than the current threshold levels that are based on the total nameplate
capacity of the equipment or the annual consumption, respectively. For
subpart DD, we are proposing to revise Table A-3 such that the
threshold is based on total estimated emissions from F-GHGs, as
determined under 40 CFR 98.301 (subpart DD), that are equivalent to
25,000 mtCO2e or more per year. For subpart SS, we are
proposing to revise Tables A-3 and Tables A-4 such that: (1) subpart SS
would be removed from Table A-3; and (2) Table A-4 would be revised to
specify that subpart SS facilities would be included in 40 CFR
98.2(a)(2) and Table A-4, as determined under the requirements of 40
CFR 98.451 (subpart SS), which provide estimation methods for total
estimated emissions from F-GHGs for comparison to a threshold
equivalent to 25,000 mtCO2e or more per year. Refer to
sections III.N and III.U of this preamble for a detailed discussion of
these proposed changes and how the proposed new thresholds would be
implemented. The proposed revisions are intended to harmonize Tables A-
3 and A-4 with the proposed changes described in sections II.B.1,
III.N, and III.U of this preamble, which would update the threshold to
be consistent with the threshold set for the majority of subparts and
would account for additional fluorinated gases (including F-GHG
mixtures) reported by industry, and for subpart DD, would also
streamline the reporting requirements to

focus Agency resources on the substantial emission sources within the
sector by excluding facilities or operations that may report emissions
that are consistently and substantially below 25,000 mtCO2e
per year (see section IV.C (``Rationale for Selection of Thresholds'')
of the preamble to the 2009 Proposed Rule (74 FR 16467, April 10,
2009)).

B. Subpart C--General Stationary Fuel Combustion Sources

1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart C
    We are proposing several amendments to improve the quality of the
data collected under subpart C of part 98 (General Stationary Fuel
Combustion Sources). This section describes the specific changes
proposed.
    First, for the reasons provided in section II.A.2 of this preamble,
we are proposing to modify the Tier 3 calculation methodology in
subpart C. Reporters to subpart C may use the Tier 3 methodology
provided in 40 CFR 98.33(a)(3) for determining annual CO2
emissions from combustion units. The Tier 3 methodology requires a
calculation based on annual fuel use, measured carbon content, and for
gaseous fuels, measured molecular weight. For gaseous fuels, equation
C-5 at 40 CFR 98.33(a)(3)(iii) requires that the carbon content and
molecular weight be in units of kilogram (kg) C/kg fuel and kg/kg-mole,
respectively, and be determined using the same procedures as specified
for high heating value (HHV) at 40 CFR 98.33(a)(2)(ii). However, when
using equation C-2b at 40 CFR 98.33(a)(2)(ii)(A) in this manner, the
fuel carbon content is on a mass basis (i.e., kg C/kg fuel) while the
fuel flow is on a volumetric basis (i.e., scf), resulting in a
weighting factor that is potentially problematic because the units of
measure are not in equivalent terms, i.e., the average annual carbon
content should be in mass terms (i.e., kg C/kg fuel). When using
equation C-2b for calculating an annual flow-weighted molecular weight,
a similar situation occurs. This has been the case since the 2009 Final
Rule (74 FR 56397).
    To address this matter, the EPA is proposing to modify the Tier 3
calculation methodology in 40 CFR 98.33(a)(3)(iii) to provide new
equations C-5a and C-5b for calculating a weighted annual average
carbon content and a weighted annual average molecular weight.
respectively. These new proposed equations incorporate the molar volume
conversion factor at standard conditions (as defined at 40 CFR 98.6)
and for annual average carbon content, the measured molecular weight of
the fuel, in order to convert the fuel flow to the appropriate units of
measure. This proposed change will correct the calculation method for
Tier 3 gaseous fuels. The EPA does not expect a significant change in
reported emissions because the change to the values for carbon content
and molecular weight is expected to be minimal under the proposed
calculation methods. Additionally, some reporters have previously
exercised the option to manually override the calculated emission
values with their own calculated values to address this issue when it
has been identified.
    We are also proposing several revisions to rule provisions
pertaining to the calculation of biogenic emissions from tire
combustion to improve the existing calculation methodology. First, for
the reasons described in section II.A.2 of this preamble, the EPA is
proposing to revise the calculation methods that must be used to
determine the total annual CO2 emissions under 40 CFR
98.33(e)(3)(iv)(A) when determining the biogenic CO2
emissions of MSW or tires under 40 CFR 98.33(e)(3)(iv). Currently, 40
CFR 98.33(e)(3)(iv) provides procedures in certain circumstances to
estimate the annual biogenic CO2 emissions in the combustion
of MSW or tires, which start with requiring that the Tier 1 calculation
method be used to determine the total annual CO2 emissions
from MSW or tires under 40 CFR 98.33(e)(3)(iv)(A). The value determined
under 40 CFR 98.33(e)(3)(iv)(A) is then multiplied by the applicable
default biogenic fraction specified at 40 CFR 98.33(e)(3)(iv)(B) to
determine the total biogenic CO2 emissions. At the same
time, 40 CFR 98.33(a) provides four calculation methodologies, Tier 1
through 4, and an alternative methodology for certain units subject to
40 CFR part 75, for calculating CO2 emission for fuel
combustion. In certain circumstances, a reporter may be required under
40 CFR 98.33(a) to calculate CO2 emissions from combustion
of MSW or tires using Tiers 2 or 3 for the purposes of annual
reporting, but then must also calculate the total CO2
emissions using Tier 1 under 40 CFR 98.33(e)(3)(iv)(A) for the purpose
of determining and reporting the biogenic CO2 emissions from
combustion of MSW or tires under 40 CFR 98.33(e)(3)(iv). This has
previously resulted in some confusion for reporters where total
CO2 emissions are calculated twice using different tiers,
one tier for one aspect of annual reporting and another tier for
biogenic calculation and reporting, and a redundancy in calculation of
total CO2 emissions by reporters. This has also resulted in
some confusion when comparing the calculated total CO2
emissions under 40 CFR 98.33(a) to the estimated total biogenic
CO2 emissions under 40 CFR 98.33(e)(3)(iv), since they are
based on different calculation methodologies. The EPA is proposing to
revise 40 CFR 98.33(e)(3)(iv)(A) so that total annual CO2
emissions will be calculated using the applicable methodology in
paragraphs 40 CFR 98.33(a)(1) through (3) for units using Tier 1
through 3 for purposes of 40 CFR 98.33(a), and using the Tier 1
calculation methodology in paragraph 40 CFR 98.33(a)(1) for units using
the Tier 4 or part 75 for purposes of 40 CFR 98.33(a), when determining
the biogenic component of MSW or tires under 40 CFR 98.33(e)(3)(iv).
    The EPA is proposing two additional substantive revisions to the
procedures for calculating and reporting emissions of biogenic
CO2 from the combustion of tires. First, for the reasons
discussed in section II.A.1 of this preamble, we are proposing to
update a default factor that is used to determine biogenic
CO2 emissions from the combustion of tires. Separately
reporting the biogenic CO2 emissions (i.e., specifying which
emissions are biogenic) from the combustion of tires is currently
optional, but if a reporter elects to do so, then 40 CFR 98.33(e)(3)
specifies the calculation procedure. Under 40 CFR 98.33(e)(3), if tires
provide more than 10 percent of the annual heat input to a unit and the
owner or operator elects to separately report the biogenic
CO2 emissions from the combustion of tires, then the owner
or operator must conduct testing using ASTM method D6866-16, Standard
Test Methods for Determining the Biobased Content of Solid, Liquid, and
Gaseous Samples Using Radiocarbon Analysis (2016) and ASTM method
D7459-08, Standard Practice for Collection of Integrated Samples for
the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide
Emitted from Stationary Emissions Sources (2016) to determine the
biogenic fraction of CO2.\8\ But if tires provide 10 percent
or less of the annual heat input, then reporters have the option to
separately report the biogenic CO2 emissions by multiplying
the total CO2 emissions by a default factor of 0.20. The
0.20 factor is based on

information from the Rubber Manufacturers Association (RMA) that was
based on most current data available at the time of the publication of
the GHG Reporting Rule revisions in the Federal Register on December
17, 2010 (75 FR 79092) (hereafter referred to as the 2010 Final
Revisions Rule) and represented an arithmetic average of the natural
rubber content (i.e., composition) of passenger and commercial tires
sold and thus available for combustion.\9\ Since publication of the
2010 Final Revisions Rule, we have received a memorandum from the U.S.
Tire Manufacturers Association (USTMA, formerly RMA) that based on
updated data, the weighted average composition of natural rubber in
tires is now 24 percent.10 11 The proposed default value was
calculated by weighting the average rubber content, average weight, and
shipment percentage of both light duty vehicle and commercial vehicle
scrap tires, which is more accurate than would result from using the
arithmetic average. In addition to the comments and information
provided by the USTMA, the Portland Cement Association (PCA) provided
supporting information from one of its member companies, Mitsubishi
Cement. Operational data (total count and weight of tires combusted)
and analytical data (percent of biogenic carbon based on ASTM D6866-20)
from 2020 was provided.\12\ The EPA reviewed these data and determined
that they support the USTMA's recommended 0.24 default biogenic
fraction for tires.\13\ We are therefore proposing to revise 40 CFR
98.33(e)(3)(iv)(B) to update the default biogenic fraction to 0.24.\14\
---------------------------------------------------------------------------

    \8\ ASTM D7459-08 was approved for use in the October 30, 2009
final rule (74 FR 56291), see Docket Id. No. EPA-HQ-OAR-2008-0508.
ASTM D6866-16 was approved for use in the December 9, 2016 final
rule (81 FR 89196), see Docket Id. No. EPA-HQ-OAR-2015-0526.
    \9\ Please refer to the memorandum, Natural Rubber Fraction in
Tire Derived Fuel by Matt Hakos and Cassy Becker, RTI International
to Michael Hannan, EPA (August 2021), available in the docket for
this rulemaking, Docket Id. No EPA-HQ-OAR-2019-0424, for more
detail.
    \10\ See the memorandum, Methodology for Determining the Natural
Rubber Fraction in Tire Derived Fuel, by Sarah Amick and Jesse
Levine, USTMA to U.S. EPA (April 11, 2019), available in Docket Id.
EPA-HQ-OAR-2019-0424.
    \11\ Supra note 9.
    \12\ See ``Tire Biogenic Content Data Provided by the Portland
Cement Association'' (August 2021), available in Docket Id. EPA-HQ-
OAR-2019-0434.
    \13\ Supra note 9.
    \14\ Supra note 9.
---------------------------------------------------------------------------

    Second, for the reasons described in section II.A.3 of this
preamble, we are proposing that all units that combust tires must
separately report biogenic CO2 emissions. The separate
reporting of biogenic CO2 from tires was made optional in a
2010 final rule (75 FR 79100, December 17, 2010). For that rulemaking,
we received no public comments on the proposal to make separate
biogenic CO2 emissions reporting optional for the combustion
of tires, and the proposal was finalized without modification. In the
final rule preamble, however, we stated: ``No comments were received on
the proposal to make biogenic CO2 emissions reporting
optional for the combustion of tires, and the proposal has been
finalized without modification. However, tire-derived fuel has a
biomass component, and perhaps it should be treated in the same manner
as MSW, which is also partly biogenic. A number of units that are
subject to part 98 combust tires as the primary fuel or as a secondary
fuel. Therefore, we are considering whether these units should be
required to separately account for their biogenic CO2
emissions. However, before making this mandatory we intend to open it
to notice and comment in a future rulemaking'' (75 FR 79109). In
conjunction with this change, we are proposing to remove the
restriction in 40 CFR 98.33(e)(3)(iv) that the default factor may only
be used to estimate the annual biogenic CO2 emissions from
the combustion of tires if the combustion of tires represents ``no more
than 10 percent annual heat input to a unit.'' Following the 2010 Final
Revisions Rule, reporters that chose to optionally report biogenic
CO2 emissions from tire combustion were required to use
quarterly flue-gas testing using ASTM methods, except that small units
(i.e., units in which tires provide no more than 10 percent of the
annual heat input to a unit) could alternatively use the default
factor. The proposal to remove the current restriction allowing only
small units to use the default factor (i.e., allowing the use of the
default factor for all units that combust tires), when combined with
the proposed requirement to report biogenic CO2 emissions
from tire combustion, would result in a more accurate characterization
of emissions from larger units since no units that combust tires alone
or in conjunction with fossil fuels have reported, for RY2015 through
RY2018, biogenic CO2 emissions that were calculated using
the quarterly flue-gas testing results. Therefore, the proposed
addition of reporting of biogenic CO2 emissions for tire
combustion should require no additional monitoring or data collection
and could be reported with minimal additional reporting burden. The EPA
is proposing that this change would only be finalized if the proposed
requirement to report biogenic CO2 emissions from tire
combustion is also finalized. Additionally, we are proposing another
change that would only be finalized if the proposed requirement to
report biogenic CO2 emissions from tire combustion is also
finalized. Specifically, 40 CFR 98.33(b)(1)(vii) currently allows units
that combust MSW and/or tires to use Tier 1 if the combined heat input
from both fuels is not greater than 10 percent of the heat input to the
unit but also provides that, if a reporter choose the option to not
report biogenic CO2 from tire combustion, the 10 percent
threshold applies only to the MSW fuel. If the proposed mandatory
reporting of biogenic CO2 from tire combustion is finalized,
we are proposing that the additional provision in 40 CFR
98.33(b)(1)(vii) on how to apply the threshold to only MSW fuel would
be deleted, since it would no longer be applicable. This may result in
fewer facilities being able to use Tier 1 to calculate MSW and/or tire
CO2 emissions since the tire heat input would now always be
included in conjunction with the MSW heat input to compare to the 10
percent threshold.
    In conjunction with these proposed revisions, we are also proposing
to remove the language in 40 CFR 98.33(e) and 40 CFR 98.36(e)(2)(xi)
referring to optional biogenic CO2 emissions reporting from
tire combustion, and to revise 40 CFR 98.34(d) to reference 40 CFR
98.33(e)(3)(iv) instead of 40 CFR 98.33(b)(1)(vi) and (vii). We are
proposing the latter change because 40 CFR 98.34(d) incorrectly
references 40 CFR 98.33(b)(1)(vi) and (vii), which specify certain
provisions when Tier 1 can be used, whereas 40 CFR 98.33(e)(3)(iv)
specifies when the default biogenic factor for MSW can be used (i.e.,
in cases where combustion of MSW provides no more than 10 percent of
the annual heat input to the unit or if a small, batch incinerator
combusts no more than 1,000 tons per year of MSW) and is the correct
reference for 40 CFR 98.34(d). This revision is being proposed to
correct this reference in accordance with other proposed changes.
Additionally, we are proposing a clarifying correction to 40 CFR
98.33(e), Biogenic CO2 emissions from combustion of biomass with other
fuels. Section 98.33(e)(1) specifies that equation C-1 of subpart C can
be used to calculate the annual CO2 mass emissions from the
combustion of the biomass fuels listed in Table C-1 of this subpart
(except MSW and tires). We are proposing to delete the parenthetical
clause ``(except MSW and tires)'' in 40 CFR 98.33(e)(1) because,
although MSW and tires are partially biogenic, they were never
categorized as biomass fuels

in Table C-1 of subpart C and thus no aspect of Table C-1 was excepted
by this parenthetical clause. This deletion would correct the drafting
oversight and will not result in any change to the reporting
requirements.
    Next, for the reasons discussed in section II.A.5 of this preamble,
we are proposing to correct the equation C-11 term definition for the
variable ``R''. Equation C-11 is used to calculate the CO2
emissions from sorbent use when the chemical reaction between the acid
gas and sorbent produces CO2 emissions and when these
emissions are not monitored with a CEMS. The term ``R'' is currently
defined as the number of moles of CO2 released upon capture
of one mole of the acid gas species being removed (R = 1.00 when the
sorbent is CaCO3 and the targeted acid gas species is
SO2). However, the units of measure for the equation as
presented do not currently result in metric tons CO2
emitted. We are proposing to revise the definition of the term ``R'' as
``the number of moles of CO2 released per mole of sorbent
used (R = 1.00 when the sorbent is CaCO3 and the targeted
acid gas species is SO2)'' so that the equation is
dimensionally correct (i.e., results in metric tons CO2
emitted).
    We are also proposing to amend 40 CFR 98.33(c)(6)(i), (ii),
(ii)(A), and (iii)(C), and delete (ii)(B) to clarify the methods used
to calculate CH4 and N2O emissions for blended
fuels when heat input is determined after the fuels are mixed and
combusted. There would be no new reporting requirements because of this
proposed clarification.
    For the reasons described in section II.A.4 of this preamble, we
are proposing a substantive revision to rule provisions pertaining to
the reporting of unit level information for the aggregation of units
and common pipe configurations. Currently, subpart C allows facilities
to report data using six different configurations. These configurations
are:
     Individual unit using Tiers 1, 2, or 3 to calculate
emissions.
     Individual unit using Tier 4 to calculate emissions.
     Group of units using the aggregation of units reporting
alternative with Tiers 1, 2 or 3.
     Group of units using the common pipe configuration
reporting alternative with Tiers 1, 2, or 3.
     Group of units using Tier 4 to calculate emissions and
reporting under the monitored common stack or duct configuration
reporting alternative.
     Part 75 units using the alternative CO2 mass
emissions calculation methods.
     For RY2019, the approximate use of reporting
configurations and the percent of emissions for each is summarized:

----------------------------------------------------------------------------------------------------------------
                                                                                Percent of      Percent of
                                                                     Number of     total Subpart   total Subpart
                       Configuration type                            Subpart C           C             C CO2
                                                                  configurations  configurations     emissions
----------------------------------------------------------------------------------------------------------------
Individual Unit (Tiers 1-3).....................................           9,185              58              36
Individual Unit (Tier 4)........................................             208               1               9
Aggregation of Units (Tiers 1-3)................................           4,362              27              24
Common Pipe (Tiers 1-3).........................................           1,905              12              26
Common Stack (Tier 4)...........................................              21             0.1               2
Alternative Part 75.............................................             192               1               2
----------------------------------------------------------------------------------------------------------------

    Individual unit information (i.e., the unit type and the maximum
rated heat input capacity) is currently only required to be reported
for the individual unit (Tiers 1-3 and Tier 4) reporting
configurations. The individual unit information allows the EPA to
aggregate emissions according to unit type and size and provides a
better understanding of the emissions from specific unit types.
    Individual unit information is not reported for the aggregation of
units, common pipe, common stack, or alternative part 75 reporting
configurations. As such, the EPA is currently unable to aggregate
emissions by unit type and size for these reporting configurations,
which represent 40 percent of the configurations used and 54 percent of
the emissions reported in subpart C.
    The aggregation of units and common pipe configurations are the
second and third most used configurations and together, they represent
approximately 39 percent of the configurations and 50 percent of the
emissions reported to subpart C. Both of these reporting alternatives
allow multiple units to be reported under one configuration group.
Because the unit type and maximum rated heat input capacity are
currently not reported for the individual units within these two
configurations, there is a significant gap in the EPA's ability to
aggregate subpart C emissions data by unit type and size.
    To better analyze reported data by unit type and size, the EPA is
proposing to revise 40 CFR 98.36(c)(1) and (3) (by adding 40 CFR
98.36(c)(1)(ii) and (c)(3)(xi)) to require reporting for each unit in
either an aggregation of units or common pipe configuration, excluding
units less than 10 mmBtu/hr from both, of the unit type, maximum rated
heat input capacity, and an estimate of the fraction of the total
annual heat input. Under the proposed amendments, unit level
information would be reported for four of the six configuration types.
This would allow the EPA to aggregate data according to unit type and
size for approximately 98 percent of the configurations and 95 percent
of the emissions in subpart C (the actual percent of emissions that
could be aggregated by unit type would be somewhat lower than 95
percent because units less than 10 would be excluded from the
additional reporting requirements) to provide unit level information
for the aggregated unit and common pipe configurations. We expect the
percent of emissions to be only somewhat lower than 95 percent because
units less than 10 mmBtu/hr are estimated to have minor emissions
contributions in aggregated unit and common pipe configurations, as
previously described in the 2016 final rulemaking (81 FR 89203,
December 9, 2016). Given the relatively low emissions from the common
stack (Tier 4) and part 75 configurations, the EPA is not proposing to
require reporting of individual unit information for these
configurations at this time. The EPA seeks comment on whether to
propose these requirements for the common stack (Tier 4) and part 75
configurations.
    The proposed reporting requirements are not expected to
significantly increase burden for reporters. The requirement to report
the cumulative maximum rated heat input capacity for the aggregation of
units or common pipe configurations began with the 2017 reporting year
(81 FR 89188). Accordingly, facilities have been reporting cumulative
maximum rated heat input capacity for four years. To determine this
value, facilities must know the maximum rated heat input capacity of
all units in each aggregation

of units or common pipe configuration (greater than or equal to 10
mmBtu/hr), because these values are summed to determine the cumulative
value. The EPA expects that the other requirements (i.e., unit type and
estimate of the fraction of annual heat input) can be determined from
existing company records. The total fraction of annual heat input for
each unit in the group will be determined by dividing the estimated
actual heat input for that unit by the sum of the estimated actual heat
input for all units in the group. Accordingly, any new burden incurred
from this proposed requirement is expected to be minimal and associated
with calculating the fraction of the total annual heat input and
entering data into the e-GGRT software. To minimize the burden of
reporting these data in e-GGRT, the EPA intends to evaluate developing
a bulk unit details reporting form similar to the existing bulk
equation input reporting forms for Tiers 2 and 3.
    For the reasons described, the EPA has proposed these new reporting
requirements under 40 CFR 98.36(c)(1)(ii) (aggregation of units) and 40
CFR 98.36(c)(3)(xi) (common pipe). These proposed amendments will
better inform future policy and programs by addressing a data gap in
unit information that currently exists for these two reporting
configurations. We are proposing related confidentiality determinations
for the additional data elements, as discussed in section VI of this
preamble.
    As a corollary to proposed amendments to subpart W (Petroleum and
Natural Gas Systems) to address uncombusted methane emissions from
compressor drivers (see section III.J.1.n of this preamble), we are
proposing that natural gas-fired compressor drivers located at
facilities that are subject to subpart W would be required to use the
CH4 emission factors in Table W-9 to subpart W rather than
the default CH4 emission factor for natural gas in Table C-2
to subpart C. Specifically, we are proposing to revise the ``EF'' term
in each of the equations in 40 CFR 98.33(c) (i.e., equations C-8, C-8a,
C-8b, C-9a, C-9b, and C-10) to reference the CH4 emission
factors in Table W-9 to subpart W for natural gas compressor drivers.
We are also proposing to add a footnote to Table C-2 that specifies
that for reporters subject to subpart W, the default CH4
emission factor for natural gas may only be used for natural gas-fired
combustion units that are not compressor drivers. Finally, we are
proposing to amend 40 CFR 98.36(c)(1) and (c)(3). Under the proposed
amendments, reporters may not report a combination of one design class
of compressor driver (using one Table W-9 CH4 emission
factor) and other combustion units (e.g., using a Table C-2
CH4 emission factor or another Table W-9 CH4
emission factor) in the same aggregation of units or common pipe
configuration. This change would ensure that all units in an
aggregation of units or common pipe configuration are using the same
CH4 emission factor for each fuel combusted in the unit.
    We are proposing two additional clarifications to existing
reporting and record keeping requirements, for the reasons described in
section II.A.5 of this preamble. First, we are proposing to revise the
first sentence of 40 CFR 98.36(e)(2)(ii)(C) to clarify that both the
annual average, and, where applicable, monthly high heat values are
required to be reported. The monthly HHV reporting requirement was
always clear based on the language in this provision and the proposed
clarification plainly states that the annual average high heat value is
also a reporting requirement (for reporters who do not use the
electronic inputs verification tool (IVT) within e-GGRT). There are no
new reporting requirements because of this proposed clarification.
    Second, we are proposing to revise 40 CFR 98.37(b)(9), (10), (11),
(14), (18), (20), (22), and (23) to specify recordkeeping data that is
currently contained in the file generated by the verification software
that is already required to be retained by reporters under 40 CFR
98.37(b) but was inadvertently omitted from being specified in those
subparagraphs. These proposed revisions correct omissions that
currently exist in the verification software recordkeeping requirements
specific to equations C-2a, C-2b, C-3, C-4, and C-5. They also align
the verification software recordkeeping requirements with the proposed
revisions to equation C-5 at 40 CFR 98.33(a)(3)(iii), as noted above.
These proposed revisions do not require any new action from affected
reporters, as all new recordkeeping data proposed is already contained
in the file generated by the verification software.
2. Proposed Revisions To Streamline Implementation and Reduce Burden
for Subpart C
    We are proposing several revisions to subpart C to streamline
requirements and to adopt minor revisions to improve implementation of
the rule.
    For the reasons described in section II.B.2 of this preamble, the
EPA is proposing to amend 40 CFR 98.34(c)(6). In the 2010 Final
Revisions Rule (75 FR 79092), the EPA added 40 CFR 98.34(c)(6), which
allowed cylinder gas audits (CGAs) of the CO2 monitor to be
performed using calibration gas concentrations of 40-60 percent and 80-
100 percent of CO2 span, when the CO2 span value
is set higher than 20 percent CO2. Under appendix F of 40
CFR part 60, CGAs of the CO2 analyzer are required at two
calibration gas concentrations (i.e., 5-8 percent and 10-14 percent
CO2 by volume). These CO2 concentration levels
are appropriate for certain stationary combustion applications (e.g., a
typical span value for a CO2 monitor installed on a coal-
fired boiler is 20 percent CO2). These CGA concentrations
represent 25-40 percent and 50-70 percent of the CO2 span
value, when the CO2 span is at 20 percent CO2.
When the CO2 span exceeds the typical span value of the fuel
being evaluated (e.g., 20 percent CO2 on a coal-fired
boiler), the CGA concentrations specified in part 60 are no longer
representative, as they only evaluate the lower portion of the
measurement scale. Since the EPA had information indicating that there
were cases when the CO2 span was set greater than 20 percent
CO2 (e.g., process and combustion emissions from cement
manufacturing may require 30 percent CO2 span), 40 CFR
98.34(c)(6) was added so that CGAs could be conducted at two separate
portions of the measurement scale, as opposed to just the lower portion
(see 75 FR 79111, December 17, 2010).
    Since 2010, the EPA has received questions through GHGRP Help Desk
indicating that industrial flue gases also occur where the measured
CO2 concentration is very low (e.g., natural gas turbines
typically have about 5 percent CO2 in flue gas). In this
case, the required calibration gas concentrations (i.e., 5-8 percent
and 10-14 percent CO2 by volume) under appendix F of 40 CFR
part 60 would not be appropriate because they may be above the
CO2 span value and so would not provide information
regarding accuracy of the monitor at actual representative stack gas
concentrations. Accordingly, the EPA is proposing to amend 40 CFR
98.34(c)(6) to allow CGAs to be performed using calibration gas
concentrations of 40-60 percent and 80-100 percent of CO2
span, whenever the required CO2 span value for a flue gas
does is not appropriate for the prescribed audit ranges in appendix F
of 40 CFR part 60. This will allow CGAs to check the response of the
CO2 analyzer at two calibration gas concentrations,
representing separate portions of the measurement scale,

when the CO2 span is significantly lower or higher than 20
percent CO2.
    For the reasons described in section II.B.3 of this preamble, the
EPA is proposing to amend certain provisions in 40 CFR 98.36 that
require facilities with the aggregation of units or common pipe
configuration types to report the annual CO2 mass emissions
from the combustion of all fossil fuels, per the requirements in 40 CFR
98.36(c)(1)(vi) and 40 CFR 98.36(c)(3)(vi). The EPA has reviewed the
data provided under these reporting requirements and has tentatively
concluded that they are no longer required for the verification or
analysis of subpart C annual reports. In addition, the reporting of
this data for the aggregation of units or common pipe configuration
types has caused confusion for reporters because they mistakenly
believe that the value is used in subpart C total CO2
emission calculations. Therefore, we are proposing to revise the
provisions in 40 CFR 98.36(c)(1)(vi) and 40 CFR 98.36(c)(3)(vi) to
remove the language requiring reporting of the total annual
CO2 mass emissions from all fossil fuels combined.
    For these two configuration types (aggregation of units and common
pipe), the reported configuration-level annual CO2 emissions
from all fossil fuels does not factor into any subpart- or facility-
level total CO2 emission calculations. The e-GGRT calculates
the subpart-level non-biogenic CO2 emissions for these two
configuration types by summing the reported fuel-level CO2
emissions values from each fuel, regardless of whether it is biogenic
or not, then subtracting the reported configuration-level biogenic
CO2 emissions values. For the aggregation of units
configuration type, the reported configuration-level sorbent
CO2 emissions value, which is typically zero, is also added
into this ``rolled-up'' non-biogenic CO2 emissions total.
The calculation was specifically designed in this manner because the
reported fuel-level information for Table C-1 partially biogenic fuels
(i.e., tires, MSW) and some ``other'' or ``blend'' fuels that contain
biogenic material is not sufficient to allow the calculation of
biogenic CO2 emissions for each fuel such that it could be
accurately subtracted from the fuel-level CO2 emissions
values. Thus, the reported configuration-level biogenic CO2
emissions must be used in the subpart total calculations. Many
reporters then assume that the configuration-level annual
CO2 emissions from all fossil fuels is also used in the
subpart total calculations, which creates confusion for reporters and
has resulted in GHGRP Help Desk submissions stating that these
requirements are redundant and confusing. By proposing to revise the
provisions in 40 CFR 98.36(c)(1)(vi) and 40 CFR 98.36(c)(3)(vi) to
remove the language requiring reporting of the total annual
CO2 mass emissions from all fossil fuels combined, we would
remove this unnecessary confusion for reporters with aggregation of
units and common pipe configuration types.

C. Subpart G--Ammonia Manufacturing

    For the reasons discussed in section II.A.2 of this preamble, we
are proposing several revisions to subpart G of part 98 (Ammonia
Manufacturing) to improve the quality of the data collected from this
subpart. Subpart G estimates CO2 emissions from ammonia
manufacturing based on a carbon mass balance, which assumes that all
carbon contained in feedstocks is transformed to CO2 and all
CO2 is emitted from the ammonia manufacturing process. The
EPA has received numerous comments from The Fertilizer Institute (TFI)
related to the calculation of CO2 emissions from the
production of ammonia in subpart G. Most comments from TFI were related
to the carbon mass balance methodology, especially with regard to other
products that could be produced using the CO2 emissions from
ammonia production. TFI has asserted that most ammonia manufacturing
facilities capture and use the CO2 resulting from the
ammonia manufacturing process to produce urea. Subpart G does not
currently allow the subtraction of the CO2 that is bound in
urea from calculated and reported emissions or otherwise allow separate
reporting of that CO2.
    In response to the 2009 Proposed Rule, TFI submitted a comment
letter dated June 9, 2009, and provided comments via a public hearing
on April 6, 2009, stating that the CO2 produced through
ammonia manufacturing is often utilized in the manufacturing of urea
and that the EPA mistakenly assumed that all CO2 in urea
will be released into the atmosphere.\15\ \16\ In response, in the 2009
Final Rule, the EPA changed the rule requirements to collect
information on urea production and uses of the urea if known, stating
``Collecting information on urea production and its uses will help
[the] EPA to improve methodologies for estimating emissions from
ammonia manufacturing, urea production and urea consumption in the
future.''
---------------------------------------------------------------------------

    \15\ TFI's Comments on the ``Proposed Mandatory Reporting of
Greenhouse Gases Rule'' Docket Id. No. EPA-HQ-OAR-2008-0508-2376,
June 9, 2009. Also available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
    \16\ USEPA Public Hearing for Proposed Rulemaking for Mandatory
Reporting of Greenhouse Gases. Transcript Day One of Two. April 6,
2009. Docket Id. No. EPA-HQ-OAR-2008-0508-0212. Also available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    The EPA next revised 40 CFR 98.72(a) and 40 CFR 98.73(b)(5) in
subpart G (75 FR 79092, December 17, 2010) to explain that the
``CO2 process emissions reported under this subpart may
include CO2 that is later consumed on site for urea
production, and therefore is not released to the ambient air from the
ammonia manufacturing process unit.'' This revision was proposed
pursuant to a settlement agreement with TFI, after TFI challenged the
2009 rulemaking.\17\
---------------------------------------------------------------------------

    \17\ The Fertilizer Institute v. EPA, Docket Id. No. 09-1329
(D.C. Circuit), 2010. Also available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    In response to an April 2, 2013 EPA-proposed rule (78 FR 19802),
TFI submitted a comment letter dated May 2, 2013, requesting that the
EPA revise subpart G to require only the reporting of CO2
emitted directly to the atmosphere from the synthetic ammonia
production process instead of continuing to include the CO2
captured during ammonia production and used to produce urea, noting its
view that the captured CO2 ``does not contribute to the
CO2 emission estimates for ammonia production.'' \18\ TFI
further argued the existing methodology is inconsistent with other
source categories covered by the rule (namely subpart P (Hydrogen
Production) and subpart X (Petrochemical Production)) and is contrary
to the EPA's methodology used in the U.S. GHG Inventory. TFI pointed to
similarities between the structure of subpart G and subpart P, and
argued that the structure of subpart G be revised to be more consistent
with subpart X, which allows sources to account for carbon (i.e.,
subtract from direct facility emissions) that is being shipped off-site
in products. In response, the EPA responded that TFI had raised a
consistency issue within part 98 that ``merits evaluation and requires
further analysis by the EPA.'' However, the EPA explained that no
changes were made at that time because TFI's comment was outside of the
scope of the rulemaking.\19\
---------------------------------------------------------------------------

    \18\ 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-2012-0934-0036, May 2, 2013. Also
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424.
    \19\ Summary of Public Comments and Responses for Greenhouse Gas
Reporting Rule: 2013 Revisions to the Greenhouse Gas Reporting Rule
and Confidentiality Determinations for New or Substantially Revised
Data Elements. Docket Id. No. EPA-HQ-OAR-2012-0934-0127, November
2013. Also available in the docket for this rulemaking, Docket Id.
No. EPA-HQ-OAR-2019-0424.

---------------------------------------------------------------------------

    In response to a January 15, 2016 EPA-proposed rule (81 FR 2536),
TFI submitted a comment letter dated March 30, 2016, again requesting
that part 98 be made consistent with the methodology used in the U.S.
GHG Inventory, such that CO2 bound in urea would not be
considered an emission from the ammonia manufacturing process.\20\
Also, TFI asked for clarification regarding a new requirement in
subpart G to report the amount of methanol produced at the ammonia
manufacturing facility. In response, the EPA noted the potential of
using a future rulemaking to address TFI's suggested revisions ``to
require reporting only CO2 that is emitted directly to the
atmosphere from ammonia manufacturing, rather than reporting
CO2 that is bound in the urea that is produced from ammonia
at some facilities,'' but explained that the comment was outside the
scope of that rulemaking. The EPA clarified in the preamble and in the
final rule (81 FR 89188, December 9, 2016) that the quantity of
methanol being reported only includes methanol that is ``intentionally
produced as a desired product'' and does not include the quantity of
methanol that is vented or destroyed.
---------------------------------------------------------------------------

    \20\ 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.
---------------------------------------------------------------------------

    TFI submitted two other comment letters in 2017. The letter dated
March 31, 2017 was submitted to the Department of Commerce as part of a
request for information ``Impact of Federal Regulations on Domestic
Manufacturing'' (82 FR 12786, March 7, 2017).\21\ The letter dated May
15, 2017 was submitted to the EPA's request for comment on ``Evaluation
of Existing Regulations'' (82 FR 17793, April 13, 2017).\22\ Both
letters contained similar language asking that the GHGRP be amended to
``report the quantity of GHG that is actually emitted to the atmosphere
as part of the manufacturing processes'' instead of ``GHG emissions
that are captured and either sold or used in other industrial
processes.''
---------------------------------------------------------------------------

    \21\ TFI, Impact of Federal Regulations on Domestic
Manufacturing, Docket Id. No. DOC-2017-0001-0064, March 31, 2017,
available in Compilation of Comments Related to the Greenhouse Gas
Reporting Program submitted to the Department of Commerce under
Docket ID No. DOC-2017-0001 and the Environmental Protection Agency
under Docket ID No. EPA-HQ-OA-2017-0190 and in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
    \22\ TFI, Comments on ``Evaluation of Existing Regulations,''
Docket Id. No. EPA-HQ-OA-2017-0190-40791, May 15, 2017, available in
Compilation of Comments Related to the Greenhouse Gas Reporting
Program submitted to the Department of Commerce under Docket ID No.
DOC-2017-0001 and the Environmental Protection Agency under Docket
ID No. EPA-HQ-OA-2017-0190 and in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    After consideration of the comments from TFI summarized above, the
EPA has tentatively concluded that requiring reporters subject to
subpart G to report the GHG emissions that occur directly from the
ammonia manufacturing process (i.e., net CO2 process
emissions) after subtracting out carbon or CO2 captured and
used in other products would provide a more accurate estimate of the
emissions and would provide consistency in our approach across the
GHGRP. Therefore, for the reasons described in this section and in
section II.A.2 of this preamble, we are proposing multiple amendments
to subpart G. Under the proposed rule, equation G-4 and equation G-5
would be combined into a new equation G-4 and paragraph 98.73(b)(5)
would be deleted. The reporting requirement in paragraph 98.76(b)(1)
specifies emissions for each individual ammonia manufacturing
processing unit, so determining the combined CO2 emissions
from all ammonia manufacturing processing units using equation G-5 is
not necessary for reporting. The new equation G-4 would allow reporters
to subtract CO2 used in the production of urea and carbon
bound in methanol that is intentionally produced as a desired product
instead of assuming that the CO2 bound in urea is emitted or
that the carbon contained in methanol is converted to CO2
and emitted, resulting in the calculation of net CO2
emissions that occur directly from ammonia manufacturing. We are also
proposing a harmonizing revision to the introductory paragraph of 40
CFR 98.73. These proposed changes are not expected to result in an
increase in burden because the monthly equation inputs for the new
equation G-4 would already be available to calculate the annual values
of CO2 collected from ammonia production and consumed on-
site for urea production and the quantity of intentionally produced
methanol, both of which are already reported. Similarly, for reporters
that do not produce urea or methanol, the burden under the new equation
to calculate CO2 emissions remains unchanged. Further,
because we are retaining the requirement to report the CO2
collected from ammonia for urea production and methanol production, the
proposed amendments would not result in any negative impacts to the
quality of the data collected under the GHGRP and such data would
remain available for potential policy evaluation.
    As a result of the new proposed equation G-4, two new monthly
recordkeeping data elements are being proposed as part of the
verification software records required in 40 CFR 98.77(c), including:
(1) quantity of CO2 collected from ammonia production and
consumed on site for urea production each month; and (2) quantity of
methanol intentionally produced as a desired product each month. These
recordkeeping changes are not expected to result in a significant
increase in burden because both elements are already being reported on
an annual basis (40 CFR 98.76(b)(13) and (15)). For reporters that do
not produce urea or methanol, the requirements for recordkeeping remain
unchanged. We are proposing harmonizing revisions to the introductory
paragraph of 40 CFR 98.76 and to the reported data elements at 40 CFR
98.76(b)(1) to clarify that reporters must provide the ``annual net
CO2 process emissions'' for each ammonia manufacturing unit,
and at 40 CFR 98.76(b)(13) to clarify that reports must provide the
``annual amount of CO2 collected from ammonia production
(metric tons) and consumed on site for urea production and the method
used to determine the CO2 consumed in urea production.'' The
proposed revision to the reported emissions value excludes any
CO2 used in the production of urea and carbon bound in
methanol that is intentionally produced as a desired product. We are
proposing related confidentiality determinations for the revised data
elements, as discussed in section VI of this preamble.
    Finally, corresponding amendments are being proposed to remove the
language specified above that was added in the 2010 Final Revisions
Rule (75 FR 79092), described above. Paragraph 98.72(a) will be amended
to read, ``CO2 process emissions from steam reforming of a
hydrocarbon or the gasification of solid and liquid raw material,
reported for each ammonia manufacturing unit following the requirements
of this subpart.''
    In addition, minor amendments to equation G-1, equation G-2, and
equation G-3 are being proposed to simplify the equations by removing
the process unit ``k'' designation in the terms ``CO2,G,k,''
``CO2,L,k,'' and ``CO2,S,k.'' The introductory
paragraph to each of these equations already specifies that emissions
must be calculated for each ammonia manufacturing unit. Removing the
extra subscript will

clarify the equations. No changes to burden are expected from these
changes.

D. Subpart H--Cement Production

    For the reasons described in section II.A.4 of this preamble, we
are proposing to add new data elements to the data reporting
requirements for subpart H of part 98 (Cement Production) to enhance
the quality and accuracy of the data collected. Specifically, we are
proposing to collect new data elements under 40 CFR 98.86(a) and 40 CFR
98.86(b). Subpart H currently requires calculation of CO2
emissions using one of two methodologies, either direct measurement
using CEMS, or a mass balance (non-CEMS) methodology based on mass,
carbonate content, and fraction of calcination for each carbonate-based
material. For the mass balance method, facilities enter input data that
is used to calculate emissions factors for produced materials. These
inputs include, for example, monthly measurements of calcium oxide
content and magnesium oxide content. Subpart H emission equations
inputs are not collected under the GHGRP, and so the EPA has little
data on which to build verification checks for these inputs in the
reporting system. In order to improve the data verification process, we
are proposing to collect annual averages for these chemical composition
input data on a facility-basis. The proposed data elements (for both
facilities that report CEMS data and those that report using a mass-
balance method) include the annual arithmetic average weight fraction
of: total CaO content, non-calcined CaO content, total MgO content, and
non-calcined MgO content of clinker at the facility; and total CaO
content of cement kiln dust (CKD) not recycled to the kiln(s), non-
calcined CaO content of CKD not recycled to the kiln(s), total MgO
content of CKD not recycled to the kiln(s), and non-calcined MgO
content of CKD not recycled to the kiln(s) at the facility. The
proposed data elements would rely on an arithmetic average of the
measurements rather than requiring reporters to weigh by quantity
produced in each month. CEMS facility emissions calculations are
importantly different from non-CEMS emissions calculations because
combustion and process emissions are typically vented through the same
stack, causing process and combustion emissions to be mixed and
indifferentiable. Therefore, in addition to improving the input
verification process, collecting average chemical composition data for
CEMS facilities will provide the EPA the ability to check the reported
CEMS emission data for accuracy by creating the ability to back-
estimate process emissions. In order to be able to estimate and check
the accuracy of process emissions, we are also proposing to collect
other data elements for both facilities using CEMS and those that
report using the mass-balance method, including annual facility CKD not
recycled to the kiln(s) in tons and raw kiln feed consumed annually at
the facility in tons (dry basis). Facilities are already required to
report or maintain records of other production data that would be
needed to perform these estimates. Facilities using the mass-balance
method currently collect CKD not recycled to the kiln(s) on a quarterly
basis to estimate CO2 emissions from clinker production.
Similarly, facilities also record the annual raw kiln feed for each
kiln, which is used to determine the CO2 emissions from raw
materials for each kiln in equation H-5. The proposed data elements
would instead sum the CKD not recycled and raw kiln feed quantity
across all kilns at a facility. The proposed data elements will allow
us to estimate process emissions for comparison to facility reported
emissions estimates as a verification check. In addition to improving
verification and data quality for cement emissions, the proposed data
elements will also improve the U.S. GHG Inventory. The U.S. GHG
Inventory can use the proposed data elements to internally disaggregate
process and combustion emissions that are reported by facilities using
CEMS, and create more accurate national-level cement emissions profile.
    In general, 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. These additions would result in especially minimal
reporting changes for non-CEMS facilities, as the chemical composition
averages can be calculated using the input data that is already
required to be entered in the reporting system. However, we are
requesting comment on whether any of the above listed data elements
would not be readily available to reporters. We are proposing related
confidentiality determinations for the additional data elements, as
discussed in section VI of this preamble.
    Finally, for the reasons described in section II.A.5 of this
preamble, we are proposing to clarify equations H-1 and H-5. We are
proposing to clarify that equation H-5 calculates the CO2
emissions from raw materials on a per kiln basis. Facilities currently
maintain records of the amount and organic carbon content of raw
materials and raw kiln feed consumed annually per kiln, and enter this
data into the e-GGRT verification software during submission of their
annual reports. The verification software collects the kiln-level data
to verify the inputs and generates a file containing the records, which
are specified in 40 CFR 98.87(c)(14) through (17). The CO2
emissions for the facility are then summed for all kilns at the
facility-level using equation H-1, which sums the annual CO2
emissions from clinker production (from equation H-2) and the annual
emissions from raw materials for each kiln (from equation H-5). We are
proposing revisions to the inputs ``rm,'' ``CO2 rm,'' and
``TOCrm'' in equation H-5 to clarify that the data elements
are input on a per-kiln basis, and to add brackets to clarify that
emissions are calculated as the sum of emissions from all raw materials
or raw kiln feed used in the kiln. Similarly, we are proposing to
revise equation H-1 to add brackets to clarify the summation of clinker
and raw material emissions for each kiln, and updating the definition
of ``CO2 rm'' to clarify the raw material input is on a per-
kiln basis. The proposed revisions are corrections that would harmonize
equations H-1 and H-5 with the existing recordkeeping requirements and
align the calculation methodology in the rule and e-GGRT. We are also
proposing minor corrections to the parameters of equation H-4 for
quarterly non-calcined CaO content of CKD not recycled to the kiln and
quarterly non-calcined MgO content of CKD not recycled to the kiln. The
2009 final rule inadvertently defined the equation parameters for both
quarterly non-calcined CaO content and quarterly non-calcined MgO
content as ``CKDCaO'' and ``CKDMgO'',
respectively, while equation H-4 defines these parameters as
``CKDncCaO'' and ``CKDncMgO''. To remove any
confusion for reporters, we are proposing to correct the defined
parameters for quarterly non-calcined CaO content and quarterly non-
calcined MgO content of CKD not recycled to ``CKDncCaO'' and
``CKDncMgO'', respectively. These clarifications would not
require any changes to the monitoring, recordkeeping, or reporting
provisions, or impact how reporters currently collect or enter data for
their annual reports.

E. Subpart I--Electronics Manufacturing

    Under subpart I of part 98 (Electronics Manufacturing), electronics
manufacturing facilities must report F-GHG and F-HTF emissions from
electronic manufacturing production processes and N2O
emissions from chemical vapor deposition (CVD) and

other electronics manufacturing processes. Facilities must also report
CO2, CH4, and N2O emissions from each
stationary combustion unit by following the requirements of subpart C
(General Stationary Combustion Sources).
    We are proposing several amendments and clarifications to the
calculation methodologies requirements in subpart I. In addition, the
EPA is proposing conforming changes to the reporting and recordkeeping
requirements of subpart I. Changes include updating existing default
emission factors and destruction or removal efficiencies (DREs) based
on new data, revising certain calculation methods, adding a calculation
method for calculating by-products produced in abatement systems,
amending data reporting requirements, and providing clarification on
reporting requirements. We are proposing revisions that will better
reflect new industry data and current practice, improve the quality of
the data collected, and streamline the reporting requirements. We are
also proposing related confidentiality determinations for the proposed
new or revised data elements, as discussed in section VI of this
preamble.
1. Proposed Revisions To Improve the Quality of Data Collected for
Subpart I
a. Revisions To Improve the Calculation Methodology for Stack Testing
    We are proposing to revise 40 CFR 98.93(i), which specifies how to
calculate GHG emissions based on stack testing, in order to improve,
simplify, and correct the calculation method. As discussed in section
II.A.2 of this preamble, the proposed edits would improve the quality
of the data collection and calculation requirements associated with
stack testing. First, we are proposing to add new equations I-24C and
I-24D and a table of default weighting factors (new Table I-18) to
calculate the fraction of fluorinated input gases exhausted from tools
with abatement systems, ai,f, for use in equations I-19A
through I-19C and I-21, and the fraction of by-products exhausted from
tools with abatement systems, ak,i,f, for use in equations
I-20 and I-22. Second, we are proposing to revise equations I-24A and
I-24B, which calculate the weighted average DREs for individual F-GHGs
across process types in each fab.\23\ Third, we are proposing at 40 CFR
98.93(i)(3) to require that all stacks be tested if the stack test
method is used. Finally, we are proposing to replace equation I-19 with
a set of equations (i.e., equations I-19A, I-19B, and I-19C) that will
more accurately account for emissions when pre-control emissions of an
F-GHG come close to or exceed the consumption of that F-GHG during the
stack testing period.
---------------------------------------------------------------------------

    \23\ Fab is defined in 40 CFR 98.98 as ``the portion of an
electronics manufacturing facility located in a separate physical
structure that began manufacturing on a certain date.''
---------------------------------------------------------------------------

    The first three changes to the stack test method would remove the
requirements to apportion gas consumption to different process types,
to manufacturing tools equipped versus not equipped with abatement
systems, and to tested versus untested stacks. Currently, the fractions
of fluorinated input gases and by-product gases exhausted from
manufacturing tools with abatement systems, used in equations 1-19a
through I-22, must be estimated by apportioning gas consumption to
these tools. The proposed equations I-24C and I-24D would add the
option to calculate the fraction of each input gas ``i'' and by-product
gas ``k'' exhausted from tools with abatement systems based on the
number of tools that are equipped versus not equipped with abatement
systems, along with weighting factors that account for the different
per-tool emission rates that apply to different process types.
Facilities would continue to have the option to apportion gas
consumption to tools with and without abatement systems by using
paragraph 98.93(e). They would also have the option to apportion gas
consumption to the different process types and sub-types, calculating
ai,f and ak,i,f based on the numbers of tools
with and without abatement systems within each process type or sub-
type.
    Weighting factors are necessary when: (1) per-tool pre-control
emission rates differ between different process types; (2) an input gas
is consumed by more than one process type; (3) the use of the input gas
is not apportioned between the process types; and (4) the fractions of
tools equipped with emissions control technologies differ between
process types. The weighting factors ([gamma]i,p for input
gases and [gamma]k,i,p for by-product gases, provided in
Table I-18) are based on data submitted by semiconductor manufacturers
during the process of developing the 2019 Refinement.\24\ This data
source was used in lieu of subpart I data, as the EPA does not collect
data on gas consumption or gas consumption per tool. The calculated
weighting factors were within the expected range, considering the
differences between the emission factors used and the expected per-tool
gas consumption for the different process types. For
microelectromechanical systems (MEMS) or PV manufacturing that uses
semiconductor tools and processes, the weighting factors in Table I-18
can be used. For processes without a weighting factor in Table I-18, a
default of 10 must be used. More information on the data used to
develop the weighting factors in Table I-18 can be found in the
document, Technical Support for Proposed Revisions to Subpart I (2021)
(hereafter referred to as ``subpart I TSD''), available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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    \24\ The data used to develop the gamma weighting factors are
also available in the IPCC workbook, ``Gamma Data Submitted by
Industry.xlsx,'' (2019), available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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    Equations I-24A and I-24B, which calculate the weighted average
DREs for individual F-GHGs across process types, would rarely be used
if the EPA adopts the same default DREs for all process types as
discussed in section III.E.1.b of this preamble, because there will
rarely be any need to calculate weighted average DREs across process
types in that case. The sole exception may occur when a facility uses
one or more abatement systems with a certified DRE value that is
different from the default to calculate and report controlled
emissions. To accommodate this situation and to simplify equations I-
24A and I-24B, we are proposing to modify equations I-24A and I-24B to
calculate the average DRE for each input gas ``i'' and by-product gas
``k'' based on tool counts and the same weighting factors that would be
used in equations I-24C and I-24D. This would eliminate the requirement
to apportion gas consumption by process type when using the stack test
method, even for those facilities that use abatement systems with
different DREs for the same input gas ``i'' or by-product gas ``k''.
    Requiring that all stacks be tested (if the stack test method is
used) would remove not only the need to apportion gas usage to tested
versus untested stacks, but also the requirement to perform a
preliminary calculation of the emissions from each stack system (we are
proposing to remove the requirements at 40 CFR 98.93(i)(1)). The EPA
expects that the data received would be more accurate due to requiring
testing of all stacks. The EPA also expects that the revision to
measure all stacks instead of apportioning gas usage between process
type and subtype and between tested and untested stacks would
streamline the implementation of the stack testing method at facilities
and increase the likelihood of this method being used instead of the
emission factor approach. Currently, to account

for emissions from untested stacks, facilities must calculate gas
consumption of each F-GHG used in tools that are vented from untested
stacks by apportioning gas between untested and tested stacks. When
abatement is used, facilities also currently need to apportion by
process type. Apportioning gas requires using a fab-specific
engineering model that must be based on a quantifiable metric, such as
wafer passes or wafer starts, or direct measurement of input gas
consumption and must be verified by demonstrating its precision and
accuracy as described in 40 CFR 98.94(c)(1). As the number of stacks at
each fab is expected to be small (e.g., one to two), the EPA expects
that measuring all stacks would be more accurate and less burdensome
than developing and verifying an apportioning model.
    We also seek comment on whether stack testing should also be used
to estimate N2O emissions if stack testing is the
calculation method elected. Currently, the stack testing option in
subpart I is limited to estimating emissions from F-GHGs;
N2O emissions must be estimated using the default emission
factors in Table I-8. The use of the stack testing method for
N2O was not previously recommended by industry due to: (1)
the high monthly and yearly variability in measured N2O
emission factors estimated from stack testing for some fabs; and (2)
the observation that estimated N2O emission factors from
stack testing also often exceeded 1, indicating a second, unidentified,
source of N2O.\25\ No source for the additional
N2O formation or the high variability was identified. The
EPA requests comment on the extent to which the sources of
N2O formation from electronics manufacturing have been
identified. We are also requesting comment on the expected variability
of the estimated N2O emission factor from stack testing if
using the current or revised methods for estimating emissions using
stack testing and whether new data are available. If estimated
N2O emission factors are now expected to be consistent over
time, the use of N2O in stack testing could be re-evaluated
during a future rulemaking.
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    \25\ See Semiconductor Industry Association (SIA) Response to
EPA's Stack Test Question 1, March 7, 2012, and Technical Support
for Other Technical Issues Addressed in Revisions to Subpart I, U.S.
EPA, August 2012, both of which are available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    We are also proposing to replace equation I-19 with a set of
equations that will more accurately account for by-product emissions
when that by-product F-GHG is also an input gas. Specifically, the new
equations will more accurately account for emissions when emissions of
an F-GHG prior to entering any abatement system (i.e., pre-control
emissions) would approach or exceed the consumption of that F-GHG
during the stack testing period. Pre-control emissions of an F-GHG can
approach or exceed consumption of that F-GHG when the F-GHG is
generated as a by-product of other F-GHGs used in the fab. To ensure
that calculated emission factors reflect this physical reality, any
excess pre-control emissions of the F-GHG should be assumed to be
formed as a by-product. Currently, the paragraph containing equation I-
19, 40 CFR 98.93(i)(3)(iii), does not sufficiently account for such by-
product formation, potentially resulting in overestimated input gas
emission factors and underestimated by-product gas emission factors.
    This potential inaccuracy arises because 40 CFR 98.93(i)(3)(iii),
in its assignment of portions of the emissions to either input gases or
by-products, does not currently account for the utilization
(dissociation) of the input gas or for any abatement of the input gas.
Instead, the provision compares the total measured emissions of the F-
GHG, which may have passed through abatement systems prior to
measurement, to the consumption (termed ``activity'' in equation I-19)
of that F-GHG during the stack testing period. If the measured
emissions equal or exceed consumption, the term for total emissions in
equation I-19, [sum]sEi,s, is equated to
consumption to calculate the input gas emission factor, and any
difference between the measured emissions of the F-GHG and the
consumption of the F-GHG is treated as by-product emissions and used to
calculate a by-product emission factor (BEF) in equation I-20. While
this approach avoids assigning a controlled emission factor greater
than 1.0 to the input gas, in cases where the measured emissions are
greater than consumption, the corresponding pre-control emission factor
is either equal to 1.0 (if the measured emissions are uncontrolled) or
greater than 1.0 (if the measured emissions are controlled). In the
first case, the pre-control emission factor fails to account for any
utilization of the input gas. In the second case, the pre-control
emission factor both fails to account for any utilization of the input
gas and attributes emissions to the input gas for which the input gas
cannot possibly be the source (because that would violate conservation
of mass).
    To more accurately assign emissions of the gas to by-product or
input gas emissions, a better methodology is to compare the measured
emissions to the maximum expected controlled emissions of the input gas
during the stack testing period, rather than to the consumption during
that period. To make this change, we are proposing to remove equation
I-19 and replace that equation with equations I-19A, I-19B, and I-19C,
making corresponding changes to 40 CFR 98.93(i)(3)(iii). Equation I-19A
estimates the maximum expected controlled emissions for each F-GHG from
the fab during the stack testing period at a utilization rate (U) equal
to 0.2 (i.e., a 1-U or input gas emission factor of 0.8) and at the
levels of abatement and abatement system uptime observed during the
stack testing period. If the total emissions measured during the stack
testing period are less than the maximum expected controlled emissions
calculated using I-19A, then all emissions of gas i are attributed to
the consumption of gas ``i'' and equation I-19B is used to calculate
the input gas emission factor for gas ``i''. Equation I-19B is similar
to equation I-19 in the current rule, but with an updated process-
independent variable for the DRE. However, if the total measured
emissions are greater than the estimate of the maximum controlled
emissions, then the input gas emission factor is assumed to be equal to
the maximum controlled emission rate at an uptime equal to 1, as
calculated in equation I-19C. The remaining emissions (the difference
between the measured emissions and the value calculated in equation I-
19A) are used to calculate the BEF for that gas from other input gases
in equation I-20.
    The revised equations improve upon the current equations because
they account both for any control of the emissions and for some
utilization of the input gas. The input gas emission factor (1-U) of
0.8 used in equations I-19A and I-19C is the same as the default 1-U
factor that would be assigned where a default is not available in
Tables I-3 and I-4, as discussed in III.E.2.b of this preamble. Using a
value of 0.8 as a maximum input gas emission factor (1-U) would be
consistent with the other proposed changes and is expected to increase
the accuracy of the stack testing method, as some utilization of the
input gas is expected. These changes to the stack testing equations
would improve the quality of the stack testing method by more
accurately assigning emissions to their source.
    In addition to the substantive changes to equation I-19, the EPA is
proposing to clarify the definitions of the variables

dif and dkif, the average DREs for input gases
and by-product gases respectively, in equations I-19A, I-19B, I-19C,
and I-19D, in equations I-20 through I-22, in equations I-24A and B,
and in equation I-28 of subpart I. Currently, the definition for the
variable dif reads ``Fraction of fluorinated GHG input gas i
destroyed or removed in abatement systems connected to process tools in
fab f,'' which could be interpreted to reflect both the fraction of
emissions of gas i that is fed into abatement systems and the fraction
of gas i that is destroyed once gas i is fed into abatement systems.
However, dif (and dkif) are only intended to
reflect the fraction of gas i (or by-product gas k) that is destroyed
once gas i (or by-product gas k) is fed into abatement systems. To make
this clear, we are proposing to change the definition of dif
to read ``Fraction of fluorinated GHG input gas i destroyed or removed
when fed into abatement systems by process tools in fab f,'' and we are
proposing a parallel change to the definition of dkif.
b. Revisions To Clarify and Revise Calculation Methodologies and
Required Data Elements for Data Submitted in the Technology Assessment
Report
    For the reasons described in section II.A.1 of this preamble, we
are proposing to require that three emission factor calculation
methods, specified in this section and described in the subpart I TSD
(available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424), be used when calculating utilization and by-product
emission rates submitted in technology assessment reports. These three
methods would be used to report the results of each emissions test.
Based on a comparison among the results of the three methods, we may
ultimately require use of a single method through a future rulemaking.
    As stated in the preamble to the 2013 final rule that established
the requirement to submit technology assessment reports (78 FR 68175,
November 13, 2013), one of the EPA's goals in collecting emission
factor data through the reports is to better understand how emission
factors may be changing as a result of technological changes in the
semiconductor industry, and whether the changes to the emission factors
may justify further data collection to comprehensively update the
default emission factors in Tables I-3 and I-4. To meet this goal, the
emission factors submitted in the technology assessment reports should
be calculated the same way as the emission factors already in the EPA's
database were calculated; otherwise, differences attributable to
differences in calculation methods may amplify or obscure differences
attributable to technology changes. To date, the EPA has not initiated
a broad data collection to comprehensively update the default emission
factors, but the EPA is now proposing to use the emission factor data
submitted in the 2017 and 2020 technology assessment reports to make
minor updates to the default emission factors, and the EPA may continue
this practice in the future. This introduces a second goal for the
emission factors submitted in the technology assessment report, which
is that they be robust to ensure that the resulting updated default
emission factors are robust. To meet this goal, the reported emission
factors should be broadly applicable because they reflect physical
reality as much as possible and are not unduly affected by changing
proportions of input gases. In addition, the reported emission factors
should be consistently calculated across facilities and processes to
ensure that the resulting defaults are not biased by ``cherry-picking''
of methods to achieve a desired result for a given process or facility
(or set of processes or facilities). Requiring facilities to (1) use
specified methods to calculate emission factors and (2) use all three
methods for each test meets these goals to different extents and in
different ways.
    Requiring facilities to use specified emission factor calculation
methods would ensure that the emission factors are robust insofar as
the calculation methods are designed to yield robust factors. It would
also help ensure that the emission factors are developed in a
reasonably, though not perfectly, consistent manner across processes
and facilities and over time, given that the proposed calculation
methods are similar but not identical. (As discussed in this section,
two of the proposed emission factor calculation methods are based
closely on the emission factor calculation methods used for the
emission factors already in the EPA's database.) The EPA has previously
received emission factors calculated via a variety of methods, as
described further in this section. This has sometimes made it difficult
to determine whether changes in calculated emission factors are due to
changes in technology or to changes in the emission factor calculation
method. In some cases, we have not been able to use submitted emission
factor data because it was found to be calculated using a method that
was significantly different from previous methods and that appeared
unlikely to represent actual gas behavior. (The lead authors of the
Electronics chapter of the 2019 Refinement declined to use this data
for similar reasons.) \26\ Specifying emission factor calculation
methods would at least partially address these problems.
---------------------------------------------------------------------------

    \26\ 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.
---------------------------------------------------------------------------

    Requiring facilities to submit three sets of emission factors for
each test would more fully address these problems by enabling us: (1)
to directly compare the new emission factor data to the emission factor
data that is already in the EPA's database and that was calculated
using the same method; and (2) to compare the results across the
available emission factor calculation methods and to identify any
systematic differences in the results of the different methods for each
gas and process type. By identifying and quantifying systematic
differences in the results of the different methods, we would be better
able to distinguish these differences from differences attributable to
technology changes. This would enable us to build a bridge between the
data sets resulting from the different methods, which would be useful
in the event that we ultimately required facilities to submit emission
factors using one method only, particularly if that method was not one
of the methods used historically. We would also be able to evaluate how
much the results of each method varied for each gas and process type;
high variability may indicate that the results of a method are being
affected by varying input gas proportions rather than differences in
gas behavior, as discussed further in this section. Ultimately, these
analyses would enable us to more accurately characterize emissions from
semiconductor manufacturing by selecting the most robust emission
factor data for updating the default emission factors in Tables I-3 and
I-4. Because we plan to incorporate the three methods into spreadsheets
that would calculate three sets of emission factors based on a single
set of entered data, we do not anticipate that requiring reporting of
the results of the three methods would significantly increase burden.
We are proposing the three emission factor calculation methods in 40
CFR 98.96(y)(2)(iv)(A) through (C).
    Two of the proposed methods are closely based on the methods that
have been used historically to calculate emission factors for processes
that use multiple gases: ``all-input gas method''

and the ``dominant gas method''.\27\ \28\ Consequently, the emission
factors calculated using these methods are generally expected to be
comparable to the emission factors calculated and submitted to the EPA
in the past. The emission factors calculated using these methods are
also expected to be reasonably robust except under certain
circumstances discussed further in this section. To increase the
robustness of the emission factors calculated using these methods under
those circumstances, we are proposing to modify the methods to avoid
input gas emission factors greater than 0.8 for processes that use
multiple gases.
---------------------------------------------------------------------------

    \27\ See section 2.0 of the document, Technical Support for
Modifications to the Fluorinated Greenhouse Gas Emission Estimation
Method Option for Semiconductor Facilities under Subpart I (2012),
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424).
    \28\ Previously, the EPA had suggested that the all-input gas
method be used for etch emission factors (Ibid.), and most of the
etch data in the data set used to develop the current emission
factors used this method (see 78 FR 68185 and previously submitted
data sets Etch Process Equipment Emissions Characterization Data and
International SEMATECH Manufacturing Initiative Environmental Safety
and Health Technology Center, February 2012, and the document Draft
Emission Factors for Refined Semiconductor Manufacturing Process
Categories (2010), all available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424). However, some of this data was
calculated using the dominant gas method.
---------------------------------------------------------------------------

    Historically, both the all-input gas and dominant gas methods have
calculated the input gas emission rate in the same way: all emissions
of each F-GHG that is an input gas have been attributed to the 1-U
factor for that gas (kg of input gas emitted/kg of input gas used);
that is, both methods imply that if an F-GHG is used as an input gas,
that F-GHG is not also formed as a by-product. However, the two methods
treat by-product F-GHGs that are not used as input gases differently.
The dominant gas convention assigns all emissions of F-GHG by-products
to the carbon-containing F-GHG input gas accounting for the largest
share by mass of the input gases (kg of by-product emitted/kg of
dominant gas used), while the all-input gas convention assigns
emissions of F-GHG by-products to all F-GHG input gases (kg of by-
product emitted/kg of all F-GHGs used). With a slight modification, the
all-input convention has also been used to assign emissions of F-GHG
by-products to only all carbon-containing F-GHG input gases, i.e., not
to SF6 or NF3 input gases (kg of by-product
emitted/kg of all F-GHGs used).
    Due to the complex set of chemical reactions necessary to describe
plasma etching by multiple input gas processes, it is not generally
known what fractions of a by-product gas are produced by each input
gases, or what fractions of an emitted input gas consist of unreacted
residual gas versus newly formed by-products of other gases. Both
methods of assigning emission factors described above have historically
been based on the assumption that the emissions of each input gas (1-U)
are much larger than the emissions of the same gas as a by-product of
the other input gases (e.g., CF4 produced from
C2F6) and thus, the BEF can be approximated as
zero. However, as stated in section III.E.1.c of this preamble on
updates to the default emission factors, it has been well established
that most input gases produce CF4 and
C2F6 in significant quantities. Thus, in cases
where C2F6 or CF4 is an input gas (and
possibly for some additional cases), assigning all of the emissions of
C2F6 or CF4 to the
C2F6 or CF4 input gas, respectively,
may not be a good approximation and can lead to cases where the
reported emission factor is greater than 1, which violates conservation
of mass. This is most likely to happen when an input gas such as
CF4 makes up a relatively small share of the total input gas
mass and is also generated in significant quantities as a by-product by
the other input gases.
    To address this issue, our proposed methods include a modification
to both of the historically recommended methods to avoid an input gas
emission factor greater than 0.8 when multiple gases are used, and we
are also proposing to introduce an additional calculation method. The
modified methods would attribute emissions of each F-GHG used as an
input gas to that input gas until the mass emitted equaled 80 percent
of the mass fed into the process, that is, until the 1-U factor equaled
0.8. The methods would then assign the remaining emissions of the F-GHG
either to the dominant input gas as a by-product (in the dominant gas
method) or to the other input gases as a by-product in proportion to
the quantity of each input gas used in the process (in the all-input
gas method). This approach avoids violating conservation of mass and
better reflects the expectation that at least a small portion of the
input gas will be utilized in the process. Nevertheless, because 0.8
represents an upper bound for input gas emission factors, even the
modified methods have the potential to significantly overestimate input
gas emission factors. To the extent that these factors are later
applied to processes where the input gas accounts for a larger share of
the total input gas mass (e.g., because they are used to calculate
default factors), they will overestimate emissions of the input gas.
    A third convention, the reference emission factor method, is likely
to provide more robust, realistic results, although it represents a
somewhat larger change from the emission factor calculation conventions
historically used. The reference emission factor method begins with the
average input gas utilizations (1-U factors) and/or BEFs observed based
on single gas recipes. In single-gas recipes, all emissions of an input
gas clearly originate from its use as an input gas, and all emissions
of a by-product clearly originate from its generation as a by-product;
thus, the 1-U factor and BEFs based on single-gas recipes are not
affected by the uncertainties regarding the origins of the emissions
that can affect these factors for multi-gas recipes.
    Since it is not known whether the 1-U factor or BEFs are more
likely to change in moving from single- to multiple-gas recipes, the
reference emission factor method calculates emissions using the 1-U and
the BEFs that are observed in single gas recipes and then adjusts both
factors based on the ratio between the emissions calculated based on
the factors and the emissions actually observed in the multi-gas
process. This approach uses all the information available on
utilization and by-product generation rates from single-gas recipes
while avoiding assumptions about which of these are changing in the
multi-gas recipe.
    In summary, the chief advantage of the dominant gas method proposed
at 40 CFR 98.96(y)(2)(iv)(A) and the all-input gas method proposed at
40 CFR 98.96(y)(2)(iv)(B) is that they are the methods used previously
to calculate the emission factors that are already in the EPA's
database and that form the basis of the current subpart I default 1-U
and BEFs. Therefore, new emission factors calculated using these
methods are expected to be comparable \29\ to the emission factors
already in the EPA's database, facilitating efforts to identify changes
in emission factors that are attributable to technology changes. The
chief disadvantage of these two methods is that they can result in a
significantly overestimated 1-U value when the share of an input gas
such as CF4 declines.

This disadvantage is mitigated partly, but not completely, by capping
1-U values at 0.8. At the same time, however, capping 1-U values at 0.8
decreases the comparability of these methods with those previously used
to calculate and report emission factors. The EPA requests comment on
whether the gain in robustness achieved by capping 1-U values at 0.8
justifies the accompanying loss in comparability to previously
submitted data, particularly given that we are proposing to require
submission of results using both the historically used methods and the
new, likely more robust, reference emission factor method. The
reference emission factor method is being proposed at 40 CFR
98.96(y)(2)(iv)(C). The advantages and disadvantages of the three
methods are described further in the document Technical Support for
Modifications to the Fluorinated Greenhouse Gas Emission Estimation
Method Option for Semiconductor Facilities under Subpart I, cited above
in this section. The EPA also considered requiring use of one specific
method for the data submitted in future technology assessment reports.
This would allow all future reports to have comparable data. However,
if one of the historically used methods were specified, the resulting
emission factors might not be as robust as they would be if the
reference emission factor method were specified. On the other hand, if
the reference emission factor method were specified, the resulting
emission factors would not be fully consistent with previously
submitted emission factors, and this inconsistency would be difficult
to address without having seen the results of the different methods
side-by-side at least once. Another option would be to let the reporter
choose one of three methods in 40 CFR 98.96(y)(2)(iv)(A) through (C)
for subsequent reports. This option would result in a loss of
comparability between tests. The EPA is requesting comment on these
alternatives.
---------------------------------------------------------------------------

    \29\ As discussed further in the document Technical Support for
Modifications to the Fluorinated Greenhouse Gas Emission Estimation
Method Option for Semiconductor Facilities under Subpart I, cited
above in this section, trends in gas usage, such as the use of more
and more individual input gases, may introduce apparent, but not
real, trends in the 1-U values calculated using these methods.
---------------------------------------------------------------------------

    We request comment on the methods proposed at 40 CFR
98.96(y)(2)(iv)(A) through (C) for calculating emission factors for
multi-gas recipes, particularly concerning their reliability as
indicators of actual emission rates and emission rate trends. In
addition, the EPA requests comment on the use of 0.8 as the maximum 1-U
value in the modified dominant-gas and all-input gas methods.
    We also request comment on the reference emission factor method
proposed at 40 CFR 98.96(y)(2)(iv)(C). While this method differs from
the historically used methods, the differences are not expected to
become important except where CF4 or
C2F6 make up a small share of the input gas mass,
that is, where the historically used methods are known to yield
inaccurate results. The EPA believes that the increase in accuracy
gained through the new method justifies some loss of time series
consistency (i.e., comparability between newly submitted emission
factor data and previously submitted emission factor data). Moreover,
because we are proposing to require reporting of the results of each
test using all three calculation methods, we can compensate for the
loss of time series consistency between the historically used methods
and the reference emission factor method by: (1) comparing the emission
factors already in the EPA's database to the versions of the new
emission factors calculated using the historically used methods (i.e.,
the all-input gas and dominant gas methods); and (2) analyzing
systematic differences that occur between the results of the
historically used methods and of the reference emission factor method
so that these can be considered in future comparisons between new and
existing data. We also request comment on whether BEFs based on multi-
gas recipes should be included in the reference BEFs for the reference
emission factor method. The benefit of including BEFs based on multi-
gas recipes in the reference BEFs is that this would increase the
number of data points used as a basis for those BEFs, in some cases
providing reference BEFs where none are available from the single gas
data set (due to a lack of data). The drawback of including BEFs based
on multi-gas recipes is that these BEFs are subject to some
uncertainty. BEFs measured for multi-gas recipes where the by-product
F-GHG is not also used as an input gas are less uncertain than BEFs
where the by-product F-GHG is also an input gas. However, uncertainty
remains regarding which of the multiple input gases are primarily
responsible for the formation of that by-product and whether all input
gases contribute to the formation of each by-product. For more
information on the advantages and disadvantages of using only single-
gas measurements or all measurement to determine reference emission
factors see the subpart I TSD, cited above in this section.
    We also seek comment on whether there are alternative methods for
calculating utilization and by-product formation rates that the EPA
should consider in the future. To enable us to evaluate any suggested
methods, we request that commenters suggesting an alternative method
also provide information on the rationale for using the alternative
method instead of one of the methods described above and a comparison
between a representative group of emission factors (both 1-U and BEFs)
calculated using the alternative method and a group of emission factors
based on the same data but calculated using the all-input gas method,
the dominant gas method, and the reference emission factor method. The
EPA may evaluate, at a future date, such alternative methods based, for
example, on the likely accuracy of the alternative calculation method
and its consistency with previously used calculation methods.\30\
---------------------------------------------------------------------------

    \30\ See document Technical Support for Proposed Revisions to
Subpart I (2021), available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    We are also proposing that where reporters provide any data on
utilization and by-product formation rates in the technology assessment
report, they must also specify the method used to calculate the
reported utilization and by-product formation rates and assign and
provide an identifying record number for each data set. This
information allows the EPA to better understand the data being
submitted. For example, this information helps the EPA identify all the
gases used in a multi-gas test and understand the influence of the
calculation method and gas mixtures on the resulting emission factors.
This detailed understanding may help us to develop new or revised
emission factors that are representative of the industry. Without
collecting these data, the EPA may not be able to effectively evaluate
the influence of different emission factor calculation methods or gas
combinations on the resulting emission factors.
    We are also proposing at 40 CFR 98.96(y)(2)(iv) that for any
destruction or removal efficiency (DRE) data submitted, the report must
include whether the abatement system used for the measurement is
specifically designed to abate the gas measured under the operating
condition used for the measurement. This information will help the EPA
understand whether the submitted data should be considered to be a
result for a certified abatement system for the gas being measured. The
efficacy of abatement systems generally depends on both whether it is
designed to abate the F-GHG and whether it is installed, operated, and
maintained according to the manufacturer's specifications. Abatement
systems are known to have reduced efficacy when the individual process
gas and total gas flow rates (including any added purge

gases) as specified by the abatement system supplier are exceeded.
c. Updates to Default Emission Factors and Destruction or Removal
Efficiencies To Improve the Accuracy of Emissions Estimates
    The EPA is proposing to update the default emission factors and
destruction or removal efficiencies (DREs) in subpart I based on new
data submitted as part of the 2017 technology assessment report
(submitted with the RY2016 annual report) and the 2020 technology
assessment report (submitted with the RY2019 annual report).\31\ First,
we are proposing to update the utilization rates and BEFs for F-GHGs
used in semiconductor manufacturing in Tables I-3, I-4, I-11 and I-12
to reflect new data received in the 2017 and 2020 technology assessment
reports, to correct errors identified in the data set on which the
current default emission factors are based, and to remove BEFs where
both the emission factor and the GWP of the emitted by-product are very
low. Second, we are also proposing to update and expand the default
emission factors for N2O used in all electronics
manufacturing in Table I-8 based on both new data from the 2017 and
2020 technology assessment reports and new emission factors available
in the 2019 Refinement. Third, we are proposing at 40 CFR 98.93(a)(6)
to revise the utilization rate and BEF values assigned to gas/process
combinations where no default utilization rate is available. Finally,
we are proposing to update the default DREs in Table I-16 to reflect
the incorporation of new data from the 2017 and 2020 technology
assessment reports and a new approach to abatement system
certification. These updates are expected to increase the accuracy of
the emissions reported by facilities under subpart I.
---------------------------------------------------------------------------

    \31\ Available in ``UPDATED Appendix A Process Emissions
Characterization Data,'' Semiconductor Industry Association, April
2018, and ``2020 Subpart I Consolidated Triennial Report, Appendices
A-B,'' Semiconductor Industry Association, March 2020, available in
the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    The proposed emission factors for Tables I-3, I-4, I-11, and I-12
were calculated from measured data submitted by U.S. semiconductor
manufacturers as part of the 2020 technology assessment report, 2017
technology assessment report, and data collected in previous years.\32\
The total data set contains 4,358 input gas and BEFs across all
commonly used gas and process type combinations, with 1,506 of these
data points newly available via the 2020 and 2017 triennial technology
assessment report. All the data submitted via the 2020 and 2017
triennial technology assessment report were applicable to the 300-mm
wafer size. All data sets were reviewed for errors, including, but not
limited to, transcription errors and violations of the fluorine
balance. Calculated emission factors (1-U or BEFs) greater than 1.00 (a
total of 18 data points) were excluded from the calculation of the
proposed default emission factors (EFs). Input gas and by-product gas
emission factors were also analyzed for each test to see whether the
fluorine balance was violated. This resulted in the exclusion of 40
data points from the calculation of the proposed default emission
factors. There were also a small number of transcription or other
errors, including duplicate rows of data, that were corrected or
excluded prior to calculating the proposed emission factors.
Transcription and other errors resulted in the exclusion of 33 data
points. A single reported by-product value for SF6 was also
excluded from the calculation, as there was no source of sulfur. Four
emission factors for NF3 in remote plasma cleaning (RPC)
processes that were previously excluded \33\ were re-included in the
data set, as discussed in the subpart I TSD, available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    \32\ The data submitted in previous years can be found in
Semiconductor Industry Association; Etch Process Equipment Emissions
Characterization Data, International SEMATECH Manufacturing
Initiative Environmental Safety and Health Technology Center,
February 2012, and Draft Emission Factors for Refined Semiconductor
Manufacturing Process Categories, Office of Air and Radiation, May
2010, each of which is available in the docket for this rulemaking,
Docket Id. No. EPA-HQ-OAR-2019-0424.
    \33\ See Technical Support Document for Process Emissions from
Electronics Manufacture (e.g., Micro-Electro-Mechanical Systems,
Liquid Crystal Displays, Photovoltaics, and Semiconductors):
Proposed Rule for Mandatory Reporting of Greenhouse Gases, Revised,
November 2010, available in the docket for this rulemaking, Docket
Id. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------

    Submitted data were also reviewed for methodological consistency
with previously submitted data. As discussed earlier in III.E.1.b of
the preamble, data submitted to the EPA prior to 2017 used either the
dominant gas or all-input gas convention. However, many of the data
points for etching submitted as part of the 2020 and 2017 technology
assessment report used an alternative convention that had not been
previously used. This new ``multi-gas'' convention differed in how it
assigned emissions of input gases. Instead of assigning measured
emissions of an input gas entirely to the input gas, emissions of an
input gas were assigned to all input F-GHGs used in the process by
dividing the measured mass emitted of a specific input gas by the total
mass of all input F-GHGs and assigning this emission factor to each
input F-GHG as either the 1-U factor or the by-product factor, i.e.,
all input F-GHGs were considered to equally contribute to the emissions
of each input gas. This method was inconsistent with the methods of the
previous data set, and the alternative method often resulted in large
increases to the reported BEFs and concurrently large decreases to the
reported 1-U. This change appeared to be largely a result of the change
in methodology; however, it was not possible, based on the data
received, to fully assess the effect of the new methodology as the data
were not directly comparable to previously submitted data. The data
points that were affected by the change in convention were excluded
from the calculation of the proposed default EFs, resulting in the
exclusion of 338 data points. This left a total of 3,951 data points in
the combined data set that were included in the calculations of the
proposed default emission factors in Tables I-3 and I-4.
    The proposed default EFs for Tables I-3 and I-4 were calculated
using a simple arithmetic mean of all EF data that used either the all-
input gas or the dominant gas convention. The technology assessment
reports reported no major changes to semiconductor production
technology, and the differences between the average emission rates
calculated based on the new and previously submitted data,
respectively, are generally small (i.e., less than  20
percent for most commonly used input gases). Therefore, it is assumed
in most cases that the proposed default emission factors for F-GHGs
reflect increased and/or improved data rather than changes in actual
emission or utilization rates. This means that for each wafer size
(<200 mm and 300 mm), the proposed emission factors are generally
likely to represent emission rates over all the years of the GHGRP.
However, for a few gas and process type combinations for the 300-mm
wafer size, the differences between the averages calculated based on
the new and previously submitted data are more significant and could
have an appreciable impact on the overall calculated CO2e
emissions. More information on the differences between the data
contained in the two technology assessment reports received to-date and
the previously submitted data is available in the subpart I TSD,

available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2019-0424. In light of these findings, we request comment on whether
the new data reflect recent technology changes or simply better
represent technologies that have been in use over the long term (i.e.,
at least since 2011, the first year of reporting under the GHGRP). This
is important for understanding the time period to which the new data
for these four factors are applicable.
    We are also proposing to update the calculation methodology for
MEMs and PV manufacturing to allow use of 40 CFR 98.3(a)(1), the
current methodology for semiconductor manufacturing, in lieu of using
40 CFR 98.3(a)(2) for manufacture of MEMs and PV using semiconductor
tools and processes. This would have the effect of applying the default
emission factors in Tables I-3 and I-4 to these processes. In the 2019
Refinement, use of semiconductor default emission factors for MEMs
manufacturing is recommended when using semiconductor tools to
manufacture MEMs. Similarly, we are also proposing the use of
semiconductor emission factors for PV manufacturing that uses
semiconductor manufacturing tools. It is expected that the use of
semiconductor emission factors will result in more accurate emissions
estimates when semiconductor manufacturing tools and processes are
used.
    The current Table I-8 does not distinguish N2O emission
factors either by the type of electronic device manufactured
(semiconductor versus LCD) or by wafer size. Due to the increased
availability of N2O emission factor data, we are proposing
to update Table I-8 to include distinct utilization rates for
N2O for semiconductor manufacturing and LCD manufacturing
and, for semiconductor manufacturing, utilization rates by wafer size
(<200 mm and 300 mm) and by process type.\34\ The proposed emission
factor for N2O used in CVD thin film deposition for LCD
manufacturing can be found in the 2019 Refinement.\35\ Currently there
is no LCD manufacturing in the United States and thus, no U.S. data is
available for LCD manufacturing.
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    \34\ More information regarding the development of the proposed
default emission factors can be found in the workbook titled, ``Data
sets Supporting Revised Emission Factors.xlsx,'' (U.S. EPA, April
2020) and in the subpart I TSD, available in the docket for this
rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
    \35\ 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.
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    We are also proposing to remove BEFs from Tables I-3 and I-4 where
there is a combination of both a low BEF and a low GWP, resulting in
very low reported emissions per metric ton of input gas used (<0.03
mtCO2e and less than 0.0002 percent of emissions (in
CO2e) per metric ton of input gas consumed). This would
result in: (1) removing the BEFs for C4F6 and
C5F8 for all input gases used in wafer cleaning
or plasma etching processes due to the combination of a low GWP (0.003
and 1.97, respectively) and low BEFs (less than 0.009); and (2) not
adding BEFs for COF2 and C2F4 for any
input gas/process combination from the new data received in the 2020 or
2017 technology assessment reports because these BEFs are less than 0.2
and COF2 and C2F4 have low GWPs (0.14
and 0.004, respectively). COF2 does not have a chemical
specific GWP in Table A-1 (it is currently assigned a default GWP of
2000 as an ``Other Fluorinated GHG''), but the 2018 WMO Scientific
Assessment listed the 100-year GWP of COF2 as ``<1.'' We
calculated a precise GWP for COF2 of 0.14 using the
atmospheric lifetime and radiative efficiency provided in the 2018 WMO
Scientific Assessment. (The method we used to calculate the GWP of
COF2 was the method we used to calculate precise GWPs for
low-GWP compounds in the most recent update to GHGRP GWPs (79 FR 73750,
December 11, 2014)). Currently, Table I-3 lists the BEF for
C4F6 from all input gases as `NA'. Similarly,
Table I-4 currently lists the BEF for C5F8 from
all input gases as `NA'. Thus, for these two cases, there will be no
change in reported emissions. Data reported to the GHGRP in 2013 \36\
indicates that, in total, for all semiconductor manufacturers reporting
to the GHGRP in 2013, by-product emissions of
C5F8 and C4F6 totaled 0.27
and 0.0004 mtCO2e, respectively. Similarly, it is estimated
that based on 2013 gas consumption COF2 and
C2F4 by-product emissions for the semiconductor
fabs reporting to the GHGRP in 2013 would have been 0.43
mtCO2e and 0.005 mtCO2e, respectively, if
COF2 and C2F4 emission factors were
adopted. For the largest fabs, generation of all by-products listed
above whose emission factors are being proposed for removal or
exclusion from Tables I-3 and I-4 would result in less than 0.6
mtCO2e in combined emissions per fab and significantly less
for smaller fabs. We are also proposing to modify the applicability of
carbon-containing BEFs to chamber cleaning process subtypes where
neither the input gas(es) nor the films being processed by the chamber
contain carbon. In the emission factor tables in subpart I (e.g., Table
I-3 and I-4), there are cases where a perfluorocarbon BEF is provided
even when the input gas i does not contain carbon (e.g.,
NF3). However, when none of the input gases contain carbon
(e.g., NF3 or SF6), and when the chamber being
cleaned does not process films that contain carbon, then neither
CF4 nor other carbon-containing gases are expected to be
formed during the process.\37\ Thus, we are proposing that in cases
where neither the input gas nor the films being processed in the tool
contain carbon, the BEF for the carbon-containing by-products be set to
zero (refer to variable ``Bkij'' in proposed equation I-8B).
We are proposing to apply this provision at the process subtype level;
a BEF of zero would only be used for a combination of input gas and
chamber cleaning process subtype (e.g., NF3 in RPC) if no
carbon-containing materials were removed using that combination of
input gas and chamber cleaning process subtype during the year and no
carbon-containing input gases were used on those tools. Otherwise, the
default BEF would be used for that combination of input gas and chamber
cleaning process subtype for all of that gas consumed for that subtype
in the fab for the year. An alternative approach would be to implement
this change at the individual process or tool level, tracking gas
consumption used in processes and tools that deposit films that contain
carbon. This would lead to a more precise estimate of carbon-containing
by-product emissions but may require

greater apportioning than is otherwise required by the rule. We request
comment on this alternative approach. Whether this revision was
implemented at the process subtype or process level, it would improve
the accuracy of the emissions estimate compared to the current rule by
differentiating between process subtypes (or processes) where there is
a source of carbon from which carbon-containing by-products may be
generated and process subtypes (or processes) where there is no source
of carbon from which carbon-containing by-products may be generated.
---------------------------------------------------------------------------

    \36\ GHGRP data from RY2013 was used for this analysis as it is
the last year for which it is was relatively simple to estimate gas
consumption due to revisions to the default emission factors applied
in 2014 and later. For more information on how gas consumption was
estimated, see U.S. EPA. Inventory of Greenhouse Gas Emissions and
Sinks:1990-2017 (2019). https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2017.
    \37\ Chamber cleaning processes, which typically use only one
input gas, are not expected to generate carbon-containing byproducts
from that input gas unless either the input gas or the film being
removed contains carbon. The situation with etching and wafer
cleaning processes, where multiple input gases are often used, is
more complex. This is because input gases that do not contain carbon
can still contribute fluorine to carbon-containing F-GHG by-products
that obtain their carbon from other input gases, particularly if
relatively fluorine-rich and carbon-poor by-products such as
CF4 predominate. The data set supporting the default
emission factors proposed in this action includes by-product
emission factors that have sometimes been calculated assuming that
carbon-containing by-products are attributable to all input gases
(including those lacking carbon) and that have other times been
calculated assuming that carbon-containing by-products are only
attributable to input gases that contain carbon.
---------------------------------------------------------------------------

    In addition, we are proposing to update the default emission
factors for semiconductor manufacturing for use with the stack test
method (Tables I-11 and I-12). These tables will continue to be needed
to calculate emissions from consumption of each intermittent low-use F-
GHG as defined in 40 CFR 98.98. The proposed default emission factors
for Tables I-11 and I-12 were developed using the same data used to
calculate revised emissions factors for Tables I-3 and I-4, as
discussed above. To calculate the proposed default emission factors for
Tables I-11 and I-12, which are process-independent, gas consumption by
process type and wafer size was first estimated from emissions data
reported under subpart I for RY2013. Gas consumption by process type
was then used to weight the process-dependent emission factors from
Tables I-3 and I-4 to arrive at the proposed default emission factors
for Tables I-11 and I-12, respectively. Gas consumption by process type
was used as a weighting factor to arrive at process-independent
emission factors in order to have default emission factors that
represent the average emission factor over total gas consumption by the
industry for each wafer size.\38\ Although the proposed emission
factors proposed in this rulemaking differ slightly from the 2019
Refinement due to the inclusion of newly available data, the
methodology for developing Tables I-11 and I-12 are the same as those
used to develop the Tier 2b tables in the 2019 Refinement. For more
information on the EPA's method for estimating gas consumption from
emission data reported under subpart I for RY2013, which was used in
the 2019 Refinement, see the Inventory of U.S. Greenhouse Gas Emissions
and Sinks: 1990-2017.\39\ The workbook ``Data Sets Supporting Revised
Emission Factors'' also shows the calculations for deriving the
emissions factors in Tables I-11 and I-12 from Tables I-3 and I-4
(available in the docket for this rulemaking, Docket Id. No. EPA-HQ-
OAR-2019-0424).
---------------------------------------------------------------------------

    \38\ For more information on the development of the proposed
emission factors for Tables I-11 and I-12, see the explanation for
the equivalent Tier 2b tables in the subpart I TSD in the docket for
this rulemaking (Docket Id. No. EPA-HQ-OAR-2019-0424).
    \39\ U.S. EPA 2019. Available at https://www.epa.gov/ghgemissions/inventory-us-greenhouse-gas-emissions-and-sinks-1990-2017.
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    We are requesting comment on three options regarding default
emission factors for MEMS and PV manufacturing. One option is to allow
MEMS and/or PV manufacturers to use either the current default emission
factors for those sub-sectors in Tables I-5 (MEMS) and I-7 (PV) or the
default emission factors for semiconductor manufacturing in Tables I-3
and I-4, as applicable. The second option is to remove Tables I-5 and
I-7 from subpart I and to require MEMS and/or PV manufacturers to use
the default emission factors in Tables I-3 and I-4, as applicable. The
third option is to continue to require MEMS and PV manufacturers to use
the default factors in Tables I-5 and I-7, respectively. Information
gathered during the development of the 2019 Refinement and through the
GHGRP indicates that the emission factors for semiconductor
manufacturing in Tables I-3 and I-4, as applicable, are often, and
perhaps always, applicable to MEMS and PV manufacturing. (In the 2019
Refinement, semiconductor default emission factors are applied to MEMS
manufacturing that is ``carried out using tools and processes similar
to those used to manufacture semiconductors.'') However, we request
comment on the extent to which semiconductor manufacturing default
emission factors are applicable to MEMS and PV manufacturing. We also
request comment on whether the distinction between different wafer
sizes that separates Table I-3 from Table I-4 is applicable to MEMS
and/or PV manufacturing.
    We are also proposing to revise the input gas and BEF values
assigned to gas/process combinations where no default input gas
emission factor is available (due to a lack of data) in 40 CFR
98.93(a)(6). Currently, if no default input gas emission factor is
available for a particular gas/process combination, reporters must use
a general default value of one for the input gas emission factor (i.e.,
a utilization rate of zero) and a general default value of zero for the
BEFs. This assumes that emissions equal consumption, i.e., all gas used
in a process is emitted, without any utilization or conversion into
other gases. However, in the majority of cases where emission factor
data are available, both CF4 and C2F6
are emitted as by-products, and both CF4 and
C2F6 are long-lived GHGs with very high GWPs (see
Table A-1). Where the input gas has a GWP similar to those of PFCs,
accounting for the generation of CF4 and
C2F6 by-products is not expected to significantly
change the GWP-weighted emissions calculated for the process compared
to the current method, but where the input gas has a GWP significantly
lower than those of PFCs, accounting for the generation of the by-
products would considerably improve the estimate of GWP-weighted
emissions compared to the current method. In both cases, accounting for
the likely emissions of CF4 and C2F6
would also lead to a better estimate of each species emitted. Thus, we
propose to revise the general defaults where no default input gas
emission factor is available to account for the likely partial
conversion of the input gas into CF4 and
C2F6. Specifically, for a gas/process combination
where no default input gas emission factor is available in Tables I-3,
I-4, I-5, I-6, and I-7, we are proposing at 40 CFR 98.93(a)(6) that
reporters would use an input gas emission factor (1-U) equal to 0.8
(i.e., a default utilization rate or U equal to 0.2) with BEFs of 0.15
for CF4 and 0.05 for C2F6. It is
assumed here in cases where data do not exist, that the input gas is
partially converted into CF4 and C2F6
during the process and the remainder is emitted. The default input gas
emission factor is conservatively based on the least efficient gas in
Table I-4 for etch processes (C2F6 in the revised
Table I-4). The remainder of the input gas is assigned to
CF4 and C2F6. Due to a generally
higher CF4 BEF for most input gas/process combinations, the
majority (75 percent) of the remaining mass is assigned to
CF4.
    Additionally, we are proposing to update the default DREs in Table
I-16 to reflect the incorporation of new data from the 2017 and 2020
technology assessment reports and a new approach to abatement system
certification. Currently, Table I-16 to subpart I lists default DREs by
gas and process type. Where data were unavailable for some gas and
chamber cleaning process combinations, DRE values were set to a
conservative value of 60 percent in the current tables.\40\ Commenters
have

previously noted that where exceptionally conservative DREs exist,
there is a large incentive to invest in measuring site-specific DREs.
Based on the measured data received by the EPA, the EPA is proposing to
assign chemical-specific DREs to all commonly used F-GHGs for the
semiconductor manufacturing sub-sector without distinguishing between
process types.\41\
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    \40\ For more information, see ``Technical Support for
Accounting for Destruction or Removal Efficiency for Electronics
Manufacturing Facilities under subpart I,'' (August 2012) prepared
for the Final Amendments and Confidentiality Determination for
Electronics Manufacturing Final Rule (78 FR 68162, November 13,
2013), available in the docket for this rulemaking, Docket Id. No.
EPA-HQ-OAR-2019-0424.
    \41\ See data sets ``UPDATED-04-02-2018-Triennial Report Data
for EPA,'' ``Attachment B. New and Revised DRE Test Used in SIA
Analysis of Alternative Default DREs'' from Comments of the SIA on
the Greenhouse Gas Reporting Program: Proposed Amendments and
Confidentiality Determinations for Subpart I (Docket Id. No EPA-HQ-
OAR-2011-0028-0095), and ``Etch DRE Testing With Flow Data, March 6,
2012,'' [2020 Triennial Data set]. All are available in the docket
for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-0424.
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    We are proposing to revise the default DREs in Table I-16 by
incorporating new data received via the 2017 and 2020 technology
assessment reports. The proposed DREs were calculated using a simple
arithmetic mean of all DRE data by gas. The DRE data sets submitted to
the EPA by the U.S. electronics manufacturing industry, including both
data received via the technology assessment reports and previously
submitted data, contains 1,353 data points for DREs of F-GHGs (for a
discussion on DREs for N2O, see the subpart I TSD, available
in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-2019-
0424). Of these, 58 of the data points corresponded to gases that are
not known to be input gases or significant by-products
(C2F4 and COF2, see previous
discussion on emission factors excluded from Tables I-3 and I-4). Thus,
we are not proposing default DREs in Table I-16 for these gases. Data
points were not included in the calculations of the proposed DREs if
the data points were reported as corresponding to emissions control
systems that were not certified to abate that particular gas.
Additional data points were excluded from the calculations of the
proposed DREs if an accurate DRE could not be measured due to detection
limits. Negative DREs were also excluded from the calculation for all
F-GHGs. All but two of the negative DREs submitted for F-GHGs were on
emissions control devices that were not designed to abate that
particular gas. For the two cases where the system was designed to
abate the gas, the testers noted either low gas inlet or inherent noise
in the measurement (e.g., due to low inlet). For the DREs from systems
recorded as not designed or certified to abate the input gas, the
negative DREs were reported only for CF4 and
COF2. Results from literature \42\ indicate that
CF4 can be formed within some emission control systems that
use hydrocarbon fuels by reaction between the fuel and fluorinated
species (e.g., F2) emitted from a NF3 remote
plasma chamber clean. All but one of the negative CF4 DREs
are from remote plasma chamber cleaning processes. However, since not
all abatement systems form CF4, these data points were
excluded from this analysis and this formation of CF4 is
accounted for separately in the proposed rule. Data points were also
excluded from the calculation if the gas being measured was noted as
being less than two percent of the total inlet fluoride to the
abatement system during testing, as the error in measuring DREs for
such low inlet concentrations may have biased the DREs low. It is also
known in the industry that when extremely low concentrations (e.g., 100
ppm) of F-GHGs in the abatement system are present, the system is less
efficient at destroying the F-GHG. Including these DREs in an
unweighted average would have a disproportionate effect on the
estimated emissions. Lastly, additional data points were excluded if
the abatement system required maintenance or repair (e.g., due to
fouling of the system due to poor water quality), or the abatement
system was operated in a manner inconsistent with the manufacturer's
recommendations (e.g., using clean dry air (CDA) instead of
O2 as the oxidant, as is recommended by the manufacturer).
The data sets include data for most gas-process combinations. The EPA
also considered using the DREs published in the 2019 Refinement.\43\
However, some of the data included in the 2019 Refinement are not
available to the EPA due to confidentiality concerns. Thus, the EPA was
only able to determine how this subset differed on average to the EPA
data sets. The confidential data set had higher average DREs for most
F-GHGs. This may be due to fact that this subset contained DREs as
measured by abatement system manufacturers and may not be
representative of actual fab conditions. The EPA has also received
additional data via the 2020 technology assessment report that was not
available during the development of the 2019 Refinement. The most
recent data set received from industry via the 2020 technology
assessment report included a significant number of DRE values that were
significant outliers. Many of these outliers were excluded due to the
reasons discussed above. The EPA considered excluding additional data
points from the DRE calculations for Table I-16 but did not have enough
information to determine whether the data points were representative of
fab operating conditions, due to abnormal conditions, or due to
operating the abatement system outside of manufacturer specifications.
The EPA is requesting comment on the conditions under which data points
were measured and whether any correspond to conditions that were
atypical or outside of the manufacturer's recommendation for operation
of the abatement system. The DREs in the proposed rule include data
from the 2020 and 2017 technology assessment reports and earlier data