98.53(a)(2) to state conditions under which annual approval will not be
required. The reporter must continue to request approval annually where
there have been changes in the reporter's requested methodology. If a
reporter receives approval to use an alternative method in the previous
reporting year and the methodology has not changed, the EPA is allowing
use of the alternative method to be automatically approved for
subsequent reporting years. Reporters will only need to notify the EPA
that they are using a previously approved alternative method and will
not require further approval from the Agency. This notification will be
included in the annual report submission. If, however, a reporter makes
any changes to the previously-approved alternative method, then the
reporter must request permission to use the revised method as stated in
40 CFR 98.53(a)(2). These revisions are being finalized as proposed.
2. Revisions to Subpart E To Improve the Quality of Data Collected
Under Part 98 and Improve the U.S. GHG Inventory
    We are finalizing one amendment that is intended to improve the
quality of

data collected under subpart E while generally resulting in only a
slight increase in burden for reporters. As proposed, we are revising
40 CFR 98.56(f) to require reporting of the date of installation of any
N2O abatement technology (if applicable). This data element
may be carried over from one reporting year to the next. The reporter
will not be required to make changes unless additional abatement
technology is installed at a later date.
3. When the Final Amendments to Subpart E Become Effective
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart E will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018. No comments were received on the timing of revisions
to subpart E.

D. Subpart F--Aluminum Production

    In this action, we are finalizing several amendments to 40 CFR part
98, subpart F (Aluminum Production), as proposed. This section
discusses the substantive changes to subpart F; additional minor
corrections and clarifications are summarized in the Final Table of
Revisions available in the docket for this rulemaking (Docket Id. No.
EPA-HQ-OAR-2015-0526). The EPA received no comments objecting to the
proposed changes to subpart F.
    We are finalizing amendments to 40 CFR part 98, subpart F, to
improve the quality of the data collected under Part 98 and improve the
U.S. GHG Inventory. As proposed, we are requiring reporting of two data
elements that influence perfluorocarbon (PFC) emissions from aluminum
production: annual average anode effect minutes per cell-day and annual
smelter-specific slope coefficients. We are also finalizing our
determination that the annual average of the anode effect minutes per
cell day is CBI. See the memorandum ``Final Data Category Assignments
and Confidentiality Determinations for Data Elements in the Proposed
2015 Revisions'' in Docket Id. No. EPA-HQ-OAR-2015-0526 for additional
information. In conjunction with our determination that the annual
average of the anode effect minutes is CBI, we are revising, as
proposed, our previous finding that the annual smelter-specific slope
coefficients, which are inputs to emission equations, present
disclosure concerns associated with this input to equation, and are
finalizing our proposal to collect these data. Note that we will
continue to use IVT to verify the results of Equation F-2. See the
preamble to the proposed rule (81 FR 2553) for additional information
on this change.
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart F will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018. No comments were received on the timing of revisions
to subpart F.

E. Subpart G--Ammonia Manufacturing

    In this action, we are finalizing several amendments to subpart G
of Part 98 (Ammonia Manufacturing). This section discusses all of the
final revisions to subpart G. We are also finalizing as proposed
confidentiality determinations for new data elements resulting from the
revisions to subpart G; see section IV of this preamble and the
memorandum ``Final Data Category Assignments and Confidentiality
Determinations for Data Elements in the Proposed 2015 Revisions'' in
Docket Id. No. EPA-HQ-OAR-2015-0526 for additional information on the
final category assignments and confidentiality determinations for this
data element.
    The EPA received several comments for subpart G. Substantive
comments are addressed in section III.E.2 of this preamble; see the
document ``Summary of Public Comments and Responses for Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Data Elements under the Greenhouse Gas Reporting Rule'' in Docket Id.
No. EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart G.
1. Summary of Final Amendments to Subpart G
a. Revisions to Subpart G To Improve Quality of Data Collected in Part
98 and Improve the U.S. GHG Inventory
    We are finalizing revisions that will allow the EPA to collect data
that will improve the EPA's understanding of GHG emissions from ammonia
manufacturing while generally resulting in only a slight increase in
burden for reporters. As proposed, we are amending 40 CFR 98.76(a) to
require reporting of annual ammonia production for facilities where a
continuous emissions monitoring system (CEMS) is used to measure
CO2 emissions; 40 CFR 98.76(b)(2) to require reporting of
annual feedstock consumption; and 40 CFR 98.76(b)(7) to require
reporting of annual average carbon content.
b. Other Amendments to Subpart G
    We are finalizing multiple amendments to subpart G to clarify the
EPA's intentions related to the reporting of annual ammonia production
and annual methanol production and making one change from proposal.
    The change from proposal is with regard to the proposed revisions
to 40 CFR 98.76(b)(15) to indicate that facilities must report the
annual methanol production for each process unit in 40 CFR 98.76(b)(15)
regardless of whether the methanol is subsequently destroyed, vented,
or sold as product. As discussed in section III.E.2 of this preamble,
the EPA received comments objecting to the proposed revisions, and for
the reasons discussed below is instead clarifying that while
intentionally produced methanol must be reported, it is not necessary
to report the unintended generation of methanol as a by-product. The
final rule revises 40 CFR 98.76(b)(15) to ``Annual quantity of methanol
intentionally produced as a desired product, for each process unit
(metric tons).''
2. Summary of Comments and Responses on Subpart G
    This section summarizes the significant comments and responses
related to the proposed amendments to subpart G. See the document
``Summary of Public Comments and Responses for Greenhouse Gas Reporting
Rule: 2015 Revisions and Confidentiality Determinations for Data
Elements under the Greenhouse Gas Reporting Rule'' in Docket Id. No
EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart G.
    Comment: One commenter opposed the EPA's proposal to clarify 40 CFR
98.76(b)(15) to add that annual methanol production must be reported
``regardless of whether the methanol is subsequently destroyed, vented,
or sold as product.'' The commenter opposed reporting of methanol that
is vented or destroyed as part of the annual methanol production. The
commenter stated that the amount of methanol produced does not
contribute to the GHG emission calculations, which are based on fuel
and feedstock. The commenter also asserted that the EPA should not
attempt to capture the generation of by-products in the ammonia
production process, due to the complexity of determining the amount of
methanol vented or destroyed. The commenter noted that methanol is
generated in the low temperature shift reaction portion of the ammonia
manufacturing unit, and, in much

smaller quantities, in the high temperature shift reaction portion of
the ammonia manufacturing unit. The commenter stated that methanol can
leave the process in either a gaseous stream or as a process
condensate. The commenter noted that some facilities use a low methanol
catalyst in the low temperature shift reactor to control the amount of
methanol produced. The commenter stated that process condensate is
normally routed back into the condensate stripper where methanol is
stripped and routed to the ammonia reformer for combustion. The
commenter argued that this portion should not be accounted for in the
amount of methanol destroyed.
    Response: The EPA agrees with the commenter that reporting of
unintentional methanol production by subpart G reporters is not
necessary. The current requirement is to report ``Annual methanol
production for each process unit (metric tons),'' without limitation.
As demonstrated by reports in RY2014 and RY2015, the amount of methanol
from most subpart G reporters, which are thought to be reporting
unintentional production, is very small relative to the total quantity
of intentional methanol production being reported across the GHGRP
(subparts G, P, and X). Reporters that have intentional methanol
production are more likely to have existing mechanisms in place for
measuring the quantity than reporters that have unintentional methanol
production. Therefore, the burden for quantifying the small amounts of
unintentional methanol production is expected to be higher than the
burden required to report intentional methanol production. In striking
a balance between the burden required to quantify the small amount of
unintentional methanol production and the EPA's potential uses for the
methanol data being requested, the EPA has decided not to finalize the
proposed language for 40 CFR 98.76(b)(15), which was ``Annual methanol
production for each process unit (metric tons), regardless of whether
the methanol is subsequently destroyed, vented, or sold as product.''
Instead, the EPA is revising this requirement to read: ``Annual
quantity of methanol intentionally produced as a desired product, for
each process unit (metric tons).'' These final revisions are included
in the Final Table of Revisions to this rulemaking (see Docket Id. No.
EPA-HQ-OAR-2015-0526).
3. When the Final Amendments to Subpart G Become Effective
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart G will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018.
    We received comment on our proposed implementation schedule for
subpart G requesting an additional year before implementation of the
new reporting requirements (i.e., annual ammonia production for
facilities using a continuous emission monitoring system (CEMS), annual
consumption, and annual average carbon content data) to align the
implementation schedule with the schedule for implementing the new
reporting requirements for subpart V--Nitric Acid Production (i.e.,
RY2018). The commenter requested this change because some facilities
are subject to both subparts. The EPA does not agree that an additional
year is needed for implementation of the new reporting requirements for
subpart G or that the reporting schedules for these amendments for
subparts G and V need to be aligned. First, all existing ammonia
production plants are already required to report ammonia production
under 40 CFR 98.76(b)(14) (i.e., these data have been reported for
RY2014 and RY2015), and according to the GHG reports for subpart G
received to date, no existing ammonia production plants subject to
subpart G use CEMS. Therefore, while the new requirement for reporters
using CEMS to report annual ammonia production introduces no additional
burden to plants currently reporting to the GHGRP, should any plants
choose to use CEMS in the future, the requirement will be in place.
Second, the new requirement for reporters to calculate and report
annual consumption and annual average carbon content (using monthly
data) introduces only a minor burden because these facilities are
already required to use monthly consumption and carbon content data to
calculate emissions, including entering these data into IVT. Third, the
requirements of subparts G and V have no common input parameters,
therefore, there is no need for facilities to coordinate reporting of
the data reported under subparts G and V. As such, the EPA sees no
compelling reason to delay the implementation schedule for subpart G.
Therefore, the final amendments to subpart G will be effective January
1, 2018, and will be reflected starting with RY2017 reports, as
proposed.

F. Subpart I--Electronics Manufacturing

    In this action, we are finalizing several amendments to subpart I
of Part 98 (Electronics Manufacturing). This section discusses the
substantive revisions to subpart I; additional minor amendments,
corrections, and clarifications are summarized in the Final Table of
Revisions available in the docket for this rulemaking (Docket Id. No.
EPA-HQ-OAR-2015-0526). We are also finalizing confidentiality
determinations for new data elements resulting from these revisions to
subpart I; see section IV of this preamble and the memorandum ``Final
Data Category Assignments and Confidentiality Determinations for Data
Elements in the Proposed 2015 Revisions'' in Docket Id. No. EPA-HQ-OAR-
2015-0526 for additional information on the final category assignments
and confidentiality determinations for these data elements.
    The EPA received several comments for subpart I. Substantive
comments are addressed in section III.F.2 of this preamble; see the
document ``Summary of Public Comments and Responses for Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Data Elements under the Greenhouse Gas Reporting Rule'' in Docket Id.
No. EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart I.
1. Summary of Final Amendments to Subpart I
    This section discusses the substantive revisions to subpart I to
improve the quality of data collected under Part 98. We are finalizing
the proposed revisions to Equation I-24 with some modifications as
described in section III.F.2 of this preamble. We are also finalizing
clarifications to one provision of the Triennial Report requirement at
40 CFR 98.96(y) with some modifications from the proposal as described
in section III.F.2 of this preamble. We are finalizing all of the
proposed minor corrections presented in the Table of 2015 Revisions
(see Docket Id. No. EPA-HQ-OAR-2015-0526), with one additional change
to Table I-4 as discussed in this section.
    As part of the stack testing methodology in 40 CFR 98.93(i),
Equation I-24 calculates the weighted-average destruction or removal
efficiency for individual F-GHGs across process types. The equation is
intended to account for the fact that emissions from different process
types are destroyed with different efficiencies. Previously, Equation
I-24 weighted the fraction of the fluorinated GHG destroyed by the
quantity of gas consumed by each process type. However, the quantity
and type of gas flowing into destruction devices are also

affected by (1) The quantity of each input gas dissociated by the
process (which varies across process types and sub-types) and (2) the
quantity of by-product gas generated by the process (which also varies
across process types and sub-types). The revision (and renaming) of
Equation I-24A, for input gases, and the addition of Equation I-24B,
for by-product gases, enable facilities to properly account for these
effects. The addition of Equation I-24B also defines a term,
dkf, which is used in several other equations but has not
previously been defined.
    For the triennial technology report required of certain facilities
as specified in 40 CFR 98.96(y), we are revising paragraph (y)(2)(iv)
to require that any utilization and by-product formation rate data
include the input gases used and measured, the utilization rates
measured, the by-product formation rates measured, the process type,
the process sub-type for chamber clean processes, the wafer size, and
the method used for the measurements. We are requiring that any
destruction or removal efficiency (DRE) data include the input gases
used and measured, the destruction and removal efficiency measured, the
process type, and the method used for the measurements.
    The data elements specified in the final amendments to 40 CFR
98.96(y)(2)(iv) differ in several respects from the data elements
specified in the proposed amendments. First, the final rule limits the
required data elements to the parameters used to categorize the current
sets of default emission factors and DREs or, in the case of the
measurement method, to assure data quality. We are not finalizing the
proposed requirements for facilities to provide the film type, the
substrate type, and the linewidth or technology node. Second, the final
rule includes two slightly different sets of requirements for reporting
utilization and byproduct formation rate data and for reporting
destruction or removal efficiency data; these different requirements
reflect the different criteria used to classify the corresponding
default factors in subpart I. Finally, we have removed the
qualification ``where available'' from the list of required data
elements. These modifications to the proposed requirements arose from
public comments and from our review of the purpose of the requirements,
as discussed in section III.F.2 of this preamble.
    In this final rule, we are finalizing revisions that we proposed to
five default factors in Table I-3 for 150 and 200 mm fabs. This is to
correct typographical and calculation errors. One of the corrected
default factors, the 1-Ui value for NF3 used in the remote
plasma clean process subtype, is intended to be the same as the
corresponding value for 300 mm fabs in Table I-4. (This is because a
single dataset was used to develop the 1-Ui value for NF3
used in remote plasma clean across both sets of wafer sizes.) However,
we did not propose to correct the value in Table I-4. Because the
correction is applicable to Table I-4 as well as to Table I-3, and we
received no negative comments on the Table I-3 correction, we are
making the correction to Table I-4 in this final rule. The correction
revises the default I-Ui value for NF3 used in the remote
plasma clean subtype from 0.018 to 0.017.
2. Summary of Comments and Responses on Subpart I
    This section summarizes the significant comments and responses
related to the proposed amendments to subpart I. See the document
``Summary of Public Comments and Responses for Greenhouse Gas Reporting
Rule: 2015 Revisions and Confidentiality Determinations for Data
Elements under the Greenhouse Gas Reporting Rule'' in Docket Id. No
EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart I.
    Comment: One commenter expressed concern that the revisions to
Equation I-24, including revision of Equation I-24 and the addition of
Equation I-24B for stack testing at semiconductor fabs, would require
reporters to essentially employ both the default emission factor method
and the stack testing method, because the revised equations would
require that facilities perform calculations using the default emission
factor method to make adjustments for variations in the usage and
performance of abatement. The commenter noted that any revisions to the
default emissions factors would therefore change the emissions of a
facility that performs stack testing. The commenter argued that the
proposed revisions would discourage the use of the stack testing
method, especially for facilities with abatement systems installed.
    Finally, the commenter argued that the EPA has not demonstrated
that the added complexity and cost will result in a more accurate
emissions estimate.
    Response: We demonstrated that the added accuracy of the revised
equations justifies their added complexity in the preamble to the
proposed rule and are providing further explanation here. As we
explained in the preamble to the proposed rule (81 FR 2555, January 15,
2016), we proposed these revisions to Equation I-24 because the
original equation relied on GHG gas consumption by process type, rather
than GHG emissions by process type, to determine the weighted average
DRE. As explained in the proposal preamble, the original equation
introduced several sources of error because it did not account for
either input gas utilization or by-product formation, both of which can
make the distribution of emissions of an F-GHG between process types
very different from the distribution of consumption of that F-GHG
between process types. These sources of error are eliminated in the
revised Equations I-24 A and I-24B.
    We disagree with the commenter that the added complexity of the
revised equations is excessive and will discourage use of the stack-
test method. The original Equation I-24 required users to apportion gas
usage by process type (i.e., to either etching/wafer cleaning or
chamber cleaning). The revised equations require reporters to
additionally apportion gases used in chamber cleaning to the
appropriate sub-type, but the added burden of this step is expected to
be low. We analyzed gas usage patterns in RY2014 and found that, on
average, between 56 and 80 percent of the time that a fab used an F-GHG
in chamber cleaning, the fab used that F-GHG in only one chamber
cleaning subtype.\5\ Only five to eight percent of the time was an F-
GHG used in all three chamber cleaning subtypes. Once they have
apportioned gas usage, reporters will simply apply the default
utilization rates and byproduct formation rates from Tables I-3 and I-4
to the apportioned gases, and this step can be simplified with the use
of a spreadsheet.
---------------------------------------------------------------------------

    \5\ The 56-percent figure was based on the assumptions that (1)
Every combination of wafer size and chamber cleaning process subtype
for which CF4 or C2F6 emissions
were reported used CF4 or C2F6 as
an input gas and (2) emissions of particular F-GHGs that were
reported as zero represent very small emissions rather than no
emissions of that F-GHG. The 80-percent figure was based on the
assumptions that (1) For combinations of wafer size and chamber
cleaning process subtype that have no input gas emission factors for
CF4 or C2F6, but that do have by-
product generation factors for these gases, CF4 or
C2F6 are emitted as by-product gases rather
than input gases, and (2) emissions of particular F-GHGs that were
reported as zero are truly zero.
---------------------------------------------------------------------------

    The commenter does not address how the term dkf, which
is used in several equations in the stack test method (e.g., Equations
I-20 and I-22), would be defined without the addition of Equation I-
24B. We note that equating dkf to the previous definition of
dif (that is, weighting process types by input gas
consumption rather than by by-product

emissions) would lead to large errors in the weighted DRE for by-
products because the shares of F-GHGs consumed by the two process types
can be very different from the shares of F-GHGs emitted as by-products
from the two process types (particularly for CF4 and
C2F6). For example, based on the 2009 and 2010 F-
GHG consumption data that were provided by the semiconductor industry
to EPA, the weighted average DRE for by-product
C2F6 would be 0.6 based on consumption but 0.97
based on by-product emissions, using the Table I-16 default DREs for
both process types.
    In response to the commenter's assertion that the revision
effectively requires users of the stack method to employ the emission
factor method as well as stack testing procedures, we reiterate that
the incremental effort associated with implementing the revision is
expected to be modest, as discussed above. We also note that facilities
using the stack method are already required to use a modified version
of the emission factor method to perform preliminary estimates of
emissions and to estimate emissions from stack systems that are not
tested. (See 40 CFR 98.93(i)(1) and (4)).
    Finally, regarding the impact of changes in default emission
factors on the calculated emissions of facilities that use stack
testing, we anticipate that this impact will be considerably smaller
than the initial impact of weighting process-type and sub-type DREs by
F-GHG emissions rather than by consumption, particularly where most
emissions are by-product emissions from a process type other than the
process type that consumes the F-GHG. In this case, the process that
emits the F-GHG by-product but does not consume it is given a weight of
almost zero when consumption is used as the weighting factor; but it is
given a weight of nearly one when by-product emissions are used as the
weighting factor. In contrast, all subsequent changes to emission
factors, with the exception of the very largest ones, are likely to
have relatively limited impact on this weighting, and consequently on
calculated emissions.
    Comment: One commenter expressed concern that the proposed list of
the data elements to be submitted with emission factor and DRE data in
the Triennial Report would increase burden on reporters, was
inconsistent with the terms of the final rule negotiated between the
EPA and industry members, and would result in the collection of data
that were not relevant to setting accurate emission factors. This
commenter argued that the EPA should wait until after the submission of
the first Triennial Report in 2017 before finalizing any revisions to
the requirements for the report. The commenter stated that some of the
data elements went beyond the original goals for the Triennial Report
and would require facilities submitting reports to collect additional
data that are not typically collected during testing and that were
found not to be relevant to emissions during the development of the
current subpart I requirements. Specifically, the commenter argued that
input gas, wafer size, and process type were sufficient to characterize
emissions considering precision, accuracy, and technical feasibility,
and that several other data elements, such as film type and technology
node, were not statistically relevant to calculating emission factors.
    The commenter also asserted that several of the proposed data
requirements were irrelevant to characterizing DRE data, including film
type, substrate type, linewidth or technology node, process type, and
utilization rates measured.
    Finally, the commenter claimed that the information being sought
raised confidentiality issues because the industry considers the
requested product and technology information to be CBI. The commenter
argued that, although linewidth estimates were available in publicly
available databases such as the World Fab Forecast, those data were
only estimates and their accuracy was questionable. Thus, disclosing
linewidth or technology node threatens the disclosure of intellectual
property. The commenter concluded by stating that several of the
proposed data elements, such as film type and technology node, were the
same types of data that were required in the recipe-specific emission
factor reporting that was removed from the rule in the amendments that
were finalized on November 13, 2013 (78 FR 68162) as a result of the
industry's petition for reconsideration and EPA's grant of the
petition.
    Response: As noted above, the EPA is finalizing a list of data
elements that must be submitted as part of emission factor and DRE
measurements included in the Triennial Report. After considering this
comment, we have limited this list to those parameters that are
absolutely necessary for relating the new data to the existing data and
to the corresponding default emissions factors and DRE factors. Rather
than specifying additional parameters that may affect emission and DRE
factors, the EPA is relying on the existing requirements of 40 CFR
98.96(y)(2), which state in part that the Triennial Report must
describe (1) ``How the gases and technologies used in semiconductor
manufacturing using 200 mm and 300 mm wafers in the United States have
changed in the past three years and whether any of the identified
changes are likely to have affected the emissions characteristics of
semiconductor manufacturing processes in such a way that the default
utilization and by-product formation rates or default destruction or
removal efficiency factors of this subpart may need to be updated'' and
(2) ``the effect on emissions of the implementation of new process
technologies and/or finer line width processes in 200 mm and 300 mm
technologies, the introduction of new tool platforms, and the
introduction of new processes on previously tested platforms.'' We have
concluded that these requirements, in combination with the introductory
sentence of 40 CFR 98.96(y)(2)(iv), which requires reporters to
``provide any utilization and by-product formation rates and/or
destruction or removal efficiency data that have been collected in the
previous three years that support the changes in semiconductor
manufacturing processes described in the report,'' already require
reporters to explain how each measurement illustrates one or more of
the changes in semiconductor manufacturing processes described in the
report. As discussed below, this in turn requires reporters to discuss
the parameters whose changes are (or are not) affecting emission
factors and emissions.
    As noted in the proposed rule, the EPA's intent in specifying the
list of data requirements is to allow us to better understand the data
being submitted and its implications for the current subpart I default
utilization rates, by-product formation rates, and DREs. To achieve
this goal, the submitted data must include information on two
relationships: The relationship between the new data and the existing
emission factors and DREs, and the relationship between the new data
and the technological developments in semiconductor manufacturing. The
relatively limited list of parameters in the final revision to 40 CFR
98.96(y)(2)(iv) illuminates the first relationship, while the
explanation of the link between the data and the changes in
semiconductor manufacturing illuminates the second.
    The proposed amendment to 40 CFR 98.96(y)(2)(iv) would have
required the submission of the specified data elements only ``where
available.'' Thus, it would not have required facilities submitting the
Triennial Report to

collect any new data, but only to submit data that were already in
their possession (and, as specified in the November 13, 2013 amendments
to subpart I, that supported the description of the technological
changes in the Triennial Report). Nevertheless, we agree with the
commenter that some of the proposed data elements, specifically, film
type, linewidth, and substrate type, would not necessarily be helpful
to illuminating how the processes or DRE equipment for which the
submitted measurements were made are different from the processes and
equipment that are represented by the current default factors. First,
these particular parameters may not be the key drivers that result in a
new set of processes having different emission factors from the old set
of processes. Second, by itself, information on linewidth and substrate
type would be difficult to relate to the data on which the current
factors are based because this information was not included in the
earlier data.
    We believe that the existing text of 40 CFR 98.96(y)(2) requires
reporters to explain how the measurements illustrate the impacts of the
changes in semiconductor manufacturing described in the report. This
allows reporters to focus on the relevant parameters and to explain how
and how much they are influencing emission factors and emissions, which
is more informative than simply providing the value of a parameter by
itself. For example, where a new tool platform has been introduced,
e.g., because a tool manufacturer is now supplying a market that it did
not supply previously, the Triennial Report should describe this
development and note that the new data have expanded the set of
represented tool manufacturers for a particular gas and process type
relative to the old data. (It would not be necessary for the reporter
to specify the ``new'' manufacturer.) \6\ Similarly, where emission
factors have changed because a new film type that includes less (or
more) carbon is being manufactured, the Triennial Report should note
that the decrease (or increase) in carbon has resulted in a lower (or
higher) CF4 emission factor from NF3 chamber
cleaning processes. This type of qualitative description allows
Triennial Report submitters to avoid identifying exact values or
entities that may pose disclosure concerns. (While the data elements
included in 40 CFR 98.96(y)(2)(i), (ii), (iii), and (v) have been
determined to be CBI, semiconductor manufacturers have historically
been reluctant to submit certain sensitive data despite this
determination.)
---------------------------------------------------------------------------

    \6\ A similar approach was used by the Semiconductor Industry
Association (SIA) to describe the representativeness of emission
factor measurements with respect to tool manufacturers during the
development of the November 13, 2013 final amendments to subpart I.
(See, e.g., SIA's ``Report to EPA on Etch Factor Proposal for Fab
GHG Emissions Reporting,'' page 18, EPA-HQ-OAR-2011-0028-0074.)
---------------------------------------------------------------------------

    The EPA is aware of multiple parameters that may affect emission
factors and DREs. For emission factors, these include radio frequency
power, pressure, flow rate, film type, feature type, and tool platform
in addition to process type and wafer size, and this list is probably
not exhaustive. For DREs, these include equipment make and model and
age as well as input gas and process type. The reason that only some of
these parameters were used to establish the categories for the default
emission factors in Tables I-3 and I-4 and for the default DREs in
Table I-16 was not because the other parameters did not influence
emissions.\7\ Rather, it was because adding one or more other
parameters would have increased the burden and complexity of the
calculations under subpart I and would have introduced another source
of error from the additional F-GHG apportioning required, offsetting
the decrease in model error associated with including the additional
parameter (see 77 FR 63551). Thus, if one or more of the parameters
listed above is a driver behind a change in emission factors for
certain sets of processes in the field, facilities should note this in
their reports. Acknowledging the relevance of a parameter does not
compel the EPA to expand the number of categories of default factors in
Tables I-3, I-4, or I-16 to reflect the influence of that parameter,
but helps us to understand how and why the new data are different from
the old data, and therefore whether and how the current default
emission factors and DREs may need to be updated. Again, this is the
goal of the revision to 40 CFR 98.96(y)(2)(iv). We anticipate that,
except in extraordinary circumstances, updates would consist of
revisions to emission factors and DREs in the current set of
categories, not an increase in the number of categories.
---------------------------------------------------------------------------

    \7\ For example, the report cited by the contractor (``Report to
EPA on Etch Factor Proposal for Fab GHG Emissions Reporting,''
Docket item number EPA-HQ-OAR-2011-0028-0074) showed that radio
frequency power had the second-highest R squared value of any
single-variable model.
---------------------------------------------------------------------------

    The EPA agrees that some of the proposed data requirements are not
relevant to DREs, and the EPA has therefore distinguished in the final
rule between the data required for DREs and the data required for
emission factors in the Triennial Report. However, the EPA disagrees
with the commenter's assertion that process type is not relevant to
DREs, which is contradicted by the fact that the current rule includes
different sets of default DREs for etch processes and chamber clean
processes.\8\ Thus, the EPA has retained ``process type'' in the list
of data elements that must be submitted with DRE data.
---------------------------------------------------------------------------

    \8\ During the development of the current subpart I
requirements, SIA supported using process type to organize and apply
default DREs. In the document titled, ``Briefing Paper on Abatement
Issues: Destruction Removal Efficiency (DRE), SIA stated, ``SIA is
proposing an alternative method to group abatement systems and apply
the DREs to F-gas emissions. This alternative is based on a
combination of the process types [emphasis added] as defined in the
MRR and the gas or gas groups being treated by the abatement units''
(SIA. Briefing Paper on Abatement Issues: Destruction Removal
Efficiency (DRE), January 10, 2012, EPA-HQ-OAR-2011-0028-0045).
---------------------------------------------------------------------------

    Because the limited sets of data elements required by this final
rule should always be available and are necessary for the measurements
to be meaningful, we have removed the qualification ``where available''
from the lists of required data elements for emission factor and DRE
measurements.
3. When the Final Amendments to Subpart I Become Effective
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.1 of this preamble, all
amendments to subpart I will be effective on January 1, 2017 as
proposed and will be reflected starting with RY2016 reports that are
submitted in 2017. No comments were received on the timing of revisions
to subpart I.

G. Subpart N--Glass Production

    In this action, we are finalizing amendments to subpart N of Part
98 (Glass Production) as proposed. This section discusses the
substantive revisions to subpart N; additional minor corrections are
summarized in the Final Table of Revisions available in the docket for
this rulemaking (Docket Id. No. EPA-HQ-OAR-2015-0526).
    The EPA received only supportive comments for subpart N; therefore,
there are no changes from proposal to the final rule based on these
comments. See the document ``Summary of Public Comments and Responses
for Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket Id. No. EPA-HQ-OAR-2015-0526 for a complete listing of
all comments and responses related to subpart N.

    We are finalizing amendments that are intended to clarify the rule
requirements in subpart N, while resulting in no impact on burden for
reporters. Specifically, the revisions clarify that a default value of
1.0 can be used for the fraction of calcination and the carbonate mass
fraction for each carbonate type contained in the raw materials charged
to the furnace. As proposed, we are revising 40 CFR 98.144(b), 40 CFR
98.144(c), 40 CFR 98.144(d), 40 CFR 98.146(b)(5), and 40 CFR
98.146(b)(7) to clarify that no further chemical analysis is required
if the default value of 1.0 is selected. These amendments will clarify
the original intent of the requirements and address multiple Help Desk
questions. Additional minor editorial corrections may be found in the
Final Table of Revisions in the docket for this rulemaking (Docket Id.
No. EPA-HQ-OAR-2015-0526).
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart N will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018. No comments were received on the timing of revisions
to subpart N.

H. Subpart O--HCFC-22 Production and HFC-23 Destruction

1. Summary of Final Amendments to Subpart O
    We are finalizing all amendments to subpart O of Part 98 (HCFC-22
Production and HFC-23 Destruction) as proposed. This section discusses
all of the revisions to subpart O. We are also finalizing as proposed
confidentiality determinations for new data elements resulting from the
revisions to subpart O; see section IV of this preamble and the
memorandum ``Final Data Category Assignments and Confidentiality
Determinations for Data Elements in the Proposed 2015 Revisions'' in
Docket Id. No. EPA-HQ-OAR-2015-0526 for additional information on the
final category assignments and confidentiality determinations for these
data elements.
    The EPA received several comments for subpart O. Substantive
comments are addressed in section III.H.2 of this preamble; see the
document ``Summary of Public Comments and Responses for Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Data Elements under the Greenhouse Gas Reporting Rule'' in Docket Id.
No. EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart O.
a. Revisions to Subpart O To Streamline Implementation
    This section discusses the amendments to subpart O to simplify and
streamline GHGRP requirements and increase the efficiency of the report
submittal process. We are finalizing these revisions to subpart O as
proposed. Specifically, we are removing the reporting requirements at
40 CFR 98.156(d)(2), (3), and (4), which include, respectively, the
concentration (mass fraction) of HFC-23 at the outlet of the
destruction device, the flow rate at the outlet of the destruction
device in kilograms per hour, and the emission rate calculated from
these two parameters. As discussed in the proposed rule, reporting of
these data elements is no longer needed due to previous revisions to
subpart O (81 FR 2556).
b. Revisions to Subpart O To Improve the Quality of Data Collected
Under Part 98
    This section discusses the amendments to subpart O to improve the
quality of data collected under Part 98. We are finalizing these
revisions to subpart O as proposed. Specifically, we are (1)
Reinstating in 40 CFR 98.156(d) reporting of the method used to
calculate the revised destruction efficiency and (2) requiring
facilities to report HCFC-22 production and HFC-23 emissions for each
HCFC-22 production process rather than for the facility as a whole. As
described in the preamble to proposed rule (81 FR2556), these
amendments will allow the EPA to collect data that will improve the
EPA's understanding of GHG emissions from HCFC-22 production and HFC-23
destruction while generally resulting in only a slight increase in
burden to reporters.
2. Summary of Comments and Responses on Subpart O
    This section summarizes the significant comments and responses
related to the proposed amendments to subpart O. See the document
``Summary of Public Comments and Responses for Greenhouse Gas Reporting
Rule: 2015 Revisions and Confidentiality Determinations for Data
Elements under the Greenhouse Gas Reporting Rule'' in Docket Id. No
EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart O.
    Comment: One commenter disagreed with the EPA's proposed
reinstatement of the requirement to report the method used to calculate
the revised destruction efficiency. In the preamble to the proposed
rule, the EPA stated that this data element was inadvertently removed
by the Final Inputs Rule and was important for understanding data
quality. The commenter argued that this rationale did not justify
reinstatement of the data element, especially given that the previous
change was made just 18 months ago. The commenter noted that the EPA
was also proposing to reinstate previously removed data elements for
other subparts, and expressed the opinion that the number of regulatory
revisions in the GHGRP, which has been effect for six years, should be
decreasing, not increasing. The commenter concluded that the EPA should
avoid removing and reinstating data elements as such changes ``place an
undue burden on reporters and undermine confidence in the GHGRP.''
    Response: While we agree with the commenter that it is important to
minimize instances where the EPA inadvertently removes a data element
and then reinstates it, we disagree that avoiding such reversals is
more important than correcting an error that hinders our understanding
of data quality. As noted in the preamble to the proposed rule (81 FR
2556), reporting of the method used to calculate the revised
destruction efficiency helps us to understand the rigor of the method
and the reliability of the resulting revised destruction efficiency. We
do not believe that the reinstatement of this data element, which will
be implemented through a revision to the e-GGRT data reporting system,
places an undue burden on reporters. Similarly, we do not believe that
the reinstatement represents an acceleration of the rate of amendment
of Part 98 or undermines confidence in the GHGRP. The Final Inputs Rule
removed 378 data elements from Part 98 (79 FR 63752); only three of
these are being reinstated by this final rule.
3. When the Final Amendments to Subpart O Become Effective
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart O will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018. No comments were received on the timing of revisions
to subpart O.

I. Subpart Q--Iron and Steel Production

    In this action we are finalizing amendments to subpart Q of Part 98
(Iron and Steel Production). This section discusses one substantive
revision to

subpart Q; additional minor amendments, corrections, and clarifications
are summarized in the Final Table of Revisions available in the docket
for this rulemaking (Docket Id. No. EPA-HQ-OAR-2015-0526). The EPA
received no comments objecting to the proposed revisions to subpart Q.
    We are finalizing a revision to subpart Q to align with final
revisions to subpart Y (Petroleum Refineries). Under 40 CFR 98.172(b),
facilities that report under subpart Q are referred to provisions in 40
CFR part 98, subpart Y, for reporting CO2 emissions from
flares that burn blast furnace gas or coke oven gas. The final
revisions clarify that subpart Q facilities should exclude pilot gas
from the flare gas GHG emissions. Additional information regarding
these final revisions may be found in section III.M.1 of this preamble.
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart Q will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018. No comments were received on the timing of revisions
to subpart Q.

J. Subpart S--Lime Manufacturing

    In this action we are finalizing several amendments to subpart S of
Part 98 (Lime Manufacturing). This section discusses all final
amendments to subpart S. We are also finalizing as proposed
confidentiality determinations for new data elements resulting from the
revisions to subpart S; see section IV of this preamble and the
memorandum ``Final Data Category Assignments and Confidentiality
Determinations for Data Elements in the Proposed 2015 Revisions'' in
Docket Id. No. EPA-HQ-OAR-2015-0526 for additional information on the
final category assignments and confidentiality determinations for these
data elements.
    The EPA received several comments for subpart S. Substantive
comments are addressed in section III.J.2 of this preamble; see the
document ``Summary of Public Comments and Responses for Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Data Elements under the Greenhouse Gas Reporting Rule'' in Docket Id.
No. EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart S.
1. Summary of Final Amendments to Subpart S
a. Revisions to Subpart S To Improve the Quality of Data Collected in
Part 98
    The EPA is requiring as proposed reporting of three data elements
that influence CO2 emissions from lime manufacturing: Annual
emission factors for each lime product type produced, annual emission
factors for each calcined byproduct/waste by lime type that is sold,
and annual average results of chemical composition analysis of each
type of lime product produced and calcined byproduct/waste sold.
    After consideration of comments received requesting clarity on how
a reporter is to calculate annual emission factors, as described in
section III.J.2 below, the EPA is finalizing 40 CFR 98.193(b)(2)(vi),
(vii) and (viii), which contain new Equations S-5 to S-10 to calculate
the 12-month average based on monthly emission factors for lime product
type produced and calcined byproduct/waste by lime type that is sold,
in addition to the associated monthly results of the chemical
composition analysis of each type of lime product produced and calcined
byproduct/waste that is sold. As described in the preamble to the
proposed rule (81 FR 2557), collecting these data will allow us to
understand why emissions have increased or decreased in a particular
year or over longer periods. Thus they are important for informing the
development of future GHG policies and programs. In addition, they are
important for explaining U.S. emission trends through the U.S. GHG
Inventory.
2. Summary of Comments and Response on Subpart S
    This section summarizes the significant comments and responses
related to the proposed amendments to subpart S. See the document
``Summary of Public Comments and Responses for Greenhouse Gas Reporting
Rule: 2015 Revisions and Confidentiality Determinations for Data
Elements under the Greenhouse Gas Reporting Rule'' in Docket Id. No
EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart S.
    Comment: Two commenters stated that the EPA should refrain from
collecting and retaining highly confidential business information
unless there is a compelling reason to do so. In this case, the
commenters assert that an assessment or evaluation of emission factors
over long periods of time will not be a reliable indicator of why
overall GHG emissions may have increased or decreased. The commenters
explain that calcination-related emissions make up approximately 54
percent of total CO2 emissions in the lime industry, with
minimal variability in emission factors month to month or year to year
for the various product or calcined byproduct/waste type produced.
Further, the commenters state that changes and variability in emissions
are far more likely to be influenced by changes in production which are
driven by market conditions, and to a lesser extent from variability in
fuel combustion emissions which are already reported under the GHG
Reporting Rule, subpart C. The commenters conclude that the proposed
new data points will be of negligible value and at the same time will
increase the potential for sensitive information to inadvertently be
made public.
    Response: The EPA disagrees with the commenter that reporting new
data points will be of negligible value. Emission factors in
combination with production data do inform trends and represent an
emission intensity or emission rate associated with the lime production
process (e.g., GHG emission per unit of production by lime type). The
collection of these data (annual average emissions factors for each
lime product produced by type, annual emissions factors or calcined
byproduct/waste by lime type that is sold, in addition to their
associated annual average results from chemical composition analysis)
will enhance the ability for EPA to understand emission trends, in
particular emission rates at facilities to understand why emissions are
decreasing or increasing, in conjunction with other existing data
collected under GHGRP. In addition, collection of this information will
also advance integration of GHGRP information into the U.S. GHG
Inventory, and hence improve those estimates to better reflect industry
conditions and related annual trends from lime production than the
current use of IPCC default factors. The EPA adds that separate from
this rulemaking the National Lime Association has provided comments to
the EPA during the public review of the U.S. GHG Inventory (comments
dated February 22, 2013, March 14, 2014) \9\ to discontinue use of IPCC
default emissions factors, specifically for calcined byproducts

such as lime kiln dust. Further, as noted in these comments by National
Lime Association on the U.S. GHG Inventory, this information required
in this final rule will complement production data the EPA is currently
collecting on lime produced that is sold under 40 CFR 98.196(a)(6) and
(b)(18). Finally, this information will enhance EPA's ability to
compare and verify emissions across subpart S, but also the EPA's
ability to integrate GHGRP information is also enhanced by the ability
to present a transparent and consistent basis for estimating emissions
with underlying activity parameters within the inventory report.
---------------------------------------------------------------------------

    \9\ See ``Letter to Leif Hockstad, U.S. EPA, from William C.
Herz, National Lime Association re: Draft Inventory of U.S.
Greenhouse Gas Emissions and Sinks 1990-2012'' and ``National Lime
Association comments on Inventory of U.S. Greenhouse Gas Emissions
and Sinks (78 FR 12013, February 22, 2013), Arline M. Seeger''.
Available in Docket Id. No. EPA-HQ-OAR-2015-0526.
---------------------------------------------------------------------------

    The EPA acknowledges commenter's concerns about the potentially
confidential nature of the new data elements. As noted in the section
III.J of the preamble to the proposed rule, the EPA determined these
elements will be eligible for confidential treatment and will only
publish information (e.g., national averages based on GHGRP facility-
level data) that meet criteria for aggregation and publication of CBI
information in Federal Register Notification-9911-98-OAR.\10\
---------------------------------------------------------------------------

    \10\ See https://www.epa.gov/ghgreporting/confidential-business-information-ghg-reporting#CBI_Data_Aggregation.
---------------------------------------------------------------------------

    Comment: One commenter requested that the EPA add clear and
unambiguous language that defines ``Annual emission factor.'' The
commenter stated that the proposed rule does not adequately explain how
these elements are to be calculated. The commenter suggested that the
most sensible and least burdensome method is a straight 12-month
average of the monthly emission factors. According to the commenter,
this calculation method should be explicitly prescribed in the final
rule if the data points are required.
    Response: The EPA agrees that clear language, in particular
prescribing the calculation method in the rule, will facilitate
reporting of these new data points. Per the commenter's specific
recommendation, the EPA has added 40 CFR 98.193(b)(2)(vi), (vii) and
(viii), which contain new Equations S-5 to S-10 to specify calculation
of the 12-month average based on monthly emission factors for lime
product type produced and calcined byproduct/waste by lime type that is
sold, in addition to the associated monthly results of the chemical
composition analysis of each type of lime product produced and calcined
byproduct/waste that is sold.
3. When the Final Amendments to Subpart S Become Effective
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart S will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018. No comments were received on the timing of revisions
to subpart S.

K. Subpart V--Nitric Acid Production

    In this action, we are finalizing three amendments to subpart V of
Part 98 (Nitric Acid Production). This section discusses the revisions
to subpart V; additional minor clarifications, including a change to
the final rule, are summarized in the Final Table of Revisions
available in the docket for this rulemaking (Docket Id. No. EPA-HQ-OAR-
2015-0526). We are also finalizing as proposed confidentiality
determinations for new data elements resulting from the revisions to
subpart V; see section IV of this preamble and the memorandum ``Final
Data Category Assignments and Confidentiality Determinations for Data
Elements in the Proposed 2015 Revisions'' in Docket Id. No. EPA-HQ-OAR-
2015-0526 for additional information on the final category assignments
and confidentiality determinations for these data elements.
    The EPA received only supportive comments for subpart V; therefore,
there are no changes from proposal to the final rule based on these
comments. See the document ``Summary of Public Comments and Responses
for Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket Id. No. EPA-HQ-OAR-2015-0526 for a complete listing of
all comments and responses related to subpart V.
1. Revisions to Subpart V To Streamline Implementation
    We are finalizing one amendment that is intended to simplify and
streamline the requirements of subpart V and increase the efficiency of
the report submittal process. Subpart V provides the option of
requesting the Administrator to approve an alternative method of
determining N2O emissions from adipic acid production.
Previously, reporters were required to request such approval annually
in all circumstances. As proposed, we are revising 40 CFR 98.223(a)(2)
to state conditions under which annual approval will not be required.
As further discussed in section III.C of this preamble for subpart E,
the EPA is allowing for use of the alternative method to be
automatically approved for the next reporting year if the reporter
received approval to use an alternative method in the previous
reporting year and the method has not changed. Reporters who do not
wish to change their method from the one approved for the prior year
will only need to notify the EPA in the annual report submission that
they are using an already approved alternative method. If, however, a
reporter makes any changes to the previously-approved alternative
method, then the reporter must request permission to use the revised
method as stated in 40 CFR 98.223(a)(2). These revisions are being
finalized as proposed.
2. Revisions to Subpart V To Improve the Quality of Data Collected
Under Part 98
    We are finalizing two amendments that are intended to improve the
quality of data collected under subpart V. First, as proposed, we are
revising 40 CFR 98.220 to revise the definition of the source category
to require reporting from all reporters that produce nitric acid,
regardless of the nitric acid strength. We are finalizing an updated
definition of nitric acid to apply to all nitric acid strengths, to
ensure that subpart V reporting captures all N2O emissions
related to the production of nitric acid. These final changes are
summarized in the Final Table of Revisions available in the docket for
this rulemaking (Docket Id. No. EPA-HQ-OAR-2015-0526).
    As proposed, we are also revising 40 CFR 98.226(h) to require
reporting of the date of installation of any N2O abatement
technology (if applicable). This date is readily available or already
collected by reporters, and would not require additional data
collection or monitoring. This data element can be carried over from
one reporting year to the next. The reporter will not be required to
make changes unless additional abatement technology is installed at a
later date.
3. When the Revisions to Subpart V Become Effective
    Two of the three amendments to subpart V are effective on January
1, 2018 as shown in Table 4 of this preamble and are consistent with
the description of amendments effective on that date in section I.E.2
of this preamble. The remaining amendment to subpart V is effective on
January 1, 2019 as shown in Table 5 of this preamble. Although some
amendments to subpart V are effective January 1, 2018 and some

are effective January 1, 2019, all amendments to subpart V will be
reflected in RY2018 reports that are submitted in 2019 as shown in
Tables 4 and 5 of this preamble. No comments were received on the
timing of revisions to subpart V.
    The amendments to 40 CFR 98.220 of subpart V require new facilities
to report to the GHGRP. We are making these revisions effective January
1, 2018 so that the new reporters will take the necessary action to
begin monitoring to be in full compliance with these revisions
throughout 2018.
    The amendment to 40 CFR 98.223(a)(2) serves to simplify and
streamline reporting for subpart V facilities by allowing for the use
of an alternative method for determining N2O emissions if
the reporter received approval to use an alternative method in a prior
reporting year and the method has not changed. Reporters who do not
wish to change their method from the one approved for the prior year
will only need to notify the EPA in the annual report submission that
they are using an already approved alternative method. If, however, a
reporter makes any changes to the previously-approved alternative
method, then the reporter must request permission to use the revised
method as stated in 40 CFR 98.223(a)(2). Subpart V specifies that
notification, if needed, of the use of alternative monitoring must be
submitted within the first 30 days of the reporting year, which equates
to January 30. Because the notification, if needed, must take place
within the reporting year, we are making this amendment effective
January 1, 2018, so that reporters will not have to notify the Agency
if they are using the same alternative method as in the previous
reporting year.
    The amendment to 40 CFR 98.226(h) adds one new reporting
requirement to subpart V, the date of installation of any
N2O abatement technology. This date is readily available to
the reporters and is consistent with the data collection and monitoring
in the current rule; because the reporter does not need to take action
during the reporting year, this revision will be effective January 1,
2019 and reflected in RY2018 reports that are submitted in 2019.

L. Subpart X--Petrochemical Production

    In this action we are finalizing several amendments,
clarifications, and corrections to subpart X of Part 98 (Petrochemical
Production). This section discusses the substantive revisions to
subpart X. We are finalizing as proposed all of the minor amendments,
corrections, and clarifications presented in the Final Table of
Revisions (see Docket Id. No. EPA-HQ-OAR-2015-0526). We are also
finalizing as proposed confidentiality determinations for new data
elements resulting from the revisions to subpart X; see section IV of
this preamble and the memorandum ``Final Data Category Assignments and
Confidentiality Determinations for Data Elements in the Proposed 2015
Revisions'' in Docket Id. No. EPA-HQ-OAR-2015-0526 for additional
information on the final category assignments and confidentiality
determinations for these data elements.
    The EPA received several comments for subpart X. Substantive
comments are addressed in section III.L.2 of this preamble; see the
document ``Summary of Public Comments and Responses for Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Data Elements under the Greenhouse Gas Reporting Rule'' in Docket Id.
No. EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart X.
1. Summary of Final Amendments to Subpart X
a. Revisions to Subpart X To Streamline Implementation
    We are finalizing a revision to subpart X to align with the final
revisions to subpart Y. Under 40 CFR 98.243(c), facilities that report
to subpart X are referred to provisions in subpart Y for reporting
CO2, CH4, and N2O emissions from
flares. The final revisions clarify that facilities should exclude
pilot gas from the flare gas GHG emissions. Additional information
regarding these final revisions may be found in section III.M.1 of this
preamble.
    We are also finalizing, with minor clarification to what was
proposed (see section III.L.2 of this preamble), amendments to 40 CFR
98.246(a)(5) to allow operators of an integrated ethylene dichloride
(EDC) and vinyl chloride monomer (VCM) process to report the measured
quantity of VCM and an estimate of the amount of EDC produced as an
intermediate in the process. We are also finalizing as proposed a
modification of 40 CFR 98.240(a) to indicate that a reporter may elect
to consider the entire integrated process (rather than just the EDC
operations) to be the petrochemical process for the purposes of
complying with the mass balance method.
b. Revisions to Subpart X Improve the Quality of Data Collected in Part
98
    We are finalizing as proposed the addition of reporting
requirements for facilities that use the mass balance approach to
determine emissions under 40 CFR 98.243(c) to report the annual average
of the measurements of the carbon content and molecular weight of each
feedstock and product reported under subpart X. Collection of the
carbon content of each feedstock and product will enhance the quality
and accuracy of the data collected under the GHGRP by providing
additional information that will be used to verify the accuracy of
reported emissions. Once this data element and the molecular weight of
the feedstock or product are aggregated to the national level, they
will be used to improve national emission estimates in the U.S. GHG
Inventory, while resulting in only a slight increase in burden for
reporters.
2. Summary of Comments and Responses on Subpart X
    This section summarizes the significant comments and responses
related to the proposed amendments to subpart X. See the document
``Summary of Public Comments and Responses for Greenhouse Gas Reporting
Rule: 2015 Revisions and Confidentiality Determinations for Data
Elements under the Greenhouse Gas Reporting Rule'' in Docket Id. No.
EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart X.
    Comment: One commenter expressed confusion with the revision of 40
CFR 98.246(a)(5). According to the commenter, in the preamble, the EPA
seems to require facilities using the optional method to report both
the measured amount of VCM produced and an estimate of EDC produced as
an intermediate (81 FR 2588). The commenter stated that the regulatory
text does not appear to require this approach. The commenter provided
suggested revisions to clarify the reporting requirements.
    Response: The final amendments to 40 CFR 98.246(a)(5) retain the
proposed requirement to report either a measured or estimated amount of
intermediate EDC produced in an integrated EDC/VCM process unit. We are
retaining both options for this reporting requirement to provide
reporters additional flexibility. Additionally, the final amendments to
40 CFR 98.246(a)(5) clarify our intentions by making two changes to the
proposed language. First, we have made a minor change to the proposed
language under 40 CFR 98.246(a)(5) to

remove any reference to VCM produced being required to be reported
under this specific paragraph of the rule. This revision does not
change the fact that the amount of VCM produced in an integrated EDC/
VCM process unit must still be reported, regardless of whether the
reported amount of intermediate EDC produced is estimated or measured,
as reporting of the amount of VCM produced is already required under
the reporting requirement for all products in 40 CFR 98.246(a)(13) and
we neither proposed nor intended for this revision to make any changes
to 40 CFR 98.246(a)(13). This minor change from proposal is intended to
clarify the revision and eliminate the proposed duplicative requirement
for reporting of VCM production. Second, we have made a change to the
proposed language in subpart X to require that the estimated quantity
of EDC is to be based on process knowledge and best available data.
    The commenter recommended removing the proposed option for
reporting the measured quantity of EDC for an integrated EDC/VCM
process. Although we expect that a reporter that elects to consider an
integrated EDC/VCM process to be the petrochemical process unit is
unlikely to measure the amount of intermediate EDC produced, we do not
want to preclude that possibility. Thus, we have retained both proposed
reporting options for the amount of intermediate EDC produced in the
final rule. After further consideration of the comment, we realized
that the commenter also may have been confused because the proposed
option to report a measured quantity of EDC did not mention reporting
the amount of VCM. Although the proposed revision to 40 CFR
98.246(a)(5) did not indicate that the amount of VCM must be reported
for such processes when the reported amount of intermediate EDC is
based on measurements, the amount of VCM is currently, and would still
have been, required to be reported under 40 CFR 98.246(a)(13); this
requirement is unchanged in the final rule. To further clarify this
point, we removed any mention of VCM from 40 CFR 98.246(a)(5) in the
final rule to specify that only intermediate EDC production for any
integrated EDC/VCM process unit that a reporter elects to consider as
the petrochemical process unit would be reported under 40 CFR
98.246(a)(5). VCM production for any integrated EDC/VCM process unit
that a reporter elects to consider as the petrochemical process unit
will continue to be reported under 40 CFR 98.246(a)(13). This change is
intended to reduce confusion and remove duplicative reporting
requirements for VCM production from these process units. Additionally,
we have clarified subpart X to specify that if the reporter elects to
report an estimated value, the estimated value is to be based on
process knowledge and best available data. This additional language
should provide guidance to reporters with regard to how the estimate of
intermediate EDC production is to be determined, which will help to
further reduce confusion over the revised requirements in 98.246(a)(5).
This language is consistent with EPA's intentions in the proposal for
how reporters should determine the estimated value. Identical
modifications have also been made to the proposed revisions in 40 CFR
98.246(b)(8). These final revisions are included in the Final Table of
Revisions to this rulemaking (see Docket Id. No. EPA-HQ-OAR-2015-0526).
3. When the Final Amendments to Subpart X Become Effective
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart X will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018. No comments were received on the timing of revisions
to subpart X.

M. Subpart Y--Petroleum Refineries

    In this action we are finalizing several amendments to 40 CFR part
98, subpart Y (Petroleum Refineries), to reduce burden for reporters,
improve data quality, and provide corrections and clarifications. This
section discusses the substantive revisions to subpart Y. We are
finalizing as proposed the minor corrections and clarifications to
subpart Y of Part 98. These minor revisions are summarized in the Final
Table of Revisions available in the docket for this rulemaking (Docket
Id. No. EPA-HQ-OAR-2015-0526). We are also finalizing as proposed
confidentiality determinations for new and revised data elements
resulting from the revisions to subpart Y; see section IV of this
preamble and the memorandum ``Final Data Category Assignments and
Confidentiality Determinations for Data Elements in the Proposed 2015
Revisions'' in Docket Id. No. EPA-HQ-OAR-2015-0526 for additional
information on the final category assignments and confidentiality
determinations for these data elements.
    The EPA received several comments for subpart Y. Substantive
comments are addressed in section III.M.2 of this preamble; see the
document ``Summary of Public Comments and Responses for Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Data Elements under the Greenhouse Gas Reporting Rule'' in Docket Id.
No. EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart Y.
1. Summary of Final Amendments to Subpart Y
a. Revisions to Subpart Y To Streamline Implementation
    We are finalizing as proposed the amendment to paragraph 40 CFR
98.253(b) to clarify that pilot gas, which is the gas used to maintain
a pilot flame at the flare tip, may be, but is not required to be,
excluded from the quantity of flare gas used to perform GHG emissions
calculations. As we described in the proposed rule, such emissions are
relatively small and may be difficult to determine without installation
of a meter, a burden we did not intend to require. We are making a
minor change to the proposed revision, as reflected in the Final Table
of Revisions available in the docket for this rulemaking (Docket Id.
No. EPA-HQ-OAR-2015-0526). The final revision to subpart Y more clearly
states that all gas discharges must be included in the flare GHG
emission calculation with the exception noted above. This minor change
from proposal does not alter the intent of this revision.
    After consideration of comments received, as discussed in section
III.M.2 of this preamble, we are finalizing as proposed the amendment
to 40 CFR 98.256(e) to require that facilities provide a yes/no
indication as to whether a flare has a flare gas recovery system. As
discussed in the proposed rule, this requirement will provide critical
information for characterizing flare emissions, assessing trends, and
informing policy decisions, while adding only a slight burden to
reporters. These two revisions affect subpart Y as well as subparts Q
and X, as described in the preamble to the proposed rule (81 FR 2560).
b. Revisions to Subpart Y To Improve the Quality of the Data Collected
Under Part 98
    We are finalizing as proposed all of the amendments to the delayed
coking unit (DCU) GHG emission calculation methodology to require
facilities to use the steam generation model. As further described in
the proposed rule preamble, these amendments provide a more accurate
means of estimating

methane emissions from DCUs and also align the GHGRP methodology with
the methodology recently incorporated into the Emission Estimation
Protocol for Petroleum Refineries, Version 3, by EPA's Office of Air
Quality Standards and Planning (OAQPS) (the Refinery Protocol \11\).
---------------------------------------------------------------------------

    \11\ Emission Estimation Protocol for Petroleum Refineries.
Version 3. Prepared for U.S. Environmental Protection Agency, Office
of Air Quality Planning and Standards, Research Triangle Park, NC.
August 2015. See https://www3.epa.gov/ttn/chief/efpac/protocol/ProtocolReport2015.pdf.
---------------------------------------------------------------------------

    In particular, the proposed amendments for determining the mass of
coke in the coke drum, the mass of water in the coke drum, and the
average temperature of the coke bed contents are being finalizing as
proposed. For the mass of coke in the coke drum, the amendments require
reporters to determine this quantity based on either (1) Company
records, or (2) drum dimensions, drum outage (parameters already
required to be recorded under the current rule) and a new equation
provided in the rule (Equation Y-18a). For the mass of water in the
coke drum, the amendments require reporters to determine this quantity
based on the height of water in the coke drum and the mass of coke in
the coke drum. For determining the average temperature of the coke bed
contents, the amendments require reporters to comply with one of two
methods, either: (1) A method based on the measured overhead
temperature of the drum, or (2) a method based on the overhead pressure
using a temperature pressure correlation equation provided in the rule.
The use of the temperature-pressure correlation will allow reporters to
use current pressure monitoring and recordkeeping practices to obtain
the information needed to implement the new methodology. As such, the
new methodology will not require the installation or use of new
monitoring systems.
    Additionally, we are finalizing as proposed to allow facilities
that have DCU vent gas measurements to use these measurements to
develop a unit-specific methane emissions factor for the DCU. This
allows both reporters that have previously used the combined Equation
Y-18/Y-19 method, as well as other reporters, to use the measurement
data available to provide an improved, site specific emissions
estimate. If a unit specific methane emissions factor is not available,
we are finalizing as proposed that reporters must use the default
methane emissions factor for DCU of 7.9 kg methane per metric ton of
steam generated.
    With regard to reporting requirements for emissions from DCUs, we
are finalizing as proposed the amendment that the new methodology be
used to estimate the emissions for each DCU and that all DCU data
elements be reported at the unit level. As further discussed in the
preamble to the proposed rule, this revision provides information
necessary for us to verify reported data, and streamlines reporting
requirements for reporters.
    In related revisions, we are finalizing as proposed the revisions
to 40 CFR 98.253(j) to delete ``CH4 emissions if you elected
to use the method in paragraph (i)(1) of this section,'' because the
DCU methodology no longer includes an option to use a combination of
techniques to determine the CH4 emissions from DCU decoking
operations. We are also finalizing as proposed the inclusion of ``coke
produced per cycle'' in the list of quantities of petroleum process
streams that are determined using company records in 40 CFR 98.254(j),
and the addition of a requirement that temperature and pressure
measurements associated with the DCU are to be determined ``using
process instrumentation operated, maintained, and calibrated according
to manufacturer's instructions.'' These revisions are included to
clarify monitoring requirements associated with the new DCU
methodology. Additionally, we are finalizing as proposed the revisions
to the recordkeeping requirements in 40 CFR 98.257 associated with the
DCU to harmonize the recordkeeping requirements with the new DCU
methodology equations.
    We are finalizing as proposed amendments to revise 40 CFR
98.253(h)(1) to clarify that reporters with ``asphalt blowing
operations controlled either by vapor scrubbing or by another non-
combustion control device'' must use Equations Y-14 and Y-15 to
calculate their GHG emissions. Lastly, we are also finalizing as
proposed revisions to 40 CFR 98.253(h)(2) to clarify that reporters
with ``asphalt blowing operations controlled by either a thermal
oxidizer, a flare, or other vapor combustion control device'' must use
Equations Y-16a/Y-16b and Y-17 to calculate their GHG emissions. These
amendments will yield more accurate emissions values as reporters will
now be required to use the most appropriate equations for ``other''
control systems used for asphalt blowing operations.
2. Summary of Comments and Responses
    This section summarizes the significant comments and responses
related to the proposed amendments to subpart Y. See the document
``Summary of Public Comments and Responses for Greenhouse Gas Reporting
Rule: 2015 Revisions and Confidentiality Determinations for Data
Elements under the Greenhouse Gas Reporting Rule'' in Docket Id. No.
EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart Y.
    Comment: One commenter objected to the amendments to 40 CFR
98.256(e)(3) and (6), stating that the proposed amendments are
redundant and duplicative. The commenter stated that the EPA already
has this information under 40 CFR part 60, subpart Ja--Standards of
Performance for Petroleum Refineries for Which Construction,
Reconstruction, or Modification Commenced After May 14, 2007
(henceforth referred to as NSPS Ja) and that they do not support
reporting this information under the GHGRP. The commenter also noted
that, due to the special modification provisions set forth in 40 CFR
60.100a(c), nearly all refinery flares with few exceptions fall under
NSPS Ja. The commenter stated that the NSPS Ja requirements at 40 CFR
60.103a(a) require carbon content, molecular weight and annual mass of
flare gas combusted, and an indication of whether or not each flare is
serviced by a flare gas recovery system to be documented in the flare
management plan and submitted to the EPA. The commenter stated that the
EPA does not need to have the same information submitted to it under
two separate rules because such duplicative reporting is wasteful and
unnecessary.
    Response: The proposed revisions in 40 CFR 98.256(e)(6) are
modifications to existing reporting requirements to provide more direct
reporting requirements for reporters using mass flow meters, so that
those reporters would no longer need to separately determine the
molecular weight of the gas and volumetric flow rate and instead must
report only the measured mass flow rate. This amendment reduces GHGRP
reporting burden for reporters that use mass flow meters. This
information, which is needed for verification of the reported
emissions, is not available in the NSPS Ja flare management plans so
reporting this information is not duplicative. We are therefore
finalizing the amendments to 40 CFR 98.256(e)(6) related to reporting
the carbon content of flare gas, and

either the volume and molecular weight of that gas or the mass of that
gas, as proposed.
    Regarding the proposed revision to 40 CFR 98.256(e)(3), while the
presence of a flare gas recovery system could be gleaned from flare
management plans for flares subject to the NSPS Ja requirements, not
every flare required to report under the GHGRP is subject to the NSPS
Ja requirements. We have received approximately 170 flare management
plans covering approximately 340 flares under NSPS Ja; however, there
were 495 flares at refineries included in facilities' GHGRP reports in
2014. Therefore, adding the proposed reporting requirement to the GHGRP
will cover many additional flares where it is unknown to us whether a
flare gas recovery system is in place. Additionally, the proposed
revision will allow EPA to gather information on flare gas recovery
systems at petrochemical production and iron and steel production
facilities. Part 98 requires facilities in these industries to use the
methodology specified in subpart Y for flares. Facilities in these
industries are not subject to NSPS Ja.
    For the subset of flares subject to NSPS Ja, it would be time
consuming for us to compile the information regarding the presence of a
flare gas recovery system from submitted flare management plans and
update this information annually. The amount of time required by the
GHGRP reporter to make this indication would be very low. For most
flares, the presence of a flare gas recovery system would not change
annually (exceptions include cases where a flare gas recovery system
was newly installed). Potentially, once this data element is initially
reported in RY2018, the EPA may be able to develop a way to ``carry
over'' the reported information from a facility's RY2018 report and
pre-populate this information in each facility's subsequent reports. If
the carry-over process is implemented, the reporter would only need to
enter the information once (for RY2018) and make changes to this data
element in future reporting years only when the presence of the flare
gas recovery system changed. This potential future reporting process
should reduce burden even further, if implemented. Additionally, having
this information reported within the GHGRP data system will allow the
EPA to publish and review the information alongside the rest of the
reported data related to flares, which greatly improves the usability
of the information by allowing for streamlined comparison of the GHGRP
reported emissions for flares with and without flare gas recovery
systems to better gauge the effectiveness of these systems.
    For the reasons outlined above, after full consideration of this
comment we are finalizing revisions to 40 CFR 98.256(e)(3) and (6) as
proposed.
    Comment: Several commenters provided comments opposing the proposed
steam generation model method for calculating methane emissions from
DCUs on several grounds. One commenter stated that the proposed method
will significantly overstate the amount of steam that is generated upon
opening the coke drum to the atmosphere and thus overstate the methane
emissions because of the following incorrect assumptions: (1) There is
a uniform temperature throughout the entire coke bed and the quench
water at the time the vent is started; (2) the amount of heat evolved
is derived from cooling the entire mass of coke and quench water from
that initial uniform temperature to 212 [deg]F; (3) 10 percent of the
heat removed from the coke bed and quench water is dissipated through
the coke drum and overhead metal and the balance of the heat removed
from the coke bed (90 percent) goes into steam generation; and (4) 100
percent of the water in the coke drum at the time of venting is at its
bubble point (i.e., all the heat evolved goes toward affecting
evaporation and none of it is used in heating the water to the boiling
point).
    The commenter further stated that these assumptions are not
supported by the experience of the commenters or the available data.
Commenters note that coker process experts report significant
temperature gradients through the coke mass and the quench water
throughout the drum. The commenters assert that at the time a coke drum
is opened to the atmosphere the water and coke in the bottom of the
drum is at approximately the temperature of the incoming quench water
(much less than 212 [deg]F). Therefore, the commenter states, the
required assumption that the entire mass of coke and quench water is at
212 [deg]F, regardless of the actual temperature readings, overstates
the heat in the drum and thus the heat generated significantly.
Commenters provided data showing that, for the five DCUs presented, the
bottom of the drums, as reflected in the initial drain water
temperature, was at temperatures below 150 [deg]F. Furthermore,
commenters noted that the vast majority of quench water drained from
these units was below 212 [deg]F, demonstrating that most of the quench
water in the drums when they were opened to the atmosphere was not at
its bubble (boiling) point. Commenters assert that this is typical for
DCUs in general.
    Commenters further described the cooling process noting that the
quench water (100 to 130 [deg]F) continuously enters from the bottom of
the coke drum and, as the coke in the drum cools, the quench water
accumulates in the lower coke bed, being of higher density than the
water above, some of which is at its bubble point. According to the
commenters, the amount of sub-cooled water in the coke drum and its
temperature prior to atmospheric venting is dependent on a number of
factors, but some cokers completely cool their bed, such that 99
percent of the water is sub-cooled. According to the commenter, the
typical range is from 50 percent to 99 percent subcooling. Thus, the
commenters state that at best (the 50 percent case) the proposed
equations will overstate steam and methane generation by 100 percent
and in most cases will overstate it by even more.
    Response: After consideration of this comment, for the reasons
stated in this preamble, the proposed rule preamble, and in this
docket, we are finalizing the steam generation model method for
calculating methane emissions from DCUs as proposed.
    First, with respect to the comment that we have assumed that there
is a uniform temperature throughout the entire coke bed when first
opening the coke bed to the atmosphere, we do not agree that the
commenter's statement is fully accurate, as our position is that the
methodology acknowledges and accounts for the existence of a
temperature gradient. While the proposed method does calculate an
average bed temperature for the methane emissions calculation, this
calculation acknowledges that there is a temperature gradient by using
both the temperature at the top of the coke bed (or overhead line
temperature) and at the bottom of the coke bed to determine the average
temperature of the coke bed.
    Second, regarding the commenter's questioning of the methodology's
assumption that the entire mass of coke and quench water is above 212
[deg]F at the time a coke drum is opened to the atmosphere, we note
that the methodology is designed to account for emissions from the
entire decoking process (which includes venting, water draining, drum
deheading, and coke cutting) while reducing burden on reporters. To
reduce burden, rather than requiring reporters to use separate
equations to calculate emissions from each part of the process listed
above, the methodology estimates total emissions from these processes
based on steam generation at the time of venting to the

atmosphere. The methodology relies on certain assumptions in order to
calculate total emissions that are reasonable estimates. We do
acknowledge that it is physically possible for the average temperature
of the coke bed to be at or below 212 [deg]F when opened to the
atmosphere, but even if the average temperature of the coke bed were
beneath 212 [deg]F and minimal amounts of steam were generated, methane
emissions still occur for multiple reasons, which the methodology is
designed to also account for. To name a couple of examples, pockets of
gas trapped within the coke bed may not be released until the coke is
cut from the drum, or emissions may still occur from the drain water.
Using a temperature at or below 212 [deg]F within this methodology
would not account for these emissions accurately. If the methodology
were changed to allow for temperatures at or below 212 [deg]F to be
used, this methodology could not accurately represent emissions from
the entire intended process, requiring that additional equations would
need to be added to the rule to account for emissions that occur during
other parts of the decoking process. While we have considered this
alternative, we have determined that this methodology provides a
reasonable estimation of emissions from the process and is less
burdensome. Therefore, in order to properly account for all decoking
process emissions using the methodology being finalized,
Tinitial in equation Y-18e must be greater than 212 [deg]F,
regardless of the venting temperature or pressure, to account for
methane emissions that are not directly associated with steam
formation.
    Third, we maintain that a 10 percent convective heat loss is an
appropriate assumption (for more detailed reasoning, please see the
Refinery Protocol's Response to Comments document available in that
action's docket). The commenter provided no evidence to suggest
otherwise. Due to the large size of the vessel, the volume of the
vessel is much larger than the surface area and the convective heat
loss is expected to be only a small portion of the evaporative heat
loss over the duration of the venting and draining process.
    Fourth, with respect to the assumption that 100 percent of the
water in the coke drum at the time of venting is at its bubble point
(i.e., all the heat evolved goes toward affecting evaporation and none
of it is used in heating the water to the boiling point), we maintain
the reasoning behind these assumptions for the key reasons we discussed
above. Specifically, the model is designed to estimate emissions from
the entire decoking process, so a minimum average bed temperature of
greater than 212 [deg]F is necessary and appropriate to account for any
emissions from the coke cutting process and drain water. We also note
that the heat capacity of the coke and water (per degree temperature
change) is about 100 times the heat of vaporization for a given mass of
water. As such, if some of the water had to be raised to the bubble
point first, this ``heat sink'' typically has only a small impact on
the quantity of steam generated and hence the calculated emissions.
    The commenter offered limited data on drum water temperatures from
one company to suggest that the assumptions cited are inaccurate.
First, these data do not appear to be representative of DCU operations
nationwide. Forty percent of the DCU included in this company's data
use water overflow technique. Based on information collected during the
development of the December 1, 2015, amendments to 40 CFR part 63,
subpart CC (80 FR 75178), which included new standards for DCU at
petroleum refineries, this water overflow technique is estimated to be
used at about 4 percent of operating DCU (see Docket Id. No. EPA-HQ-
OAR-2010-0682, Item Numbers -0061 through -0069, -0085, -0188, -0202, -
0203, -0216, -0219, -0719, and -0747). This method allows the operator
to use an unlimited amount of water and continually overflow the coke
drum with water to reach a target cooling temperature. Thus, these
units are expected to be more effectively cooled than units commonly
used in the industry. To calculate methane emissions with the proposed
method, these DCU would generally use the minimum default temperatures.
Therefore, the emissions calculated with the proposed method would
appropriately be lower for DCU with water overflow than the industry
average, but would still account for methane emissions that occur from
the overflow water and the coke cutting phase.
    Second, the drain water temperature, particularly at the start of
draining, is not necessarily representative of the average coke bed
temperature. Cooling water is added at the base of the DCU, below the
bottom of the coke bed. Thus, the initial temperature of the drain
water may represent water that has never contacted the coke bed.
Additionally, the primary flow of water at the base of the coke bed
will be through specific channels in the coke bed. In fact, even within
the coke bed, the water will generally flow through specific channels.
As such, there can be pockets of hot coke within the coke bed even
though the water in the channels and the coke immediately surrounding
these channels are at a much lower temperature. Therefore, the drain
water temperature may not provide an accurate assessment of the average
coke bed temperature.
    Finally, the drain water temperature observed will be dependent on
the lag time between when venting begins and draining begins.
Certainly, if the pressure of the system is 12 pounds per square inch
gauge (psig) at the start of the venting cycle, there must be
significant steam generation (which is what causes the elevated
pressure) and therefore, a portion of the coke bed must be well over
212 [deg]F. If the water is drained very soon after initiation of
atmospheric venting, the drain water profile is expected to rise well
above 212 [deg]F. However, if draining is delayed for an hour or so,
the continued generation of steam at the top of the coke bed would help
to cool the top of the coke bed. Thus, if one waits to drain long
enough the evaporative heat loss effect would cool the bed (as
predicted by the heat balance model) and the drain water temperature
would not exceed 212 [deg]F.
    We maintain that the proposed model with the assumptions described
above is the most accurate available for estimating methane emissions
from the DCU considering the releases that can occur during all phases
of the decoking operations. Table 1 in the technical memorandum
``Revised Emission Methodology for Delayed Coking Units'' (Docket Id.
No. EPA-HQ-OAR-2015-0526-006), shows that the emissions predicted using
the proposed steam generation model compares well with measured
emissions from the DCU steam vent (which does not consider other
emissions from draining, deheading, or coke cutting), particularly for
DCU that did not begin draining soon after initiating venting. After
consideration of this comment, for the reasons stated in this preamble,
the proposed rule preamble, and in this docket, we are finalizing as
proposed.
    Comment: One commenter opposed the revision to the emissions
calculations for DCUs for the following reasons: (1) Poor accuracy; and
(2) that EPA cannot ``align'' Part 98 with the Refinery Protocol unless
the change in methodology is voluntary. With regard to poor accuracy,
the commenter described how the EPA ranks calculation methods in the
order of accuracy, ``Method 1'' through ``Method 5,'' with Method 1
being the most preferred/accurate. The commenter

states that the methodology EPA is proposing is ranked as ``Method \3/
4\,'' indicating a poor level of accuracy. Consequently, the proposal
does not appear to improve or further the accuracy of the inventory.
The commenter asserts that the EPA has failed to adequately explain the
relative accuracy between the existing and proposed methods in
quantitative terms, leading to the conclusion that one poor method is
being replaced for another. The commenter further states that given
that most methane emissions are controlled from DCUs in combustion
devices meeting 98 percent Destruction and Removal Efficiency (DRE),
this change in methodology will not result in a meaningful improvement
in the overall accuracy of the inventory.
    With regard to the need to make this change voluntary, the
commenter describes that during the development of Version 3 of the
Refinery Protocol it was made clear that the use of the factors and
methods therein were voluntary, not mandatory. According to the
commenter, the EPA Technology Transfer Network Web page clearly states,
``We are not requiring the use of the Refinery Protocol, just as we do
not require the use of AP-42. It is simply another tool for use in
estimating emissions when site-specific test data do not exist or are
not available'' and this was understood between both OAQPS and the
refining sector. Therefore, the commenter considers the proposed
revisions to the federal GHG inventory rule that would require the use
of these calculation methodologies, as a circumvention of the function
and purpose of the Refinery Protocol. The commenter finds that it is
inappropriate to develop calculation methods with the understanding
that their use is optional, only to then make their use mandatory in
rulemaking under the guises of ``alignment'' between the two. The
commenter states that, should EPA make the use of the Refinery Protocol
methodology in Part 98 an option, this would be considered true
alignment between inventory and Refinery Protocol and an acceptable
solution to the commenter.
    Response: The Refinery Protocol ranks different types of
methodologies that can be used to quantify emissions in terms of their
relative accuracy to provide an order of preference for which inventory
emission estimates should be developed based on the information
available to the emissions inventory compilers. Methodology Rank 1
(highest rank) is reserved for direct continuous emission monitoring of
the emissions. Methodology Rank 2 is similar, but allows, for example,
direct concentration measurements and flow rates estimated by F-
factors. As noted in the Refinery Protocol, Methodology Ranks 1 and 2
are not applicable for DCU decoking operation emissions because of the
nature of the vent (high steam content) and varied locations that
emissions can be released. Thus, for DCU, Methodology Rank \3/4\ is the
best, most accurate method available.
    During development of the Refinery Protocol, we determined that the
newer methodology is a more accurate way to determine the total
emissions from DCU than the existing methodology in the rule based on
comparisons between the emissions calculated using each methodology and
DCU source test measurement of the decoking venting step. Table 1 in
the technical memorandum ``Revised Emission Methodology for Delayed
Coking Units'' (Docket Id. No. EPA-HQ-OAR-2015-0526-006) clearly
compares the emissions predicted using the old ``depressuring model''
(Equation Y-18) with emissions predicted using the proposed steam
generation model, as well as emissions measured from the DCU steam
vent. We expect most refineries will use the pressure correlation
alternative provided in the rule we are finalizing as proposed, and
this method provided an estimate of within a factor of 1.4 of the
measured emissions and would yield a result even closer to the measured
emissions if other decoking operation emissions were included. The
depressuring model, on the other hand, resulted in emissions that were
a factor of 10 lower than the measured emissions and would
underestimate emissions by an even larger amount if other decoking
operation emissions were included in the measurements. The data we have
provided in the docket record clearly demonstrate that the proposed
steam generation model is more accurate than the old depressuring
model.
    We agree that prior to the decoking process, there is an initial
depressurization, steaming, and cooling phase where the emissions are
required to be routed to a closed vent system and either recovered as
product or controlled via a flare or similar device. During this phase,
there are no emissions when the vapors are recovered as product and
flared emissions are accounted for by the flare methodology in 40 CFR
98.253(b). While the emissions from the initial cooling cycle may be
controlled, they are not accounted for in the DCU methodology, which
only considers emissions that occur in the decoking steps after this
initial, controlled cooling phase. As such, the commenter's suggestion
that most methane emissions are controlled from DCUs in combustion
devices meeting 98 percent DRE, is incomplete.
    After this initial cooling period, the coke drum gases are no
longer routed to the closed vent system and are instead diverted to the
atmosphere. This uncontrolled, atmospheric venting is the start of the
decoking operations and the DCU emissions estimated for the GHGRP in
accordance with 40 CFR 98.253(i) include only these direct atmospheric
emissions. Therefore, we disagree with commenter's statement that the
proposed methodology's emission estimates are overstated, since
emissions that occur from the DCU while the emissions are being vented
to controls (i.e., during the initial cooling cycle) are not included
at all in the DCU emissions methodology in 40 CFR 98.253(i).
    We disagree with the commenter that the new DCU calculation
methodology must be voluntary. Generally, we want facilities to use the
most accurate method possible, rather than providing several
methodologies of varying accuracies that facilities can voluntarily
choose between, and we desire consistent methods be used where
practical to allow for reported emissions to be compared on a level
playing field across facilities. In certain cases where it may appear
that we provide alternative methodologies for facilities to voluntarily
select from (such as the alternatives provided for flares), these
methodologies provide options on the basis of the monitoring equipment
available, and so are not truly optional but rather prescribed based
upon the existing monitoring equipment. In the example of methodologies
for flares, if carbon content is measured, the reporter must use
Equation Y-1A or Y-1B in 40 CFR 98.253(b)(1)(ii)(A); they cannot elect
to use Equation Y-2 in 40 CFR 98.253(b)(1)(ii)(B) or Y-3 in 40 CFR
98.253(b)(1)(ii)(C). Where we do allow methods to be selected
voluntarily, as in the case of Equations Y-1A and Y-1B, we do so
because the methods yield very consistent results (within 0.1 percent
for typical range of CO2 concentrations in flare gas).
    This is not the case when comparing the old DCU methodology with
the new DCU methodology. The old DCU methodology was found to
underestimate actual CH4 emissions from the DCU by a factor
of 10, which is much less accurate than the new methodology, meaning
that we do not find that the emissions calculated by the two methods
are consistent enough for us to allow the methods to be used
interchangeably (as we did in the case

of Equation Y-1A and Y-1B in 40 CFR98.253(b)(1)(ii)(A)). Furthermore,
in the finalized methodology for DCU, we have provided reporters with
options to use either pressure monitoring data or overhead temperature
data to determine the average initial bed temperature. We specifically
provided the pressure monitoring alternative because the pressure of
the vessel prior to venting was already a monitoring requirement. Since
no new monitoring requirements are necessary to begin use of the
methodology being finalized, to ensure methods are employed
consistently across all reporters, and based on the method's proven
ability to better predict the emissions measured from these sources, we
are finalizing this method as mandatory for all reporters, as proposed.
    Comment: One commenter noted that DCU emissions are highly
dependent on coker operating parameters, and EPA should allow the use
of site-specific coking unit emissions models and estimation methods.
The commenter describes that some DCU have new designs and operational
procedures that are intended to lower emissions, and the generic
calculation methodology may substantially overestimate emissions. The
commenter further states that in some jurisdictions, emission
measurements on delayed coker vents are required on a three-year basis.
The commenter asserts that facilities that have such measurements
should have the option of using them for calculating methane emissions
as part of subpart Y reporting, and that if a facility is using site-
specific calculations and measurement data for reporting of coker vent
emissions, it may need to estimate emissions from draining if the drain
water temperature is above 212 [deg]F for some portion of the draining
period. The commenter offered a proposed methodology (outlined below)
and asserted that emissions from draining when drain water temperatures
are below 212 [deg]F are negligible, as are emissions from coke
cutting, because methane has a very low solubility in water. The
commenter stated that one company indicated that approximately 0.2
percent of methane would be expected to partition into the aqueous
phase. As a result, the commenter says the potential methane emissions
in DCU drain water would be expected to be low compared to those from
the venting part of the unit operational cycle.
    The commenter suggested that emissions from steam flashing during
draining could be estimated based on evaluation of coke drum drain
temperature during the entire drain period. According to the commenter,
if drain water temperatures are never above 212 [deg]F, there would be
no attendant methane emissions added to those from the vent, since
there should be negligible methane dissolved in water that has already
flashed and cooled. The commenter further states that if drain
temperatures rise above 212 [deg]F, the mass of steam would be
calculated based on the following modified version of Equation Y-18e:
[GRAPHIC] [TIFF OMITTED] TR09DE16.000

Where:

fHotDrain = Fraction of time during drain that drain water is >212
[deg]F (for example, if drain time was 60 minutes and temperature
was above 212 [deg]F during the last 15 minutes of draining, then
fHotDrain = 15/60 = 0.25).
THotDrain = The minute-averaged temperature of the water when it is
>2 12 [deg]F (for example, if drain temperatures were above 212
[deg]F during the last 15 minutes of draining, then THotDrain = (213
+ 216 + 220 + 222 + 224 + 230 + 232 + 234 + 236 + 238 + 240 + 240 +
240 + 240 + 240)/15 = 229 [deg]F).

    Per the commenter, methane emissions from draining would then be
determined by using the conservative assumption that the methane
concentration in the drain steam is the same as the vent steam.
    The commenter also asserted that the drilling process should have
negligible emissions unless there is ongoing chemical reaction,
formation of coke, or tail gas and liquid hydrocarbons due to
uncompleted reaction when feeding the coke drum. According to the
commenter, drilling emissions cannot be directly measured but can be
correlated to hot spots, coke drum blowbacks, coke dust incidents, and
odors. Further the commenter states that because these conditions are
so undesirable from a safety and community perspective, these
occurrences have been minimized and thus it is reasonable to assume the
coke cutting contribution to overall coker emissions is quite small.
The commenter then asserts that isolated hot spots in the coke bed, as
indicated by steam generation during coke cutting, if they occur at
all, are less than 0.1 percent of the coke bed volume. According to the
commenter, the amount of methane released is well within the accuracy
of the proposed calculations and the associated large assumptions, and
can be ignored.
    Response: After careful consideration of this comment, we are
finalizing the methodology as proposed. We agree that the DCU decoking
emissions are unit-specific and the new methodology includes a variety
of unit-specific inputs including the mass of water in the drum, the
mass of coke in the drum, and the drum overhead temperature or
pressure. New unit designs that allow for more effectively cooling of
the coke bed will operate with lower overhead temperatures and will
show lower emissions than units that cannot achieve these overhead
temperatures.
    As noted in the response to comment above, the methodology we are
finalizing is intended to estimate releases from all phases of the
decoking process. We agree the methane emissions from the coke-cutting
process will not necessarily be related to steam generation, so, in
order to account for these emissions in our methodology, we
intentionally do not allow temperature inputs that would estimate no
(or negative) emissions from the DCU even if the overhead temperature
is below 212 [deg]F.
    In our methodology, we allow facilities that have vent measurement
data to develop their own site-specific emissions factor for methane
emissions (in kg CH4 per metric ton of steam emitted in the
vent line). As such, facilities can use measurement data when available
to further refine their DCU emissions.
    We compared the commenter's suggested methodology to our
methodology, which includes the use of a site-specific emission factor
along with the proposed steam generation quantity. We found our method
to be a more appropriate means by which to incorporate site-specific
measurement data for the following reasons. First, the vent emissions
measured are highly dependent on the time period between initiation of
venting and draining. A facility can drain immediately when measuring
emissions from the vent to minimize the emissions released via the
vent. However, it may be more common practice to delay draining for a
longer

period after venting during routine operations. In this event, using
the measured venting emissions from the source test and then estimating
the drain emissions as suggested by the commenter could significantly
underestimate the DCU emissions from these steps. Second, the
commenter's suggested methodology does not consider releases that can
occur during drum deheading and coke cutting, but rather assumes these
to be negligible. DIAL measurement studies of DCU emissions \12\
measured elevated emissions from the drainage area during the coke
cutting process. While emissions during the coke cutting step may not
be proportional to steam generation, we disagree that these emissions
should be assumed to be zero, and instead maintain that a robust
methodology must account for these emissions. Thus, the commenter's
suggested methodology could misrepresent measured emissions based on
the timing of draining, and is too limited in scope for our intended
purposes.
---------------------------------------------------------------------------

    \12\ See Refinery Demonstration of Optical Technologies for
Measurement of Fugitive Emissions and for Leak Detection (Roy
McArthur, Environment Canada, and Allan Chambers and Mel Strosher,
Carbon and Energy Management, March 31, 2006); and Measurement and
Analysis of Benzene and VOC Emissions in the Houston Ship Channel
Area and Selected Surrounding Major Stationary Sources Using DIAL
(Differential Absorption Light Detection and Ranging) Technology to
Support Ambient HAP Concentrations Reductions in the Community
(Loren Raun & Dan W. Hoyt, Bur. Pollution Control & Prevention, City
of Houston, 2011), available in Docket Id. No. EPA-HQ-OAR-2015-0526.
---------------------------------------------------------------------------

3. When the Final Amendments to Subpart Y Become Effective
    As shown in Table 5 of this preamble and consistent with the
description of amendments in section I.E.3 of this preamble, all
amendments to subpart Y will be effective on January 1, 2019 as
proposed and will be reflected starting with RY2018 reports that are
submitted in 2019. No comments were received on the timing of revisions
to subpart Y.

N. Subpart Z--Phosphoric Acid Production

    In this action, we are finalizing amendments to subpart Z of Part
98 (Phosphoric Acid Production). This section discusses all the
amendments to subpart Z. We are also finalizing as proposed
confidentiality determinations for new data elements resulting from the
revisions to subpart Z; see section IV of this preamble and the
memorandum ``Final Data Category Assignments and Confidentiality
Determinations for Data Elements in the Proposed 2015 Revisions'' in
Docket Id. No. EPA-HQ-OAR-2015-0526 for additional information on the
final category assignments and confidentiality determinations for these
data elements.
    The EPA received only supportive comments for subpart Z; therefore,
there are no changes from proposal to the final rule based on these
comments. See the document ``Summary of Public Comments and Responses
for Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket Id. No. EPA-HQ-OAR-2015-0526 for a complete listing of
all comments and responses related to subpart Z.
    As proposed, we are revising 40 CFR 98.266(f)(3) to require that
the annual report must include the annual phosphoric acid production
capacity (tons) for each wet-process phosphoric acid line, rather than
the annual permitted phosphoric acid production capacity, for the
reasons discussed in the proposed rule (81 FR 2561). We are removing
the word ``permitted'' from the requirement to report the process-level
production capacity, noting that not all facilities have a permitted
production capacity at the process level or produce to the permitted
capacity. We are also clarifying, as proposed, the units of measurement
for this reporting requirement. The pre-existing text for 40 CFR
98.266(f)(3) requires the reporting of ``annual phosphoric acid
permitted production capacity (tons) for each wet-process phosphoric
acid process line (metric tons).'' In this action, we are removing the
phrase ``(metric tons)'' from this text to clarify that the unit of
measurement is ``tons'' and not ``metric tons.''
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart Z will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018. No comments were received on the timing of revisions
to subpart Z.

O. Subpart AA--Pulp and Paper Manufacturing

    In this action, we are finalizing three amendments and
clarifications to subpart AA of Part 98 (Pulp and Paper Manufacturing)
as proposed. This section discusses all of the final revisions to
subpart AA. The EPA received only minor comments for subpart AA and
there are no changes from proposal to the final rule based on these
comments. See the document ``Summary of Public Comments and Responses
for Greenhouse Gas Reporting Rule: 2015 Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket Id. No. EPA-HQ-OAR-2015-0526 for a complete listing of
all comments and responses related to subpart AA.
    We are finalizing as proposed all amendments to subpart AA for the
reasons described in the preamble to the proposed rule (81 FR 2562).
First, we are finalizing as proposed amendments to 40 CFR 98.273(a)(1),
(b)(1), and (c)(1), which refer to the subpart C calculation
methodologies for CO2 emissions from combustion of fossil
fuel, to clarify that Tier 4 CEMS are not used to report emissions
under subpart AA. Second, we are finalizing as proposed the revision of
40 CFR 98.275(b) to allow use of the daily mass of spent liquor solids
fired reported under 40 CFR 63.866(c)(1) as an alternative to using
maximum values for missing spent liquor solids measurements. Lastly, we
are finalizing as proposed the clarifications in Table AA-2 to subpart
AA to more clearly distinguish between kraft rotary lime kilns and
calciners.
    As shown in Table 4 of this preamble and consistent with the
description of amendments in section I.E.2 of this preamble, all
amendments to subpart AA will be effective on January 1, 2018 as
proposed and will be reflected starting with RY2017 reports that are
submitted in 2018. No comments were received on the timing of revisions
to subpart AA.

P. Subpart CC--Soda Ash Manufacturing

    In this action, we are finalizing one minor correction to subpart
CC of Part 98 (Soda Ash Manufacturing). This section discusses the
substantive revisions that were proposed for subpart CC, but that the
EPA is not finalizing. The minor correction that the EPA is finalizing
is summarized in the Final Table of Revisions available in the docket
for this rulemaking (Docket Id. No. EPA-HQ-OAR-2015-0526).
    The EPA received several comments for subpart CC. Substantive
comments are addressed in section III.P.2 of this preamble; see the
document ``Summary of Public Comments and Responses for Greenhouse Gas
Reporting Rule: 2015 Revisions and Confidentiality Determinations for
Data Elements under the Greenhouse Gas Reporting Rule'' in Docket Id.
No. EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart CC.

1. Summary of Final Amendments to Subpart CC
    No substantive amendments to subpart CC are being finalized for
this rulemaking. In response to comments and based on updated analysis
as described in section III.P.2 of this preamble, the EPA is not
finalizing the two proposed amendments to revise 40 CFR 98.296(a) and
(b) that would have required reporting of the facility-level annual
consumption of trona or liquid alkaline feedstock.
2. Summary of Comments and Responses on Subpart CC
    This section summarizes the significant comments and responses
related to the proposed amendments to subpart CC. See the document
``Summary of Public Comments and Responses for Greenhouse Gas Reporting
Rule: 2015 Revisions and Confidentiality Determinations for Data
Elements under the Greenhouse Gas Reporting Rule'' in Docket Id. No
EPA-HQ-OAR-2015-0526 for a complete listing of all comments and
responses related to subpart CC.
    Comment: Several commenters do not support the EPA's proposed
revision related to facility-level feedstock reporting under subpart
CC, stating that the EPA did not provide sufficient justification for
the proposed revisions. The commenters cite the preamble to the
proposed rule, saying that the EPA asserts that these data elements are
already required for facilities that use CEMS. However, the commenters
state there are a very limited number of soda ash manufacturers and
that very few of the manufacturing lines monitor emissions using CEMS.
Therefore, the commenters object to the significant additional
recordkeeping and reporting efforts that would be posed by these
amendments, particularly because the rule already requires reporting of
outputs of both soda ash produced and GHG emitted, in their view wholly
fulfilling the statutory requirements for the program. The commenters
cite the EPA's own U.S. GHG Inventory report to question the
justification that the reporting of trona inputs and outputs would
``improve the quality of the US GHG Inventory,'' stating that the EPA
refers to the relatively low uncertainty levels in the emission
estimates for soda ash manufacturing. The commenters further cite the
EPA's report, which says that the primary source of uncertainty in this
sector occurs downstream from the manufacturing sites that would be
affected by this rulemaking. The commenters conclude that the proposed
revisions would therefore not improve the inventory estimates in any
material way and do not warrant the additional regulatory burden.
    Response: At this time, the EPA is not finalizing the proposal to
require reporting of annual consumption of trona or liquid alkaline
feedstock at the facility level, but may do so in the future. The EPA
recognizes that a similar data element was removed in the Final Inputs
rule and is currently reported only by facilities monitoring emissions
via CEMS (79 FR 63750, October 24, 2014).\13\ The proposed new data
element is similar, but not identical to the one removed from 40 CFR
98.296(b)(5) in the Final Inputs rule. The proposed new data element
would have required reporting of annual consumption of trona or liquid
alkaline feedstock at the facility level, whereas the data element
removed in the Final Inputs rule required reporting of monthly
consumption. As proposed, this new data element would have been treated
as CBI. In preparing to finalize this rulemaking, the EPA has conducted
an updated assessment on use of this proposed information and
determined that the information very likely will not meet the EPA's
criteria for aggregation and publication of CBI information contained
in Federal Register Notification-9911-98-OAR.\14\ Inability to
aggregate and publish this information presents a significant barrier
to its use for publishing analyses to inform future GHG policies and
programs, such as emission intensities for this industry, and for
integration into the U.S. GHG Inventory.
---------------------------------------------------------------------------

    \13\ Refer to Table 1 in the memorandum ``Data Elements Deferred
to March 31, 2015: Final List of `Inputs to Equations' Data Elements
Not To Be Reported,'' September 2014 (see Docket Id. No. EPA-HQ-OAR-
2010-0929).
    \14\ See https://www.epa.gov/ghgreporting/confidential-business-information-ghg-reporting#CBI Data Aggregation.
---------------------------------------------------------------------------

    Although the EPA is not finalizing these proposed data elements at
this time, the Agency disagrees with commenters on the value of these
data to enhance estimates for the U.S. GHG Inventory. As commenters
note, the current method applied in the U.S. GHG Inventory
overestimates emissions from Soda Ash Production, so it does not
accurately reflect annual national emissions from this industry. The
EPA currently estimates CO2 process emissions from soda ash
production using a tier 1 approach, based on application of default
emission factors provided in the 2006 IPCC Guidelines to estimated
national trona consumption. National consumption of trona is
approximated in the U.S. GHG Inventory based on national trona
production presented in voluntary surveys conducted by USGS. As noted
in the Overview Chapter of the 2006 IPCC Guidelines for National GHG
Inventories, ``accuracy and precision should, in general, improve from
tier 1 to tier 3'' (p.8). The tier 3 methods in the 2006 IPCC
Guidelines recommend estimating emissions by aggregating plant-level
information per Volume 3, Chapter 3.3: Natural Soda Ash Production as
noted in the preamble to this proposed rule. Further, inclusion of the
emission factors derived from emissions and trona ore consumption would
account for fractional purity of trona ore and reflect an improvement
from IPCC defaults. Facilities subject to subpart CC must measure the
inorganic carbon contents of trona inputs and/or soda ash outputs on a
monthly basis and apply this factor to estimate their emissions.
Requiring reporting of trona consumption, in addition to the inorganic
carbon contents of trona inputs and/or soda ash outputs, would allow
tier 3 methods aggregating plant-level data to be used in preparing the
U.S. GHG Inventory emissions estimates. However, as noted above, use of
GHGRP information in the U.S. GHG Inventory also necessitates
transparent presentation of underlying activity data (e.g., national
production based on facility level data), emission factors (e.g.,
derived from production and emissions), in addition to aggregated