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
proposed 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
in the 2016 NSPS OOOOa RIA. For the proposed reconsideration, the EPA
expects there will be slight reductions in the labor required for
compliance-related activities associated with the 2016 NSPS OOOOa
requirements relating to fugitive emissions and inspections of closed
vent systems. However, due to uncertainties associated with how the
proposed reconsideration will influence the portfolio of activities
associated with fugitive emissions-related requirements, the EPA is
unable to provide quantitative estimates of compliance-related labor
changes.

E. What are the forgone benefits of the proposed standards?

    The EPA estimated the forgone domestic climate benefits from the
methane emissions associated with this reconsideration using an interim
measure of the domestic social cost of methane (SC-CH4). The
SC-CH4 estimates used here were developed under E.O. 13783
for use in regulatory analyses until an improved estimate of the
impacts of climate change to the U.S. can be developed based on the
best available science and economics. E.O. 13783 directed agencies to
ensure that estimates of the social cost of greenhouse gases used in
regulatory analyses ``are based on the best available science and
economics'' and are consistent with the guidance contained in OMB
Circular A-4, ``including with respect to the consideration of domestic
versus international impacts and the consideration of appropriate
discount rates'' (E.O. 13783, Section 5(c)). In addition, E.O. 13783
withdrew the technical support documents (TSDs) and the August 2016
Addendum to these TSDs describing the global social cost of greenhouse
gas estimates developed under the prior Administration as no longer
representative of government policy. The withdrawn TSDs and Addendum
were developed by an interagency working group (IWG) that included the
EPA and other executive branch entities and were used in the 2016 NSPS
RIA.
    The forgone benefits of the proposed reconsideration are estimated
based on semiannual monitoring at compressor stations and are in
comparison to an updated baseline with the 2016 NSPS OOOOa and the
March 12, 2018 amendments with respect to the Alaskan North Slope in
place.\125\ The EPA estimates the PV of the forgone domestic climate
benefits over 2019-2025, discounted back to 2016, will be $13.5 million
under a 7 percent discount rate and $54 million under a 3 percent
discount rate. The EAV of these forgone benefits is $2.3 million per
year under a 7 percent discount rate and $8.3 million per year under a
3 percent discount rate. These values represent only a partial
accounting of domestic climate impacts from methane emissions, and do
not account for health effects of ozone exposure from the increase in
methane emissions.
---------------------------------------------------------------------------

    \125\ While the EPA is co-proposing annual monitoring for
compressor stations, this discussion of forgone benefits is limited
to the proposal of semiannual monitoring for compressor stations.
For additional information regarding the cost savings and forgone
emission reductions, see section 2 of the RIA.
---------------------------------------------------------------------------

    The EPA expects that the forgone VOC emission reductions may
degrade air quality and adversely affect health and welfare effects
associated with exposure to ozone, PM2.5, and HAP, however
data limitations prevent us from quantifying forgone VOC-related health
benefits. This omission should not imply that these forgone benefits
may not exist; rather, it reflects the difficulties in modeling the
direct and indirect impacts of the reductions in emissions for this
industrial sector with the data currently available. As described in
the RIA, with these data currently unavailable, we are unable to
estimate forgone health benefits estimates for this rule 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.

IX. 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 OMB for review. Any changes made in response to
OMB recommendations have been documented in the docket. The EPA
prepared an analysis of the potential costs and benefits associated
with this action. This Regulatory Impact Analysis (RIA) is available in
the docket. The RIA describes in detail the empirical basis for the
EPA's assumptions and characterizes the various sources of
uncertainties affecting the estimates below. Table 4 shows the present
value and equivalent annualized value results of the cost and benefits
analysis for the proposed rule, assuming semiannual monitoring at
compressor stations, for 2019 through 2025, discounted back to 2016
using a discount rate of 7 percent. The table also shows the total
increase in emissions from 2019 through 2025 from this proposed
reconsideration. When discussing net benefits, we modify the relevant
terminology to be more consistent with traditional net benefits
analysis. In the following table, we refer to the cost savings as
presented in section 2 of the RIA, and in section VIII.C, above, as the
``benefits'' of this proposed action and the forgone benefits as
presented in section 3 of the RIA, and in section VIII.E, above, as the
``costs'' of this proposed action. The net benefits are the benefits
(cost savings) minus the costs (forgone benefits).

Table 4--Summary of the Present Value and Equivalent Annualized Value of
  the Monetized Forgone Benefits, Cost Savings and Net Benefits of the
   Proposed Oil and Natural Gas Reconsideration From 2019 Through 2025
                           [Millions of 2016$]
------------------------------------------------------------------------
                                                          Equivalent
                                     Present value     annualized value
------------------------------------------------------------------------
Benefits (Total Cost Savings)...  $380 million......  $66 million.
Costs (Forgone Domestic Climate   $13.5 million.....  $2.3 million.
 Benefits).
                                 ---------------------------------------
    Net Benefits................  $367 million......  $64 million.
------------------------------------------------------------------------
Non-monetized Forgone Benefits..  Non-monetized climate impacts from
                                   increases in methane emissions.
                                  Health effects of PM2.5 and ozone
                                   exposure from an increase of 100,000
                                   tons of VOC from 2019 through 2025.
                                  Health effects of HAP exposure from an
                                   increase of 3,800 tons of HAP from
                                   2019 through 2025.
                                  Health effects of ozone exposure from
                                   an increase of 380,000 short tons of
                                   methane from 2019 through 2025.
                                  Visibility impairment.
                                  Vegetation effects.
------------------------------------------------------------------------
Estimates may not sum due to independent rounding.

B. Executive Order 13771: Reducing Regulations and Controlling
Regulatory Costs

    This action is expected to be an Executive Order 13771 deregulatory
action. Details on the estimated cost savings of this proposed rule can
be found in the EPA's analysis of the potential costs and benefits
associated with this action.

C. Paperwork Reduction Act (PRA)

    A summary of the information collection activities submitted to the
OMB for the final action titled, ``Standards of Performance for Crude
Oil and Natural Gas Facilities for Construction, Modification, or
Reconstruction'' (2016 NSPS OOOOa) under the PRA, and assigned EPA ICR
Number 2523.02, can be found at 81 FR 35890. You can find a copy of the
ICR in the 2016 NSPS OOOOa docket (EPA-HQ-OAR-2010-0505-7626). This
proposed reconsideration revises the information collection activities
of 2016 NSPS OOOOa. The revised information collection activities in
this proposed rule have been submitted for approval to OMB under the
PRA. The revised ICR document that the EPA prepared has been assigned
EPA ICR number 2523.03. You can find a copy of the revised ICR in the
docket for this rule.
    The proposed changes to the 2016 NSPS OOOOa information collection
activities would reduce the burden on the regulated industry associated
with reporting and recordkeeping requirements. Proposed amendments to
the reporting and recordkeeping requirements are presented in section
60.5420a. Other information collection activity reductions would result
from proposed amendments that streamline and align monitoring
requirements (and associated recordkeeping) in the rule.
    The estimated average annual burden (averaged over the first 3
years after the effective date of the standards) for the recordkeeping
and reporting requirements associated with the proposed amendments to
subpart OOOOa for the estimated 2,893 owners and operators subject to
the rule is 156,188 labor hours, with an average annual cost of
$9,615,691 (2016$) over the three-year period. The information
collection activities associated with the proposed amendments would
result in an estimated average annual burden reduction of 8 percent
compared to the previously-submitted 2016 NSPS OOOOa ICR (2016$).
    An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for the
EPA's regulations in 40 CFR are listed in 40 CFR part 9.
    Submit your comments on the Agency's need for this information, the
accuracy of the provided revised burden estimates and any suggested
methods for minimizing respondent burden to the EPA using the docket
identified at the beginning of this rule. You may also send your ICR-
related comments to OMB's Office of Information and Regulatory Affairs
via email to [email protected], Attention: Desk Officer for
the EPA. Since OMB is required to make a decision concerning the ICR
between 30 and 60 days after receipt, OMB must receive comments no
later than November 14, 2018. The EPA will respond to any ICR-related
comments in the final rule.

D. Regulatory Flexibility Act (RFA)

    I certify that this action will not have a significant economic
impact on a substantial number of small entities under the RFA. In
making this determination, the impact of concern is any significant
adverse economic impact on small entities. An agency may certify that a
rule will not have a significant economic impact on a substantial
number of small entities if the rule relieves regulatory burden, has no
net burden or otherwise has a positive economic effect on the small
entities subject to the rule. This is a deregulatory action, and the
burden on all entities affected by this proposed rule, including small
entities, is reduced compared to the 2016 NSPS OOOOa. See the RIA for
details. We have therefore concluded that this action will relieve
regulatory burden for all directly regulated small entities.

E. Unfunded Mandates Reform Act of 1995 (UMRA)

    This action does not contain any unfunded mandate as described in
UMRA, 2 U.S.C. 1531-1538, and does not significantly or uniquely affect
small governments. The action imposes no enforceable duty on any state,
local or tribal governments or the private sector.

F. 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. This rule,
if finalized, would primarily affect private industry and would not
impose

significant economic costs on state or local governments.

G. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments

    This action does not have tribal implications, as specified in
Executive Order 13175. It will not have substantial direct effects on
tribal governments, on the relationship between the federal government
and Indian tribes, or on the distribution of power and responsibilities
between the federal government and Indian tribes, as specified in
Executive Order 13175. Thus, Executive Order 13175 does not apply to
this action.

H. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks

    This action is not subject to Executive Order 13045 because the EPA
does not believe the environmental health risks or safety risks
addressed by this action present a disproportionate risk to children.
The 2016 NSPS OOOOa, as discussed in the RIA,\126\ was anticipated to
reduce emissions of methane, VOC, and HAPs, and some of the benefits of
reducing these pollutants would have accrued to children. However, new
data and analysis have affected expectations about the extent of the
impact of the fugitive emissions program in the 2016 NSPS OOOOa on
these benefits. For example, as previously discussed above in section
VI.B.1. of this preamble, the EPA reviewed data provided by the
petitioners, as well as other data that have become available since
promulgation of the 2016 NSPS OOOOa. The EPA identified several areas
of our analysis that raise concerns we have overestimated the emission
reductions and, therefore, the cost effectiveness of the 2016 NSPS
OOOOa fugitive emissions program. Based on this review, the EPA updated
the model plants for non-low production well sites, re-examined the
fugitive emissions estimation method for non-low production well sites
and compressor stations, and recognized distinct operational
characteristics of compressor stations. Furthermore, while the proposed
amendment is expected to decrease the impact of the fugitive emissions
program in the 2016 NSPS OOOOa on these benefits, as discussed in
Chapter 1 of the RIA, the potential decrease in emission reduction (and
thus the benefit) from the proposed amendment is minimal compared to
the overall emission reduction that would continue to be achieved under
the amended 40 CFR part 60, subpart OOOOa.
---------------------------------------------------------------------------

    \126\ See Chapter 4, ``Economic Impact Analysis and
Distributional Assessments,'' of the RIA.
---------------------------------------------------------------------------

    Moreover, the proposed action does not affect the level of public
health and environmental protection already being provided by existing
NAAQS and other mechanisms in the CAA. This proposed action does not
affect applicable local, state, or federal permitting or air quality
management programs that will continue to address areas with degraded
air quality and maintain the air quality in areas meeting current
standards. Areas that need to reduce criteria air pollution to meet the
NAAQS will still need to rely on control strategies to reduce
emissions. For the reasons stated above, we do not believe this small
decrease in emission reduction from this action will have a
disproportionate adverse effect on children's health.

I. Executive Order 13211: Actions Concerning Regulations That
Significantly Affect Energy Supply, Distribution, or Use

    This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution, or use of energy. The basis for this determination can be
found in the 2016 NSPS OOOOa (81 FR 35894).

J. National Technology Transfer and Advancement Act (NTTAA)

    This action involves technical standards.\127\ Therefore, the EPA
conducted searches for the Oil and Natural Gas Sector: Emission
Standards for New, Reconstructed, and Modified Sources Reconsideration
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.
---------------------------------------------------------------------------

    \127\ These proposed technical standards are the same as those
previously finalized at 40 CFR part 60, subpart OOOOa (81 FR 35824).
2016 NSPS OOOOa also previously incorporated by reference 10
technical standards. The incorporation by reference remains
unchanged in this proposed action. See Docket ID Nos. EPA-HQ-OAR-
2010-0505-7657 and EPA-HQ-OAR-2010-0505-7658.
---------------------------------------------------------------------------

    Two VCS were identified as an acceptable alternative to the 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 the 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 memorandum
Voluntary Consensus Standard Results for Oil and Natural Gas Sector:
Emission Standards for New, Reconstructed, and Modified Sources
Reconsideration, located at Docket ID No. EPA-HQ-OAR-2017-0483.

K. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations

    The EPA believes that this proposed action is unlikely to have
disproportionately high and adverse human health or environmental
effects on minority populations, low-income populations and/or
indigenous peoples as specified in Executive Order 12898 (59 FR 7629,
February 16, 1994). The 2016 NSPS OOOOa was anticipated to reduce
emissions of methane, VOC, and HAPs, and some of the benefits of
reducing these pollutants would have accrued to minority populations,
low-income populations and/or indigenous peoples. However, new data and
analysis have affected expectations about the extent of the impact of
the fugitive emissions program in the 2016 NSPS OOOOa on these
benefits. For example, as previously discussed above in section VI.B.1.
of this preamble, the EPA reviewed data provided by the petitioners, as
well as other data that have become available since promulgation of the
2016 NSPS OOOOa.

The EPA identified several areas of our analysis that raise concerns we
have overestimated the emission reductions and, therefore, the cost
effectiveness of the 2016 NSPS OOOOa fugitive emissions program. Based
on this review, the EPA updated the model plants for non-low production
well sites, re-examined fugitive emissions from low production well
sites, recognized the limitations in our emissions estimation method
for non-low production well sites and compressor stations, and
recognized distinct operational characteristics of compressor stations.
Furthermore, while these communities may experience forgone benefits as
a result of this action, as discussed in Chapter 1 of the RIA, the
potential foregone emission reductions (and related benefits) from the
proposed amendments is minimal compared to the overall emission
reductions (and related benefits) from the 2016 NSPS.
    Moreover, the proposed action does not affect the level of public
health and environmental protection already being provided by existing
NAAQS and other mechanisms in the CAA. This proposed action does not
affect applicable local, state, or federal permitting or air quality
management programs that will continue to address areas with degraded
air quality and maintain the air quality in areas meeting current
standards. Areas that need to reduce criteria air pollution to meet the
NAAQS will still need to rely on control strategies to reduce
emissions.
    For the reasons stated above, the EPA believes that this proposed
action is unlikely to have disproportionately high and adverse human
health or environmental effects on minority populations, low-income
populations and/or indigenous peoples. We note that the potential
impacts of this proposed action are not expected to be experienced
uniformly, and the distribution of avoided compliance costs associated
with this action depends on the degree to which costs would have been
passed through to consumers.

List of Subjects in 40 CFR Part 60

    Environmental protection, Administrative practice and procedure,
Air pollution control, Reporting and recordkeeping.

    Dated: September 11, 2018.
Andrew R. Wheeler,
Acting Administrator.

    For the reasons set out in the preamble, title 40, chapter I of the
Code of Federal Regulations is proposed to be amended as follows:

PART 60--STANDARDS OF PERFORMANCE FOR NEW STATIONARY SOURCES

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

    Authority: 42 U.S.C. 7401, et seq.

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

0
2. Section 60.5365a is amended by revising paragraph (e) introductory
text and adding paragraph (i)(4) to read as follows:

Sec.  60.5365a  Am I subject to this subpart?

* * * * *
    (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, based on the maximum average daily throughput,
as defined in Sec.  60.5430a, 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.
* * * * *
    (i) * * *
    (4) For purposes of Sec.  60.5397a, a ``modification'' to a
separate tank battery occurs when:
    (i) Any of the actions in paragraphs Sec.  60.5365a(i)(3)(i)
through (iii) occurs at an existing separate tank battery;
    (ii) A well sending production to an existing separate tank battery
is modified, as defined in Sec.  60.5365a(i)(3)(i) through (iii); or
    (iii) A well site subject to the requirements in Sec.  60.5397a
removes all major production and processing equipment, as defined in
Sec.  60.5430a, such that it becomes a wellhead only well site and
sends production to an existing separate tank battery.
* * * * *
0
3. Section 60.5375a is amended by revising paragraph (a)(1)(iii)
introductory text and paragraph (f)(3)(ii) and adding paragraph (f)(4)
to read as follows:

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

* * * * *
    (a) * * *
    (1) * * *
    (iii) You must have a separator onsite or otherwise available for
use at a centralized facility or well pad that services the well
affected facility which is used to conduct the completion of the well
affected facility. The separator must be available and ready to be used
to comply with paragraph (a)(1)(ii) of this section during the entirety
of the flowback period, except as provided in paragraphs (a)(1)(iii)(A)
through (C) of this section.
* * * * *
    (f) * * *
    (3) * * *
    (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 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.
* * * * *
0
4. Section 60.5385a is amended by revising paragraph (a)(1) to read as
follows:

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

* * * * *
    (a) * * *
    (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, August 2, 2016, or the date of the most recent reciprocating
compressor rod packing replacement, whichever is later.
* * * * *
0
5. Section 60.5393a is amended by:

0
a. Revising paragraph (b) introductory text and paragraphs (b)(3),
(b)(5), (b)(6) and (c);
0
b. Removing and reserving paragraphs (b)(1), (b)(2), and (f).
    The revisions read as follows:

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

* * * * *
    (b) For each pneumatic pump affected facility at a well site you
must reduce natural gas emissions by 95.0 percent, except as provided
in paragraphs (b)(3), (4) and (5) of this section.
    (1) [Reserved]
    (2) [Reserved]
    (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) 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)(3)(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.
* * * * *
    (5) If an owner or operator 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 an in-house engineer or a
qualified professional engineer in accordance with paragraph (b)(5)(ii)
of this section.
    (ii) The following certification, signed and dated by the in-house
engineer or 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 in-house engineer or 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) 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(c) and (d).
* * * * *
    (f) [Reserved]
0
6. Section 60.5397a is amended by:
0
a. Revising paragraph (a);
0
b. Revising paragraphs (c)(2);
0
c. Revising paragraph (c)(8) introductory text;
0
d. Adding paragraph (c)(8)(iii);
0
e. Revising paragraph (d);
0
f. Revising paragraph (f)(2);
0
g. Revising paragraph (g) introductory text;
0
h. Revising paragraphs (g)(1) and (2);
0
i. Removing and reserving paragraph (g)(5);
0
j. Adding paragraph (g)(6); and
0
k. Revising paragraph (h).
    The revisions and additions read as follows:

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?

* * * * *
    (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 of Appendix A-7 to this
part.
* * * * *
    (c) * * *
    (2) Technique for determining fugitive emissions (i.e., Method 21
of Appendix A-7 to this part or optical gas imaging meeting the
requirements in paragraphs (c)(7)(i) through (vii) of this section).
* * * * *
    (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)
through (iii) of this section. For 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.
* * * * *
    (iii) Procedures for calibration. The instrument must be calibrated
before use each day of its use by the procedures specified in Method 21
of appendix A-7 of this part. At a minimum, you must also conduct
precision tests at the interval specified in Method 21 of appendix A-7
of this part, Section 8.1.2, and a calibration drift assessment at the
end of each monitoring day. The calibration drift assessment must be
conducted as specified in paragraph (c)(8)(iii)(A) of this section.
Corrective action for drift assessments is specified in paragraphs
(c)(8)(iii)(B) and (C) of this section.
    (A) Check the instrument using the same calibration gas that was
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. If multiple scales are used, record the
instrument reading for each scale used. Divide these readings by the
initial calibration values for each scale and multiply by 100 to
express the calibration drift as a percentage.
    (B) If a calibration drift assessment shows a negative drift of
more than 10 percent, then all equipment with instrument readings
between the fugitive emission definition multiplied by (100 minus the
percent of negative drift/divided by 100) and the fugitive emission
definition that was monitored since the last calibration must be re-
monitored.
    (C) If any calibration drift assessment shows a positive drift of
more than 10 percent from the initial calibration value, then, at the
owner/operator's discretion, all equipment with instrument readings
above the fugitive emission definition and below the fugitive emission
definition multiplied by (100 plus the percent of positive drift/
divided by 100) monitored since the last calibration may be re-
monitored.
    (d) Each fugitive emissions monitoring plan must include the
elements specified in paragraphs (d)(1) through (3) of this section, at
a minimum, as applicable.
    (1) If you are using optical gas imaging, your plan must include a
sitemap or plot plan and the information in paragraph (d)(1)(i) or
paragraphs (d)(1)(ii) through (iv):
    (i) A defined observation path that ensures that all fugitive
emissions components are within sight of the path. The observation path
must account for interferences.
    (ii) For closed vent systems regulated under this section, a
narrative description of how the closed vent system will be monitored,
including a description and the location of all fugitive emissions
components located on the closed vent system. The sitemap or plot plan
must include the location of each closed vent system.
    (iii) For controlled storage vessels regulated under this section,
a narrative description of how the storage vessel will be monitored
including a description and location of all fugitive emissions
components located on the controlled storage vessel. The sitemap or
plot plan must include the location of each controlled storage vessel.
    (iv) For all other fugitive emissions components not associated
with a closed vent system or controlled storage vessel regulated under
this section, a narrative description of how the fugitive emissions
components will be monitored, including a description and location of
all fugitive emissions components. The description and location of
fugitive emissions components may be grouped by unit operations (e.g.,
separator, heater/treater, glycol dehydrator). The sitemap or plot plan
must include the location of each unit operation.
    (2) If you are using Method 21, your plan must 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.). If you are using optical gas imaging,
you may comply with this requirement in lieu of paragraph (d)(1) of
this section.
    (3) Your fugitive emissions monitoring plan must include the
written plan developed for all of the fugitive emission components
designated as difficult-to-monitor in accordance with paragraph (g)(3)
of this section, and the written plan for fugitive emission components
designated as unsafe-to-monitor in accordance with paragraph (g)(4) of
this section.
* * * * *
    (f) * * *
    (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. Notwithstanding the preceding deadlines, for each
collection of fugitive emissions components at a new compressor station
located on the Alaskan North Slope that starts up between September and
March, you must conduct an initial monitoring survey within 6 months of
the startup date for new compressor stations, within 6 months of the
modification, or by the following June 30, 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), (4), and (6)
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 the frequencies specified in paragraphs (g)(1)(i) or (ii)
of this section.
    (i) At least annually for each collection of fugitive emissions
components located at a well site with average combined oil and natural
gas production for the wells at the site being greater than or equal to
15 barrels of oil equivalent (boe) per day averaged over the first 30
days of production, where boe equals cubic feet gas/5658.53.
Consecutive annual monitoring surveys must be conducted at least 9
months apart and no more than 13 months apart.
    (ii) At least once every other year (i.e., biennial) for each
collection of fugitive emissions components located at a well site with
average combined oil and natural gas production for the wells at the
site being less than 15 boe per day averaged over the first 30 days of
production, where boe equals cubic feet gas/5658.53. Consecutive
biennial monitoring surveys must be conducted no more than 25 months
apart.
    (2) Except as provided herein, a monitoring survey of the
collection of fugitive emissions components at a compressor station
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 and no more than 6 months
apart. Each compressor must be monitored while in operation (i.e., not
in stand-by mode) at least annually. A monitoring survey of the
collection of fugitive emissions components at a compressor station
located on the Alaskan North Slope must be conducted at least annually.
Consecutive annual monitoring surveys must be conducted at least 9
months apart and no more than 13 months apart.
* * * * *
    (5) [Reserved]
    (6) You are no longer required to comply with the requirements of
paragraph (g)(1) of this section when the owner or operator removes all
major production and processing equipment, as defined in Sec.
60.5430a, such that the well site becomes a wellhead only well site. If
any major production and processing equipment is subsequently added to
the well site, then the owner or operator must comply with the
requirements in paragraphs (f)(1) and (g)(1) of this section.
    (h) Each identified source of fugitive emissions shall be repaired,
as defined in Sec.  60.5430a, in accordance with paragraphs (h)(1) and
(2) of this section.
    (1) Each identified source of fugitive emissions shall be repaired
as soon as

practicable, but no later than 60 calendar days after detection of the
fugitive emissions.
    (2) A first attempt at repair shall be made no later than 30
calendar days after detection of the fugitive emissions.
    (3) If the repair 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 must be completed during the next scheduled compressor station
shutdown, well shutdown, well shut-in, after a scheduled vent blowdown
or within 2 years, whichever is earlier. For purposes of this
requirement, a vent blowdown is the opening of one or more blowdown
valves to depressurize major production and processing equipment, other
than a storage vessel.
    (4) Each repaired fugitive emissions component must be resurveyed
according to the requirements in paragraphs (h)(4)(i) through (iv) of
this section, to ensure that there are no fugitive emissions.
    (i) The operator may resurvey the fugitive emissions components to
verify repair using either Method 21 of appendix A-7 of this part or
optical gas imaging.
    (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 during the monitoring survey when the fugitives were initially
found for identification purposes and subsequent repair. The digital
photograph must include the date that the photograph was taken and 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 of appendix A-7 of this part to
resurvey the repaired fugitive emissions components are subject to the
resurvey provisions specified in paragraphs (h)(4)(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 of
appendix A-7 of this part 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 of
appendix A-7 of this part.
    (iv) Operators that use optical gas imaging to resurvey the
repaired fugitive emissions components, are subject to the resurvey
provisions specified in paragraphs (h)(4)(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.
* * * * *
0
7. Section 60.5398a is amended by revising paragraphs (a), (c), (d) and
(f) to read as follows:

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.
* * * * *
    (c) The Administrator will consider applications under this section
from owners or operators of affected facilities, and manufacturers or
vendors of leak detection technologies, or trade associations provided
they are submitted in conjunction with an owner or operator.
    (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 provide information that is sufficient for
demonstrating the alternative means of emission limitation is at least
as equivalent as the relevant standards. At a minimum, the applicant
must collect, verify, and submit field data to demonstrate the
equivalence of the alternative means of emission limitation; the field
data must encompass seasonal variations over the year to ensure that
the technique works appropriately in different conditions that will be
encountered during monitoring surveys. The field data may be
supplemented with modeling analyses, test data, or other documentation.
The application must include the following information:
    (i) A description of the technology, technique, or process.
    (ii) A description of the monitoring instrument or measurement
technology used in the technology, technique, 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, technique, 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 necessary for maintaining the technology, technique, or
process.
    (vi) Timeframes for conducting ongoing quality assurance/quality
control.
    (vii) Field data verifying viability and detection capabilities of
the technology, technique, or process. Test data, modeling analyses, or
other documentation may be used to supplement field data.
    (viii) Frequency of measurements and surveys conducted with the
technology, technique, or process.
    (ix) For continuous monitoring techniques, the minimum data
availability.
    (x) Sufficient data and other supporting documentation for
determining the emissions reductions achieved or avoided by the
technology, technique, or process.
    (xi) Any restrictions for using the technology, technique, or
process.
    (xii) 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.
    (xiii) Initial and continuous compliance procedures, including
recordkeeping and reporting, if the compliance procedures are different
than those specified in Sec.  60.5397a(d).
    (2) For each determination of equivalency requested, the emission
reduction achieved by the design, equipment, work practice or
operational requirements shall be demonstrated by field data, which can
be supplemented with modeling analyses at an active

production site or test data at a controlled test environment or
facility.
    (3) For each technology, technique, or process for which a
determination of equivalency is requested, the emission reduction
achieved by the alternative means of emission limitation shall be
demonstrated.
* * * * *
    (f)(1) An application submitted under this section will be
evaluated based on the field data, modeling analyses, and other
documentation that was provided to demonstrate the equivalence of the
alternative means of emission limitation under this section.
    (2) The Administrator may condition the approval of the alternative
means of emission limitation on requirements that may be necessary to
ensure that the alternative will achieve at least equivalent emission
reduction(s) as the reduction(s) achieved under the requirement(s) for
which the alternative is being requested.
0
8. Subpart OOOOa is amended by adding section 60.5399a to read as
follows:

Sec.  60.5399a  What alternative fugitive emissions 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:
Equivalency with state, local, and tribal programs?

    This section provides alternative fugitive emissions standards for
the collection of fugitive emissions components, as defined in Sec.
60.5430a, located at well sites and compressor stations. Paragraphs (a)
through (e) of this section outline the procedure for submittal and
approval of alternative fugitive emissions standards. Paragraphs (g)
through (n) of this section provide approved alternative fugitive
emissions standards. The terms ``fugitive emissions components'' and
``repaired'' are defined in Sec.  60.5430a and must be applied to the
alternative fugitive emissions standards in this section.
    (a) The Administrator will consider applications for alternative
fugitive emissions standards under this section based on state, local,
or tribal programs that are currently in effect from any interested
person, which includes, but is not limited to individuals,
corporations, partnerships, associations, state, or municipalities.
    (b) Determination of alternative fugitive emissions standards to
the design, equipment, work practice, or operational requirements of
Sec.  60.5397a will be evaluated by the following guidelines:
    (1) The monitoring instrument, including the monitoring procedure;
    (2) The monitoring frequency;
    (3) The fugitive emissions definition;
    (4) The repair requirements; and
    (5) The recordkeeping and reporting requirements.
    (c) After notice and opportunity for public comment, the
Administrator will determine whether the requested alternative fugitive
emissions standard will achieve at least equivalent emission
reduction(s) in VOC and methane emissions as the reduction(s) achieved
under the applicable requirement(s) for which an alternative is being
requested, and will publish the determination in the Federal Register.
    (d)(1) An application submitted under this section will be
evaluated based on the documentation that was provided to demonstrate
the equivalence of the alternative fugitive emissions standards under
this section.
    (2) The Administrator may condition the approval of the alternative
fugitive emissions standards on requirements that may be necessary to
ensure that the alternative will achieve at least equivalent emissions
reduction(s) as the reduction(s) achieved under the requirements for
which the alternative is being requested.
    (e) Any alternative fugitive emissions standard approved under this
section shall:
    (1) Constitute a required design, equipment, work practice, or
operational standard within the meaning of section 111(h)(1) of the
CAA; and
    (2) May be used by any owner or operator in meeting the relevant
standards and requirements established for affected facilities under
Sec.  60.5397a.
    (f)(1) An owner or operator must notify the Administrator before
implementing one of the alternative fugitive emissions standards, as
specified in Sec.  60.5420a(a)(3).
    (2) An owner or operator implementing one of the alternative
fugitive emissions standards must include the information specified in
Sec.  60.5420a(b)(7) in the annual report and maintain the records
specified by the specific alternative fugitive emissions standard for a
period of at least 5 years.
    (g) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site or a compressor
station in the state of California. An affected facility, which is the
collection of fugitive emissions components, as defined in Sec.
60.5430a, located at a well site or a compressor station in the state
of California may elect to reduce VOC and GHG emissions through
compliance with the monitoring, repair, and recordkeeping requirements
in the California Code of Regulations, title 17, Sec. Sec.  95665-
95667, effective January 1, 2020, as an alternative to complying with
the requirements in Sec. Sec.  60.5397a(f)(1) and (2), (g)(1) through
(4), (h), and (i) of this subpart.
    (h) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site or a compressor
station in the state of Colorado. An affected facility, which is the
collection of fugitive emissions components, as defined in Sec.
60.5430a, located at a well site or a compressor station in the state
of Colorado may elect to comply with the monitoring, repair, and
recordkeeping requirements in Colorado Regulation 7, Sec. Sec.  XII.L,
effective June 30, 2018, or XVII.F, effective October 15, 2014 for well
sites and January 1, 2015 for compressor stations, as an alternative to
complying with the requirements in Sec. Sec.  60.5397a(f)(1) and (2),
(g)(1) through (4), (h), and (i) of this subpart, provided the
monitoring instrument used is an optical gas imaging or a Method 21
instrument.
    (i) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site in the state of
Ohio. An affected facility, which is the collection of fugitive
emissions components, as defined in Sec.  60.5430a, located at a well
site in the state of Ohio may elect to comply with the monitoring,
repair, and recordkeeping requirements in Ohio General Permits 12.1,
Section C.5 and 12.2, Section C.5, effective April 14, 2014, as an
alternative to complying with the requirements in Sec. Sec.
60.5397a(f)(1), (g)(1), (3), and (4), (h), and (i) of this subpart,
provided the monitoring instrument used is a Method 21 instrument and
that the leak definition used for Method 21 monitoring is an instrument
reading of 500 ppm or greater.
    (j) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a compressor station in the
state of Ohio. An affected facility, which is the collection of
fugitive emissions components, as defined in Sec.  60.5430a, located at
a compressor station in the state of Ohio may elect to comply with the
monitoring, repair, and recordkeeping requirements in Ohio General
Permit 18.1, effective February 7, 2017, as an alternative to complying
with the requirements in Sec. Sec.  60.5397a(f)(2), (g)(2) through (4),
(h), and (i) of this subpart, provided the monitoring instrument used
is a Method 21 instrument and that the leak definition used for Method
21

monitoring is an instrument reading of 500 ppm or greater.
    (k) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site in the state of
Pennsylvania. An affected facility, which is the collection of fugitive
emissions components, as defined in Sec.  60.5430a, located at a well
site in the state of Pennsylvania may elect to comply with the
monitoring, repair, and recordkeeping requirements in Pennsylvania
General Permit 5, section G, effective August 8, 2018, as an
alternative to complying with the requirements in Sec. Sec.
60.5397a(f)(2), (g)(2) through (4), (h), and (i) of this subpart,
provided the monitoring instrument used is an optical gas imaging or a
Method 21 instrument.
    (l) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a compressor station in the
state of Pennsylvania. An affected facility, which is the collection of
fugitive emissions components, as defined in Sec.  60.5430a, located at
a compressor station in the state of Pennsylvania may elect to comply
with the monitoring, repair, and recordkeeping requirements in
Pennsylvania General Permit 5, section G, effective August 8, 2018, as
an alternative to complying with the requirements in Sec. Sec.
60.5397a(f)(2), (g)(2) through (4), (h), and (i) of this subpart,
provided the monitoring instrument used is an optical gas imaging or a
Method 21 instrument.
    (m) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site in the state of
Texas. An affected facility, which is the collection of fugitive
emissions components, as defined in Sec.  60.5430a, located at a well
site in the state of Texas may elect to comply with the monitoring,
repair, and recordkeeping requirements in the Air Quality Standard
Permit for Oil and Gas Handling and Production Facilities, section
(e)(6), effective November 8, 2012, or at 30 Tex. Admin. Code Sec.
116.620, effective September 4, 2000, as an alternative to complying
with the requirements in Sec. Sec.  60.5397a(f)(2), (g)(2) through (4),
(h), and (i) of this subpart, provided the monitoring instrument used
is a Method 21 instrument and that the leak definition used for Method
21 monitoring is an instrument reading of 2,000 ppm or greater.
    (n) Alternative fugitive emissions requirements for the collection
of fugitive emissions components located at a well site in the state of
Utah. An affected facility, which is the collection of fugitive
emissions components, as defined in Sec.  60.5430a, and is required to
control emissions in accordance with Utah Administrative Code R307-506
and R307-507, located at a well site in the state of Utah may elect to
comply with the monitoring, repair, and recordkeeping requirements in
the Utah Administrative Code R307-509, effective March 2, 2018, as an
alternative to complying with the requirements in Sec. Sec.
60.5397a(f)(2), (g)(2) through (4), (h), and (i) of this subpart.
0
9. Section 60.5400a is amended by revising paragraph (a) to read as
follows:

Sec.  60.5400a  What equipment leak GHG and VOC standards apply to
affected facilities at an onshore natural gas processing plant?

* * * * *
    (a) You must comply with the requirements of Sec. Sec.  60.482-
1a(a), (b), (d), and (e), 60.482-2a, and 60.482-4a through 60.482-11a,
except as provided in Sec.  60.5401a.
* * * * *
0
10. Section 60.5401a is amended by revising paragraph (e) to read as
follows:

Sec.  60.5401a  What are the exceptions to the equipment leak GHG and
VOC standards for affected facilities at onshore natural gas processing
plants?

* * * * *
    (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 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.
* * * * *
0
11. Section 60.5410a is amended by:
0
a. Revising paragraph (c)(1);
0
b. Revising paragraphs (e)(2) through (5); and
0
c. Removing and reserving paragraph (e)(8).
    The revisions read as follows:

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?

* * * * *
    (c) * * *
    (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 initial startup,
since August 2, 2016, or since the last rod packing replacement,
whichever is later.
* * * * *
    (e) * * *
    (2) If you own or operate a pneumatic pump affected facility
located at a well site, you must reduce emissions in accordance with
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(c) and (d).
    (3) If you own or operate a pneumatic pump affected facility
located at a well site and there is no control device or process
available on site, you must submit the certification in Sec.
60.5420a(b)(8)(i)(A).
    (4) If you own or operate a pneumatic pump affected facility
located at a well site, and you are unable to route to an existing
control device or to a process due to technical infeasibility, you must
submit the certification in Sec.  60.5420a(b)(8)(i)(B).
    (5) If you own or operate a pneumatic pump affected facility
located at a well site 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).
* * * * *
    (8) [Reserved]
* * * * *
0
12. Section 60.5411a is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraph (a) introductory text;
0
c. Revising paragraph (a)(1);
0
d. Revising paragraph (c) introductory text;
0
e. Revising paragraph (c)(1);
0
f. Revising paragraph (d)(1); and
0
g. Removing and reserving paragraph (e).
    The revisions read as follows:

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
and centrifugal compressor wet seal degassing systems.

    (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 to a process. You must design the closed
vent system to route all gases, vapors, and fumes emitted from the
centrifugal compressor wet seal fluid degassing system to a process or
a control device that meets the requirements specified in Sec.
60.5412a(a) through (c).
* * * * *
    (c) Closed vent system requirements for storage vessel and
pneumatic pump 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 or
pneumatic pump to a control device or to a process. For storage
vessels, the closed vent system must route all gases, vapors, and fumes
to a control device that meets the requirements specified in Sec.
60.5412a(c) and (d).
* * * * *
    (d) * * *
    (1) You must conduct an assessment that the closed vent system is
of sufficient design and capacity to ensure that all emissions from the
affected facility 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 an in-
house engineer or 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 an in-house engineer or a 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 an in-house engineer or a qualified professional
engineer who signs the certification in paragraph (d)(1)(i) of this
section.
* * * * *
    (e) [Reserved]
0
13. Section 60.5412a is amended by
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising paragraph (a)(1)(iv);
0
c. Revising paragraph (c) introductory text;
0
d. Revising paragraph (d)(1)(iv) introductory text; and paragraph
(d)(1)(iv)(D).
    The revisions read as follows:

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?

* * * * *
    (a) * * *
    (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. 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.
* * * * *
    (iv) You must introduce the vent stream with the primary fuel or
use the vent stream as the primary fuel in a boiler or process heater.
* * * * *
    (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) and (2) of this section.
* * * * *
    (d) * * *
    (1) * * *
    (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.
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.
* * * * *
    (D) You must introduce the vent stream with the primary fuel or use
the vent stream as the primary fuel in a boiler or process heater.
* * * * *
0
14. Section 60.5413a is amended by revising paragraph (d)(5)(i)
introductory text and paragraphs (d)(9)(iii) and (d)(12) introductory
text to read as follows.

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?

* * * * *
    (d) * * *
    (5) * * *
    (i) At the inlet gas sampling location, securely connect a fused
silica-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.
* * * * *
    (9) * * *
    (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
propane) measurement range may be used.
* * * * *
    (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 for each test run 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].
* * * * *
0
15. Section 60.5415a is amended by:
0
a. Revising paragraph (b) introductory text;
0
b. Revising paragraph (b)(3);
0
c. Removing and reserving paragraph (b)(4);
0
d. Revising paragraph (c)(1); and
0
e. Revising paragraph (h)(2).
    The revisions read as follows:

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?

* * * * *
    (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.
* * * * *
    (3) You must submit the annual reports required by Sec.
60.5420a(b)(1), (3), and (8) and maintain the records as specified in
Sec.  60.5420a(c)(2), (6) through (11), (16), and (17), as applicable.
    (4) [Reserved]
    (c) * * *
    (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, since August 2, 2016, or since the
date of the most recent reciprocating compressor rod packing
replacement, whichever is later.
* * * * *
    (h) * * *
    (2) You must repair each identified source of fugitive emissions as
required in Sec.  60.5397a(h).
* * * * *
0
16. Section 60.5416a is amended by:
0
a. Revising the introductory text;
0
b. Revising paragraph (a) introductory text;
0
c. Revising paragraph (a)(4) introductory text;
0
d. Revising paragraph (c) introductory text; and
0
e. Removing and reserving paragraph (d).
    The revisions read as follows:

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 centrifugal
compressor, reciprocating compressor, pneumatic pump, and storage
vessel 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 or reciprocating compressor 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.
* * * * *
    (4) For each bypass device, except as provided for in Sec.
60.5411a(a)(3)(ii), you must meet the requirements of paragraphs
(a)(4)(i) or (ii) of this section.
* * * * *
    (c) Cover and closed vent system inspections for pneumatic pump or
storage vessel affected facilities. If you install a control device or
route emissions to a process, you must comply with the inspection and
recordkeeping requirements for each closed vent system and cover as
specified in paragraphs (c)(1) and (c)(2) of this section. You must
also comply with the requirements of (c)(3) through (7) of this
section.
* * * * *
    (d) [Reserved]
0
17. Section 60.5417a is amended by revising paragraph (a) to read as
follows:

Sec.  60.5417a  What are the continuous control device monitoring
requirements for my centrifugal compressor and storage vessel affected
facilities?

* * * * *
    (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 or control 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.
* * * * *
0
18. Section 60.5420a is amended by:
0
a. Revising paragraph (a)(1);
0
b. Adding paragraph (a)(3);
0
c. Revising paragraph (b) introductory text;
0
d. Revising paragraph (b)(2);
0
e. Revising paragraph (b)(3) introductory paragraph;
0
f. Revising paragraphs (b)(3)(ii) through (iv);
0
g. Adding paragraph (b)(3)(v);
0
h. Revising paragraph (b)(4);
0
i. Revising paragraphs (b)(5)(i) through (iii);
0
j. Revising paragraph (b)(6) introductory text;
0
k. Revising paragraphs (b)(6)(iii) and (vii);
0
l. Adding paragraphs (b)(6)(viii) and (ix);
0
m. Revising paragraph (b)(7);
0
n. Revising paragraph (b)(8) introductory text;
0
o. Revising paragraph (b)(8)(iii);
0
p. Adding paragraph (b)(8)(iv);
0
q. Revising paragraph (b)(9)(i);
0
r. Revising paragraphs (b)(11) through (13);
0
s. Adding paragraph (b)(14);
0
t. Revising paragraph (c) introductory text;
0
u. Revising paragraph (c)(1) introductory text;
0
v. Revising paragraph (c)(1)(ii);
0
w. Revising paragraph (c)(1)(iii) introductory text;
0
x. Revising paragraphs (c)(1)(iii)(A) and (B);
0
y. Revising paragraph (c)(1)(iii)(C)(1);
0
z. Revising paragraphs (c)(1)(iv), (c)(1)(vi)(B), and (c)(1)(vii);
0
aa. Revising paragraph (c)(2) introductory text;
0
bb. Revising paragraphs (c)(2)(vi)(D) and (E);
0
cc. Revising paragraph (c)(2)(vii);
0
dd. Adding paragraph (c)(2)(viii);
0
ee. Revising paragraphs (c)(3)(i) and (iii);
0
ff. Revising paragraphs (c)(4)(i) and (v);
0
gg. Revising paragraph (c)(5) introductory text;
0
hh. Revising paragraphs (c)(5)(iii) and (v);
0
ii. Revising paragraph (c)(5)(vi) introductory text;
0
jj. Revising paragraphs (c)(5)(vi)(F)(4) and (c)(5)(vi)(G);
0
kk. Adding paragraphs (c)(5)(vi)(H) and (c)(5)(vii);
0
ll. Revising paragraphs (c)(6) through (9);
0
mm. Revising paragraph (c)(15);
0
nn. Revising paragraphs (c)(16)(ii) and (iv); and
0
oo. Adding paragraph (c)(18)
    The revisions and additions read as follows:

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

    (a) * * *

    (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 the notifications required in Sec.
60.7(a)(1), (3), and (4) and Sec.  60.15(d). 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) and Sec.
60.15(d).
* * * * *
    (3) An owner or operator electing to comply with the provisions of
Sec.  60.5399a shall notify the Administrator of the alternative
standard selected 90 days before implementing any of the provisions.
    (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) and
(12) 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.
* * * * *
    (2) For each well affected facility that is subject to Sec.
60.5375a(a) or (f), the records of each well completion operation
conducted during the reporting period, including the information
specified in paragraphs (b)(2)(i) through (b)(2)(xiv) of this section,
if applicable. In lieu of submitting the records specified in paragraph
(b)(2)(i) through (b)(2)(xiv) of this section, the owner or operator
may submit a list of each well completion with hydraulic fracturing
completed during the reporting period, and the digital photograph
required by paragraph (c)(1)(v) of this section for each well
completion. For each well affected facility that routes flowback
entirely through permanent separators, the records specified in
paragraphs (b)(2)(i) through (b)(2)(iv) and (b)(2)(vi) through
(b)(2)(xiv) of this section. For each well affected facility that is
subject to Sec.  60.5375a(g), the record specified in paragraph
(b)(2)(xv) of this section.
    (i) Well Completion ID.
    (ii) Latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983.
    (iii) US Well ID.
    (iv) The date and time of the onset of flowback following hydraulic
fracturing or refracturing.
    (v) The date and time of each attempt to direct flowback to a
separator as required in Sec.  60.5375a(a)(1)(ii).
    (vi) The date and time that the well was shut in and the flowback
equipment was permanently disconnected, or the startup of production.
    (vii) The duration (in hours) of flowback.
    (viii) The duration (in hours) 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).
    (ix) The duration (in hours) of combustion.
    (x) The duration (in hours) of venting.
    (xi) The specific reasons for venting in lieu of capture or
combustion.
    (xii) For any deviations recorded as specified in paragraph
(c)(1)(ii) of this section, the date and time the deviation began, the
duration of the deviation, and a description of the deviation.
    (xiii) For each well affected facility subject to Sec.
60.5375a(f), a record of the well type (i.e., wildcat well, delineation
well, or low pressure well (as defined Sec.  60.5430a)) and supporting
inputs and calculations, if applicable.
    (xiv) For each well affected facility for which you claim an
exception under Sec.  60.5375a(a)(3), the specific exception claimed
and reasons why the well meets the claimed exception.
    (xv) For each well affected facility with less than 300 scf of gas
per stock tank barrel of oil produced, the supporting 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.
    (3) For each centrifugal compressor affected facility, the
information specified in paragraphs (b)(3)(i) through (v) of this
section.
* * * * *
    (ii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(2) of this section, the date
and time the deviation began, the duration of the deviation, and a
description of the deviation.
    (iii) If required to comply with Sec.  60.5380a(a)(2), the
information in paragraphs (b)(3)(iii)(A) through (C) of this section.
    (A) Dates of each inspection required under Sec.  60.5416a(a) and
(b);
    (B) Each defect or leak identified during each inspection, how the
defect or leak was repaired and date of repair or the date of
anticipated repair if the repair is delayed; and
    (C) Date and time of each bypass alarm or each instance the key is
checked out if you are subject to the bypass requirements of Sec.
60.5416a(a)(4).
    (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), the information in paragraphs
(b)(3)(iv)(A) through (D) of this section.
    (A) Identification of the compressor with the control device.
    (B) Make, model, and date of purchase of the control device.
    (C) For each instance where the inlet gas flow rate exceeds the
manufacturer's listed maximum gas flow rate, where there is no
indication of the presence of a pilot flame, or where visible emissions
exceeded 1 minute in any 15-minute period, include the date and time
the deviation began, the duration of the deviation, and a description
of the deviation.
    (D) For each visible emissions test following return to operation
from a maintenance or repair activity, the date of the visible
emissions test, the length of the test, and the amount of time for
which visible emissions were present.
    (v) If complying with Sec.  60.5380a(a)(1) with a control device
not tested under Sec.  60.5413a(d), identification of the compressor
with the tested control device, the date the performance test was
conducted, and pollutant(s) tested. Submit the performance test report
following the procedures specified in paragraph (b)(9) of this section.
    (4) For each reciprocating compressor affected facility, the
information specified in paragraphs (b)(4)(i) through (iii) of this
section.
    (i) The cumulative number of hours of operation or the number of
months since initial startup, since August 2, 2016, 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) If applicable, for each deviation that occurred during the
reporting period and recorded as specified in paragraph (c)(3)(iii) of
this section, the date and time the deviation began, duration of the
deviation and a description of the deviation.
    (iii) If required to comply with Sec.  60.5385a(a)(3), the
information in paragraphs (b)(4)(iii)(A) through (C) of this section.
    (A) Dates of each inspection required under Sec.  60.5416a(a) and
(b);
    (B) Each defect or leak identified during each inspection, how the
defect or leak was repaired and date of repair or date of anticipated
repair if repair is delayed; and
    (C) Date and time of each bypass alarm or each instance the key is
checked out if you are subject to the bypass requirements of Sec.
60.5416a(a)(4).
    (5) * * *
    (i) An identification of each pneumatic controller constructed,
modified or reconstructed during the reporting period, including the
month and year of installation, reconstruction or modification and
identification information that allows traceability to the records
required in paragraph (c)(4)(iii) or (iv) of this section.
    (ii) If applicable, reason why the use of pneumatic controller
affected facilities with a natural gas bleed rate greater than the
applicable standard are required.
    (iii) For each instance where the pneumatic controller was not
operated in compliance with the requirements specified in Sec.
60.5390a, a description of the deviation, the date and time the
deviation began, and the duration of the deviation.
    (6) For each storage vessel affected facility, the information in
paragraphs (b)(6)(i) through (ix) of this section.
* * * * *
    (iii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(5)(iii) of this section, the
date and time the deviation began, duration of the deviation and a
description of the deviation.
* * * * *
    (vii) For each storage vessel constructed, modified, reconstructed
or returned to service during the reporting period 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), the information in paragraphs (b)(6)(vii)(A) through (D)
of this section.
    (A) Identification of the storage vessel with the control device.
    (B) Make, model, and date of purchase of the control device.
    (C) For each instance where the inlet gas flow rate exceeds the
manufacturer's listed maximum gas flow rate, where there is no
indication of the presence of a pilot flame, or where visible emissions
exceeded 1 minute in any 15-minute period, include the date and time
the deviation began, the duration of the deviation, and a description
of the deviation.
    (D) For each visible emissions test following return to operation
from a maintenance or repair activity, the date of the visible
emissions test, the length of the test, and the amount of time for
which visible emissions were present.
    (viii) If complying with Sec.  60.5395a(a)(2) with a control device
not tested under Sec.  60.5413a(d), identification of the storage
vessel with the tested control device, the date the performance test
was conducted, and pollutant(s) tested. Submit the performance test
report following the procedures specified in paragraph (b)(9) of this
section.
    (ix) If required to comply with Sec.  60.5395a(b)(1), the
information in paragraphs (b)(6)(ix)(A) through (C) of this section.
    (A) Dates of each inspection required under Sec.  60.5416a(c);
    (B) Each defect or leak identified during each inspection, how the
defect or leak was repaired and date of repair or date of anticipated
repair if repair is delayed; and
    (C) Date and time of each bypass alarm or each instance the key is
checked out if you are subject to the bypass requirements of Sec.
60.5416a(c)(3).
    (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 information
specified in paragraphs (b)(7)(i) and (ii) of this section.
    (i)(A) For each collection of fugitive emissions components at a
well site that became an affected facility during the reporting period,
you must include the date of the startup of production or the date of
the first day of production after modification.
    (B) For each collection of fugitive emissions components at a
compressor station that became an affected facility during the
reporting period, you must include the date of startup or the date of
modification.
    (C) For each collection of fugitive emissions components at a well
site where during the reporting period you complete the removal of all
major production and processing equipment such that the well site
contains only one or more wellheads, you must include a statement that
all major production and processing equipment has been removed from the
well site, the date of the removal of the last piece of major
production and processing equipment, and if the well site is still
producing to another site, the well ID or separate tank battery ID
receiving the production.
    (D) For each collection of fugitive emissions components at a well
site where you previously reported under paragraph (b)(7)(i)(C) the
removal of all major production and processing equipment and during the
reporting period major production and processing equipment is added
back to the well site, the date that the first piece of major
production and processing equipment is added back to the well site.
    (E) For each new collection of fugitive emissions components at a
well site where the average combined oil and natural gas production for
the wells at the site is less than 15 boe per day, you must submit the
combined oil and natural gas production in boe for the wells at the
site, averaged over the first 30 days of production.
    (ii) For each fugitive emissions monitoring survey performed during
the annual reporting period, the information specified in paragraphs
(b)(7)(ii)(A) through (L) of this section.
    (A) Date of the survey.
    (B) Name or unique ID of operator(s) performing survey.
    (C) Ambient temperature, sky conditions, and maximum wind speed at
the time of the survey.
    (D) Monitoring instrument used.
    (E) Any deviations from the monitoring plan elements under Sec.
60.5397a(c)(1), (2), (7), and (8)(i) or a statement that there were no
deviations from these elements of the monitoring plan.
    (F) Number and type of components for which fugitive emissions were
detected.
    (G) Number and type of fugitive emissions components that were not
repaired as required in Sec.  60.5397a(h).
    (H) Number and type of difficult-to-monitor and unsafe-to-monitor
fugitive emission components monitored.
    (I) The date of successful repair of the fugitive emissions
component.
    (J) Number and type of fugitive emission components currently on
delay of repair and explanation for each delay of repair.

    (K) Type of instrument used to resurvey a repaired fugitive
emissions component that could not be repaired during the initial
fugitive emissions finding, if the type of instrument is different from
the type used during the initial fugitive emissions finding.
    (L) Date of planned shutdown(s) that occurred during the reporting
period if there are any components that have been placed on delay of
repair.
    (8) For each pneumatic pump affected facility, the information
specified in paragraphs (b)(8)(i) through (iv) of this section.
* * * * *
    (iii) For each deviation that occurred during the reporting period
and recorded as specified in paragraph (c)(16)(ii) of this section, the
date and time the deviation began, duration of the deviation and a
description of the deviation.
    (iv) If required to comply with Sec.  60.5393a(b), the information
in paragraphs (b)(8)(iv)(A) through (C) of this section.
    (A) Dates of each inspection required under Sec.  60.5416a(c);
    (B) Each defect or leak identified during each inspection, how the
defect or leak was repaired and date of repair or date of anticipated
repair if repair is delayed; and
    (C) Date and time of each bypass alarm or each instance the key is
checked out if you are subject to the bypass requirements of Sec.
60.5416a(c)(3).
    (9) * * *
    (i) For data collected using test methods supported by the EPA's
Electronic Reporting Tool (ERT) as listed on the EPA's ERT website
(https://www.epa.gov/electronic-reporting-air-emissions/electronic-reporting-tool-ert) 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 website. 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 website, 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.
* * * * *
    (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 website (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. If you claim that some of the information
required to be submitted via CEDRI is CBI, submit a complete report
generated using the appropriate form in CEDRI or an alternate
electronic file consistent with the XML schema listed on the EPA's
CEDRI website, including information claimed to be CBI, on a compact
disc, flash drive, or other commonly used electronic storage medium to
the EPA. The electronic medium shall 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 file with the CBI omitted shall be submitted to the EPA
via CEDRI.
    (12) You must submit the certification signed by the in-house
engineer or qualified professional engineer according to Sec.
60.5411a(d) for each closed vent system routing to a control device or
process.
    (13) If you are required to electronically submit a report through
CEDRI in the EPA's CDX, and due to a planned or actual outage of either
the EPA's CEDRI or CDX systems within the period of time beginning 5
business days prior to the date that the submission is due, you will be
or are precluded from accessing CEDRI or CDX and submitting a required
report within the time prescribed, you may assert a claim of EPA system
outage for failure to timely comply with the reporting requirement. You
must submit notification to the Administrator in writing as soon as
possible following the date you first knew, or through due diligence
should have known, that the event may cause or caused a delay in
reporting. You must provide to the Administrator a written description
identifying the date, time and length of the outage; a rationale for
attributing the delay in reporting beyond the regulatory deadline to
the EPA system outage; describe the measures taken or to be taken to
minimize the delay in reporting; and identify a date by which you
propose to report, or if you have already met the reporting requirement
at the time of the notification, the date you reported. In any
circumstance, the report must be submitted electronically as soon as
possible after the outage is resolved. The decision to accept the claim
of EPA system outage and allow an extension to the reporting deadline
is solely within the discretion of the Administrator.
    (14) If you are required to electronically submit a report through
CEDRI in the EPA's CDX and a force majeure event is about to occur,
occurs, or has occurred within the period of time beginning 5 business
days prior to the date the submission is due, the owner or operator may
assert a claim of force majeure for failure to timely comply with the
reporting requirement. For the purposes of this section, a force
majeure event is defined as an event that will be or has been caused by
circumstances beyond the control of the affected facility, its
contractors, or any entity controlled by the affected facility that
prevents you from complying with the requirement to submit a report
electronically within the time period prescribed. Examples of such
events are acts of nature (e.g., hurricanes, earthquakes, or floods),
acts of war or terrorism, or equipment failure or safety hazard beyond
the control of the affected facility (e.g., large scale power outage).
If you intend to assert a claim of force majeure, you must submit
notification to the Administrator in writing as soon as possible
following the date you first knew, or through due diligence should have
known, that the event may cause or caused a delay in reporting. You
must provide to the Administrator a written description of the force
majeure event and a rationale for attributing the delay in reporting
beyond the regulatory deadline to the

force majeure event; describe the measures taken or to be taken to
minimize the delay in reporting; and identify a date by which you
propose to report, or if you have already met the reporting requirement
at the time of the notification, the date you reported. In any
circumstance, the reporting must occur as soon as possible after the
force majeure event occurs. The decision to accept the claim of force
majeure and allow an extension to the reporting deadline is solely
within the discretion of the Administrator.
    (c) Recordkeeping requirements. You must maintain the records
identified as specified in Sec.  60.7(f) and in paragraphs (c)(1)
through (18) 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) of this section, only. For each well affected
facility that routes flowback entirely through permanent separators the
date and time of each attempt to direct flowback to a separator is not
required.
* * * * *
    (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, including the date
and time the deviation began, the duration of the deviation, and a
description of the deviation.
    (iii) 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 latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using North American Datum of 1983;
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 as 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.
    (B) For each well affected facility required to comply with the
requirements of Sec.  60.5375a(f), you must record: Latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using North American Datum of 1983;
the United States Well Number; the date and time of the onset of
flowback following hydraulic fracturing or refracturing; 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.
    (C) * * *
    (1) The latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983; the United States Well Number; the date and
time of the onset of flowback following hydraulic fracturing or
refracturing; 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.
* * * * *
    (iv) For each well affected facility for which you claim an
exception under Sec.  60.5375a(a)(3), you must record: The latitude and
longitude of the well in decimal degrees to an accuracy and precision
of five (5) decimals of a degree using North American Datum of 1983;
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.
* * * * *
    (vi) * * *
    (B) The latitude and longitude of the well in decimal degrees to an
accuracy and precision of five (5) decimals of a degree using North
American Datum of 1983; the United States Well Number;
* * * * *
    (vii) For each well affected facility subject to Sec.  60.5375a(f),
a record of the well type (i.e., wildcat well, delineation well, or low
pressure well (as defined Sec.  60.5430a)) and supporting inputs and
calculations, if applicable.
    (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, including a description of each deviation,
the date and time each deviation began and the duration of each
deviation. Except as specified in paragraph (c)(2)(viii) of this
section, you must maintain the records in paragraphs (c)(2)(i) through
(vii) 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.
* * * * *
    (vi) * * *
    (D) Records of the visible emissions test following return to
operation from a maintenance or repair activity, including the date of
the visible emissions test, the length of the test, and the amount of
time for which visible emissions were present.
    (E) Records of the manufacturer's written operating instructions,
procedures and maintenance schedule to ensure good air pollution
control practices for minimizing emissions.
    (vii) Records of deviations for instances where the inlet gas flow
rate exceeds the manufacturer's listed

maximum gas flow rate, where there is no indication of the presence of
a pilot flame, or where visible emissions exceeded 1 minute in any 15-
minute period, including a description of the deviation, the date and
time the deviation began, and the duration of the deviation.
    (viii) 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) * * *
    (i) Records of the cumulative number of hours of operation or
number of months since initial startup, since August 2, 2016, or since
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.
* * * * *
    (iii) Records of deviations in cases where the reciprocating
compressor was not operated in compliance with the requirements
specified in Sec.  60.5385a, including the date and time the deviation
began, duration of the deviation and a description of the deviation.
    (4) * * *
    (i) Records of the month and year of installation, reconstruction
or modification, location 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, identification
information that allows traceability to the records required in
paragraph (c)(4)(iii) or (iv) of this section and manufacturer
specifications for each pneumatic controller constructed, modified or
reconstructed.
* * * * *
    (v) For each instance where the pneumatic controller was not
operated in compliance with the requirements specified in Sec.
60.5390a, a description of the deviation, the date and time the
deviation began, and the duration of the deviation.
    (5) For each storage vessel affected facility, you must maintain
the records identified in paragraphs (c)(5)(i) through (vii) of this
section.
* * * * *
    (iii) For each instance 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, a description of the
deviation, the date and time each deviation began, and the duration of
the deviation.
* * * * *
    (v) You must maintain records of the identification and location 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 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 (H) 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.
* * * * *
    (F) * * *
    (4) Records of the visible emissions test following return to
operation from a maintenance or repair activity, including the date of
the visible emissions test, the length of the test, and the amount of
time for which visible emissions were present.
* * * * *
    (G) Records of deviations for instances where the inlet gas flow
rate exceeds the manufacturer's listed maximum gas flow rate, where
there is no indication of the presence of a pilot flame, or where
visible emissions exceeded 1 minute in any 15-minute period, including
a description of the deviation, the date and time the deviation began,
and the duration of the deviation.
    (H) 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.
    (vii) Records of the date that each storage vessel affected
facility is removed from service and returned to service, as
applicable.
    (6) Records of each closed vent system inspection required under
Sec.  60.5416a(a)(1) and (2) for centrifugal compressors and
reciprocating compressors, or Sec.  60.5416a(c)(1) for storage vessels
and pneumatic pumps as required in paragraphs (c)(6)(i) through (iii)
of this section.
    (i) A record of each closed vent system inspection. You must
include an identification number for each closed vent system (or other
unique identification description selected by you) and the date of the
inspection.
    (ii) For each defect detected during inspections required by Sec.
60.5416a(a)(1) and (2) or Sec.  60.5416a(c)(1), you must record the
location of the defect, a description of the defect, the date of
detection, the corrective action taken the repair the defect, and the
date the repair to correct the defect is completed.
    (iii) If repair of the defect is delayed as described in Sec.
60.5416a(b)(10), you must record the reason for the delay and the date
you expect to complete the repair.
    (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 or pneumatic pumps as required in
paragraphs (c)(7)(i) through (iii) of this section.
    (i) A record of each cover inspection. You must include an
identification number for each cover (or other unique identification
description selected by you) and the date of the inspection.
    (ii) For each defect detected during inspections required by Sec.
60.5416a(a)(3) or Sec.  60.5416a(c)(2), you must record the location of
the defect, a description of the defect, the date of detection, the
corrective action taken the repair the defect, and the date the repair
to correct the defect is completed.
    (iii) If repair of the defect is delayed as described in Sec.
60.5416a(b)(10), you must record the reason for the delay and the date
you expect to complete the repair.
    (8) If you are subject to the bypass requirements of Sec.
60.5416a(a)(4) for centrifugal compressors or reciprocating
compressors, or Sec.  60.5416a(c)(3) for storage vessels or pneumatic
pumps, you must prepare and maintain 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
or reciprocating compressors, you must prepare and maintain the records
required in paragraphs (c)(9)(i) through (iii) of this section.
    (i) A record of each closed vent system no detectable emissions
monitoring survey. You must include an identification number for each
closed vent system (or other unique identification description selected
by you) and the date of the monitoring survey.
    (ii) For each leak detected during inspections required by Sec.
60.5416a(b), you must record the location of the leak, the maximum
concentration reading obtained using Method 21, the date of detection,
the corrective action taken the repair the leak, and the date the
repair to correct the leak is completed.
    (iii) If repair of the leak is delayed as described in Sec.
60.5416a(b)(10), you must record the reason for the delay and the date
you expect to complete the repair.
* * * * *
    (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 (vii) of this section.
    (i) The date of the startup of production or the date of the first
day of production after modification for each collection of fugitive
emissions components at a well site and the date of startup or the date
of modification for each collection of fugitive emissions components
compressor station.
    (ii) For each collection of fugitive emissions components at a well
site where you complete the removal of all major production and
processing equipment such that the well site contains only one or more
wellheads, the date the well site completes the removal of all major
production and processing equipment from the well site, and, if the
well site is still producing, the well ID or separate tank battery ID
receiving the production from the well site. If major production and
processing equipment is subsequently added back to the well site, the
date that the first piece of major production and processing equipment
is added back to the well site.
    (iii) For each collection of fugitive emissions components at a
well site that is monitored annually under (g)(1)(ii)(B), the records
identified in paragraphs (c)(15)(iii)(A) and (B) of this section.
    (A) The average daily combined oil and natural gas production for
the well site during the first 30 days of production; and
    (B) A description of the methodology used to calculate the daily
average production for the well site.
    (iv) The fugitive emissions monitoring plan as required in Sec.
60.5397a(b), (c), and (d).
    (v) The records of each monitoring survey as specified in
paragraphs (c)(15)(v)(A) through (L) of this section.
    (A) Date of the survey.
    (B) Beginning and end time of the survey.
    (C) Name of operator(s) performing survey. If you choose to report
the unique ID of the operator(s) performing the survey in lieu of the
operator(s) name, you must keep a record linking the unique ID to the
operator(s) name. You must note the training and experience of the
operator(s).
    (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 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. Digital
photographs or video recorded under paragraph (c)(15)(v)(K)(1) of this
section can be used to meet this requirement, 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.
    (F) Fugitive emissions component identification when Method 21 of
appendix A-7 of this part is used to perform the monitoring survey or
when optical gas imaging is used to perform the monitoring survey and
the owner or operator chooses to comply with Sec.  60.5397a(d)(2) in
lieu of Sec.  60.5397a (d)(1).
    (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)(v)(I)(1) through (3) of
this section.
    (1) Location.
    (2) Component ID and type of fugitive emissions component.
    (3) Instrument reading of each fugitive emissions component that
requires repair when Method 21 is used for monitoring.
    (J) Number and type of fugitive emissions components that were not
repaired as required in Sec.  60.5397a(h).
    (K) For each component that cannot be repaired during the
monitoring survey when the fugitive emissions were initially found:
    (1) Number and type of components that were tagged or a digital
photograph or video of each fugitive emissions component. 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 (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.
    (2) The date and repair methods applied in each attempt to repair
the fugitive emissions components.
    (3) The date of successful repair of the fugitive emissions
component.
    (4) The date of each resurvey and instrumentation used to resurvey
a repaired fugitive emissions component that could not be repaired
during the initial fugitive emissions finding.
    (5) Identification of each fugitive emission component placed on
delay of repair and explanation for each delay of repair.
    (L) Records of calibrations for the instrument used during the
monitoring survey.
    (vi) Date of planned shutdowns that occur while there are any
components that have been placed on delay of repair.
    (16) * * *
    (ii) Records of deviations in cases where the pneumatic pump was
not operated in compliance with the requirements specified in Sec.
60.5393a, including the date and time the deviation began, duration of
the deviation and a description of the deviation.
* * * * *
    (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 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).
* * * * *
    (18) A copy of each performance test submitted under paragraph
(b)(9) of this section.
0
19. Section 60.5422a is amended by revising paragraphs (a) and (b), and
paragraph (c) introductory text to read as follows:

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)(1) through (3), (b)(5), (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 website
(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 (3) and (b)(5): 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
(iv) and (c)(2)(vii) through (viii):
* * * * *
0
20. Section 60.5423a is amended by revising paragraph (b) introductory
text and adding paragraph (b)(3) to read as follows:

Sec.  60.5423a  What additional recordkeeping and reporting
requirements apply to my sweetening unit affected facilities at onshore
natural gas processing plants?

* * * * *
    (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 procedures for submitting annual reports are
located in Sec.  60.5420a(b). For the purpose of these reports, excess
emissions are defined as specified in paragraphs (b)(1) and (2) of this
section. The report must contain the information specified in paragraph
(b)(3) of this section.
* * * * *
    (3) For each period of excess emissions during the reporting
period, include the following information in your report:
    (i) The date and time of commencement and completion of each period
of excess emissions;
    (ii) The required minimum efficiency (Z) and the actual average
sulfur emissions reduction (R) for periods defined in paragraph (b)(1)
of this section; and
    (iii) The appropriate operating temperature and the actual average
temperature of the gases leaving the combustion zone for periods
defined in paragraph (b)(2) of this section.
* * * * *
0
21. Section 60.5430a is amended by:
0
a. Revising the definitions for ``capital expenditure'', ``certifying
official'', ``flowback'', ``fugitive emissions component'', ``low
pressure well'', ``maximum average daily throughput'', ``startup of
production'', and ``well site'';
0
b. Adding in alphabetical order the definitions for ``coil tubing
cleanout'', ``custody meter'', ``custody meter assembly'', ``first
attempt at repair'', ``major production and processing equipment'',
``permanent separator'', ``plug drill-out'', ``repaired'',
``screenout'', ``UIC Class II oilfield disposal well'', and ``wellhead
only well site''; and
0
c. Removing the definition for ``greenfield site''.
    The revisions and additions read as follows:

Sec.  60.5430a  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 equations: Y =
1.0 - 0.575 log X, where X is 2015 minus the year of construction, and
Y = 1.0 when the year of construction is 2015; and
    (iii) The applicable basic annual asset guideline repair allowance,
B, is 4.5.
* * * * *
    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