[Page 35929]]

    (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 [email protected] 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://www3.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. Once the form has been available in CEDRI 
for at least 90 calendar days, you must begin submitting all subsequent 
reports via CEDRI. The reports must be submitted by the deadlines 
specified in this subpart, regardless of the method in which the 
reports are submitted.
    (12) You must submit the certification signed by the qualified 
professional engineer according to Sec.  60.5411a(d) for each closed 
vent system routing to a control device or process.
    (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 (vii) of this section, as applicable. For 
each well affected facility for which you make a claim that the well 
affected facility is not subject to the requirements for well 
completions pursuant to 60.5375a(g), you must maintain the record in 
paragraph (c)(1)(vi), only.
    (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)(3) 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) through (C) 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 United States 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 and disposition of 
recovery (i.e., routed to the gas flow line or collection system, re-
injected into the well or another well, used as an onsite fuel source, 
or used for another useful purpose that a purchased fuel or raw 
material would serve); duration of combustion; duration of venting; and 
specific reasons for venting in lieu of capture or combustion. The 
duration must be specified in hours. In addition, for wells where it is 
technically infeasible to route the recovered gas to any of the four 
options specified in Sec.  60.5375a(a)(1)(ii), you must record the 
reasons for the claim of technical infeasibility with respect to all 
four options provided in that subparagraph, including but not limited 
to; name and location of the nearest gathering line and technical 
considerations preventing routing to this line; capture, reinjection, 
and reuse technologies considered and aspects of gas or equipment 
preventing use of recovered gas as a fuel onsite; and technical 
considerations preventing use of recovered gas for other useful purpose 
that that a purchased fuel or raw material would serve.
    (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.
    (C) For each well affected facility for which you make a claim that 
it meets the criteria of Sec.  60.5375a(a)(1)(iii)(A), you must 
maintain the following:
    (1) Records specified in paragraph (c)(1)(iii)(A) of this section 
except that you do not have to record: 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; duration of 
recovery and disposition of recovery (i.e. routed to the gas flow line 
or collection system, re-injected into the well or another well, used 
as an onsite fuel source, or used for another useful purpose that a 
purchased fuel or raw material would serve.
    (2) If applicable, records that the conditions of Sec.  
60.5375a(1)(iii)(A) are no longer met and that the well completion 
operation has been stopped and a separator installed. The records shall 
include the date and time the well completion operation was stopped and 
the date and time the separator was installed.
    (3) A record of the claim signed by the certifying official that no 
liquids collection is at the well site. The claim must include 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.
    (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 United States 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).
    (vi) For each well affected facility for which you make a claim 
that the well affected facility is not subject to the well completion 
standards according to 60.5375a(g), you must maintain:
    (A) A record of the analysis that was performed in order the make 
that claim, including but not limited to, GOR values for established 
leases and data from wells in the same basin and field;
    (B) The location of the well; the United States Well Number;
    (C) A record of the claim signed by the certifying official. The 
claim must include 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

[[Page 35930]]

document are true, accurate, and complete.
    (vii) For each well affected facility for which you determine 
according to Sec.  60.5432a that it is a low pressure well, a record of 
the determination and supporting inputs and calculations.
    (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 (E) 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 1 minute during any 15 
minute period.
    (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.
    (E) Records of the manufacturer's written operating instructions, 
procedures and maintenance schedule to ensure good air pollution 
control practices for minimizing emissions.
    (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 GPS 
device within the same digital picture, provided the latitude and 
longitude output of the GPS 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 the previous replacement of 
the reciprocating compressor rod packing, whichever is later. 
Alternatively, a statement that emissions from the rod packing are 
being routed to a process through a closed vent system under negative 
pressure.
    (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 (5) 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 1 minute during any 15 
minute period.

[[Page 35931]]

    (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.
    (5) Records of the manufacturer's written operating instructions, 
procedures and maintenance schedule to ensure good air pollution 
control practices for minimizing emissions.
    (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 GPS 
device within the same digital picture, provided the latitude and 
longitude output of the GPS 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 (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 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 
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.  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) 
through (iii) of this section.
    (i) The fugitive emissions monitoring plan as required in Sec.  
60.5397a(b), (c), and (d).
    (ii) The records of each monitoring survey as specified in 
paragraphs (c)(15)(ii)(A) through (I) 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) Monitoring instrument used.
    (E) When optical gas imaging is used to perform the survey, one or 
more digital photographs or videos, captured from the optical gas 
imaging instrument used for conduct of monitoring, 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 file, the digital 
photograph or video may consist of an image of the monitoring survey 
being performed with a separately operating GPS device within the same 
digital picture or video, provided the latitude and longitude output of 
the GPS unit can be clearly read in the digital image.
    (F) Fugitive emissions component identification when Method 21 is 
used to perform the monitoring survey.
    (G) Ambient temperature, sky conditions, and maximum wind speed at 
the time of the survey.
    (H) Any deviations from the monitoring plan or a statement that 
there were no deviations from the monitoring plan.
    (I) Documentation of each fugitive emission, including the 
information specified in paragraphs (c)(15)(ii)(I)(1) through (12) of 
this section.
    (1) Location.
    (2) Any deviations from the monitoring plan or a statement that 
there were no deviations from the monitoring plan.
    (3) Number and type of components for which fugitive emissions were 
detected.
    (4) Number and type of difficult-to-monitor and unsafe-to-monitor 
fugitive emission components monitored.
    (5) Instrument reading of each fugitive emissions component that 
requires repair when Method 21 is used for monitoring.
    (6) Number and type of fugitive emissions components that were not 
repaired as required in Sec.  60.5397a(h).
    (7) Number and type of components that were tagged as a result of 
not being repaired during the monitoring survey when the fugitive 
emissions were initially found as required in Sec.  60.5397a(h)(3)(ii).
    (8) If a fugitive emissions component is not tagged, a digital 
photograph or video of each fugitive emissions component that could not 
be repaired during the monitoring survey when the fugitive emissions 
were initially found as required in Sec.  60.5397a(h)(3)(ii). The 
digital photograph or video must clearly identify the location of the 
component that must be repaired. Any digital photograph or video 
required under this paragraph can also be used to meet the requirements 
under paragraph

[[Page 35932]]

(c)(15)(ii)(E) of this section, as long as the photograph or video is 
taken with the optical gas imaging instrument, includes the date and 
the latitude and longitude are either imbedded or visible in the 
picture.
    (9) Repair methods applied in each attempt to repair the fugitive 
emissions components.
    (10) Number and type of fugitive emission components placed on 
delay of repair and explanation for each delay of repair.
    (11) The date of successful repair of the fugitive emissions 
component.
    (12) Instrumentation used to resurvey a repaired fugitive emissions 
component that could not be repaired during the initial fugitive 
emissions finding.
    (iii) For the collection of fugitive emissions components at a 
compressor station, if a monitoring survey is waived under Sec.  
60.5397a(g)(5), you must maintain records of the average calendar month 
temperature, including the source of the information, for each calendar 
month of the quarterly monitoring period for which the monitoring 
survey was waived.
    (16) For each pneumatic pump affected facility, you must maintain 
the records identified in paragraphs (c)(16)(i) through (v) 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 on the control device used for control of emissions 
from a pneumatic pump including the installation date, manufacturer's 
specifications, and if the control device is designed to achieve less 
than 95 percent emission reduction, a design evaluation or 
manufacturer's specifications indicating the percentage reduction 
achieved the control device is designed to achieve.
    (iv) Records substantiating a claim according to Sec.  
60.5393a(b)(5) that it is technically infeasible to capture and route 
emissions from a pneumatic pump to a control device or process; 
including the qualified professional engineer certification according 
to Sec.  60.5393a(b)(5)(ii)and the records of the engineering 
assessment of technical infeasibility performed according to Sec.  
60.5393a(b)(5)(iii).
    (v) You must retain copies of all certifications, engineering 
assessments and related records for a period of five years and make 
them available if directed by the implementing agency.
    (17) For each closed vent system routing to a control device or 
process, the records of the assessment conducted according to Sec.  
60.5411a(d):
    (i) A copy of the assessment conducted according to Sec.  
60.5411a(d)(1);
    (ii) A copy of the certification according to Sec.  
60.5411a(d)(1)(i); and
    (iii) The owner or operator shall retain copies of all 
certifications, assessments and any related records for a period of 
five years, and make them available if directed by the delegated 
authority.


Sec.  60.5421a  What are my additional recordkeeping requirements for 
my affected facility subject to GHG 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).
    (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 
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 GHG 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://www3.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. Once the form has been available in CEDRI for at least 90 days, 
you must begin submitting all subsequent reports via 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).

[[Page 35933]]

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://www3.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. Once the 
form has been available in CEDRI for at least 90 days, you must begin 
submitting all subsequent reports via 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.
    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.
    Artificial lift equipment means mechanical pumps including, but not 
limited to, rod pumps and electric submersible pumps used to flowback 
fluids from a well.
    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

[[Page 35934]]

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.
    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. 
Completion combustion devices include pit flares.
    Compressor station 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. The combination of one or more 
compressors located at a well site, or located at an onshore natural 
gas processing plant, is not a compressor station for purposes of Sec.  
60.5397a.
    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 or 
any other forms of transportation; and
    (2) Natural gas production, processing, transmission, and storage, 
which include the well and extend to, but do not include, the local 
distribution company custody transfer station.
    Custody transfer means the transfer of crude oil or 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).
    Delineation well means a well drilled in order to determine the 
boundary of a field or producing reservoir.
    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.
    Equipment, as used in the standards and requirements in this 
subpart relative to the equipment leaks of GHG (in the form 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 or a mainline pipeline.
    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, including but not limited to valves, connectors, 
pressure relief devices, open-ended lines, flanges, covers and closed 
vent systems not subject to Sec.  60.5411a, thief hatches or other 
openings on a controlled storage vessel not subject to Sec.  60.5395a, 
compressors, 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 thief hatch on a controlled storage vessel, 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.
    Gas to oil ratio (GOR) means the ratio of the volume of gas at 
standard temperature and pressure that is produced from a volume of oil 
when depressurized to standard temperature and pressure.
    Greenfield site means a site, other than a natural gas processing 
plant, which is entirely new construction. Natural gas processing 
plants are not considered to be greenfield sites, even if they are 
entirely new construction.
    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

[[Page 35935]]

that meets the conditions specified in Sec.  60.485a(e) or Sec.  
60.5401a(f)(2).
    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.
    Liquid collection system means tankage and/or lines at a well site 
to contain liquids from one or more wells or to convey liquids to 
another site.
    Local distribution company (LDC) custody transfer station means a 
metering station where the LDC receives a natural gas supply from an 
upstream supplier, which may be an interstate transmission pipeline or 
a local natural gas producer, for delivery to customers through the 
LDC's intrastate transmission or distribution lines.
    Low pressure well means a well that satisfies at least one of the 
following conditions:
    (1) The static pressure at the wellhead following fracturing but 
prior to the onset of flowback is less than the flow line pressure at 
the sales meter;
    (2) The pressure of flowback fluid immediately before it enters the 
flow line, as determined under Sec.  60.5432a, is less than the flow 
line pressure at the sales meter; or
    (3) Flowback of the fracture fluids will not occur without the use 
of artificial lift equipment.
    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 diaphragm pump means a positive displacement 
pump powered by pressurized natural gas that uses the reciprocating 
action of flexible diaphragms in conjunction with check valves to pump 
a fluid. A pump in which a fluid is displaced by a piston driven by a 
diaphragm is not considered a diaphragm pump for purposes of this 
subpart. A lean glycol circulation pump that relies on energy exchange 
with the rich glycol from the contactor is not considered a diaphragm 
pump.
    Natural gas-driven pneumatic controller means a pneumatic 
controller 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.
    Qualified Professional Engineer means an individual who is licensed 
by a state as a Professional Engineer to practice one or more 
disciplines of engineering and who is qualified by education, technical 
knowledge and experience to make the specific technical certifications 
required under this subpart. Professional engineers making these 
certifications must be currently licensed in at least one state in 
which the certifying official is located.
    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, or other 
mechanism that provides the same function.
    Recovered gas means gas recovered through the separation process 
during flowback.
    Recovered liquids means any crude oil, condensate or produced water 
recovered through the separation process during flowback.
    Reduced emissions completion means a well completion following 
fracturing or refracturing where gas flowback that is otherwise vented 
is captured, cleaned, and routed to the gas flow line or collection 
system, re-injected into the well or another well, used as an onsite 
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).
    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.

[[Page 35936]]

    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 
that is operational 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)(1) 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 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 surface sites that are constructed for 
the drilling and subsequent operation of any oil well, natural gas 
well, or injection well. For purposes of the fugitive emissions 
standards at Sec.  60.5397a, well site also means a separate tank 
battery surface site 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.  60.5432a  How do I determine whether a well is a low pressure 
well using the low pressure well equation?

    (a) To determine that your well is a low pressure well subject to 
Sec.  60.5375a(f), you must determine whether the characteristics of 
the well are such that the well meets the definition of low pressure 
well in Sec.  60.5430a. To determine that the well meets the definition 
of low pressure well in Sec.  60.5430a, you must use the low pressure 
well equation below:
[GRAPHIC] [TIFF OMITTED] TR03JN16.006



[[Page 35937]]


Where:

(1) PL is the pressure of flowback fluid immediately before it 
enters the flow line, expressed in pounds force per square inch 
(psia), and is to be calculated using the equation above;
(2) PR is the pressure of the reservoir containing oil, gas, and 
water at the well site, expressed in psia;
(3) Lis the true vertical depth of the well, expressed in feet (ft);
(4) qo is the flow rate of oil in the well, expressed in cubic feet/
second (cu ft/sec);
(5) qg is the flow rate of gas in the well, expressed in cu ft/sec;
(6) qw is the flow rate of water in the well, expressed in cu ft/
sec;
(7) [rho]o is the density of oil in the well, expressed in pounds 
mass per cubic feet (lbm/cu ft).
    (b) You must determine the four values in paragraphs (a)(4) 
through (7) of this section, using the calculations in paragraphs 
(b)(1) through (b)(15) of this section.

    (1) Determine the value of the bottom hole pressure, PBH (psia), 
based on available information at the well site, or by calculating it 
using the reservoir pressure, PR (psia), in the following equation:
[GRAPHIC] [TIFF OMITTED] TR03JN16.007

    (2) Determine the value of the bottom hole temperature, TBH (F), 
based on available information at the well site, or by calculating it 
using the true vertical depth of the well, L (ft), in the following 
equation:

TBH (F) = (0.014 x L) + 79.081

    (3) Calculate the value of the applicable natural gas specific 
gravity that would result from a separator pressure of 100 psig, 
[gamma]gs, using the following equation with: Separator at standard 
conditions (pressure, p = 14.7 (psia), temperature, T = 60 (F)); the 
oil API gravity at the well site, [gamma]0; and the gas 
specific gravity at the separator under standard conditions, [gamma]gp 
= 0.75:
[GRAPHIC] [TIFF OMITTED] TR03JN16.008

    (4) Calculate the value of the applicable dissolved GOR, Rs (scf/
STBO), using the following equation with: The bottom hole pressure, PBH 
(psia), determined in (b)(1) of this section; the bottom hole 
temperature, TBH (F), determined in (b)(2) of this section; the gas 
gravity at separator pressure of 100 psig, [gamma]gs, calculated in 
(b)(3) of this section; the oil API gravity, [gamma]o, at the well 
site; and the constants, C1, C2, and C3, found in Table A:
[GRAPHIC] [TIFF OMITTED] TR03JN16.009


            Table A--Coefficients for the correlation for Rs
------------------------------------------------------------------------
                                                  [gamma]API  [gamma]API
                    Constant                         <= 30       > 30
------------------------------------------------------------------------
C1..............................................      0.0362      0.0178
C2..............................................      1.0937      1.1870
C3..............................................     25.7240      23.931
------------------------------------------------------------------------

    (5) Calculate the value of the oil formation volume factor, Bo 
(bbl/STBO), using the following equation with: the bottom hole 
temperature, TBH (F), determined in paragraph (b)(2) of this section; 
the gas gravity at separator pressure of 100 psig, [gamma]gs, 
calculated in paragraph (b)(3) of this section; the dissolved GOR, Rs 
(scf/STBO), calculated in paragraph (b)(4) of this section; the oil API 
gravity, [gamma]o, at the well site; and the constants, C1, C2, and C3, 
found in Table B:
[GRAPHIC] [TIFF OMITTED] TR03JN16.010


                                Table B--Coefficients for the Correlation for Bo
----------------------------------------------------------------------------------------------------------------
                           Constant                                 [gamma]API <= 30         [gamma]API > 30
----------------------------------------------------------------------------------------------------------------
C1............................................................            4.677 x 10 -4            4.670 x 10 -4
C2............................................................            1.751 x 10 -5            1.100 x 10 -5
C3............................................................           -1.811 x 10 -8            1.337 x 10 -9
----------------------------------------------------------------------------------------------------------------


[[Page 35938]]

[GRAPHIC] [TIFF OMITTED] TR03JN16.011


[[Page 35939]]

[GRAPHIC] [TIFF OMITTED] TR03JN16.012

    (10) Calculate the critical pressure, Pc (psia), and 
critical temperature, Tc (R), using the equations below 
with: Gas gravity at standard conditions (pressure, P = 14.7 (psia), 
temperature, T = 60 (F)), [gamma] = 0.75; and where the mole fractions 
of nitrogen, carbon dioxide and hydrogen sulfide in the gas are XN2 = 
0.168225, XCO2 = 0.013163, and XH2S = 0.013680, respectively:

Pc(psia) = 678 - 50 [middot] ([gamma]g - 0.5) - 206.7 [middot] XN2 + 
440 [middot] XCO2 + 606.7 [middot] XH2S
Tc(R) = 326 + 315.7 [middot] ([gamma]g - 0.5) - 240 [middot] XN2 - 88.3 
[middot] XCO2 + 133.3 [middot] XH2S
    (11) Calculate reduced pressure, Pr, and reduced 
temperature, Tr, using the following equations with: the 
bottom hole pressure, PBH, as determined in paragraph (b)(1) of this 
section; the bottom hole temperature, TBH (F), as determined in 
paragraph (b)(2) of this section in the following equations:
[GRAPHIC] [TIFF OMITTED] TR03JN16.013

    (12)(i) Calculate the gas compressibility factor, Z, using the 
following equation with the reduced pressure, Pr, calculated 
in paragraph (b)(11) of this section:
[GRAPHIC] [TIFF OMITTED] TR03JN16.014

    (ii) The values for A, B, C, D in the above equation, are 
calculated using the following equations with the reduced pressure, 
Pr, and reduced temperature, Tr, calculated in 
paragraph (b)(11) of this section:

[[Page 35940]]

[GRAPHIC] [TIFF OMITTED] TR03JN16.015

    (15) Calculate the flow rate of water in the well, qw (cu ft/sec), 
using the following equation with the water production rate Qw (bbl/
day) at the well site:
[GRAPHIC] [TIFF OMITTED] TR03JN16.016

    Sec. Sec.  60.5433a-60.5499a [Reserved]

[[Page 35941]]



      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), %   -----------------------------------------------------------------------------
                                     2.0 < X < 5.0      5.0 < X < 15.0       15.0 < X < 300.0       X > 300.0
----------------------------------------------------------------------------------------------------------------
Y > 50............................            79.0        88.51X0.0101Y0.0125 or 99.9, whichever is smaller.
----------------------------------------------------------------------------------------------------------------
20 < Y < 50.......................            79.0    88.51X0.0101Y0.0125 or 97.9, whichever is            97.9
                                                                       smaller
----------------------------------------------------------------------------------------------------------------
10 < Y < 20.......................            79.0   88.51X0.0101Y0.0125           93.5                    93.5
                                                      or 93.5, whichever
                                                      is smaller.
----------------------------------------------------------------------------------------------------------------
Y < 10............................            79.0           79.0                  79.0                    79.0
----------------------------------------------------------------------------------------------------------------


          Table 2 to Subpart OOOOa of Part 60--Required Minimum SO2 Emission Reduction Efficiency (Zc)
----------------------------------------------------------------------------------------------------------------
                                                             Sulfur feed rate (X), LT/D
  H2S content of acid gas (Y), %   -----------------------------------------------------------------------------
                                     2.0 < X < 5.0      5.0 < X < 15.0       15.0 < X < 300.0       X > 300.0
----------------------------------------------------------------------------------------------------------------
Y > 50............................            74.0        85.35X0.0144Y0.0128 or 99.9, whichever is smaller.
----------------------------------------------------------------------------------------------------------------
20 < Y < 50.......................            74.0    85.35X0.0144Y0.0128 or 97.5, whichever is            97.5
                                                                       smaller
----------------------------------------------------------------------------------------------------------------
10 < Y < 20.......................            74.0   85.35X0.0144Y0.0128           90.8                    90.8
                                                      or 90.8, whichever
                                                      is smaller.
----------------------------------------------------------------------------------------------------------------
Y < 10............................            74.0           74.0                  74.0                    74.0
----------------------------------------------------------------------------------------------------------------

    X = The sulfur feed rate from the sweetening unit (i.e., the 
H2S in the acid gas), expressed as sulfur, Mg/D(LT/D), 
rounded to one decimal place.
    Y = The sulfur content of the acid gas from the sweetening unit, 
expressed as mole percent H2S (dry basis) rounded to one 
decimal place.
    Z = The minimum required sulfur dioxide (SO2) emission 
reduction efficiency, expressed as percent carried to one decimal 
place. Zi refers to the reduction efficiency required at the 
initial performance test. Zc refers to the reduction 
efficiency required on a continuous basis after compliance with 
Zi has been demonstrated.
    As stated in Sec.  60.5425a, you must comply with the following 
applicable General Provisions:

            Table 3 to Subpart OOOOa of Part 60--Applicability of General Provisions to Subpart OOOOa
----------------------------------------------------------------------------------------------------------------
   General provisions  citation      Subject of citation         Applies to subpart?            Explanation
----------------------------------------------------------------------------------------------------------------
Sec.   60.1.......................  General applicability  Yes
                                     of the General
                                     Provisions.
Sec.   60.2.......................  Definitions..........  Yes...........................  Additional terms
                                                                                            defined in Sec.
                                                                                            60.5430a.
Sec.   60.3.......................  Units and              Yes
                                     abbreviations.
Sec.   60.4.......................  Address..............  Yes
Sec.   60.5.......................  Determination of       Yes
                                     construction or
                                     modification.
Sec.   60.6.......................  Review of plans......  Yes
Sec.   60.7.......................  Notification and       Yes...........................  Except that Sec.
                                     record keeping.                                        60.7 only applies as
                                                                                            specified in Sec.
                                                                                            60.5420a(a).
Sec.   60.8.......................  Performance tests....  Yes...........................  Performance testing
                                                                                            is required for
                                                                                            control devices used
                                                                                            on storage vessels,
                                                                                            centrifugal
                                                                                            compressors and
                                                                                            pneumatic pumps.
Sec.   60.9.......................  Availability of        Yes
                                     information.
Sec.   60.10......................  State authority......  Yes
Sec.   60.11......................  Compliance with        No............................  Requirements are
                                     standards and                                          specified in subpart
                                     maintenance                                            OOOOa.
                                     requirements.
Sec.   60.12......................  Circumvention........  Yes
Sec.   60.13......................  Monitoring             Yes...........................  Continuous monitors
                                     requirements.                                          are required for
                                                                                            storage vessels.
Sec.   60.14......................  Modification.........  Yes...........................  To the extent any
                                                                                            provision in Sec.
                                                                                            60.14 conflicts with
                                                                                            specific provisions
                                                                                            in subpart OOOOa, it
                                                                                            is superseded by
                                                                                            subpart OOOOa
                                                                                            provisions.
Sec.   60.15......................  Reconstruction.......  Yes...........................  Except that Sec.
                                                                                            60.15(d) does not
                                                                                            apply to wells,
                                                                                            pneumatic
                                                                                            controllers,
                                                                                            pneumatic pumps,
                                                                                            centrifugal
                                                                                            compressors,
                                                                                            reciprocating
                                                                                            compressors or
                                                                                            storage vessels.
Sec.   60.16......................  Priority list........  Yes
Sec.   60.17......................  Incorporations by      Yes
                                     reference.
Sec.   60.18......................  General control        Yes
                                     device and work
                                     practice
                                     requirements.

[[Page 35942]]

 
Sec.   60.19......................  General notification   Yes
                                     and reporting
                                     requirement.
----------------------------------------------------------------------------------------------------------------

[FR Doc. 2016-11971 Filed 6-2-16; 8:45 am]
 BILLING CODE 6560-50-P