sets. As discussed above, all DRE data points from the technology
assessment reports from abatement systems designed to abate the F-GHG
input gas were included in the calculations of the proposed default
DREs except in cases where: (1) the DRE was negative; (2) there were
detection limit issues; (3) the inlet gas flow of the F-GHG measured
was less than 2 percent of the inlet gas; (4) the abatement system
required maintenance or repair; or (5) the abatement system was
operated in manner inconsistent with the manufacturer's specifications.
The subpart I TSD, available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424, describes the full data set and the
default DREs considered, including the option of excluding significant
outliers. Where data for gas-process combinations still do not exist
(or there were less than 5 data points), there are sufficient data
across the various gas/process combinations to assign DREs based on
analogy with gases with similar chemical structures. The revised Table
I-16 also includes proposed DREs for C2HF5,
C5F8, and C4F8O based on
their similarity to CHF3 (for C2HF5
and C5F8) and c-C4F8 (for
C4F8O). This results in
C2HF5 and C5F8 being
assigned a default DRE of 97 percent. Based on its similarity to c-
C4F8, C4F8O is assigned a
default DRE of 93 percent. The EPA is proposing to base the DRE for
C3F8 on the DREs for a chemically similar F-GHG
for which the EPA does have data.

C3F8 is expected to be no more difficult to abate
than C2F6. Thus, the EPA is proposing to apply
the DRE value for C2F6 (98 percent) to
C3F8. A value of 98 is slightly higher than the
DRE for C3F8 in the current rule (97
percent).44 45
---------------------------------------------------------------------------

    \42\ S.N. Li, et al. ``FTIR spectrometers measure scrubber
abatement efficiencies,'' Solid State Technology, Vol. 45. (2002);
Gray, Fraser, and Afroza Banu, ``Influence of CH4-
F2 mixing on CF4 by-product formation in the
combustive abatement of F2,'' Research Disclosure, Sept.
2018, both available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2019-0424.
    \43\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document.
    \44\ The 98-percent DRE for C3F8 in the
current rule was assigned by analogy with
C2F6, which also has an assigned DRE of 97
percent in the current rule (78 FR 68192, November 13, 2013).
    \45\ More information on the EPA's analysis of the DRE data can
be found in the subpart I TSD and supporting documents (``Combined
DRE data sets.xlsx'') in the docket for this rulemaking (Docket Id.
No. EPA-HQ-OAR-2019-0424).
---------------------------------------------------------------------------

    Since the data does not show statistically significant differences
between process types,\46\ we are proposing to remove the distinction
by process type from Table I-16. In addition, we are proposing to
equate the default DRE for each F-GHG to the straight average of the
measured DREs for that F-GHG rather than setting the default DRE
slightly below the average. The DREs currently in Table I-16 were
developed using analysis of variance (ANOVA), which took into account
the likely variations in abatement device performance across fabs and
within a single fab (see the memorandum, Final Technical
Documentation--Revision of Default Utilization Rates and By-Product
Formation Rates; Revision of Default Destruction and Removal
Efficiencies for Semiconductor Facilities under subpart I; and Revision
of Maximum Field Detection Limits for the Stack Test Method (Alexis
McKittrick, U.S. EPA, August 16, 2013), which was used in the
development of the 2013 Final Rule (78 FR 68182, November 13, 2013) and
is available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424). A conservative approach was used because the DRE
performance of abatement equipment can vary depending on the specific
design of each manufacturer, which is often proprietary, and the actual
conditions in the fab. However, here, we are proposing a more refined
method for estimating controlled emissions that would still account for
variability across manufacturers.
---------------------------------------------------------------------------

    \46\ Id.
---------------------------------------------------------------------------

    To account for the variations in device performance, we are
proposing to modify the conditions under which the default DRE can be
claimed. Currently, in 40 CFR 98.94(f), in order to claim the defaults
provided in Table I-16, abatement equipment must be certified as
specifically designed for F-GHG or N2O abatement, and the
abatement system must be certified as being properly installed,
operated, and maintained according to the site maintenance plan for
abatement systems. Site maintenance plans must also be based on the
manufacturer's recommendations and specifications. The EPA is proposing
to clarify the definition of operational mode in 40 CFR 98.98 to
specify that operational mode means that the system is operated within
the range of parameters as specified in the DRE certification
documentation. Thus, the abatement system should only be considered
operational and the default or certified lower DRE claimed when the
system is operated within the range of parameters for which the system
is certified to meet or exceed the claimed DRE. The specified
parameters must include a range of total F-GHG or N2O flows
and total gas flows (with N2 dilution accounted for) through
the emissions control systems. For systems operated outside the range
of parameters specified in the documentation supporting the DRE
certification (e.g., with total flows exceeding the original equipment
manufacturer (OEM) specifications), a site-specific DRE could be
measured and claimed. The system could then be considered operational
within the range of parameters used to develop a site-specific DRE. We
are also proposing to modify the conditions in 40 CFR 98.94(f) under
which the default DRE may be claimed to require that the reporter, in
order to claim the default value for that abatement system and gas,
must: (1) certify that the abatement device is able to achieve a value
equal to or greater than the default DRE value under the worst-case
flow conditions during which the facility is claiming that the system
is operational; and (2) provide supporting documentation. Worst-case
flow conditions would be defined as the highest total F-GHG or
N2O flows through each model of emissions control systems
(gas by gas and process type by process type across the facility) and
the highest total flow scenarios (with N2 dilution accounted
for) across the facility during which the emission control system is
claimed to be operational. The certification would be based on testing
of the abatement system model by the abatement system manufacturer
using a scientifically sound, industry-accepted measurement methodology
that accounts for dilution through the abatement system, such as the
Protocol for Measuring Destruction or Removal Efficiency (DRE) of
Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing (March 2010) (EPA 430-R-10-003, hereinafter ``EPA DRE
Protocol,'' available in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2019-0424). If the equipment is certified to abate the F-GHG
or N2O but at a value lower than the default DRE, facilities
would not be able to claim the default; however, facilities would be
allowed to claim the lower manufacturer verified value. Site-specific
measurements by the electronics manufacturer would still be required to
claim a higher DRE than the default. The updated DREs reflect increased
data and a refined approach rather than changes in the actual
destruction rates. The updates to the DREs in Table I-16 would increase
the accuracy of emissions reported by facilities and would be expected
to reduce the number of facilities that choose to measure site-specific
DREs.
d. Calculation of By-Products Produced in Hydrocarbon Fueled Abatement
Systems To Improve the Accuracy of Emissions Estimates
    We are proposing to add a calculation methodology that would
estimate the emissions of CF4 produced in hydrocarbon-fuel
based emissions control systems that are not certified not to generate
CF4. (In this section III.E.1.d, all references to
``uncertified hydrocarbon-fuel based emission control systems'' refer
to hydrocarbon-fuel based emissions control systems that are not
certified not to generate CF4.) The proposed calculation
would be codified in equation I-9; we are proposing to renumber the
previous equation I-9 as equation I-8b. Hydrocarbon-fuel based emission
control systems are hydrocarbon-fuel based combustion devices that are
designed to reduce emissions from exhaust streams from electronics
manufacturing processes and include, but are not limited to, abatement
systems that are designed to abate F-GHGs or N2O. Studies
have shown that direct reaction between molecular fluorine
(F2) and hydrocarbons (e.g., CH4) to form
CF4 can occur in hydrocarbon-fueled combustion emissions
control systems, and the 2019 Refinement includes calculations to
account for the formation and emission of CF4 from this
source.\47\ Where emissions control systems that generate
CF4 are used to abate NF3 from RPC processes, the
CF4 is expected to account for 1.5 times the emissions of
NF3 (in CO2e) that would have occurred with no
abatement (see the subpart I

TSD available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424).
---------------------------------------------------------------------------

    \47\ S.N. Li, et al. ``FTIR spectrometers measure scrubber
abatement efficiencies,'' Solid State Technology, Vol. 45. (2002);
Gray, Fraser, and Afroza Banu, ``Influence of CH4-
F2 mixing on CF4 by-product formation in the
combustive abatement of F2,'' Research Disclosure, Sept.
2018, both available in this docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    Equation I-9 would be used to estimate the emissions of
CF4 from generation in emissions control systems by
calculating the mass of the fluorine entering uncertified hydrocarbon-
fuel based emissions control systems (the product of the consumption of
the input gas, the emission factor for fluorine, and ai,
where ai is the ratio of the number of tools with
uncertified abatement devices for the gas-process combination to the
total number of process tools for the gas-process combination) and
multiplying that mass by a CF4 emission factor,
ABCF4,F2. The proposed default emission factor for this
reaction (ABCF4,F2) is 0.116.\48\ This reaction is expected
to result in significant emissions only where F2 is used as
an input gas or where large amounts of F2 can be formed as a
by-product of the decomposition of the cleaning gas into atomic
fluorine and subsequent recombination of the unreacted fluorine into
F2. Thus, this equation would only apply to processes that
use F2 as an input gas or to RPC processes that use
NF3 as an input gas. When NF3 is used as a
cleaning gas during the RPC process, the vast majority of the
NF3 molecules (approximately 98 percent, based on the
default values for (1-UNF3,RPC)) are decomposed within the
remote plasma unit to form fluorine and nitrogen radicals, ions, and
excited species. While some of the fluorinated species clean the solid
residues deposited on the chamber walls by combining with the residues
to form gaseous by-products such as SiF4, HF,
COF2, and CF4, some fluorine atoms recombine to
form molecular fluorine (F2). Based on confidential data
received from Edwards, Ltd.,\49\ a manufacturer of abatement equipment,
the proposed BEF for F2 from NF3 used in remote
plasma clean processes is 0.5. This data was also used to update the
2019 Refinement. The proposed by-product is reasonable considering that
emission factor data for NF3 from RPC processes submitted to
the EPA show that emissions of NF3 and CF4
accounted for less than 20 percent of the total mass of fluorine in the
NF3 used in the process in all but one of the 123 processes
measured, and generally significantly less, leaving at least 80 percent
of the fluorine available to form F2, SiF4, and
HF. (The last two compounds are formed when fluorine combines with
solid residue on the chamber walls, but the EPA's emission factor data
do not include specific information on the quantities of those
compounds--or of the fluorine--formed in the process.) No data from
processes that use F2 as an input gas are currently
available for the 1-U of F2; however, data from
NF3-using processes (where most of the NF3 is
dissociated into atomic fluorine during the process) indicate that the
1-U value for F2 may be near 0.7 (Confidential data received
from Edwards, Ltd.,\50\ 2018, available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424).\51\
---------------------------------------------------------------------------

    \48\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document, and the
subpart I TSD (available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424).
    \49\ The by-product emission factor for F2 from
NF3 was calculated from 15 measurements of remote plasma
clean processes following a variety of different Thin Film
Deposition (TFD) processes. F2 generation was estimated
using a mass-balance approach that compared the mass of atomic
fluorine (F) flowing into each process chamber in the form of
NF3 with the mass of fluorine exiting the process
chambers in the form of SiF4, COF2, HF, and
NF3. The mass of fluorine that was not accounted for at
the exhaust of the process chamber was assumed to be in the form of
F2.
    \50\ The by-product emission factor for F2 from
NF3 was calculated from 15 measurements of remote plasma
clean processes following a variety of different Thin Film
Deposition (TFD) processes. F2 generation was estimated
using a mass-balance approach that compared the mass of atomic
fluorine (F) flowing into each process chamber in the form of
NF3 with the mass of fluorine exiting the process
chambers in the form of SiF4, COF2, HF, and
NF3. The mass of fluorine that was not accounted for at
the exhaust of the process chamber was assumed to be in the form of
F2.
    \51\ All documents in the docket are listed at https://www.regulations.gov. Although listed in the index, some information
is not publicly available, e.g., CBI or other information whose
disclosure is restricted by statute.
---------------------------------------------------------------------------

    As for other gas and process combinations where no data is
available (listed as ``NA'' in Tables I-3 and I-4), a 1-U of 0.8 would
be used for F2 in equation I-9 for all process types. The
EPA is seeking comment on whether there is data available to support an
alternative 1-U for F2. The addition of this calculation is
expected to increase the accuracy of emissions estimates from
electronics manufacturers that use emissions control equipment. Along
with the new calculation, we are proposing corresponding monitoring,
reporting, and recordkeeping requirements (see 40 CFR 98.94(e), 40 CFR
98.96(o), and 40 CFR 98.97(b), respectively) for facilities that: (1)
use hydrocarbon-fuel-based emissions control systems to control
emissions from tools that use either NF3 as an input gas in
RPC processes or F2 as an input gas in any process; and (2)
assume in equation I-9 that one or more of those systems do not form
CF4 from F2. These proposed provisions, which are
patterned after the current provisions covering abatement systems from
which facilities quantify emission reductions, would require that the
facility certify and document that the model for each of the systems
that the facility assumes does not form CF4 from
F2 has been tested and verified to produce less than 0.1
percent CF4 from F2, and that each of these
systems is installed, operated, and maintained in accordance with the
directions of the emissions control system manufacturer. The facility
could perform the testing itself, or it could supply documentation from
the emissions control system manufacturer that supports the
certification. If the facility performed the testing, it would be
required to measure the rate of conversion from F2 to
CF4 using a scientifically sound, industry-accepted method
that accounts for dilution through the abatement device, such as the
EPA DRE Protocol, adjusted to calculate the rate of conversion from
F2 to CF4 rather than the DRE. The EPA requests
comment on whether there are other measurement methods that should be
cited as examples or listed as options for this measurement. The EPA
has considered that it may be difficult to adapt the EPA DRE Protocol
to measure the rate of conversion from F2 to CF4
if the analytical methods cited in the Protocol (Fourier Transform
Infrared (FTIR) and Quadrupole Mass Spectroscopy (QMS)) do not work
well to measure F2 flows. Instead, other measuring or
metering methods, such as calibrated mass-flow controllers or
electrochemical cells, may be more effective. The EPA requests comment
on this and any other issues that may arise in adapting the EPA DRE
Protocol to measure the rate of conversion from F2 to
CF4 in hydrocarbon-fuel-based emissions control systems.
These issues and means of handling them could then be specifically
addressed in the final rule.
    Given the potential sensitivity of a calculated stack emission
factor to any emissions of CF4 produced in hydrocarbon-fuel
based emissions control systems, we are also proposing to amend
paragraph 40 CFR 98.94(j)(1)(i) to require that the uptime (i.e., the
fraction of time that abatement system is operational and maintained
according to the site maintenance plan for abatement systems) during
the stack testing period average at least 90 percent for uncertified
hydrocarbon-fueled emissions control systems. This would ensure that
the calculated stack emission factor for CF4 will not be
underestimated due to a significant fraction of uncertified systems not

operating during the stack test. This proposed amendment is similar to
the current requirement in 40 CFR 98.98(j)(1)(i), which requires at
least 90 percent uptime averaged over all abatement systems during the
stack testing period, but would now require that this specific set,
hydrocarbon-fueled abatement systems that are not certified not to
generate CF4, also average at least 90 percent uptime during
the test.
    Because CF4 may be formed from F2 in any
hydrocarbon-fuel-based emissions control system, not only abatement
systems from which facilities claim reductions for purposes of
reporting under subpart I, we are proposing to apply these provisions
to all hydrocarbon-fuel-based emissions control systems used in
electronics manufacturing facilities. This includes, but is not limited
to, abatement systems as defined at 40 CFR 98.98. We are proposing to
add a definition of ``hydrocarbon-fuel-based emissions control system''
to clarify the scope of coverage.
e. Revisions to Calibration Requirements for Abatement Systems
    We are proposing to modify 40 CFR 98.97(d)(9)(ii) to require that a
vacuum pump's purge flow indicators are calibrated every time a vacuum
pump is serviced or exchanged. Some vacuum pumps' purge flow indicators
are inaccurate and could deliver higher than indicated purge flow,
exceeding the manufacturer's maximum flow specification for an
abatement system.\52\ Requiring calibration of the vacuum pumps would
make it less likely that facilities would unknowingly claim an
abatement system as operational during a time period when the abatement
system is being operated outside of the manufacturer's flow
specifications. Operating outside of the manufacturer's flow
specifications is problematic because abatement systems are generally
certified to meet or exceed the claimed DRE only when operated within a
specified range of flow. We expect that this requirement would require
calibrations every 1 to 6 months, depending on the process. The EPA is
requesting comment on whether this approach and expected frequency is
recommended or an approach that specifies the frequency of calibration,
such as a minimum calibration of twice a year, would be a sufficient
approach to maintain accurate flow rates.
---------------------------------------------------------------------------

    \52\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document.
---------------------------------------------------------------------------

2. Revisions To Streamline and Improve Implementation for Subpart I
a. Revisions to the Applicability Calculations for Subpart I
    As discussed in section II.B.1 of this preamble, we are proposing
to revise the applicability of subpart I. We are proposing to do this
by adding a second option in 40 CFR 98.91(a) for estimating GHG
emissions for semiconductor, MEMS, and LCD manufacturers; by revising
the current applicability calculation for PV manufacturers; and by
updating the emission factors used in the current applicability
calculations for MEMS and LCD manufacturers. Currently, semiconductor,
MEMS, and LCD manufacturers that have not previously reported under the
GHGRP are required to calculate the subpart I contribution toward the
25,000 mtCO2e reporting threshold by using a calculation
based on annual manufacturing capacity in substrate area (square
meters, m\2\). The calculation based on manufacturing capacity was
adopted in part to limit the burden required for facilities to estimate
their electronics manufacturing emissions for purposes of assessing the
applicability of the GHGRP, as this method does not require either
tracking gas consumption or apportioning gas consumption by process
type. Instead, it is based on production capacity in terms of substrate
area and default emission factors based on manufacturing type. However,
this method may not be suitable for some facilities that have emissions
per m\2\ rates that are atypical and could consequently require some
facilities that emit considerably less than 25,000 mtCO2e
(unabated) to report under the GHGRP.
    We are therefore proposing to add a second option for estimating
emissions in 40 CFR 98.91(a)(1) and (2) that includes two new
equations, I-1B and I-2B (and renumbering equations I-1 and I-2 to I-1A
and I-2A, respectively). Specifically, we are proposing to add an
optional calculation method that uses gas consumption multiplied by a
simple set of emission factors (along with GWPs and a factor to account
for heat transfer fluid) to estimate emissions in 40 CFR 98.91(a)(1)
and (2). To estimate emissions, facilities would, for each F-GHG, apply
an input gas emission factor of 0.8 and by-product gas formation
factors of 0.15 for CF4 and 0.05 for
C2F6. The emission factors we are proposing for
this optional calculation method are included in proposed new Table I-2
of subpart I of part 98 and are the same as the emission factors we are
proposing in this rulemaking for gas and process combinations for which
there is no default in Tables I-3, I-4, or I-5, as applicable; and the
factors are discussed further under the updates to emission factors in
section III.E.1.c of this preamble. As discussed in III.E.1.c of this
preamble, almost all gas and process combinations emit CF4
and C2F6 as by-products. Assigning default values
for these by-products, instead of assuming emissions to be equal to gas
consumption, would result in a more accurate emissions estimate,
especially in cases where the input gas has a significantly lower or
higher GWP than average. An emission factor of 1.0 would be applied to
N2O. Finally, as is currently required for the production-
based method, the calculated emissions of each F-GHG and N2O
would be multiplied by the chemical-specific or default GWP for that
GHG and the resulting CO2e emissions would be summed across
GHGs. The total would continue to be multiplied by a factor to account
for the use of F-HTFs using equation I-4. The result would be the
calculated subpart I contribution toward the 25,000 mtCO2e-
per-year emissions threshold in 40 CFR 98.2(a)(2).
    Facilities that choose to use this option for their calculation
method would be required to track annual gas consumption by GHG but
would not be required to apportion consumption by process type for the
purposes of assessing rule applicability. The EPA is proposing a
simplified consumption-based calculation method option for
semiconductor, MEMS, and LCD manufacturing facilities to provide a
calculation method that could appropriately exclude some lower-emitting
facilities that would otherwise be subject to subpart I. Facilities
would continue to have the option to use the manufacturing capacity-
based method for estimating emissions in 40 CFR 98.91(a)(1) and (2).
Facilities using either method would continue to calculate total annual
GHG emissions, including combined emissions from stationary fuel
combustion units and other applicable source categories, for comparison
to the 25,000 mtCO2e per year emission threshold in 40 CFR
98.2(a)(2).
    Facilities that manufacture PV already have a consumption-based
method in the current rule. However, currently, the applicability
calculation for PV manufacturing includes only GHGs ``that have listed
GWP values in Table A-1 to subpart A of this part.'' Because default
GWPs are now available for F-GHGs that do not have chemical-specific
GWPs in Table A-1, we are proposing to delete the limiting phrase
``that have listed GWP values in Table A-1.'' We are also proposing to
revise

equation I-3 to be identical to the new equations I-1B and I-2B and to
also use newly proposed Table I-2. As for semiconductor, MEMS, and LCD
manufacturers, this revision is expected to increase the accuracy of
the estimated emissions for determining applicability.
    We are also proposing to revise the emission factors in Table I-1
used for estimating emissions for MEMS and LCD manufacturing when
equation I-1A (based on production in substrate area) is used to assess
the applicability of part 98. The emission factors currently in Table
I-1 include emissions factors for semiconductor, LCD, and MEMS
manufacturing. For semiconductor and LCD manufacturing, the emissions
factors that are currently in Table I-1 are based on the Tier 1 default
emission factors in Vol. 3, Ch. 6 Electronics Industry Emissions in the
2006 IPCC Guidelines for National Greenhouse Gas Inventories.\53\
---------------------------------------------------------------------------

    \53\ IPCC. Guidelines for National Greenhouse Gas Inventories,
Volume 3, Ch. 6 Electronics Industry Emissions, 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/. Available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    For MEMS manufacturing, there were no IPCC Tier 1 factors available
at the time of the 2010 Final Rule for Additional Sources of
Fluorinated GHGs (75 FR 74774), and the emission factors were instead
based on the IPCC Tier 2b SF6 emission factor for
semiconductors.\54\ The 2019 Refinement included an update to the IPCC
Guidelines Tier 1 emission factors using newly available data.\55\ For
LCD and MEMS manufacturing, the EPA has tentatively determined that the
new Tier 1 emission factors in the 2019 Refinement would better reflect
industry-wide technological trends and are expected to improve the
accuracy of the emissions estimated for the GHGRP using Table I-1.
However, for semiconductor manufacturing, emission rates vary
significantly depending on the wafer size used for manufacturing, and
therefore no single set of default emission factors accurately
estimates emissions for all wafer sizes. The Tier 1 emission factors in
the 2019 Refinement are, overall, lower than those in the 2006 IPCC
Guidelines because they reflect the increasing importance of the 300-mm
wafer size technology, which has lower emission rates than the older
but still significant 200-mm (or smaller) wafer size technology. (The
Tier 1 emission factors in the 2019 Refinement were developed assuming
a 50/50 split between 200-mm and 300-mm wafer production.) To estimate
emissions for manufacturing using the 200-mm wafer size, the 2019
Refinement recommends that the Tier 1 emission factors in the 2006 IPCC
Guidelines be used because they more accurately reflect emission rates
for that wafer size than do the Tier 1 emission factors in the 2019
Refinement. Use of the Tier 1 emission factors in the 2019 Refinement
would underestimate emissions from facilities manufacturing on wafers
sized 200 mm or smaller. In addition, our analysis (CBI TSD Comparison
of Subpart I Emissions to New Tier 1 EFs, available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424 \56\) indicates
that use of these factors would underestimate emissions from a few
facilities manufacturing on wafers sized 300 mm. To maintain the
simplicity of the applicability calculation in equation I-1A for
semiconductors, the EPA prefers to retain a single set of default
emission factors for semiconductors in Table I-1, and to ensure that
facilities manufacturing on the 200-mm wafer size are not improperly
excluded from coverage by the GHGRP, we are not proposing to revise the
emission factors for semiconductor manufacturing in Table I-1. While
this could result in overestimated emissions for some facilities that
manufacture on the 300-mm wafer size, the EPA notes that such
facilities would have the option to use gas consumption data rather
than capacity in square meters to assess applicability, as discussed
above.
---------------------------------------------------------------------------

    \54\ Refer to Technical Support Document for Process Emissions
from Electronics Manufacture (e.g., Micro-electro-mechanical
Systems, Liquid Crystal Display, Photovoltaics, and Semiconductors),
November 2010, available in the docket for this rulemaking, Docket
Id. No, EPA-HQ-OAR-2019-0424.
    \55\ See Volume 3, Chapter 6. Electronics Industry Emissions to
the 2019 Refinement to the 2006 IPCC Guidelines for National
Greenhouse Gas Inventories, as cited above in this document.
    \56\ Supra note 51.
---------------------------------------------------------------------------

    There is no expected impact on the number of LCD manufacturing
facilities reporting to the GHGRP due to the proposed update to those
emission factors, as there are currently no known LCD manufacturers in
the United States. For MEMS manufacturers, the proposed update to Table
I-1 could possibly result in one additional facility reporting to the
GHGRP (estimated to have annual emissions greater than or equal to
25,000 mtCO2e). However, due to a lack of actual capacity
data, it is difficult to assess with precision how many facilities, if
any, would be impacted.
b. Revisions to the Frequency and Applicability of the Technology
Assessment Report
    For the reasons described in section II.B.3 of this preamble, we
are proposing to revise the frequency and applicability of the
technology assessment report requirements in 40 CFR 98.96(y), which
applies to semiconductor manufacturing facilities with GHG emissions
from subpart I processes greater than 40,000 mtCO2e per
year. (Other proposed changes to 40 CFR 98.96(y) are discussed in
section III.E.1 of this preamble.) The purpose of the technology
assessment report is to provide regular review of technology changes in
the semiconductor manufacturing industry and ensure that default gas
utilization rates, by-product formation rates, and DRE values
accurately reflect changes in the industry's practices, such as the
introduction of manufacturing on 450-mm sized wafers. In the 2012
proposed amendments to subpart I (77 FR 63538, October 16, 2020), we
noted that the semiconductor manufacturing industry had historically
been ``fast-evolving, achieving exponentially increasing processor
speeds and improving manufacturing efficiencies through the rapid
adoption of new manufacturing processes'' (see 77 FR 63565). At that
time the EPA had identified the potential introduction of 450 mm wafer
technology, as well as other new process technologies that could affect
emissions. Therefore, we considered a three-year report appropriate for
collecting information on changes in the semiconductor industry that
would potentially affect emissions. However, following submission and
review of the first three-year reports, we have determined that
industrial advancements are occurring at a slower pace. As such, we are
proposing to amend 40 CFR 98.96(y) to decrease the frequency of
submission of the reports from every three years to every five years.
Under the current rule, semiconductor manufacturing facilities are
required to submit their next technology assessment report by March
31st, 2023 (concurrent with their RY2022 annual report). This proposed
revision would affect the due date for that technology assessment,
moving the due date from March 31, 2023, to March 31, 2025. Our review
of the technology assessment reports submitted for RY2016 and RY2019
did not find significant technology changes within the industry over
the three years the reports covered. Based on an assessment of the
RY2016 and RY2019 reports (CBI memorandum, Review of 2017 Subpart

I Triennial Reports Submitted by the Electronics Industry (Transcarbon
International, 2017, available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424) \57\ gas emissions and wafer size
data that have been submitted to e-GGRT in annual reports, and
information gathered from outside sources (summarized in a literature
review, Memorandum: Review of trade and scientific publications to
identify significant recent changes in technologies and gas usage in
electronic devices manufacturing, prepared by S[eacute]bastien Raoux,
Transcarbon International, and Brian Palmer, Eastern Research Group,
Inc. (April 3, 2017), available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424), we believe that a five-year
period would provide updates to the EPA more in line with the pace of
technological change within the semiconductor industry. Revising the
frequency of submission to every five years would increase the
likelihood that reports will include updates in technology rather than
conclusions that technology has not changed. Because we have found that
changes within the industry have been incorporated at a slower pace and
do not anticipate significant changes in technology on a three-year
frequency, the proposal to require submission of these reports on a
five-year frequency would likely not significantly affect the quality
of the data available annually in the GHGRP.
---------------------------------------------------------------------------

    \57\ Supra note 51.
---------------------------------------------------------------------------

    Second, we are proposing to revise the applicability of 40 CFR
98.96(y). Currently, any facility with emissions greater than 40,000
mtCO2e in their most recently submitted emissions report
must submit a technology assessment report, including facilities
manufacturing devices only using wafer sizes smaller than 200 mm (e.g.,
150 mm). Because the focus of the technology assessment report is on
semiconductor manufacturing using 200-mm, 300-mm, and potentially 450-
mm wafers (see 40 CFR 98.96(y)(2)(i)-(iii)), we are proposing to
restrict the reporting requirement in 40 CFR 98.96(y) to facilities
that emitted greater than 40,000 mtCO2e and produced wafer
sizes greater than 150 mm (i.e., 200 mm or larger) during the period
covered by the technology assessment report. We are also proposing to
explicitly state that semiconductor manufacturing facilities that
manufacture only 150-mm or smaller wafers are not required to prepare
and submit a technology assessment report. The applicability of 40 CFR
98.96(y) is currently based on the emissions in a facility's most
recently submitted report (typically the emissions occurring in the
second-to-last year covered in the technology assessment report, e.g.,
RY2022 emissions for the technology reports that would be submitted in
2023). However, because facilities that cease all operations related to
subpart I are eligible to discontinue reporting under 40 CFR
98.2(i)(3), we are also proposing to further revise the applicability
of 40 CR 98.96(y) to clarify that a technology assessment report need
not be submitted by a facility that has ceased (and has not resumed)
semiconductor manufacturing before the last reporting year covered by
the technology assessment report (i.e., no manufacturing at the
facility for the entirety of the year immediately before the year
during which the technology assessment report is due). For example, if
a facility manufacturing on 300-mm wafers exceeded the 40,000
mtCO2e threshold in 2023 but ceased operations in December
of that year and has not since then resumed operations, that facility
would not be required to submit a technology assessment report in March
of 2025.

F. Subpart N--Glass Production

    For the reasons described in section II.A.4 of this preamble, we
are proposing two revisions to the recordkeeping and reporting
requirements of subpart N of part 98 (Glass Production) to enhance the
quality and accuracy of the data collected under the GHGRP. Subpart N
currently requires calculation of CO2 emissions using one of
two methodologies, either direct measurement using CEMS, or a mass
balance methodology based on mass, carbonate content, and fraction of
calcination for each carbonate-based input material. For each option,
reporters are required to provide the annual quantities of glass
produced from each glass melting furnace, and the annual quantities of
glass produced from all furnaces combined. The annual quantities of
glass produced have been used historically in verification of reported
emissions under the GHGRP for comparison to, and to check for temporal
consistency with, carbonate content data and emissions estimates
provided by facilities. Facilities also maintain records of monthly
glass production rate for each glass furnace. We are proposing to
revise the existing reporting and recordkeeping requirements for both
CEMS and non-CEMS reporters to require that facilities report and
maintain records of annual glass production by glass type.
Specifically, we are proposing to revise 40 CFR 98.146(a)(2) and (b)(3)
to require the annual quantity of glass produced in tons, by glass
type, from each continuous glass melting furnace and from all furnaces
combined, and the annual quantity of glass produced in tons, by glass
type, from each continuous glass melting furnace and from all furnaces
combined. The major raw materials (i.e., fluxes and stabilizers) that
emit process-related CO2 emissions in glass production are
limestone, dolomite, and soda ash, though there are variations in
ingredients and other carbonates may be used in smaller quantities. In
general, the composition profile of raw materials is relatively
consistent among individual glass types (e.g., container, flat glass,
fiber glass, specialty glass), however, some facilities make use of
recycled glass in their production process. Differences in the use of
recycled material, and other factors, lead to differences in emissions
from the production of different glass types. The annual quantities of
glass produced by type would provide a useful metric for understanding
variations and differences in emissions estimates that may not be
apparent in the existing annual production data collected, improve our
understanding of industry trends, and improve verification for the
GHGRP. The proposed data elements would also provide useful information
to improve analysis of this sector in the U.S. GHG Inventory. As noted
in the 2019 U.S. GHG Inventory report,\58\ the EPA reviews the GHGRP
data in the development of inventory estimates for this sector to help
understand the completeness of emission estimates and for quality
control. Including glass product type would increase the transparency
of the data set produced by the Inventory. In addition to the proposed
reporting of these data elements, we are proposing harmonizing
revisions in 40 CFR 98.147(a)(1) and (b)(1), to add that records must
also be kept on the basis of glass type.
---------------------------------------------------------------------------

    \58\ See U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2019 (EPA 2021), available at: https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2019.
---------------------------------------------------------------------------

    We do not anticipate that the proposed data elements would require
any additional monitoring or data collection by reporters, as annual
production data by glass type is likely available in existing company
records. The proposed changes would therefore result in minimal
additional burden to reporters. We are also proposing related
confidentiality determinations for the

additional data elements, as discussed in section VI of this preamble.

G. Subpart P--Hydrogen Production

1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart P
    As discussed in section II.A of this preamble, we are proposing
several amendments to enhance the quality of the data collected under
subpart P of part 98 (Hydrogen Production).
    Subpart P estimates CO2 emissions from hydrogen
production units using a carbon mass balance along with an assumption
that all carbon is transformed to CO2 and is emitted from
the hydrogen production process. This assumption is reasonable for the
majority of hydrogen production units because these facilities produce
hydrogen using either steam methane reforming or partial oxidation,
followed by a water-gas-shift reaction. The first step (steam methane
reforming or partial oxidation) produces a mixture of carbon monoxide
(CO) and hydrogen, commonly referred to as syngas. The water gas shift
reaction uses water to react with the CO in the syngas to produce
CO2 and additional hydrogen. While the majority of hydrogen
production units use the water-gas-shift reaction, some facilities only
produce syngas as their product. Some facilities may also intentionally
produce methanol as a product of these reactions. In these cases, the
assumption that 100 percent of the carbon used in the process is
converted to CO2 and thus are direct CO2
emissions from hydrogen production units is inaccurate.
    As noted in section III.C of this preamble for subpart G (Ammonia
Manufacturing), TFI has commented numerous times regarding its view of
the lack of a true mass balance for subpart G. In several of their
comments (specifically, TFI's Comments on the Proposed ``2013 Revisions
to the Greenhouse Gas Reporting Rule and Proposed Confidentiality
Determinations for New or Substantially Revised Data Elements,'' May 2,
2013, and Comments on the Proposed ``2015 Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule,'' March 30, 2016),59 60 TFI stated that subpart P
lacked a true mass balance because the emissions calculation
methodology in 40 CFR 98.163 does not account for carbon that is bound
in methanol or other by-products of the process and therefore is not
emitted as CO2. TFI pointed out that subpart P requires
reporting of methanol that is intentionally produced and ``carbon other
than CO2'' that is transferred off site, but that the
emissions calculation methodology in 40 CFR 98.163 still assumes that
100 percent of the carbon is emitted as CO2 because the mass
balance equations do not subtract out the carbon that leaves the
facility as methanol or another product.
---------------------------------------------------------------------------

    \59\ TFI's Comments on the Proposed ``2013 Revisions to the
Greenhouse Gas Reporting Rule and Proposed Confidentiality
Determinations for New or Substantially Revised Data Elements,''
Docket Id. No. EPA-HQ-OAR-2012-0934, May 2, 2013. Also available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
    \60\ TFI's Comments on the Proposed ``2015 Revisions and
Confidentiality Determinations for Data Elements under the
Greenhouse Gas Reporting Rule,'' Docket Id. No. EPA-HQ-OAR-2015-
0526-0064, March 30, 2016. Also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    Syngas is used as a feedstock for chemical production, most
commonly to produce methanol. Carbon transformed into methanol or other
chemicals are not emitted as CO2 unless the syngas is used
directly as fuel. For fuel combustion units other than the hydrogen
process units, and to which subpart C (General Stationary Fuel
Combustion Sources) applies, the CO2 emissions from syngas
combustion would be reported under subpart C of part 98. In considering
TFI comments, as noted in the preamble to the November 2013 amendments
(78 FR 71935, November 29, 2013), we considered both the emissions from
the production processes and consistency with the reporting
requirements for other subparts. We note that subpart X (Petrochemical
Production) uses a more direct mass balance approach in that carbon
contained in produced products (e.g., ethylene) is subtracted from the
carbon contained in feedstocks to calculate CO2 emissions.
The EPA has tentatively concluded that requiring reporters subject to
subpart P to report net CO2 process emissions after
subtracting out carbon contained in other products would provide a more
accurate estimate of the direct GHG emissions from these processes and
would provide consistency in our approach across the GHGRP. Therefore,
the EPA is proposing to amend subpart P to allow the subtraction of
carbon contained in products other than CO2 (excluding
methanol) and the carbon contained in methanol from the carbon mass
balance used to estimate CO2 emissions. The proposed
revisions would add new paragraph 40 CFR 98.163(d) to allow facilities
to adjust the calculated emissions from fuel and feedstock consumption
to subtract the mass of both non-CO2 carbon (excluding
methanol) and carbon contained in the intentionally produced methanol
in order to calculate net CO2 process emissions. We are also
proposing harmonizing revisions to the introductory paragraph of 40 CFR
98.163 and 40 CFR 98.163(b).
    In conjunction with adding the new paragraph to 40 CFR 98.163(d),
we are proposing a clarifying revision to the reporting requirements at
40 CFR 98.166(b)(1) to specify that the annual CO2 emissions
may be determined in accordance with either 40 CFR 98.163(b), the
existing equations, or 40 CFR 98.163(d), the revision requiring the
calculation of net CO2 emissions using equation P-4. We are
proposing to revise 40 CFR 98.166(d) to require reporting the mass of
non-CO2 carbon (excluding methanol) collected and
transferred off-site for each process unit rather than for all process
units combined, as currently reported. Reporters are already required
to account for and report under 40 CFR 98.166(d) the mass of non-
CO2 carbon (excluding methanol) collected and transferred
off-site for all process units combined and under 40 CFR 98.166(e) the
mass of methanol produced for each process unit. This proposed revision
would cause a slight increase in reporting burden, but the additional
level of reporting is necessary to implement the requested change in
the calculation method and facilitate report verification. The proposed
revision would provide the same breadth of information that was
previously reported to inform future policy decisions. Additionally,
this data element may be determined using company records, which also
should minimize the increased burden. We are proposing related
confidentiality determinations for the additional data elements, as
discussed in section VI of this preamble.
    As a result of the new equation P-4, the EPA is proposing to add
two new monthly recordkeeping elements as part of the verification
software records required in 40 CFR 98.167(e): (1) monthly mass of
carbon other than CO2 or methanol collected and transferred
off site; and (2) monthly mass of methanol intentionally produced as a
desired product. This proposed change is not expected to result in a
significant increase in burden because both elements are already being
reported on an annual basis. For reporters that do not produce carbon
other than CO2 (excluding methanol) or methanol, the
requirements for recordkeeping would remain unchanged. We are also
clarifying that retention of the file required in 40 CFR 98.167(e)
satisfies

the recordkeeping requirements for each hydrogen production unit.
2. Proposed Revisions To Streamline and Improve Implementation for
Subpart P
    We are proposing several revisions to subpart P to streamline the
requirements of this subpart and improve flexibility for reporters.
First, we are proposing several revisions to address unconventional
feedstocks being used for hydrogen production. For example, in RY2017,
a new facility started reporting under subpart P that produced hydrogen
via brine electrolysis. Additionally, we understand facilities are
considering using anhydrous ammonia as a feedstock for hydrogen
production. The test methods included in 40 CFR 98.164(b)(5) are
generally not applicable for these feedstocks. Moreover, the reduced,
annual measurement frequency allowances in 40 CFR 98.164(b)(2) and (3)
are specific to ``hydrocarbon fuels and feedstocks having consistent
composition'' [emphasis added].
    To address the recent use of unconventional non-hydrocarbon
feedstocks, and for the reasons described in section II.B.2 of this
preamble, we are proposing to add an allowance in a new paragraph 40
CFR 98.164(b)(5)(xix) to use alternative methods if the methods
currently in 40 CFR 98.164(b)(5) are not appropriate because the
relevant compounds cannot be detected, the quality control requirements
are not technically feasible, or use of the method would be unsafe.
Similar provisions have been provided in other GHGRP subparts, such as
subpart X. This proposed revision will ensure that subpart P will not
mandate the use of inappropriate or unsafe methods for these
unconventional feedstocks.
    Additionally, we are proposing revisions to 40 CFR 98.164(b)(2) and
(3) to allow the use of product specification information annually for
non-hydrocarbon gaseous fuels and feedstocks that have carbon content
less than or equal to 20 parts per million by weight (i.e., 0.00002 kg
carbon per kg of gaseous fuel or feedstock) rather than at least weekly
sampling and analysis. Similarly, we are proposing revisions to 40 CFR
98.164(b)(3) to allow the use of product specification information
annually for non-hydrocarbon liquid fuels and feedstocks that have a
carbon content of less than or equal to 0.00006 kg carbon per gallon of
liquid fuel or feedstock rather than monthly sampling and analysis. The
value of 0.0006 kg/gallon was derived using 20 parts per million by
weight and assuming the liquid that has a specific gravity of 0.8
(i.e., a density of approximately 3.0 kg/gal). The current
unconventional non-hydrocarbon fuels and feedstocks utilized in
hydrogen production have very limited GHG emission potential and are
currently an insignificant contribution to the GHG emissions from
hydrogen production. Therefore, we consider it reasonable to provide a
simple alternative of allowing use of product specification information
on an annual basis for determining carbon content for these
unconventional, non-hydrocarbon fuels and feedstocks.
    We are also proposing revisions to 40 CFR 98.164(b)(5) to clarify
that the methods in 40 CFR 98.164(b)(5) must be used for determining
carbon content except for the newly proposed provisions for gaseous and
liquid fuels and feedstocks that have a low carbon content as provided
in paragraphs 40 CFR 98.164(b)(2) and (3). Additionally, we are
proposing to revise paragraphs 40 CFR 98.164(b)(2) through (4) to
specifically state that the carbon content must be determined ``. . .
using the applicable methods in paragraph (b)(5) of this section.''
This proposed revision does not alter the existing requirements for
fuels and feedstocks, it simply clarifies the linkage between the
requirements in paragraphs 40 CFR 98.164(b)(2) through (4) and (5) of
the current rule.
    These proposed revisions to address unconventional hydrogen
production feedstocks would increase flexibility for reporters and
clarify requirements to reduce the number of reporters performing
monthly sampling and analysis using potentially inappropriate methods.
We expect that the proposed changes would allow reporters using
unconventional non-hydrocarbon fuels and feedstocks to use the proposed
product specifications provisions and reduce the need for sampling and
analysis. Even if the reporter cannot use the product specifications
provisions, the proposed revision to allow the use of modified or
alternative methods would likely reduce the analytical burden of trying
to use hydrocarbon-focused methods for a non-hydrocarbon stream. While
the proposed revisions would provide significant relief for those
reporters using unconventional non-hydrocarbon fuels or feedstocks, the
proposed change is expected to only affect a small number of reporters
due to the limited number of reporters that currently use these types
of feedstocks.
    In providing these alternatives, we also evaluated whether
amendments to the recordkeeping and reporting requirements were
necessary. There are no direct reporting requirements for the
analytical method used to determine carbon content. The recordkeeping
requirements are included in 40 CFR 98.167(b), which requires retention
of ``. . . records of all analyses and calculations conducted as listed
in 40 CFR 98.166(b), (c), and (d).'' In reviewing these requirements,
we noted that these recordkeeping requirements were not revised when
the EPA added reporting requirements at 40 CFR 98.166(e) (79 FR 63787,
Oct. 24, 2014). Therefore, we are proposing to revise the recordkeeping
requirements at 40 CFR 98.167(b) to refer to paragraphs (b) through (e)
of 40 CFR 98.166. We note that, for facilities using the proposed
alternatives at 40 CFR 98.164(b)(2), (3) or (5)(xix), these
requirements include retention of product specification sheets, records
of modifications to the methods listed in 40 CFR 98.164(b)(5)(i)
through (xviii) that are used, and records of the alternative methods
used, as applicable.

H. Subpart Q--Iron and Steel Production

1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart Q
    For the reasons described in section II.A.4 of this preamble, we
are proposing revisions to the reporting requirements for subpart Q of
part 98 (Iron and Steel Production) to enhance the quality and accuracy
of the data collected. Subpart Q currently requires calculation of
CO2 emissions using one of three methodologies: direct
measurement using CEMS, carbon mass balance methodologies, or site-
specific emission factors. Subpart Q requires that the CO2
emissions be calculated and reported for the following types of units:
taconite indurating furnace, basic oxygen furnace, non-recovery coke
oven battery, sinter process, EAF, decarburization vessel, and direct
reduction furnace. We are proposing to revise the existing reporting
requirements at 40 CFR 98.176(g) for all unit types and all calculation
methods to require that facilities report the type of unit, the annual
production capacity, and the annual operating hours for each unit. The
capacity of the unit as well as the level of operation have a
significant influence on the emissions of that unit. Therefore, the
annual production capacity in combination with annual operating hours
would provide useful information for understanding variations in annual
emissions and would provide useful information to verify reported data.
We often contact facilities seeking to understand yearly variations in
the emissions of a unit, and facilities explain that the variation

was due to the unit not operating for a particular time period. If data
on the capacity of the unit and the operating hours are included in the
annual report, it could explain the variation and eliminate the need
for correspondence with facilities. In addition, this data would
provide useful information to understand trends across the sector and
support analysis of these sources.
    In general, we do not anticipate that the proposed data elements
would require any additional monitoring or data collection by
reporters. For facilities using the carbon mass balance method, this
data is already included in the record keeping requirements described
at 40 CFR 98.177(c) and (d). Although the record keeping requirement at
40 CFR 98.177(d) does not specify whether the data would be retained at
the facility or unit level, we do not anticipate that reporting data at
the unit level would present additional burden. For facilities using
the CEMS method or the site-specific emission factor calculation
method, we anticipate that this data would be readily available in
company records. However, we seek comment on both these assumptions. We
are proposing related confidentiality determinations for the additional
data elements, as discussed in section VI of this preamble.
    For the reasons described in section II.A.5 of this preamble, we
are proposing to correct equation Q-5 in 40 CFR 98.173(b)(1)(v). An
error appears to have been introduced in equation Q-5 in revisions to
the equation in a final rule published in 2016 (81 FR 89188, December
9, 2016). Specifically, the final rule inadvertently published the
equation such that it appeared that the total CO2 emissions
from EAFs are determined as a fraction of, rather than the total of,
carbon mass emissions from inputs to the furnace. The proposed
revisions would correct the equation to remove the unnecessary fraction
symbol and would not add additional burden for the calculation or
reporting requirements for subpart Q.
2. Proposed Revisions To Streamline and Improve Implementation for
Subpart Q
    For the reasons described in section II.B.2 of this preamble, we
are proposing two revisions to subpart Q to streamline monitoring.
First, we are proposing to revise 40 CFR 98.174(b)(2) to provide a new
option for facilities to determine the carbon content of process inputs
and outputs. Reporters are currently allowed to determine carbon
content either through direct sampling using the methods provided in 40
CFR 98.174(b)(2) or from similar analyses provided by a supplier. We
are proposing to allow reporters an additional third option to use
analyses provided by material recyclers that manage process outputs for
sale or use by other industries. Several of the process output
materials used in iron and steel production are typically sent to
recycling facilities (e.g., secondary zinc recycling facilities), which
process the material for supply to another entity. Such material
recyclers conduct testing on their inputs and products to provide to
entities using the materials downstream, and therefore perform carbon
content analyses using similar test methods and procedures as
suppliers. In the 2009 Final Rule, we determined that the use of carbon
content analyses from a material supplier was appropriate because the
carbon content does not vary widely at a given facility for the
significant process inputs and outputs that contain carbon, and because
the EPA continued to account for variations in emissions due to changes
in production rate, which are more likely to be a significant source of
variability (i.e., the quantity of carbon-containing materials that are
inputs and outputs to the process more directly influence emissions).
For these same reasons, we anticipate that analyses received from a
material recycling entity would be a reliable source of carbon content.
The proposed change would add flexibility for reporters by allowing an
additional option for obtaining measurements, in lieu of direct
sampling. We are proposing a minor harmonizing change to 40 CFR
98.176(e)(2) to require reporters to indicate if the carbon content was
determined from information supplied by a material recycler.
    We are also proposing to revise 40 CFR 98.174(b)(2) to incorporate
a new test method for carbon content analysis of low-alloy steel. The
EPA has become aware that an additional method is available for
analysis of carbon content, specifically, ASTM E415-17, Standard Test
Method for Analysis of Carbon and Low-Alloy Steel by Spark Atomic
Emission Spectrometry (2017). We have reviewed the method, which is
targeted to this sector, and have tentatively concluded it is a valid
method for the purposes of subpart Q monitoring and reporting. The EPA
allows for the use of standard methods based on atomic emission
spectrometry in other sections of the rule, including under 40 CFR
98.144(b) where it can be used to determine the composition of coal,
coke, and solid residues from combustion processes by glass production
facilities. Therefore, we are proposing to incorporate the method by
reference in 40 CR 98.7 and cross-reference that incorporation in 40
CFR 98.174(b)(2) for use for steel, as applicable. The proposed test
method would be an alternative method and would provide additional
flexibility for reporters. We are also proposing a harmonizing change
to the reporting requirements of 40 CFR 98.176(e)(2), to clarify that
the carbon content analysis methods available to report are those
methods listed in 40 CFR 98.174(b)(2).

I. Subpart S--Lime Manufacturing

    For the reasons discussed in this section and section II.A of this
preamble, we are proposing several revisions to subpart S of part 98
(Lime Manufacturing) to improve the quality of the data collected from
this subpart. First, for the reasons described in this section and in
section II.A.2 of this preamble, we are proposing to amend subpart S to
improve the methodology for calculation of annual CO2
process emissions from lime production. The proposed revisions would
account for CO2 that is captured from lime kilns and used
on-site. Under subpart S, reporters currently calculate CO2
emissions by either operating and maintaining a CEMS as specified in 40
CFR 98.193(a) or (b)(1), or by using the mass balance methodology under
40 CFR 98.193(b)(2). All lime kilns that are subject to 40 CFR
98.193(b) must calculate and report process and combustion
CO2 emissions by using the procedures in either 40 CFR
98.193(b)(1), for estimation of combined process and combustion
emissions from all lime kilns, or 40 CFR 98.193(b)(2), for estimation
of process and combustion CO2 emissions from all lime kilns
separately. For those lime kilns that use 40 CFR 98.193(b)(2),
calculation of annual CO2 process emissions from all lime
kilns is estimated through summing the following three values (per 40
CFR 98.193(b)(2)(iv)): (1) the product of a monthly site-specific
emission factor and weight or mass for each type of lime produced, (2)
the product of a monthly site-specific emission factor and each type of
calcined byproduct or waste that is sold, and (3) the annual
CO2 emissions from each type of calcined byproduct or waste
that is not sold. There is currently no allowance for subtraction of
CO2 that may be captured and used in another process on-site
(e.g., for use in a purification process or the manufacture of another
product such as refined beet sugars, precipitated calcium carbonate,
etc.).
    In response to the 2009 Proposed Rule, one subpart S reporter,
Specialty

Minerals Inc., submitted a comment that stated that subpart S does not
include a ``deduction for the carbon dioxide that is taken up as a raw
material'' for use in another product, resulting in ``an overstatement
of total carbon dioxide emissions'' from lime manufacturing.\61\ In
section III.C of this preamble, we describe similar comments received
from TFI requesting changes that would allow sources to subtract from
direct facility emissions CO2 that is being used in the
manufacturing of other products on-site.
---------------------------------------------------------------------------

    \61\ Specialty Minerals Inc.'s Comments on the Proposed 2009
Greenhouse Gas Reporting Rule, Docket Id. No. EPA-HQ-OAR-2008-0508-
0907, June 4, 2009. Also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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    Following review of these comments, the EPA has tentatively
concluded that allowing reporters subject to subpart S to report net
CO2 process emissions after subtracting out CO2
captured and used in other on-site processes would provide a more
accurate estimate of the direct GHG emissions from the lime
manufacturing process and would provide consistency in our approach
across the GHGRP. Therefore, we are proposing to modify equation S-4 to
subtract the CO2 that is captured and used in on-site
processes, with corresponding proposed revisions to the recordkeeping
requirements in 40 CFR 98.197(c) (to record the monthly amount of
CO2 from the lime manufacturing process that is captured for
use in all on-site processes). We are also proposing minor amendments
to the reporting elements in 40 CFR 98.196(b)(17) to clarify that we
only intend to collect data on CO2 that is captured and used
on-site (i.e., reporters do not need to account for CO2 that
was not captured but was used on-site), and to clarify that reporters
must account for CO2 usage from all on-site processes,
including for manufacture of other products, in the total annual amount
of CO2 captured. The proposed changes would also correct
some instances where reporters have provided values of CO2
used on-site that exceed facility emissions, where they have
inadvertently included CO2 that was not captured on-site
(e.g., CO2 purchased for water treatment), which incorrectly
implied that the facility's emissions were net negative. The proposed
amendments would not change the reporting of emissions from manufacture
of lime products, calcined lime by-products, or waste; this information
would continue to be collected. As such, the proposed amendments would
provide the same breadth of information that was previously reported to
inform future policy decisions.
    Second, for the reasons described in section II.A.4 of this
preamble, we are proposing to add reporting requirements for reporters
using the CEMS methodology in order to improve our understanding of
source category emissions and our ability to verify reported data.
Subpart S reporters who use CEMS collect CO2 emissions data
through direct measurement, and no data on the chemical composition of
the products, byproducts, or wastes at CEMS facilities are collected
through the GHGRP.\62\ As such, there is currently limited data
available to the EPA to evaluate process emissions for reporters using
CEMS. As we noted for cement production facilities in section III.D of
this preamble, CEMS facility emissions are different from non-CEMS
emissions because combustion and process emissions are typically vented
through the same stack, causing process and combustion emissions to be
mixed and indifferentiable. In order to be able to differentiate
process emissions, we are proposing to collect other data elements from
CEMS reporters that are not currently reported, including annual
average results of the chemical composition analysis of lime products,
byproducts, or wastes. Collecting average chemical composition data for
CEMS facilities will provide the EPA the ability to develop a process
emission estimation methodology for CEMS reporters, which can be used
to verify the accuracy of the reported CEMS emission data. The EPA is
proposing to add data elements under 40 CFR 98.196(a) to collect annual
averages of the chemical composition input data on a facility-basis.
The proposed data elements include the annual arithmetic average
calcium oxide content (metric tons CaO/metric tons lime) and magnesium
oxide content (metric tons MgO/metric tons lime) for each type of lime
produced, for each type of calcined lime byproduct and waste sold, and
for each type of calcined lime byproduct and waste not sold. The
proposed data elements would rely on an arithmetic average of the
measurements rather than requiring reporters to weight by quantities
produced in each month. In addition to improving verification and data
quality for the GHGRP, the proposed data elements will also improve the
U.S. GHG Inventory, which could use the proposed data elements to
disaggregate process and combustion emissions that are reported by
facilities using CEMS.
---------------------------------------------------------------------------

    \62\ Subpart S reporters who use the mass balance methodology
under 40 CFR 98.193(b)(2) currently estimate CO2
emissions using monthly chemical composition data as inputs to
calculate emissions factors for the lime produced, calcined
byproducts and wastes sold, and calcined byproducts and wastes not
sold. These data inputs are not collected by the EPA but are only
entered into the EPA's Inputs Verification Tool, which conducts
verification checks at the time of report submission but does not
retain the data entered.
---------------------------------------------------------------------------

    Similarly, in order to improve verification, we are proposing to
collect additional data elements for reporters using the mass balance
methodology (i.e., reporters that comply using the requirements at 40
CFR 98.193(b)(2)). These proposed amendments would allow the EPA to
build verification checks for the actual inputs entered (e.g., MgO
content). We currently rely on verification checks within the IVT to
check the accuracy of inputs and reported emissions from non-CEMS
reporters, however, these checks are of limited usefulness since we
lack the information to develop specific anticipated ranges or
references for the entered data. Reporters using the mass balance
methodology are currently required to report the annual average results
of chemical composition analysis of each type of lime product produced
and calcined byproduct or waste sold, but do not supply data for
byproducts or wastes not sold. The EPA is proposing to add data
elements under 40 CFR 98.196(b) to collect the annual average results
of the chemical composition analysis of all lime byproducts or wastes
not sold (e.g., a single facility average calcium oxide content
calculated from the calcium oxide content of all lime byproduct types
at the facility), and the annual quantity of all lime byproducts or
wastes not sold (e.g., a single facility total calculated as the sum of
all quantities, in tons, of all lime byproducts at the facility not
sold during the year). Because the proposed data elements rely on
annual averages of the chemical composition measurements and an annual
quantity of all lime byproducts or wastes at the facility, they are
distinct from the data entered into the EPA's IVT. These proposed data
elements would inform and improve the EPA's existing reference checks
and allow the EPA to build additional checks for the data that are
currently verified through IVT. The proposed amendments would improve
the verification of entered data and confirm the veracity of reported
emissions.
    We do not anticipate that the proposed data elements would require
any additional monitoring or data collection by reporters, as these
data are likely already available in existing company records. However,
we are requesting comment on whether any of

the above listed data elements would not be readily available to
reporters. Reporters using the mass balance methodology are expected to
have very minimal changes to reporting, as the chemical composition
averages and quantities we are proposing can be calculated from the
inputs that are currently entered into IVT. Finally, we are proposing
related confidentiality determinations for the additional data
elements, as discussed in section VI of this preamble.

J. Subpart W--Petroleum and Natural Gas Systems

    We are proposing several revisions to subpart W (Petroleum and
Natural Gas Systems). Section III.J.1 of this preamble presents
proposed amendments that would improve the quality of data collected,
including new requirements for reporting of additional emission
sources, updated emission factors, new and revised reporting
requirements, and clarification of reporting requirements that
reporters have indicated are unclear, as described in section II.A of
this preamble. We are also proposing revisions described in section
III.J.2 of this preamble that would streamline and improve
implementation, including removing redundant or unnecessary reporting
requirements, and providing additional flexibility in the calculation
methods and monitoring requirements for some emission sources, as
described in section II.B of this preamble. We are proposing the
miscellaneous technical corrections and clarifications described in
section III.J.3 of this preamble. Finally, section III.J.4 of this
preamble describes the provisions for which we propose subpart W
reporters would be able to use best available monitoring methods (BAMM)
for RY2023. We are also proposing related confidentiality
determinations for new or revised data elements that result from these
proposed amendments, as discussed in section VI of this preamble.
    In addition, on November 15, 2021 (86 FR 63110), the EPA proposed
under CAA section 111(b) NSPS for new, reconstructed, and modified oil
and natural gas sources, i.e., sources for which owners or operators
commence construction, modification, or reconstruction after November
15, 2021 (40 CFR part 60, subpart OOOOb) (hereafter referred to as
``NSPS OOOOb''), as well as emissions guidelines under CAA section
111(d) for existing oil and natural gas sources, i.e., sources for
which owners or operators commence construction, modification, or
reconstruction on or before November 15, 2021 (40 CFR part 60, subpart
OOOOc) (hereafter referred to as ``EG OOOOc'') (the sources affected by
these two proposed subparts are collectively referred to in this
preamble as ``affected sources''). While the standards in NSPS OOOOb
would directly apply to new, reconstructed, and modified sources when
finalized, the final EG OOOOc would not impose binding requirements
directly on sources; rather it would contain guidelines, including
presumptive standards, for states to follow in developing, submitting,
and implementing plans to establish standards of performance to limit
GHGs (in the form of methane limitations) from existing oil and gas
sources within their own states. If a state does not submit a plan to
the EPA for approval in response to the final emission guidelines, or
if the EPA disapproves a state's plan, then the EPA must establish a
Federal plan that would apply to existing sources within that state
that are not covered by a state plan. In addition, a Federal plan could
apply to facilities located on tribal land that do not request approval
to develop a tribal implementation plan similar to a state plan. Once
the Administrator approves a state plan under CAA section 111(d), the
plan is codified in 40 CFR part 62 (Approval and Promulgation of State
Plans for Designated Facilities and Pollutants) within the relevant
subpart for that state.\63\ 40 CFR part 62 also includes all Federal
plans promulgated pursuant to CAA section 111(d). Therefore, rather
than referencing the presumptive standards in EG OOOOc, which would not
directly apply to sources, the proposed amendments to subpart W
reference 40 CFR part 62.
---------------------------------------------------------------------------

    \63\ 40 CFR part 62 contains a subpart for each of the 50
states, District of Columbia, American Samoa, Puerto Rico, Virgin
Islands, and Northern Mariana Islands.
---------------------------------------------------------------------------

    Similar to the 2016 amendments to align subpart W with certain
requirements in 40 CFR part 60, subpart OOOOa (hereafter referred to as
``NSPS OOOOa'') (81 FR 86500, November 30, 2016), we are proposing
revisions to certain requirements in subpart W relative to the
requirements proposed for NSPS OOOOb and the presumptive standards
proposed in the EG OOOOc (which would inform the standards to be
developed and codified under 40 CFR part 62). Specifically, we are
proposing amendments to the subpart W calculation methodologies for
natural gas pneumatic devices and equipment leak surveys related to the
proposed NSPS OOOOb and presumptive standards in EG OOOOc, and we are
proposing new reporting requirements for ``other large release events''
as defined in subpart W that would reference the NSPS OOOOb and
approved state plans or applicable Federal plan in 40 CFR part 62.
These proposed amendments are described in sections III.J.1.a, k, and
m, respectively. These proposed amendments, if finalized, would not
apply to individual reporters unless and until their emission sources
are required to comply with either the final NSPS OOOOb or an approved
state plan or applicable Federal plan in 40 CFR part 62. In the
meantime, reporters would comply with the applicable provisions of
subpart W for sources not subject to NSPS OOOOb or 40 CFR part 62.
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart W
    As further described in section II.A of this preamble, the EPA is
proposing amendments that would ensure that accurate data are being
collected under the rule, improve the accuracy of emissions reported
under part 98, and enhance the overall quality of the data collected
under the GHGRP. Consistent with section II.A.1 of this preamble, we
are proposing to incorporate recent data to update selected subpart W
emission factors. Where emission factors are currently provided in
subpart W for certain emission source types, those emission factors
were based on the best available public data at the time that subpart W
was promulgated. In the years since promulgation of subpart W,
additional data have been collected for some source types as part of
emissions studies, and the EPA has reviewed and evaluated the data in
these studies. Based on those evaluations, the EPA is proposing to
update selected subpart W population emission factors \64\ for natural
gas pneumatic device vents across a variety of industry segments and
equipment leaks from the Onshore Petroleum and Natural Gas Production,
Onshore Petroleum and Natural Gas Gathering and Boosting, and Natural
Gas Distribution industry segments. The EPA is also proposing revisions
to the leaker emission factors for all industry segments conducting
equipment leak surveys to account for differences in the leak detection
methodologies. Consistent with section II.A.2 of this preamble, the EPA
is proposing amendments to improve calculation methodologies for
emissions from natural gas pneumatic pumps,

centrifugal compressors, reciprocating compressors, equipment leak
surveys, combustion units, and sources that use the acoustic leak
detection method for leak detection. Consistent with section II.A.3 of
this preamble, we are proposing to add calculation and reporting
requirements for ``other large release events,'' which are emission
events that are not sufficiently accounted for using the current
subpart W methodologies, and emissions from uncombusted methane from
compressor engines. We are also proposing to require facilities in the
Onshore Natural Gas Processing industry segment to begin calculating
and reporting emissions from natural gas pneumatic devices and
proposing to require facilities in the LNG Import/Export industry
segment to begin calculating and reporting emissions from acid gas
removal vents. Consistent with section II.A.4 of this preamble, we are
proposing to add or revise reporting requirements to better understand
and characterize the emissions from acid gas removal units, glycol
dehydrator vents, liquids unloadings, atmospheric storage tanks,
associated gas flaring, flare stacks, and equipment leaks, as well as
to better characterize facilities in the Onshore Petroleum and Natural
Gas Gathering and Boosting industry segment. Finally, consistent with
section II.A.5 of this preamble, we are proposing to clarify
calculation and reporting requirements for natural gas pneumatic
devices, natural gas driven pneumatic pumps, blowdown vent stacks,
atmospheric storage tanks (including requirements for open thief
hatches), associated gas venting and flaring, centrifugal and
reciprocating compressors, combustion devices, and facilities in the
Onshore Natural Gas Transmission Pipeline industry segment, in part to
address questions asked by reporters to the GHGRP Help Desk and in
verification correspondence via e-GGRT.
---------------------------------------------------------------------------

    \64\ When the total emissions from all leaking sources of the
same type are divided by the total count of that source type, then
the resultant factor is referred to as a population emission factor.
When the total emissions from all leaking sources of the same type
are divided by the total count of leaking sources for that source
type, then the resultant factor is referred to as a leaker emission
factor.
---------------------------------------------------------------------------

a. Natural Gas Pneumatic Device Vents
    Revisions to emission factors. Subpart W requires calculation of
GHG emissions from natural gas pneumatic device venting using default
population emission factors multiplied by the number of devices and the
average time those devices are ``in-service'' (i.e., supplied with
natural gas). Subpart W provides two sets of pneumatic device emission
factors, one for devices in the Onshore Petroleum and Natural Gas
Production and Onshore Petroleum and Natural Gas Gathering and Boosting
industry segments and one for the Onshore Natural Gas Transmission
Compression and Underground Natural Gas Storage industry segments. Each
set of emission factors consists of emission factors for three
different types of natural gas pneumatic devices: continuous low bleed
devices, continuous high bleed devices, and intermittent bleed
devices.\65\
---------------------------------------------------------------------------

    \65\ The development of the current emission factors for natural
gas pneumatic devices is described in Greenhouse Gas Emissions
Reporting from the Petroleum And Natural Gas Industry: Background
Technical Support Document, U.S. EPA, November 2010, (Docket Id. No.
EPA-HQ-OAR-2009-0923-3610), also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    The EPA has become aware of several studies on emissions from
natural gas pneumatic device vents since subpart W was first
promulgated. For example, in April 2015, the EPA reviewed three
recently published studies on emissions from pneumatic devices (also
referred to as ``pneumatic controllers'' within the studies as well as
in NSPS OOOOa, NSPS OOOOb, and EG OOOOc) at onshore production
facilities and evaluated those studies for use in the U.S. GHG
Inventory.\66\ As part of this proposed rulemaking, we have reviewed
these and other available studies to evaluate the potential for
revisions to the natural gas pneumatic device emission factors in
subpart W. For more information regarding this review, see the document
Greenhouse Gas Reporting Rule: Technical Support for Revisions and
Confidentiality Determinations for Data Elements Under the Greenhouse
Gas Reporting Rule; Proposed Rule--Petroleum and Natural Gas Systems,
(hereafter referred to as ``subpart W TSD''), available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    \66\ U.S. EPA. Inventory of U.S. Greenhouse Gas Emissions and
Sinks: Potential Revisions to Pneumatic Controller Emissions
Estimate (Production Segment). April 2015. Available at https://www.epa.gov/sites/production/files/2015-12/documents/ng-petro-inv-improvement-pneumatic-controllers-4-10-2015.pdf.
---------------------------------------------------------------------------

    As part of our review, we found there are significantly more data
available now by which to characterize pneumatic device emissions.
Therefore, consistent with section II.A.1 of this preamble, we are
proposing to amend the emission factors for the Onshore Petroleum and
Natural Gas Production, Onshore Petroleum and Natural Gas Gathering and
Boosting, Onshore Natural Gas Transmission Compression, and Underground
Natural Gas Storage industry segments. We are also proposing to add
pneumatic device venting as an emission source for the Onshore Natural
Gas Processing industry segment using the same emission factors we are
proposing for the Onshore Natural Gas Transmission Compression and
Underground Natural Gas Storage industry segments, consistent with
section II.A.3 of this preamble.
    Intermittent bleed pneumatic devices subject to surveys. As part of
our review to characterize pneumatic device emissions, we found a
significant difference in the emissions from intermittent bleed
pneumatic devices that appeared to be functioning as intended (short,
small releases during device actuation) and those that appeared to be
malfunctioning (continuously emitting or exhibiting large or prolonged
releases upon actuation). For natural gas intermittent bleed pneumatic
devices, it is possible to identify malfunctioning devices through
routine monitoring using optical gas imaging (OGI) or other
technologies. As noted in the introduction to section III.J of this
preamble, the EPA recently proposed NSPS OOOOb and EG OOOOc for oil and
natural gas sources. Under the proposed standards in NSPS OOOOb and the
proposed presumptive standards in EG OOOOc (which would inform the
state plans or, if necessary, the Federal plan in 40 CFR part 62),
nearly all covered pneumatic devices (continuous bleed and intermittent
vent) would be required to have a methane and volatile organic compound
(VOC) emission rate of zero. The only exception would be for pneumatic
devices in Alaska at locations where on-site power is not available, in
which case owners and operators would be required to use low bleed
pneumatic devices in place of high bleed pneumatic devices (unless a
high bleed device is needed for a functional need such as safety), and
to verify that any intermittent bleed pneumatic devices operate such
that they do not vent when idle by monitoring these devices during the
fugitive emissions survey.
    We envision relatively few intermittent bleed pneumatic devices
under the proposed zero-emission standard and presumptive standard for
these pneumatic devices, compliance with which would require the use of
non-emitting devices. As noted in the previous paragraph, we proposed
in NSPS OOOOb and EG OOOOc to require periodic monitoring of those few
intermittent bleed pneumatic devices. In addition, as noted in section
III.J of this preamble, the proposed amendments that would apply to
sources subject to the NSPS OOOOb and approved state plans or
applicable Federal plan in 40 CFR part 62 would not become effective
for individual reporters unless and until their emission sources become
subject to and are required to comply with either the final NSPS OOOOb
or an

approved state plan or applicable Federal plan in 40 CFR part 62. Prior
to that time, a reporter may elect to conduct inspections or surveys of
their intermittent bleed pneumatic devices. Therefore, similar to the
2016 amendments to subpart W (81 FR 4987, January 29, 2016), the EPA is
proposing amendments to subpart W to provide an alternative methodology
to calculate emissions from intermittent bleed pneumatic devices based
on the results of inspections or surveys, consistent with section
II.A.2 of this preamble. Specifically, for facilities that would be
required to inspect their intermittent bleed pneumatic devices
requirements under NSPS OOOOb or an approved state plan or the
applicable Federal plan in 40 CFR part 62 (to the extent there are any)
or facilities that elect to conduct routine monitoring surveys of their
existing natural gas intermittent bleed pneumatic devices consistent
with the methods in NSPS OOOOb prior to becoming subject to 40 CFR part
62, we are proposing to provide an alternative calculation methodology
analogous to a ``leaker factor'' approach used for equipment leaks.
Reporters using this calculation methodology would report the total
number of natural gas intermittent bleed pneumatic devices at the
facility, the frequency of monitoring, the number of devices found to
be malfunctioning, and the average time the malfunctioning devices were
malfunctioning. For more information regarding this proposed
alternative calculation methodology for natural gas intermittent bleed
pneumatic devices, see the subpart W TSD, available in the docket for
this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
    Hours of operation of natural gas pneumatic devices and natural gas
driven pneumatic pumps. In correspondence with the EPA via e-GGRT,
reporters have indicated that there is confusion over the use of the
term ``operational'' in the definition of variable ``Tt'' in
equation W-1 in 40 CFR 98.233(a) and the term ``in operation'' in the
reporting requirements in 40 CFR 98.236(b)(2). Both the current
emission factors and the proposed updated emission factors described
earlier in this section for natural gas pneumatic devices were
developed by taking both periods of actuation and periods without
actuation into account; \67\ in other words, the emission factors are
population emission factors. To calculate emissions accurately using a
population emission factor, the average number of hours used in
equation W-1 should be the number of hours that the devices of a
particular type are in service (i.e., the devices are receiving a
measurement signal and connected to a natural gas supply that is
capable of actuating a valve or other device as needed). Therefore,
consistent with section II.A.5 of this preamble, we are proposing to
revise the definition of variable ``Tt'' in equation W-1 and
the corresponding reporting requirement in 40 CFR 98.236(b)(2) to use
the term ``in service (i.e., supplied with natural gas)'' rather than
``operational'' or ``in operation.''
---------------------------------------------------------------------------

    \67\ As noted previously, the development of the current
emission factors for natural gas pneumatic devices is described in
Greenhouse Gas Emissions Reporting from the Petroleum And Natural
Gas Industry: Background Technical Support Document, U.S. EPA,
November 2010, (Docket Id. No. EPA-HQ-OAR-2009-0923-3610), also
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
---------------------------------------------------------------------------

    Similarly, the population emission factor for natural gas driven
pneumatic pumps was developed using measurements taken during
actuations together with manufacturer data and observed operational
data at facilities (e.g., pump actuation rate).\68\ In other words, the
emission factor represents the average emissions over the period when
the pump is operating, not just the emissions during periods when the
pump was actuating. Therefore, we are also proposing to revise the
definition of variable ``T'' in equation W-2 in 40 CFR 98.233(c)(1) for
natural gas driven pneumatic pumps to use the term ``in service (i.e.,
supplied with natural gas),'' and we are proposing to use that same
term in the corresponding reporting requirement in proposed 40 CFR
98.236(c)(4).
---------------------------------------------------------------------------

    \68\ The development of the emission factor for natural gas
pneumatic pumps is described in Greenhouse Gas Emissions Reporting
from the Petroleum And Natural Gas Industry: Background Technical
Support Document, U.S. EPA, November 2010, (Docket Id. No. EPA-HQ-
OAR-2009-0923-3610), also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

b. Natural Gas Driven Pneumatic Pump Venting
    The current procedures in subpart W for calculating and reporting
emissions from natural gas driven pneumatic pump venting are specified
in 40 CFR 98.233(c) and 40 CFR 98.236(c). The inputs to equation W-2 in
40 CFR 98.233(c) are the total number of natural gas driven pneumatic
pumps and average estimated number of hours in the operating year the
pumps were operational. Reporters then report these inputs along with
the emissions under 40 CFR 98.236(c). As the calculated emissions are
vented emissions from natural gas driven pneumatic pumps, the intent is
that the total number of natural gas driven pneumatic pumps should
include only those pumps that are vented directly to the atmosphere
(i.e., uncontrolled). However, based on contact with reporters, we
understand that emissions from some natural gas driven pneumatic pumps
are routed to controls, particularly flares or combustion units. Flared
emissions from natural gas driven pneumatic pumps are not required to
be calculated and reported separately from other flared emissions.
Instead, emission streams from natural gas driven pneumatic pumps that
are routed to flares are required to be included in the calculation of
total emissions from the flare according to the procedures in 40 CFR
98.233(n) and reported as part of the total flare stack emissions
according to the procedures in 40 CFR 98.236(n), in the same manner as
emission streams from other source types that are routed to the flare.
Similarly, emissions from natural gas driven pneumatic pumps that are
routed to a combustion unit are required to be combined with other
streams of the same fuel type and used to calculate total emissions
from the combustion unit as specified in 40 CFR 98.233(z) and reported
as part of the total emissions from the combustion unit as specified in
40 CFR 98.236(z).
    In correspondence with the EPA via e-GGRT, some reporters have
expressed confusion regarding the requirements for natural gas driven
pneumatic pumps that are routed to flares or combustion devices,
particularly between 40 CFR 98.236(c) (for vented emissions) and 40 CFR
98.236(n) or (z) (for flared or combusted emissions, respectively).
Additionally, the counts of controlled natural gas driven pneumatic
pumps currently are not reported separately from counts of vented
natural gas driven pneumatic pumps under 40 CFR 98.236(c), and the
emissions currently reported from flares and combustion units are not
attributed specifically to natural gas driven pneumatic pumps. This
lack of reported information leads to uncertainty in verification of
reported data when there are significant changes in reported data at a
facility from one year to the next, which can result in additional
communication with the reporter to clarify whether or not the changes
are an error. The lack of reported information also means changes in
the trends related to implementation of such controls relative to
trends in overall use of natural gas driven pneumatic pumps in the
petroleum and natural gas systems source category would be difficult to
track. In addition, there are other rules

that require the control of pneumatic pumps (e.g., NSPS OOOOa), so we
expect that there will be an increase in the number of natural gas
driven pneumatic pumps that are routed to controls as more facilities
become subject to those rules.
    Thus, consistent with section II.A.2 of this preamble, we are
proposing to revise 40 CFR 98.233(c) to clarify requirements for
calculating emissions from both natural gas driven pneumatic pumps that
are vented to the atmosphere and controlled natural gas driven
pneumatic pumps that are consistent with the intent of the current
rule. Specifically, we are proposing to revise 40 CFR 98.233(c)
introductory text and the definitions of the terms ``Count'' and ``T''
in equation W-2 to further clarify that the provisions of 40 CFR
98.233(c)(1) and (2) should only be used to calculate emissions from
natural gas driven pneumatic pumps venting directly to the atmosphere.
We are proposing to add 40 CFR 98.233(c)(3) to specify that if the
emissions are flared, then flared emissions would be calculated using
the method for flare stack emissions in 40 CFR 98.233(n) and reported
as flare stack emissions under 40 CFR 98.236(n). If emissions are
routed to a combustion device, then emissions would be calculated using
the methods for combustion devices as specified in 40 CFR 98.233(z) and
reported as specified in 40 CFR 98.236(z). Finally, if the emissions
are routed to vapor recovery and are not subsequently routed to a
combustion device, then we are proposing that reporters would not
calculate or report emissions. If a natural gas driven pneumatic pump
is vented directly to the atmosphere for part of the year and routed to
a flare, combustion, or vapor recovery system during another part of
the year, the reporter would calculate emissions using all applicable
procedures and adjust the number of hours used in equation W-2 as
needed. We request comment on whether pneumatic pumps are routed to
vapor recovery systems and whether there are other controls that should
be addressed with these new provisions. In addition, we request comment
on whether flared emissions associated with natural gas driven
pneumatic pumps should continue to be reported as flare stack emissions
under 40 CFR 98.236(n) or should be reported in the natural gas driven
pneumatic pumps emission source under 40 CFR 98.236(c).
    We are also proposing to add new reporting elements in 40 CFR
98.236(c) to align with the proposed clarifications to the emission
calculation procedures. Specifically, we are proposing to expand the
current requirement to report the total count of natural gas driven
pneumatic pumps to three separate counts: the number of natural gas
driven pneumatic pumps that are vented directly to atmosphere (i.e.,
uncontrolled); the number of natural gas driven pneumatic pumps that
are routed to a flare, combustion, or vapor recovery (i.e.,
controlled); and the total number of natural gas driven pneumatic pumps
at the facility. The total count of pneumatic pumps is a proposed
reporting element along with the counts of uncontrolled and controlled
pneumatic pumps because the total count would not always be equal to
the sum of the other two counts. For example, a reporter that switches
from one scenario to another during a year for a particular pneumatic
pump (e.g., from vented to flared) would include that pneumatic pump in
the count of pumps that vent directly to atmosphere and in the count of
pumps that are routed to flares, but that pneumatic pump would only be
counted once towards the total number of pneumatic pumps. The number of
pneumatic pumps vented directly to the atmosphere would be equal to the
``Count'' in equation W-2 and would be used in the verification of
annual reports to the GHGRP. The total count of pneumatic pumps at the
facility and the number of pneumatic pumps that are routed to a flare,
combustion, or vapor recovery would provide the EPA with information to
better characterize emissions from this source, including how many
pneumatic pumps are controlled across the industry, how often pneumatic
pumps are both controlled and vented directly to the atmosphere in the
same year, and how the use of controls for pneumatic pumps changes
across multiple years.
c. Acid Gas Removal Vents
    Acid Gas Removal Units at LNG Import/Export Facilities. Emissions
from acid gas removal units are currently reported for three industry
segments: Onshore Petroleum and Natural Gas Production, Onshore Natural
Gas Processing, and Onshore Petroleum and Natural Gas Gathering and
Boosting. However, prior to becoming LNG, natural gas is treated to
specifications more stringent than pipeline quality natural gas to
remove nearly all of the heavy hydrocarbons, mercury, CO2,
sulfur compounds, and other impurities to prevent problems with the
liquefaction process (e.g., CO2 and hydrogen sulfide can
cause freezing and plugging in downstream units once the gas is
liquefied). Therefore, liquefaction plants at LNG export facilities may
include acid gas removal units, and those emissions are not currently
reported to the GHGRP if the acid gas removal unit vents are vented
directly to the atmosphere. Emissions from acid gas removal unit vents
that are routed to flares or thermal oxidizers that meet the subpart W
definition of flare in 40 CFR 98.238 are reported under the flare
stacks emission source, but they are not characterized as acid gas
removal emissions. LNG export facilities may receive natural gas that
has already been treated in a natural gas processing plant as well as
raw material from dedicated gas fields, so the emissions from acid gas
removal units at these facilities can comprise a significant portion of
the facility's emissions if the gas received at an LNG export facility
has a relatively high CO2 content.\69\
---------------------------------------------------------------------------

    \69\ American Petroleum Institute (API). Liquefied Natural Gas
(LNG) Operations Consistent Methodology for Estimating Greenhouse
Gas Emissions. Prepared for API by The LEVON Group, LLC. Version
1.0, May 2015. Available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    Therefore, consistent with section II.A.3 of this preamble, the EPA
is proposing to revise 40 CFR 98.232(h) and 40 CFR 98.236(a)(7) to add
acid gas removal vents to the list of emission sources for which
facilities in the LNG Import/Export industry segment must calculate and
report emissions. Facilities in this industry segment with an acid gas
removal unit would use one of the four calculation methods currently
provided in 40 CFR 98.233(d) and report emissions as currently provided
in 40 CFR 98.236(d). Facilities in this industry segment without an
acid gas removal unit would only be required to indicate that in their
report. We request comment on whether all four calculation methods
currently provided in 40 CFR 98.233(d) are appropriate for facilities
in the LNG Import/Export industry segment and if not, how specific
calculation methods could be adjusted to be more applicable to this
industry segment. In addition, we request comment on whether there are
other emission sources at LNG Import/Export facilities with significant
emissions that should be added to subpart W (e.g., glycol dehydrators),
as well as whether there are other industry segments with acid gas
removal units that are not reported and make up a significant portion
of facility emissions.
    Calculation method 4 reporting. Reporters with acid gas removal
units that elect to calculate emissions using Calculation Method 4 are
required to report several data elements that are inputs to the
simulation software package that is used to calculate

emissions. One of the required inputs to report is the solvent weight,
in pounds per gallon (40 CFR 98.236(d)(2)(iii)(L)). A variety of
different solvents may be used in an acid gas removal unit (e.g.,
chemical solvents such as monoethanolamine (MEA) and methyl
diethanolamine (MDEA), physical solvents such as SelexolTM
and Rectisol[supreg]), and the solubility of CO2 varies
across the different types of solvent. Requiring reporters to provide
solvent characteristics provides information about the type of solvent
used so the emissions calculated by the modeling run could be verified.
However, the ``solvent weight'' is the only data element related to the
identification of the solvent that is currently collected, and the
values reported across all reporters have been inconsistent over the
last few years, indicating that this data element is likely not clear
to reporters (e.g., some reporters appear to be providing the density
of the solvent and others appear to be providing the amine
concentration in weight percent). In addition, the densities of common
amine-based solvents are fairly close in value, so even among reporters
that are providing values within the expected range of solvent
densities, we have found it difficult to use this data element to
identify the solvent type. Finally, the current requirement to report
solvent weight does not specify how this value should be determined,
but given the precise values being reported, it appears that reporters
are either measuring the solvent or reporting a specific value provided
by the vendor.
    Therefore, we are proposing to replace the requirement to report
solvent weight with a requirement to report the solvent type and, for
amine-based solvents, the general composition. Reporters would choose
the type/general composition option from a pre-defined list that most
closely matches the solvent type and composition used in their acid gas
removal unit. The standardized response options would include the
following: ``SelexolTM,'' ``Rectisol[supreg],''
``PurisolTM,'' ``Fluor SolventSM,''
``BenfieldTM,'' ``20 wt% MEA,'' ``30 wt% MEA,'' ``40 wt%
MDEA,'' ``50 wt% MDEA,'' and ``Other.'' We are proposing to use
commercially available trade names in this list rather than chemical
compositions, as the trade names are more commonly used among acid gas
removal unit operators and therefore more readily available. This
proposed amendment to collect standardized information about the
solvent is expected to result in more useful data that would improve
verification of reported data and better characterize acid gas removal
vent emissions, consistent with section II.A.4 of this preamble. It
would also improve the quality of the data reported compared to the
apparently inconsistent application of the current requirements. In
addition, the solvent type and composition rarely change from one year
to the next, so once the data element is reported the first time, most
reporters would be able to copy the response from the previous year's
reporting form each year. Therefore, the proposal to require reporters
to select a solvent type and composition from these standardized
responses is also expected to streamline and improve implementation
compared to the current requirement of reporting an exact value for
solvent weight, consistent with section II.B.3 of this preamble.
d. Dehydrator Vents
    Dehydrators are used to remove water from produced natural gas
prior to transferring the natural gas into a pipeline or to a gas
processing facility. Subpart W requires reporting of GHG emissions from
dehydrator vents at onshore petroleum and natural gas production,
onshore petroleum and natural gas gathering and boosting, and natural
gas processing facilities. Emissions are determined using one of the
calculation methodologies for glycol dehydrators provided in 40 CFR
98.233(e) based on the unit's annual average daily natural gas
throughput. For units with an annual average daily natural gas
throughput less than 0.4 MMscf per day, reporters currently use
population emission factors and equation W-5 to calculate volumetric
CO2 and CH4 emissions per 40 CFR 98.233(e)(2).
For units with an annual average daily natural gas throughput greater
than or equal to 0.4 MMscf per day, reporters must follow the
provisions under 40 CFR 98.233(e)(1), which require modeling GHG
emissions using a software program (e.g., AspenTech HYSYS[supreg] \70\
or GRI-GLYCalcTM \71\).
---------------------------------------------------------------------------

    \70\ AspenTech HYSYS[supreg] software available from AspenTech
website (https://www.aspentech.com/).
    \71\ GRI-GLYCalcTM software available from Gas
Technology Institute website (https://sales.gastechnology.org/).
---------------------------------------------------------------------------

    The EPA has reviewed the subpart W glycol dehydrator data and
reporting requirements in 40 CFR 98.236(e) and has made a preliminary
determination that additional information would help to more accurately
characterize emissions from glycol dehydrators with an annual average
daily natural gas throughput greater than or equal to 0.4 MMscf per
day. Specifically, the EPA's review found no strong correlations
between glycol dehydrator emissions and the operating parameters
currently reported under 40 CFR 98.236(e)(1). This assessment is
consistent with the results of an analysis provided to the EPA by GPA
Midstream, which indicated that the correlations between vent gas flow
rate, glycol circulation rate, and glycol pump type provided the most
accurate approximation of dehydrator emissions.\72\ While subpart W
does currently collect information on glycol pump type and circulation
rate for each modeled glycol dehydrator with an annual average daily
natural gas throughput greater than or equal to 0.4 MMscf per day,
reporters are not asked to report any characteristics of their units'
flash tank and still vents, including vent gas flow rate. As such, the
EPA is not able to review historical subpart W dehydrator data to
verify GPA Midstream's suggested correlation between vent gas flow
rate, glycol circulation rate, and glycol pump type. Therefore, the EPA
is proposing to add new reporting requirements to 40 CFR 98.236(e)(1),
consistent with section II.A.4 of this preamble. The following new data
elements are proposed to be added to subpart W for glycol dehydrators
with an annual average daily natural gas throughput greater than or
equal to 0.4 MMscf per day:
---------------------------------------------------------------------------

    \72\ GPA Midstream Association. Presentation slides regarding
three alternatives for possible development of emission factors for
large glycol dehydrators. November 20, 2019. Available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.

 Flash tank control technique
 Regenerator still vent control technique
 Flash tank vent gas flow rate (standard cubic feet per hour
(scfh))
 Regenerator still vent gas flow rate (scfh)
 Concentrations of CH4 and CO2 in flash
tank vent gas (mole fraction)
 Concentrations of CH4 and CO2 in
regenerator still vent gas (mole fraction)
 Type of stripping gas used
 Flow rate of stripping gas (standard cubic feet per minute
(scfm))

    These proposed additional data elements are intended to allow the
EPA to derive a correlation between vent flow rate and absorbent
circulation rate and better characterize emissions from glycol
dehydrators with an annual average daily natural gas throughput greater
than or equal to 0.4 MMscf per day. Further, the EPA is proposing to
require separate reporting of emissions for a modeled glycol
dehydrator's still vent and flash tank vent. These vents

often use different control techniques, so requiring the emissions from
these vents to be reported separately would ensure that future analyses
accurately characterize the emissions. The proposed data elements are
included in the output files from the modeling software used for glycol
dehydrators and are, therefore, not expected to be difficult for
reporters to implement.
    Additionally, in correspondence with the EPA via e-GGRT, some
reporters have expressed confusion regarding the requirements for
glycol dehydrators emissions that are routed to vapor recovery and
subsequently routed to a flare or regenerator firebox/fire tubes. As
such, the EPA is proposing edits to the vapor recovery calculation
methodology of 40 CFR 98.233(e)(5) (proposed to be moved to 40 CFR
98.233(e)(4)) to clarify that unrecovered emissions that are not routed
to flares or regenerator fireboxes/fire tubes should be reported as
emissions vented directly to atmosphere, while emissions that are
routed to flares or regenerator fireboxes/fire tubes should be reported
as flared emissions from dehydrators. Along with the proposed
amendments to 40 CFR 98.233(e)(6) (proposed to be moved to 40 CFR
98.233(e)(5)) for calculating emissions from flares or regenerator
fireboxes/fire tubes (discussed in section III.J.1.i of this preamble),
the EPA seeks to enhance the overall quality of the data collected
under the GHGRP, consistent with section II.A.5 of this preamble.
e. Liquids Unloading
    Subpart W currently requires reporting of emissions from well
venting for liquids unloading. Facilities calculate emissions using
measured flow rates under Calculation Method 1 (40 CFR 98.233(f)(1)) or
engineering equations under Calculation Method 2 for unloadings without
plunger lifts (40 CFR 98.233(f)(2)) and Calculation Method 3 for
unloadings with plunger lifts (40 CFR 98.233(f)(3)). Under the
reporting requirements of 40 CFR 98.236(f), facilities must report
whether plunger lifts were used when using Calculation Method 1 and
must report the data elements used in equations W-7A and W-7B. For
Calculation Methods 2 and 3, however, reporters only report a subset of
the data elements used to calculate emissions in equations W-8 and W-9.
Specifically, for Calculation Methods 2 and 3, reporters must provide a
plunger lift indicator (i.e., whether plunger lifts were used), total
number of wells with well venting for liquids unloading, the total
number of unloading events, and the casing diameter (Calculation Method
2) or the tubing diameter (Calculation Method 3).
    In a 2019 study, Zaimes et al.\73\ evaluated various liquid
unloading scenarios, and the results indicated that differentiating
emissions only on the basis of type of unloading (plunger or non-
plunger lift) may not accurately assess emissions from this source. In
particular, Zaimes et al. noted that type of unloading should be
further differentiated for plunger lift unloadings between automated
and manual unloadings, suggesting further granularity is necessary to
properly characterize emissions. In particular, there could be
significant differences in the number and duration of unloadings and,
hence, differences in emissions between manual and automated plunger
lift unloadings and liquids unloading emissions.
---------------------------------------------------------------------------

    \73\ Zaimes, G.G. et al. ``Characterizing Regional Methane
Emissions from Natural Gas Liquid Unloading.'' Environ. Sci.
Technol. 2019, 53, 4619-4629. Available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    The Zaimes et al. study did not evaluate manual and automated non-
plunger lift unloadings separately, but further differentiating non-
plunger lift unloadings between manual and automated unloadings in
subpart W could also improve data quality. Correspondence with
reporters via e-GGRT since subpart W reporting for the onshore
production segment began in 2011 indicates potentially significant
differences in the number of unloadings and emissions for manual versus
automated non-plunger lift unloadings. When the EPA finalized the
calculation methods and reporting requirements for well venting for
liquids unloading, the reporting requirements did not differentiate
between manual and automated non-plunger lift unloadings. However,
reporters have clearly affirmed the use of automated non-plunger lift
unloadings in response to multiple inquiries the EPA has made as part
of the annual report verification process.
    In addition, there are several data elements used to calculate
emissions from liquids unloading in equations W-8 and W-9 for
Calculation Methods 2 and 3 that are not currently required to be
provided. Specifically, reporters do not report well depth (Calculation
Method 2) or tubing depth (Calculation Method 3), the average flow-line
rate of gas, the hours that wells are left open to the atmosphere
during unloading events, and the shut-in, surface or casing pressure
(Calculation Method 2) or the flow-line pressure (Calculation Method
3). Requiring reporting of these data elements would improve
verification of annual reports to the GHGRP and would allow the EPA and
the public to replicate calculations and more confidently confirm
reported calculated emissions than is currently possible.
    The EPA is, therefore, proposing to revise the reporting
requirements in 40 CFR 98.236(f)(1) and (2) to require reporters to
include the following data elements, consistent with section II.A.4 of
this preamble. In 40 CFR 98.236(f)(1), for Calculation Method 1, the
EPA is proposing that reporters would identify the type of unloading as
an automated or manual unloading in addition to identifying whether the
unloading is a plunger lift or non-plunger lift unloading. We are also
proposing that reporters would report emissions from automated
unloadings separately from manual unloadings. In addition, for each
individual Calculation Method 1 well that was tested during the year,
we are proposing that reporters would specify the type of unloading as
an automated or manual unloading under 40 CFR 98.236(f)(1)(xi)(F) or 40
CFR 98.236(f)(1)(xii)(F), as applicable.
    For non-plunger lift unloadings that use Calculation Method 2 in 40
CFR 98.233(f)(2), the EPA is proposing that reporters would identify
the type of non-plunger lift unloading as an automated or manual non-
plunger lift unloading and that reporters would report emissions and
activity data separately for each unloading type. In addition, for all
non-plunger lift unloadings, the EPA is proposing to add requirements
in 40 CFR 98.236(f)(2)(ix) (proposed to be moved to 40 CFR
98.236(f)(2)(xi)) to report the average well depth for all wells in the
sub-basin (WDp) and the average shut-in pressure or surface
pressure for wells with tubing production, or average casing pressure
for wells with no packers for all wells in the sub-basin
(SPp).
    For plunger lift unloadings that use Calculation Method 3 in 40 CFR
98.233(f)(3), the EPA is proposing that reporters would identify the
type of plunger lift unloading as an automated or manual plunger lift
unloading and that reporters would report emissions and activity data
separately for each unloading type. In addition, for all plunger lift
unloadings, the EPA is proposing to add requirements in 40 CFR
98.236(f)(2)(x) (proposed to be moved to 40 CFR 98.236(f)(2)(xii)) to
report the average tubing depth to plunger bumper for all wells in the
sub-basin (WDp) and the average flow-line pressure for all
wells in the sub-basin (SPp). Finally, for all unloadings
that use Calculation Method 2 or 3, the EPA is proposing to add
requirements in 40

CFR 98.236(f)(2)(ix) and (x) to report the average flow-line rate of
gas for all wells in the sub-basin (SFRp) and cumulative
number hours that all wells in the sub-basin are left open to the
atmosphere during unloading events (HRp,q), respectively.
f. Blowdown Vent Stacks
    Subpart W currently requires reporting of blowdowns either using
flow meter measurements (40 CFR 98.233(i)(3)) or using unique physical
volume calculations by equipment or event types (40 CFR 98.233(i)(2)).
Stakeholders have indicated that there is some confusion regarding the
reference to ``distribution'' pipelines in the descriptions of the
``facility piping'' and ``pipeline venting'' categories because
compressor stations are not associated with distribution pipelines.
Therefore, the EPA is proposing to revise the descriptions of the
facility piping and pipeline venting categories to reduce confusion
regarding which equipment or event type category is appropriate for
each blowdown, consistent with section II.A.5 of this preamble. Our
intent is that the ``facility piping'' equipment category is limited to
unique physical volumes of piping (i.e., piping between isolation
valves) that are located entirely within the facility boundary.
Conversely, the intent for the ``pipeline venting'' equipment category
is that a portion of the unique physical volume of pipeline is located
outside the facility boundary and the remainder, including the blowdown
vent stack, is located within the facility boundary. The proposed
revisions to the equipment type descriptions would clarify these
distinctions. Additionally, we are proposing to remove the reference to
``distribution'' pipelines because we did not intend to limit the
pipeline venting category to unique physical volumes that include such
pipelines. We agree with the industry stakeholders that facilities
subject to the blowdown vent stack reporting requirements typically are
connected to other pipelines such as gathering pipelines or
transmission pipelines, and on-site blowdowns from sections of these
pipelines should be reported. Finally, we note that for the ``facility
piping'' equipment category and the ``pipeline venting'' equipment
category, the phrase ``located within a facility boundary'' generally
refers to being part of the facility as defined by the existing
provisions of subpart A or subpart W, as applicable. In other words,
blowdowns from unique physical volumes of gathering pipeline that are
entirely considered to be part of the ``facility with respect to
onshore petroleum and natural gas gathering and boosting'' as defined
in 40 CFR 98.238 would be assigned to the ``facility piping'' equipment
category. The ``pipeline venting'' equipment category would only apply
if the unique physical volume includes some sections of gathering
pipelines that are not part of the ``facility with respect to onshore
petroleum and natural gas gathering and boosting'' as defined in 40 CFR
98.238.
g. Atmospheric Storage Tanks
    Open thief hatches. Facilities in the Onshore Petroleum and Natural
Gas Production and Onshore Petroleum and Natural Gas Gathering and
Boosting industry segments are required to report CO2 and
CH4 emissions (and N2O emissions when flared)
from atmospheric pressure fixed roof storage tanks receiving
hydrocarbon liquids (hereafter referred to as ``atmospheric storage
tanks''). The purpose of a thief hatch on an atmospheric storage tank
is generally to allow access to the contents of the tank for sampling,
gauging, and determining liquid levels. The thief hatch also works
along with the vent valve to maintain pressure on the tank while
preventing excessive vacuum from collapsing the tank. The EPA
previously evaluated emissions from atmospheric storage tanks as part
of the 2016 amendments to subpart W (81 FR 86500, November 30, 2016)
and determined that the subpart W calculation methodology in 40 CFR
98.233(j) already includes emissions from thief hatches or other
openings on atmospheric storage tanks in the Onshore Petroleum and
Natural Gas Production and Onshore Petroleum and Natural Gas Gathering
and Boosting industry segments. The subpart W calculation methodologies
for controlled atmospheric storage tanks include procedures for
determining emissions from storage tanks with a vapor recovery system
(40 CFR 98.233(j)(4)) and storage tanks with a flare (40 CFR
98.233(j)(5)). The procedure for determining emissions from a tank with
a vapor recovery system instructs reporters to adjust the storage tank
emissions downward by the magnitude of emissions recovered using a
vapor recovery system as determined by engineering estimate based on
best available data (40 CFR 98.233(j)(4)(i)). The procedure for
determining emissions from an atmospheric storage tank with a flare
references 40 CFR 98.233(n), which instructs reporters to use
engineering calculations based on process knowledge, company records,
and best available data to determine the flow to the flare if the flare
does not have a continuous flow measurement device. If a reporter sees
emissions from a thief hatch or other opening on a controlled
atmospheric storage tank during an equipment leak survey conducted
using OGI, the reporter should consider that information as part of the
``best available data'' used to calculate emissions from that storage
tank.
    However, it appears that emissions from open thief hatches on
atmospheric storage tanks may not be accurately portrayed in subpart W,
as many reporters claim 100 percent capture efficiency from vapor
recovery systems and flares. In order to alleviate any reporting
confusion, the EPA is proposing several clarifying edits to 40 CFR
98.233(j)(4) and (5), consistent with section II.A.5 of this preamble.
We are proposing to specifically state in each paragraph that emissions
during times of reduced capture efficiency are required to be evaluated
to determine if adjustments are needed to the calculated recovered mass
from vapor recovery units or flare feed gas volumes. Reduced capture
efficiency may occur during periods when the control device is not
operating or is bypassed and at times when the control device is
operating, such as open thief hatches. The emissions that are not
captured by a vapor recovery system or sent to a flare must be
considered when calculating emissions from atmospheric storage tanks
vented directly to the atmosphere.
    The EPA is also proposing revisions to the atmospheric storage tank
reporting requirements in 40 CFR 98.236(j) with regard to open thief
hatches. Specifically, the EPA is proposing to require reporting of the