fraction of production comes from large corporations and not those
with less than 20 employee enterprises. The smaller enterprises in
most cases deal with very small operations (such as a single family
owning a few production wells) that are unlikely to cross the 25,000
metric tons CO2e threshold.''
---------------------------------------------------------------------------

    Finally, we evaluated the costs associated with revisions to
recordkeeping and reporting, specifically revisions to the data
elements that are reported in e-GGRT or entered into IVT, for each
subpart (C, G, H, I, N, P, Q, S, W, X, Y, BB, DD, GG, HH, OO, PP, and
SS). Based on the detailed small business analyses performed for each
subpart in the initial promulgation packages (74 FR 56370, October 10,
2009; 75 FR 39738, July 12, 2010; 75 FR 75075, December 1, 2010; and 75
FR 74813, December 1, 2010), the costs associated with the reporting
program are estimated to be less than one percent of sales in all firm
size categories, with the exception of a small number of entities in
the 1 to 20 employee range, which we determined to be unlikely to meet
the regulatory thresholds and unlikely to be covered by the rule. With
the exception of subpart W, the impacts from the proposed revisions to
reporting and recordkeeping in this action for each subpart are less
than $100 per entity, with an average annual burden increase of $46 per
entity. For subpart C reporters, the highest average burden increase is
$44 per facility. Because these costs are minimal, we have determined
that the proposed revisions are unlikely to result in costs exceeding
more than one percent of sales in any firm size category. For subpart
W, the total annual average costs from the proposed revisions to
reporting and recordkeeping are $412 per facility. However, as noted
above in this section, we do not anticipate any small entities are
currently subject to or reporting under subpart W. Further, the
proposed revisions to reporting and recordkeeping under subpart W are
unlikely to result in costs exceeding more than one percent of sales in
any firm size category. Therefore, we have determined there are no
significant economic impacts for any potential small entities subject
to the revisions to reporting or recordkeeping requirements.
    We have therefore concluded that this proposed action will have no
significant regulatory burden for any directly regulated small entities
and thus that this proposed action would not have a significant
economic impact on a substantial number of small entities. Details of
this analysis are presented in the memorandum, Assessment of Burden
Impacts for Proposed Revisions for the Greenhouse Gas Reporting Rule
available in the docket for this rulemaking, Docket Id. No. EPA-HQ-OAR-
2019-0424. The EPA continues to conduct significant outreach on the
GHGRP and maintains an ``open door'' policy for stakeholders to help
inform the EPA's understanding of key issues for the industries. We
continue to be interested in the potential impacts of the proposed rule
amendments on small entities and welcome comments on issues related to
such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    This action does not contain an unfunded mandate of $100 million or
more as described in UMRA, 2 U.S.C. 1531-1538, and does not
significantly or uniquely affect small governments. The action
implements mandate(s) specifically and explicitly set forth in CAA
section 114(a)(1) without the exercise of any policy discretion by the
EPA.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have
substantial direct effects on the states, on the relationship between
the national government and the states, or on the distribution of power
and responsibilities among the various levels of government.

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

    This action has tribal implications. However, it will neither
impose substantial direct compliance costs on federally recognized
tribal governments, nor preempt tribal law. This regulation will apply
directly to stationary combustion units, cement production facilities,
landfills, and petroleum and natural gas facilities that may be owned
by tribal governments that emit GHGs. However, it will only have tribal
implications where the tribal entity owns a facility that directly
emits GHGs above threshold levels; therefore, relatively few
(approximately 8) tribal facilities would be affected. This regulation
is not anticipated to impact facilities or suppliers of additional
sectors owned by tribal governments. Further, the proposed rule
amendments are amendments that would improve the existing emissions
estimation methodologies; implement requirements to collect additional
data to understand new source categories or new emission sources for
specific sectors; improve the EPA's understanding of the sector-
specific processes or other factors that influence GHG emission rates
and improve verification of collected data; provide additional data to
complement or inform other EPA programs; clarify or update provisions
that have been unclear; or that streamline or simplify requirements. In
general, these changes are improvements or clarifications of
requirements that for the most part would not require new equipment,
sampling, or monitoring, and instead, would only require reporters to
provide data that is readily available and may be obtained from company
records or estimated from existing inputs or data elements already
collected under part 98. Therefore, these proposed changes do not
significantly change the part 98 requirements that may apply to tribal
facilities because they generally do not require new equipment,
sampling, or monitoring, and would not substantially increase reporter
burden, impose significant direct compliance costs for tribal
facilities, or preempt tribal law.
    Although few facilities subject to part 98 are likely to be owned
by tribal governments, the EPA previously sought opportunities to
provide information to tribal governments and representatives during
the development of the proposed and final rules for part 98 subparts
that were promulgated on October 30, 2009 (74 FR 52620), July 12, 2010
(75 FR 39736), November 30, 2010 (75 FR 74458), and December 1, 2010
(75 FR 74774 and 75 FR 75076). Consistent with the 2011 EPA Policy on
Consultation and Coordination with Indian Tribes,\174\ the EPA
previously consulted with tribal officials early in the process of
developing part 98 regulations to permit them to have meaningful and
timely input into its development and to provide input on the key
regulatory requirements established for these facilities. A summary of
these consultations is provided in section VIII.F of the preamble to
the final rule published on October 30, 2009 (74 FR 52620), section V.F
of the preamble to the final rule published on July 12, 2010 (75 FR
39736), section IV.F of the preamble to the re-proposal of subpart W
(Petroleum and Natural Gas Systems) published on April 12, 2010 (75 FR
18608), section IV.F of the preambles to the final rules published on
December 1, 2010 (75 FR 74774 and 75 FR 75076). As described in this
section, the proposed rule does not significantly revise the
established regulatory requirements and would not

substantially change the equipment, monitoring, or reporting activities
conducted by these facilities, or result in other substantial impacts
for tribal facilities.
---------------------------------------------------------------------------

    \174\ EPA Policy on Consultation and Coordination with Indian
Tribes, May 4, 2011. Available at: https://www.epa.gov/sites/default/files/2013-08/documents/cons-and-coord-with-indian-tribes-policy.pdf.
---------------------------------------------------------------------------

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

    The EPA interprets Executive Order 13045 as applying only to those
regulatory actions that concern environmental health or safety risks
that the EPA has reason to believe may disproportionately affect
children, per the definition of ``covered regulatory action'' in
section 2-202 of the Executive Order. This action is not subject to
Executive Order 13045 because it does not concern an environmental
health risk or safety risk.

H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use

    This action is not a ``significant energy action'' because it is
not likely to have a significant adverse effect on the supply,
distribution or use of energy. The proposed amendments would improve
the existing emissions estimation methodologies; implement requirements
to collect additional data to understand new source categories or new
emission sources for specific sectors; improve the EPA's understanding
of factors that influence GHG emission rates; improve verification of
collected data; and provide additional data to complement or inform
other EPA programs. We are also proposing revisions that clarify or
update provisions that have been unclear, or that streamline or
simplify requirements, alleviate burden through revision,
simplification, or removal of certain calculation, monitoring,
recordkeeping, or reporting requirements. In general, these changes
would not substantially impact the supply, distribution, or use of
energy. In addition, the EPA is proposing confidentiality
determinations for new and revised data elements proposed in this
rulemaking and for certain existing data elements for which a
confidentiality determination has not previously been proposed, or
where the EPA has determined that the current determination is no
longer appropriate. These proposed amendments and confidentiality
determinations do not make any changes to the existing monitoring,
calculation, and reporting requirements under part 98 that would affect
the supply, distribution, or use of energy.

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

    This action involves technical standards. The EPA proposes to allow
the use of an alternate method, ASTM E415-17, Standard Test Method for
Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission
Spectrometry (2017), for the purposes of subpart Q (Iron and Steel
Production) monitoring and reporting. The EPA currently allows for the
use of standard methods based on atomic emission spectrometry in other
sections of part 98, including under 40 CFR 98.144(b) where it can be
used to determine the composition of coal, coke, and solid residues
from combustion processes by glass production facilities. Therefore,
the EPA is allowing ASTM E415-17 to be used in subpart Q. ASTM E415-17
uses spark atomic emission vacuum spectrometry to determine 21 alloying
and residual elements in carbon and low-alloy steels. The method is
designed for chill-cast, rolled, and forged specimens. Anyone may
access the standards on the ASTM website (https://www.astm.org/) for
additional information. These standards are available to everyone at a
cost determined by the ASTM ($50). The ASTM also offers memberships or
subscriptions that allow unlimited access to their methods. The cost of
obtaining these methods is not a significant financial burden, making
the methods reasonably available for reporters. The EPA is also
proposing to add new subpart VV for certain EOR operations that choose
to use the ISO standard designated as CSA/ANSI ISO 27916:2019, Carbon
Dioxide Capture, Transportation and Geological Storage--Carbon Dioxide
Storage Using Enhanced Oil Recovery (CO2-EOR) (2019), as a means of
quantifying geologic sequestration. The method quantifies
CO2 that is stored in association with EOR operations,
focusing on the safe, long-term containment of CO2 within
the EOR complex. CSA/ANSI ISO 27916:2019 identifies and quantifies
CO2 losses (including fugitive emissions) and quantifies the
amount of CO2 stored in association with the CO2-EOR
project. It also shows how allocation rations can be used to account
for the anthropogenic portion of the stored CO2. Anyone may
access the standard on the ANSI/ISO website (https://webstore.ansi.org/SDO/ISO/) for additional information. The standard is available to
everyone at a cost determined by ANSI/ISO ($225). ANSI/ISO also offers
memberships or subscriptions for reduced costs. Because the proposed
standard is optional, the cost of obtaining this standard is not a
significant financial burden. The EPA will also make a copy of these
documents available in hard copy at the appropriate EPA office (see the
FOR FURTHER INFORMATION CONTACT section of this preamble for more
information) for review purposes only.

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

    The EPA believes the human health or environmental risk addressed
by this action will not have potential disproportionately high and
adverse human health or environmental effects on minority, low-income
or indigenous populations as it does not affect the level of protection
provided to human health or the environment because it is a rule
addressing information collection and reporting procedures.

K. Determination Under CAA Section 307(d)

    Pursuant to CAA section 307(d)(1)(V), the Administrator determines
that this action is subject to the provisions of CAA section 307(d).
Section 307(d)(1)(V) of the CAA provides that the provisions of CAA
section 307(d) apply to ``such other actions as the Administrator may
determine.''

List of Subjects

40 CFR Part 9

    Environmental protection, Administrative practice and procedure,
Reporting and recordkeeping requirements

40 CFR Part 98

    Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Reporting and
recordkeeping requirements, Suppliers.

Michael S. Regan,
Administrator.
    For the reasons stated in the preamble, the Environmental
Protection Agency proposes to amend title 40, chapter I, of the Code of
Federal Regulations as follows:

PART 9--OMB APPROVALS UNDER THE PAPERWORK REDUCTION ACT

0
1. The authority citation for part 9 continues to read as follows:

    Authority: 7 U.S.C. 135 et seq., 136-136y; 15 U.S.C. 2001, 2003,
2005, 2006, 2601-2671; 21 U.S.C. 331j, 346a, 31 U.S.C. 9701; 33
U.S.C. 1251 et seq., 1311, 1313d, 1314, 1318, 1321, 1326, 1330,
1342, 1344, 1345 (d) and (e), 1361; E.O. 11735, 38 FR 21243, 3 CFR,

1971-1975 Comp. p. 973; 42 U.S.C. 241, 242b, 243, 246, 300f, 300g,
300g-1, 300g-2, 300g-3, 300g-4, 300g-5, 300g-6, 300j-1, 300j-2,
300j-3, 300j-4, 300j-9, 1857 et seq., 6901-6992k, 7401-7671q, 7542,
9601-9657, 11023, 11048.

0
2. Amend Sec.  9.1 by adding an undesignated center heading and an
entry for ``98.1-98.489'' in numerical order to read as follows:

Sec.  9.1  OMB approvals under the Paperwork Reduction Act.

* * * * *

------------------------------------------------------------------------
                                                            OMB control
                     40 CFR citation                            No.
------------------------------------------------------------------------

                                * * * * *
------------------------------------------------------------------------
Mandatory Greenhouse Gas Reporting
------------------------------------------------------------------------
98.1-98.489.............................................       2060-0629

                                * * * * *
------------------------------------------------------------------------

PART 98--MANDATORY GREENHOUSE GAS REPORTING

0
3. The authority citation for part 98 continues to read as follows:

    Authority: 42 U.S.C. 7401-7671q.

Subpart A--General Provision

0
4. Amend Sec.  98.1 by revising paragraph (c) to read as follows:

Sec.  98.1  Purpose and scope.

* * * * *
    (c) For facilities required to report under onshore petroleum and
natural gas production under subpart W of this part, the terms Owner
and Operator used in this subpart have the same definition as Onshore
petroleum and natural gas production owner or operator, as defined in
Sec.  98.238. For facilities required to report under onshore petroleum
and natural gas gathering and boosting under subpart W of this part,
the terms Owner and Operator used in this subpart have the same
definition as Gathering and boosting system owner or operator, as
defined in Sec.  98.238. For facilities required to report under
onshore natural gas transmission pipeline under subpart W of this part,
the terms Owner and Operator used in this subpart have the same
definition as Onshore natural gas transmission pipeline owner or
operator, as defined in Sec.  98.238.
0
5. Amend Sec.  98.2 by revising paragraphs (f)(1) and (i)(1) and (2)
and adding paragraph (k) to read as follows:

Sec.  98.2  Who must report?

* * * * *
    (f) * * *
    (1) Calculate the mass in metric tons per year of CO2,
N2O, each fluorinated GHG, and each fluorinated heat
transfer fluid that is imported and the mass in metric tons per year of
CO2, N2O, each fluorinated GHG, and each
fluorinated heat transfer fluid that is exported during the year.
* * * * *
    (i) * * *
    (1) If reported CO2e emissions, calculated in accordance
with Sec.  98.3(c)(4)(i), are less than 25,000 metric tons per year for
five consecutive years, then the owner or operator may discontinue
complying with this part provided that the owner or operator submits a
notification to the Administrator that announces the cessation of
reporting and explains the reasons for the reduction in emissions. The
notification shall be submitted no later than March 31 of the year
immediately following the fifth consecutive year of emissions less than
25,000 tons CO2e per year. The owner or operator must
maintain the corresponding records required under Sec.  98.3(g) for
each of the five consecutive years prior to notification of
discontinuation of reporting and retain such records for three years
following the year that reporting was discontinued. The owner or
operator must resume reporting if annual CO2e emissions,
calculated in accordance with paragraph (b)(4) of this section, in any
future calendar year increase to 25,000 metric tons per year or more.
    (2) If reported CO2e emissions, calculated in accordance
with Sec.  98.3(c)(4)(i), were less than 15,000 metric tons per year
for three consecutive years, then the owner or operator may discontinue
complying with this part provided that the owner or operator submits a
notification to the Administrator that announces the cessation of
reporting and explains the reasons for the reduction in emissions. The
notification shall be submitted no later than March 31 of the year
immediately following the third consecutive year of emissions less than
15,000 tons CO2e per year. The owner or operator must
maintain the corresponding records required under Sec.  98.3(g) for
each of the three consecutive years and retain such records for three
years prior to notification of discontinuation of reporting following
the year that reporting was discontinued. The owner or operator must
resume reporting if annual CO2e emissions, calculated in
accordance with paragraph (b)(4) of this section, in any future
calendar year increase to 25,000 metric tons CO2e per year
or more.
* * * * *
    (k) To calculate GHG quantities for comparison to the 25,000 metric
ton CO2e per year threshold under paragraph (a)(4) of this
section for facilities that destroy fluorinated GHGs or fluorinated
heat transfer fluids, the owner or operator shall calculate the mass in
metric tons per year of CO2e destroyed as described in
paragraphs (k)(1) through (k)(3) of this section.
    (1) Calculate the mass in metric tons per year of each fluorinated
GHG or fluorinated heat transfer fluid that is destroyed during the
year.
    (2) Convert the mass of each destroyed fluorinated GHG or
fluorinated heat transfer fluid from paragraph (k)(1) of this section
to metric tons of CO2e using Equation A-1 of this section.
    (3) Sum the total annual metric tons of CO2e in
paragraph (k)(2) of this section for all destroyed fluorinated GHGs and
destroyed fluorinated heat transfer fluids.
0
6. Amend Sec.  98.3 by revising paragraphs (b)(2) and (h)(4) to read as
follows:

Sec.  98.3  What are the general monitoring, reporting, recordkeeping
and verification requirements of this part?

* * * * *
    (b) * * *
    (2) For a new facility or supplier that begins operation on or
after January 1, 2010 and becomes subject to the rule in the year that
it becomes operational, report emissions starting the first operating
month and ending on December 31 of that year. Each subsequent annual
report must cover emissions for the calendar year, beginning on January
1 and ending on December 31.
* * * * *
    (h) * * *
    (4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon
request by the owner or operator, the Administrator may provide
reasonable extensions of the 45-day period for submission of the
revised report or information under paragraphs (h)(1) and (2). If the
Administrator receives a request for extension of the 45-day period, by
email to an address prescribed by the Administrator prior to the
expiration of the 45-day period, the extension request is deemed to be
automatically granted for 30 days. The Administrator may grant an
additional extension beyond the automatic 30-day extension if the owner
or operator submits a request for an additional extension and the
request is received by

the Administrator prior to the expiration of the automatic 30-day
extension, provided the request demonstrates that it is not practicable
to submit a revised report or information under paragraphs (h)(1) and
(2) within 75 days. The Administrator will approve the extension
request if the request demonstrates to the Administrator's satisfaction
that it is not practicable to collect and process the data needed to
resolve potential reporting errors identified pursuant to paragraph
(h)(1) or (2) within 75 days. The Administrator will only approve an
extension request for a total of 180 days after the initial
notification of a substantive error.
* * * * *
0
7. Amend Sec.  98.4 by revising paragraph (h) and adding paragraph (n)
to read as follows:

Sec.  98.4  Authorization and responsibilities of the designated
representative.

* * * * *
    (h) Changes in owners and operators. Except as provided in
paragraph (n) of this section, in the event an owner or operator of the
facility or supplier is not included in the list of owners and
operators in the certificate of representation under this section for
the facility or supplier, such owner or operator shall be deemed to be
subject to and bound by the certificate of representation, the
representations, actions, inactions, and submissions of the designated
representative and any alternate designated representative of the
facility or supplier, as if the owner or operator were included in such
list. Within 90 days after any change in the owners and operators of
the facility or supplier (including the addition of a new owner or
operator), the designated representative or any alternate designated
representative shall submit a certificate of representation that is
complete under this section except that such list shall be amended to
reflect the change. If the designated representative or alternate
designated representative determines at any time that an owner or
operator of the facility or supplier is not included in such list and
such exclusion is not the result of a change in the owners and
operators, the designated representative or any alternate designated
representative shall submit, within 90 days of making such
determination, a certificate of representation that is complete under
this section except that such list shall be amended to include such
owner or operator.
* * * * *
    (n) Alternative provisions for changes in owners and operators for
industry segments with a unique definition of facility as defined in
Sec.  98.238. When there is a change to the owner or operator of a
facility required to report under the onshore petroleum and natural gas
production, natural gas distribution, onshore petroleum and natural gas
gathering and boosting, or onshore natural gas transmission pipeline
industry segments of subpart W of this part, or a change to the owner
or operator for some emission sources from the facility in one of these
industry segments, the provisions specified in paragraphs (n)(1)
through (4) of this section apply for the respective type of change in
owner or operator and the provisions specified in paragraph (n)(5) of
this section apply to all types of change in owner or operator for such
facilities.
    (1) If the entire facility is acquired by an owner or operator that
does not already have a reporting facility in the same industry segment
and basin (for onshore petroleum and natural gas production or onshore
petroleum and natural gas gathering and boosting) or state (for natural
gas distribution), a certificate of representation that is complete
under this section shall be submitted to reflect the new owner or
operator within 90 days after the change in the owner or operator and
according to the procedure specified in paragraph (b) of this section.
If the new owner or operator already had emission sources listed in the
applicable paragraph of Sec.  98.232 prior to the acquisition in the
same basin (for onshore petroleum and natural gas production or onshore
petroleum and natural gas gathering and boosting) or state (for natural
gas distribution) as the acquired facility but had not previously met
the applicability requirements in Sec.  98.2(a) and Sec.  98.231, then
per the applicable definition of facility in Sec.  98.238, the
previously owned applicable emission sources must be included in the
acquired facility. The new owner or operator and the new designated
representative shall be responsible for submitting the annual report
for the facility for the entire reporting year beginning with the
reporting year in which the acquisition occurred.
    (2) If the entire facility is acquired by an owner or operator that
already has a reporting facility in the same industry segment and basin
(for onshore petroleum and natural gas production or onshore petroleum
and natural gas gathering and boosting) or state (for natural gas
distribution), the new owner or operator shall merge the acquired
facility with their existing facility for purposes of the annual GHG
report. Within 90 days after the change in the owner or operator, a
certificate of representation that is complete under this section shall
be submitted for the acquired facility to reflect the new owner or
operator. The owner or operator shall also follow the provisions of
Sec.  98.2(i)(6) to notify EPA that the acquired facility will
discontinue reporting and shall provide the e-GGRT identification
number of the merged, or reconstituted, facility. The owner or operator
of the merged facility shall be responsible for submitting the annual
report for the merged facility for the entire reporting year beginning
with the reporting year in which the acquisition occurred.
    (3) If only some emission sources from the facility are acquired by
one or more new owners or operators, the existing owner or operator
(i.e., the owner or operator of the portion of the facility that is not
sold) shall continue to report under subpart W of this part for the
retained emission sources unless and until that facility meets one of
the criteria in Sec.  98.2(i). Each owner or operator that acquires
emission sources from the facility must account for those acquired
emission sources according to paragraph (n)(3)(i) or (ii) of this
section, as applicable.
    (i) If the purchasing owner or operator that acquires only some of
the emission sources from the existing facility does not already have a
reporting facility in the same industry segment and basin (for onshore
petroleum and natural gas production or onshore petroleum and natural
gas gathering and boosting) or state (for natural gas distribution),
the purchasing owner or operator shall begin reporting as a new
facility. The new facility must include the acquired emission sources
listed in the applicable paragraph of Sec.  98.232 and any emission
sources the purchasing owner or operator already owned in the same
industry segment and basin (for onshore petroleum and natural gas
production or onshore petroleum and natural gas gathering and boosting)
or state (for natural gas distribution). The designated representative
for the new facility must be selected by the purchasing owner or
operator according to the schedule and procedure specified in
paragraphs (b) through (d) of this section. The purchasing owner or
operator shall be responsible for submitting the annual report for the
new facility for the entire reporting year beginning with the reporting
year in which the acquisition occurred.
    (ii) If the purchasing owner or operator that acquires only some of
the emission sources from the existing facility already has a reporting
facility in the same industry segment and basin (for onshore petroleum
and natural gas

production or onshore petroleum and natural gas gathering and boosting)
or state (for natural gas distribution), then per the applicable
definition of facility in Sec.  98.238, the purchasing owner or
operator must add the acquired emission sources listed in the
applicable paragraph of Sec.  98.232 to their existing facility for
purposes of reporting under subpart W. The purchasing owner or operator
shall be responsible for submitting the annual report for the entire
facility, including the acquired emission sources, for the entire
reporting year beginning with the reporting year in which the
acquisition occurred.
    (4) If all the emission sources from a facility are sold to
multiple owners or operators, such that the current owner or operator
of the existing facility does not retain any of the emission sources,
then the current owner or operator of the existing facility shall
notify EPA within 90 days of the transaction that all of the facility's
emission sources were acquired by multiple purchasers. Each owner or
operator that acquires emission sources from a facility shall account
for those sources according to paragraph (n)(3)(i) or (ii) of this
section, as applicable.
    (5) Each owner or operator involved in a transaction that results
in a change to the owner or operator of a facility shall, as part of
the acquisition agreement or ownership transfer contract, agree upon
the entity who will be responsible for revisions to annual GHG reports
under Sec.  98.3(h) for reporting years prior to the reporting year in
which the transaction occurred. That responsible entity will select a
representative who will submit revisions to annual GHG reports under
Sec.  98.3(h) for that facility. If the selected individual is not the
designated representative for the facility, the individual must be
designated as the alternate designated representative or an agent for
the facility.
0
8. Amend Sec.  98.6 by:
0
a. Revising the definitions for ``Carbon dioxide stream'',
``Dehydrator'', and ``Dehydrator vent emissions;''
0
b. Removing the definition for ``Desiccant'';
0
c. Adding a definition for ``Direct air capture (DAC)'' in alphabetical
order; and
0
d. Revising the definition for ``Vapor recovery system''.
    The revisions and addition read follows:

Sec.  98.6  Definitions.

* * * * *
    Carbon dioxide stream means carbon dioxide that has been captured
from an emission source (e.g., a power plant or other industrial
facility, captured from ambient air (e.g., direct air capture), or
extracted from a carbon dioxide production well plus incidental
associated substances either derived from the source materials and the
capture process or extracted with the carbon dioxide.
* * * * *
    Dehydrator means a device in which a liquid absorbent (e.g.,
ethylene glycol, diethylene glycol, or triethylene glycol) directly
contacts a natural gas stream to absorb water vapor.
    Dehydrator vent emissions means natural gas and CO2
released from a natural gas dehydrator system absorbent (typically
glycol) regenerator and, if present, a flash tank separator, to the
atmosphere, flare, regenerator fire-box/fire tubes, or vapor recovery
system. Emissions include stripping natural gas and motive natural gas
used in absorbent circulation pumps.
* * * * *
    Direct air capture (DAC), with respect to a facility, technology,
or system, means that the facility, technology, or system uses carbon
capture equipment to capture carbon dioxide directly from the air.
Direct air capture does not include any facility, technology, or system
that captures carbon dioxide:
    (1) That is deliberately released from a naturally occurring
subsurface spring or
    (2) Using natural photosynthesis.
* * * * *
    Vapor recovery system means any equipment located at the source of
potential gas emissions to the atmosphere or to a flare, that is
composed of piping, connections, and, if necessary, flow-inducing
devices, and that is used for routing the gas back into the process as
a product and/or fuel. For purposes of Sec.  98.233, routing emissions
from a dehydrator regenerator still vent or flash tank separator vent
to a regenerator fire-box/fire tubes does not meet the definition of
vapor recovery system.
* * * * *
0
9. Amend Sec.  98.7 as follows:
0
a. Revise the introductory text;
0
b. In paragraph (c)(1), remove the text ``, incorporation by reference
(IBR)'' and add, in its place, the text ``; IBR'';
0
c. Redesignate paragraph (e)(38) as paragraph (e)(39);
0
d. Add new paragraph (e)(38) and paragraph (g)(6); and
0
e. In addition to the previous amendments to this section, remove the
text ``, IBR'' and add, in its place, the text ``; IBR'' wherever it
appears throughout this section.
    The revision and additions read as follows:

Sec.  98.7  What standardized methods are incorporated by reference
into this part?

    Certain material is incorporated by reference into this part with
the approval of the Director of the Federal Register under 5 U.S.C.
552(a) and 1 CFR part 51. To enforce any edition other than that
specified in this section, the EPA must publish a document in the
Federal Register and the material must be available to the public. All
approved incorporation by reference (IBR) material is available for
inspection at the EPA and at the National Archives and Records
Administration (NARA). Contact EPA at: EPA Docket Center, Public
Reading Room, EPA WJC West, Room 3334, 1301 Constitution Ave. NW,
Washington, DC; phone:<PHONE_NUMBER>. For information on the
availability of this material at NARA, email [email protected], or
go to www.archives.gov/federal-register/cfr/ibr-locations.html. The
material may be obtained from the following source(s):
* * * * *
    (e) * * *
    (38) ASTM E415-17, Standard Test Method for Analysis of Carbon and
Low-Alloy Steel by Spark Atomic Emission Spectrometry; IBR approved for
Sec.  98.174(b).
* * * * *
    (g) * * *
    (6) CSA/ANSI ISO 27916:19, Carbon dioxide capture, transportation
and geological storage--Carbon dioxide storage using enhanced oil
recovery (CO2-EOR). Edition 1. January 2019; IBR approved
for Sec. Sec.  98.480(a), 98.481(a) and (b), 98.482, 98.483, 98.484,
98.485, 98.486(g), 98.487, 98.488(a)(5), and 98.489.
* * * * *
0
10. Amend table A-1 to subpart A of part 98 by:
0
a. Adding under the heading ``Other Fluorinated Compounds'' the entry
``Carbonyl fluoride'' after the entry ``2-Bromo-2-chloro-1,1,1-
trifluoroethane (Halon-2311/Halothane);''
0
b. Removing the heading ``Fluorinated GHG Group \d\'' and adding in its
place the heading ``Fluorinated GHG Group \e\''
0
c. Revising the entry ``Unsaturated perfluorocarbons (PFCs),
unsaturated HFCs, unsaturated hydrochlorofluorocarbons (HCFCs),
unsaturated halogenated ethers, unsaturated halogenated esters,
fluorinated aldehydes, and fluorinated ketones'' under the revised
heading ``Fluorinated GHG Group; \e\''
0
d. Redesignating footnote ``d'' as footnote ``e;'' and

0
e. Adding new footnote ``d'' and footnote ``f.''
    The additions and revisions read as follows:
* * * * *

                          Table A-1 to Subpart A of Part 98--Global Warming Potentials
----------------------------------------------------------------------------------------------------------------
                                                                                Global
                                                                                warming
                     Name                           CAS No.             Chemical formula             potential
                                                                                (100 yr.)
----------------------------------------------------------------------------------------------------------------

                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------
                                           Other Fluorinated Compounds
----------------------------------------------------------------------------------------------------------------

                                                  * * * * * * *
Carbonyl fluoride.............................        353-50-4  COF2............................        \d\ 0.14
----------------------------------------------------------------------------------------------------------------
                                            Fluorinated GHG Group \e\
----------------------------------------------------------------------------------------------------------------

                                                  * * * * * * *
Unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated hydrochlorofluorocarbons                    1
 (HCFCs), unsaturated halogenated ethers, unsaturated halogenated esters, unsaturated
 bromofluorocarbons, unsaturated chlorofluorocarbons, unsaturated bromochlorofluorocarbons,
 unsaturated hydrobromofluorocarbons, unsaturated hydrobromochlorofluorocarbons, fluorinated
 aldehydes, and fluorinated ketones \f\

                                                  * * * * * * *
----------------------------------------------------------------------------------------------------------------
* * * * *
\d\ This compound was added to Table A-1 in the final rule published on [Date of publication of the final rule
  in the Federal Register] and effective on January 1, 2023.
\e\ For electronics manufacturing (as defined in Sec.   98.90), the term ``fluorinated GHGs'' in the definition
  of each fluorinated GHG group in Sec.   98.6 shall include fluorinated heat transfer fluids (as defined in
  Sec.   98.98), whether or not they are also fluorinated GHGs.
\f\ This fluorinated GHG group was updated in the final rule published on [Date of publication of the final rule
  in the Federal Register] and effective on January 1, 2023.

0
11. Amend table A-3 to subpart A of part 98 by:
0
a. Revising the entry ``Electrical transmission and distribution
equipment use at facilities where the total nameplate capacity of SF6
and PFC containing equipment exceeds 17,820 pounds, as determined under
Sec.  98.301 (subpart DD).'';
0
b. Removing the entry for ``Electrical transmission and distribution
equipment manufacture or refurbishment (subpart SS).''; and
0
c. Adding the entry ``Geologic Sequestration of Carbon Dioxide with
Enhanced Oil Recovery Using ISO 27916 (subpart VV).'' at the end of the
table.
    The revision and addition read as follows:
* * * * *

    Table A-3 to Subpart A of Part 98--Source Category List for Sec.
                               98.2(a)(1)
------------------------------------------------------------------------

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

                              * * * * * * *
Additional Source Categories \a\ Applicable in Reporting Year 2011 and
 Future Years
Electrical transmission and distribution equipment use at facilities
 where the total estimated emissions from fluorinated GHGs, as
 determined under Sec.   98.301 (subpart DD), are equivalent to 25,000
 metric tons CO2e or more per year.

                              * * * * * * *
Geologic Sequestration of Carbon Dioxide with Enhanced Oil Recovery
 Using ISO 27916 (subpart VV).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.

* * * * *
0
12. Amend table A-4 to subpart A of part 98 by adding the entry
``Electrical transmission and distribution equipment manufacture or
refurbishment, as determined under Sec.  98.451 (subpart SS).'' after
the entry ``Industrial wastewater treatment (subpart II).'' to read as
follows:

    Table A-4 to Subpart A of Part 98--Source Category List for Sec.
                               98.2(a)(2)
------------------------------------------------------------------------

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

                              * * * * * * *
Additional Source Categories \a\ Applicable in Reporting Year 2011 and
 Future Years

                              * * * * * * *
Electrical transmission and distribution equipment manufacture or
 refurbishment, as determined under Sec.   98.451 (subpart SS).

                              * * * * * * *
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.

* * * * *

Subpart C--General Stationary Fuel Combustion Sources

0
13. Amend Sec.  98.33 by:
0
a. Revising parameters ``CC'' and ``MW'' of Equation C-5 in paragraph
(a)(3)(iii) introductory text;
0
b. Adding paragraphs (a)(3)(iii)(A) and (B);
0
c. Revising paragraph (b)(1)(vii);
0
d. Revising parameter ``EF'' of Equations C-8 in paragraph (c)(1)
introductory text, C-8a in paragraph (c)(1)(i), C-8b in paragraph
(c)(1)(ii), C-9a in paragraph (c)(2), C-9b in paragraph (c)(3), and C-
10 in paragraph (c)(4) introductory text;
0
e. Revising paragraphs (c)(6)(i), (c)(6)(ii) introductory text, and
(c)(6)(ii)(A) and (C);
0
f. Removing and reserving paragraph (c)(6)(ii)(B);
0
g. Revising parameter ``R'' of Equation C-11 in paragraph (d)(1); and
0
h. Revising the introductory text of paragraphs (e), (e)(1), (e)(2)(v),
and (e)(3) and paragraph (e)(3)(iv).
    The additions and revisions read as follows:

Sec.  98.33  Calculating GHG emissions.

* * * * *
    (a) * * *
    (3) * * *
    (iii) * * *

CC = Annual average carbon content of the gaseous fuel (kg C per kg
of fuel). The annual average carbon content shall be determined
using the procedures specified in paragraphs (a)(3)(iii)(A)(1) and
(a)(3)(iii)(A)(2) of this section.
MW = Annual average molecular weight of the gaseous fuel (kg per kg-
mole). The annual average molecular weight shall be determined using
the procedures specified in paragraphs (a)(3)(iii)(A)(3) and
(a)(3)(iii)(A)(4) of this section.
* * * * *
    (A) The minimum required sampling frequency for determining the
annual average carbon content (e.g., monthly, quarterly, semi-annually,
or by lot) is specified in Sec.  98.34. The method for computing the
annual average carbon content for Equation C-5 is a function of unit
size and how frequently you perform or receive from the fuel supplier
the results of fuel sampling for carbon content. The methods are
specified in paragraphs (a)(3)(iii)(A)(1) and (2) of this section, as
applicable.
    (1) If the results of fuel sampling are received monthly or more
frequently, then for each unit with a maximum rated heat input capacity
greater than or equal to 100 mmBtu/hr (or for a group of units that
includes at least one unit of that size), the annual average carbon
content for Equation C-5 shall be calculated using Equation C-5a of
this section. If multiple carbon content determinations are made in any
month, average the values for the month arithmetically.
[GRAPHIC] [TIFF OMITTED] TP21JN22.000

Where:

(CC)annual = Weighted annual average carbon content of
the fuel (kg C per kg of fuel).
(CC)I = Measured carbon content of the fuel, for sample
period ``i'' (which may be the arithmetic average of multiple
determinations), or, if applicable, an appropriate substitute data
value (kg C per kg of fuel).
(Fuel)i = Volume of the fuel (scf) combusted during the sample
period ``i'' (e.g., monthly, quarterly, semi-annually, or by lot)
from company records.
(MW)i = Measured molecular weight of the fuel, for sample period
``i'' (which may be the arithmetic average of multiple
determinations), or, if applicable, an appropriate substitute data
value (kg per kg-mole).
MVC = Molar volume conversion factor at standard conditions, as
defined in Sec.  98.6. Use 849.5 scf per kg-mole if you select 68
[deg]F as standard temperature and 836.6 scf per kg-mole if you
select 60 [deg]F as standard temperature.
n = Number of sample periods in the year.

    (2) If the results of fuel sampling are received less frequently
than monthly, or, for a unit with a maximum rated heat input capacity
less than 100 mmBtu/hr (or a group of such units) regardless of the
carbon content sampling frequency, the annual average carbon content
for Equation C-5 shall either be computed according to paragraph
(a)(3)(iii)(A)(1) of this section or as the arithmetic average carbon
content for all values for the year (including valid samples and
substitute data values under Sec.  98.35).
    (B) The minimum required sampling frequency for determining the
annual average molecular weight (e.g., monthly, quarterly, semi-
annually, or by lot) is specified in Sec.  98.34. The method for
computing the annual average molecular weight for Equation C-5 is a
function of unit size and how frequently you perform or receive from
the fuel supplier the results of fuel sampling for molecular weight.
The methods are specified in paragraphs (a)(3)(iii)(B)(1) and
(a)(3)(iii)(B)(2) of this section, as applicable.
    (1) If the results of fuel sampling are received monthly or more
frequently, then for each unit with a maximum rated heat input capacity
greater than or equal to 100 mmBtu/hr (or for a group of units that
includes at least one unit of that size), the annual average molecular
weight for Equation C-5 shall be calculated using Equation C-5b of this
section. If multiple molecular weight determinations are made in any
month, average the values for the month arithmetically.
[GRAPHIC] [TIFF OMITTED] TP21JN22.001

Where:

(MW)annual = Weighted annual average molecular weight of
the fuel (kg per kg-mole).
(MW)i = Measured molecular weight of the fuel, for sample
period ``i'' (which may be the arithmetic average of multiple

determinations), or, if applicable, an appropriate substitute data
value (kg per kg-mole).
(Fuel)i = Volume of the fuel (scf) combusted during the
sample period ``i'' (e.g., monthly, quarterly, semi-annually, or by
lot) from company records.
MVC = Molar volume conversion factor at standard conditions, as
defined in Sec.  98.6. Use 849.5 scf per kg-mole if you select 68
[deg]F as standard temperature and 836.6 scf per kg-mole if you
select 60 [deg]F as standard temperature.
n = Number of sample periods in the year.

    (2) If the results of fuel sampling are received less frequently
than monthly, or, for a unit with a maximum rated heat input capacity
less than 100 mmBtu/hr (or a group of such units) regardless of the
molecular weight sampling frequency, the annual average molecular
weight for Equation C-5 shall either be computed according to paragraph
(a)(3)(iii)(A)(3) of this section or as the arithmetic average
molecular weight for all values for the year (including valid samples
and substitute data values under Sec.  98.35).
* * * * *
    (b) * * *
    (1) * * *
    (vii) May be used for the combustion of MSW and/or tires in a unit,
provided that no more than 10 percent of the unit's annual heat input
is derived from those fuels, combined.
* * * * *
    (c) * * *
    (1) * * *

EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu), except for natural gas compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
    (i) * * *

EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu), except for natural gas compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
    (ii) * * *

EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu), except for natural gas compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
    (2) * * *

EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu), except for natural gas compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
    (3) * * *

EF = Fuel-specific emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu), except for natural gas compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
    (4) * * *

EF = Fuel-specific emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu), except for natural gas compressor drivers
at facilities subject to subpart W of this part, which must use the
applicable CH4 emission factor from Table W-9 to subpart
W of this part.
* * * * *
    (6) * * *
    (i) If the mass, volume, or heat input of each component fuel in
the blend is determined before the fuels are mixed and combusted,
calculate and report CH4 and N2O emissions
separately for each component fuel, using the applicable procedures in
this paragraph (c).
    (ii) If the mass, volume, or heat input of each component fuel in
the blend is not determined before the fuels are mixed and combusted, a
reasonable estimate of the percentage composition of the blend, based
on best available information, is required. Perform the following
calculations for each component fuel ``i'' that is listed in Table C-2:
    (A) Multiply (% Fuel)i, the estimated mass, volume, or heat input
percentage of component fuel ``i'' (expressed as a decimal fraction),
by the total annual mass, volume, or heat input of the blended fuel
combusted during the reporting year, to obtain an estimate of the
annual value for component ``i'';
* * * * *
    (C) Calculate the annual CH4 and N2O
emissions from component ``i'', using Equation C-8 (fuel mass or
volume), C-8a (fuel heat input), C-8b (fuel heat input), C-9a (fuel
mass or volume), or C-10 (fuel heat input) of this section, as
applicable;
* * * * *
    (d) * * *
    (1) * * *

R = The number of moles of CO2 released per mole of
sorbent used (R = 1.00 when the sorbent is CaCO3 and the
targeted acid gas species is SO2).
* * * * *
    (e) Biogenic CO2 emissions from combustion of biomass
with other fuels. Use the applicable procedures of this paragraph (e)
to estimate biogenic CO2 emissions from units that combust a
combination of biomass and fossil fuels (i.e., either co-fired or
blended fuels). Separate reporting of biogenic CO2 emissions
from the combined combustion of biomass and fossil fuels is required
for those biomass fuels listed in Table C-1 of this section, MSW, and
tires. In addition, when a biomass fuel that is not listed in Table C-1
is combusted in a unit that has a maximum rated heat input greater than
250 mmBtu/hr, if the biomass fuel accounts for 10% or more of the
annual heat input to the unit, and if the unit does not use CEMS to
quantify its annual CO2 mass emissions, then, pursuant to
Sec.  98.33(b)(3)(iii), Tier 3 must be used to determine the carbon
content of the biomass fuel and to calculate the biogenic
CO2 emissions from combustion of the fuel. Notwithstanding
these requirements, in accordance with Sec.  98.3(c)(12), separate
reporting of biogenic CO2 emissions is optional for the 2010
reporting year for units subject to subpart D of this part and for
units that use the CO2 mass emissions calculation
methodologies in part 75 of this chapter, pursuant to paragraph (a)(5)
of this section. However, if the owner or operator opts to report
biogenic CO2 emissions separately for these units, the
appropriate method(s) in this paragraph (e) shall be used.
    (1) You may use Equation C-1 of this subpart to calculate the
annual CO2 mass emissions from the combustion of the biomass
fuels listed in Table C-1 of this subpart, in a unit of any size,
including units equipped with a CO2 CEMS, except when the
use of Tier 2 is required as specified in paragraph (b)(1)(iv) of this
section. Determine the quantity of biomass combusted using one of the
following procedures in this paragraph (e)(1), as appropriate, and
document the selected procedures in the Monitoring Plan under Sec.
98.3(g):
* * * * *
    (2) * * *
    (v) Calculate the biogenic percentage of the annual CO2
emissions expressed as a decimal fraction, using Equation C-14 of this
section:
* * * * *
    (3) You must use the procedures in paragraphs (e)(3)(i) through
(iii) of this section to determine the annual biogenic CO2
emissions from the

combustion of MSW, except as otherwise provided in paragraph (e)(3)(iv)
of this section. These procedures also may be used for any unit that
co-fires biomass and fossil fuels, including units equipped with a
CO2 CEMS.
* * * * *
    (iv) In lieu of following the procedures in paragraphs (e)(3)(i)
through (iii) of this section, the procedures of this paragraph may be
used for the combustion of tires regardless of the percent of the
annual heat input provided by tires. The calculation procedure in this
paragraph may be used for the combustion of MSW if the combustion of
MSW provides no more than 10 percent of the annual heat input to the
unit or if a small, batch incinerator combusts no more than 1,000 tons
per year of MSW.
    (A) Calculate the total annual CO2 emissions from
combustion of MSW and/or tires in the unit, using the applicable
methodology in paragraphs (a)(1) through (3) of this section for units
using Tier 1, Tier 2, or Tier 3; otherwise use the Tier 1 calculation
methodology in paragraph (a)(1) of this section for units using either
the Tier 4 or Alternative Part 75 calculation methodologies to
calculate total CO2 emissions.
    (B) Multiply the result from paragraph (e)(3)(iv)(A) of this
section by the appropriate default factor to determine the annual
biogenic CO2 emissions, in metric tons. For MSW, use a
default factor of 0.60 and for tires, use a default factor of 0.24.
* * * * *
0
14. Amend Sec.  98.34 by revising paragraphs (c)(6) and (d) to read as
follows:

Sec.  98.34  Monitoring and QA/QC requirements.

* * * * *
    (c) * * *
    (6) For applications where CO2 concentrations in process
and/or combustion flue gasses are lower or higher than the typical
CO2 span value for coal-based fuels (e.g., 20 percent
CO2 for a coal fired boiler), cylinder gas audits of the
CO2 monitor under appendix F to part 60 of this chapter may
be performed at 40-60 percent and 80-100 percent of CO2
span, in lieu of the prescribed calibration levels of 5-8 percent and
10-14 percent CO2 by volume.
* * * * *
    (d) Except as otherwise provided in Sec.  98.33(e)(3)(iv), when
municipal solid waste (MSW) is either the primary fuel combusted in a
unit or the only fuel with a biogenic component combusted in the unit,
determine the biogenic portion of the CO2 emissions using
ASTM D6866-16 Standard Test Methods for Determining the Biobased
Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon
Analysis) and ASTM D7459-08 Standard Practice for Collection of
Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-
Derived Carbon Dioxide Emitted from Stationary Emissions Sources (both
incorporated by reference, see Sec.  98.7). Perform the ASTM D7459-08
sampling and the ASTM D6866-16 analysis at least once in every calendar
quarter in which MSW is combusted in the unit. Collect each gas sample
during normal unit operating conditions for at least 24 total (not
necessarily consecutive) hours, or longer if the facility deems it
necessary to obtain a representative sample. Notwithstanding this
requirement, if the types of fuels combusted and their relative
proportions are consistent throughout the year, the minimum required
sampling time may be reduced to 8 hours if at least two 8-hour samples
and one 24-hour sample are collected under normal operating conditions,
and arithmetic average of the biogenic fraction of the flue gas from
the 8-hour samples (expressed as a decimal) is within 5
percent of the biogenic fraction from the 24-hour test. There must be
no overlapping of the 8-hour and 24-hour test periods. Document the
results of the demonstration in the unit's monitoring plan. If the
types of fuels and their relative proportions are not consistent
throughout the year, an optional sampling approach that facilities may
wish to consider to obtain a more representative sample is to collect
an integrated sample by extracting a small amount of flue gas (e.g., 1
to 5 cc) in each unit operating hour during the quarter. Separate the
total annual CO2 emissions into the biogenic and non-
biogenic fractions using the average proportion of biogenic emissions
of all samples analyzed during the reporting year. Express the results
as a decimal fraction (e.g., 0.30, if 30 percent of the CO2
is biogenic). When MSW is the primary fuel for multiple units at the
facility, and the units are fed from a common fuel source, testing at
only one of the units is sufficient.
* * * * *
0
15. Amend Sec.  98.36 by:
0
a. Revising paragraphs (c)(1) introductory text, (c)(1)(ii) and (vi),
(c)(3) introductory text, and (c)(3)(vi);
0
b. Adding paragraph (c)(3)(xi); and
0
c. Revising paragraphs (e)(2)(ii)(C) and (e)(2)(xi).
    The revisions and addition read as follows:

Sec.  98.36  Data reporting requirements.

* * * * *
    (c) * * *
    (1) Aggregation of units. If a facility contains two or more units
(e.g., boilers or combustion turbines), each of which has a maximum
rated heat input capacity of 250 mmBtu/hr or less, you may report the
combined GHG emissions for the group of units in lieu of reporting GHG
emissions from the individual units, provided that the use of Tier 4 is
not required or elected for any of the units and the units use the same
tier for any common fuels combusted. Compressor drivers that calculate
emissions using an applicable CH4 emission factor from Table
W-9 to subpart W of this part, must be reported as their own
aggregation of units configuration, according to design class (i.e.,
two-stroke lean-burn, four-stroke lean-burn, and four-stroke rich-
burn). You may not have a combination of one design class of compressor
driver (using one Table W-9 CH4 emission factor) and other
combustion units (e.g., using a Table C-2 CH4 emission
factor or another Table W-9 CH4 emission factor) in the same
aggregation of units configuration. If this option is selected, the
following information shall be reported instead of the information in
paragraph (b) of this section:
* * * * *
    (ii) For each unit in the group greater than or equal to 10 mmBtu/
hr, the unit type, maximum rated heat input capacity, and an estimate
of the total annual heat input (expressed as a decimal fraction). To
determine the total annual heat input decimal fraction for a unit,
divide the actual heat input for that unit (all fuels) by the sum of
the actual heat input for all units (all fuels), including units less
than 10 mmBtu/hr. Estimates of the actual heat inputs may be based on
company records. If all units in this configuration are less than 10
(mmBtu/hr), this requirement does not apply.
* * * * *
    (vi) Annual CO2 mass emissions and annual
CH4, and N2O mass emissions, aggregated for each
type of fuel combusted in the group of units during the report year,
expressed in metric tons of each gas and in metric tons of
CO2e. If any of the units burn biomass, report also the
annual CO2 emissions from combustion of all biomass fuels
combined, expressed in metric tons.
* * * * *

    (3) Common pipe configurations. When two or more stationary
combustion units at a facility combust the same type of liquid or
gaseous fuel and the fuel is fed to the individual units through a
common supply line or pipe, you may report the combined emissions from
the units served by the common supply line, in lieu of separately
reporting the GHG emissions from the individual units, provided that
the total amount of fuel combusted by the units is accurately measured
at the common pipe or supply line using a fuel flow meter, or, for
natural gas, the amount of fuel combusted may be obtained from gas
billing records. For Tier 3 applications, the flow meter shall be
calibrated in accordance with Sec.  98.34(b). If a portion of the fuel
measured (or obtained from gas billing records) at the main supply line
is diverted to either: A flare; or another stationary fuel combustion
unit (or units), including units that use a CO2 mass
emissions calculation method in part 75 of this chapter; or a chemical
or industrial process (where it is used as a raw material but not
combusted), and the remainder of the fuel is distributed to a group of
combustion units for which you elect to use the common pipe reporting
option, you may use company records to subtract out the diverted
portion of the fuel from the fuel measured (or obtained from gas
billing records) at the main supply line prior to performing the GHG
emissions calculations for the group of units using the common pipe
option. If the diverted portion of the fuel is combusted, the GHG
emissions from the diverted portion shall be accounted for in
accordance with the applicable provisions of this part. When the common
pipe option is selected, the applicable tier shall be used based on the
maximum rated heat input capacity of the largest unit served by the
common pipe configuration, except where the applicable tier is based on
criteria other than unit size. For example, if the maximum rated heat
input capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3
will apply, unless the fuel transported through the common pipe is
natural gas or distillate oil, in which case Tier 2 may be used, in
accordance with Sec.  98.33(b)(2)(ii). As a second example, in
accordance with Sec.  98.33(b)(1)(v), Tier 1 may be used regardless of
unit size when natural gas is transported through the common pipe, if
the annual fuel consumption is obtained from gas billing records in
units of therms or mmBtu. Compressor drivers that calculate emissions
using an applicable CH4 emission factor from Table W-9 to
subpart W of this part, must be reported as their own common pipe
configuration, according to design class (i.e., two-stroke lean-burn,
four-stroke lean-burn, and four-stroke rich-burn). You may not have a
combination of one design class of compressor driver (using one Table
W-9 CH4 emission factor) and other combustion units (e.g.,
using a Table C-2 CH4 emission factor or another Table W-9
CH4 emission factor) in the same common pipe configuration.
When the common pipe reporting option is selected, the following
information shall be reported instead of the information in paragraph
(b) of this section:
* * * * *
    (vi) If any of the units burns biomass, the annual CO2
emissions from combustion of all biomass fuels from the units served by
the common pipe, expressed in metric tons.
* * * * *
    (xi) For each unit in the group greater than or equal to 10 mmBtu/
hr, the unit type, maximum rated heat input capacity, and an estimate
of the total annual heat input (expressed as a decimal fraction). To
determine the total annual heat input decimal fraction for a unit,
divide the actual heat input for that unit (all fuels) by the sum of
the actual heat input for all units (all fuels), including units less
than 10 mmBtu/hr. Estimated heat input values may be based on company
records. If all units in this configuration are less than 10 (mmBtu/
hr), this requirement does not apply.
* * * * *
    (e) * * *
    (2) * * *
    (ii) * * *
    (C) The annual average, and, where applicable, monthly high heat
values used in the CO2 emissions calculations for each type
of fuel combusted during the reporting year, in mmBtu per short ton for
solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf for
gaseous fuels. Report an HHV value for each calendar month in which HHV
determination is required. If multiple values are obtained in a given
month, report the arithmetic average value for the month.
* * * * *
    (xi) When ASTM methods D7459-08 and D6866-16 (both incorporated by
reference, see Sec.  98.7) are used in accordance with Sec.  98.34(e)
to determine the biogenic portion of the annual CO2
emissions from a unit that co-fires biogenic fuels (or partly-biogenic
fuels, including tires) and non-biogenic fuels, you shall report the
results of each quarterly sample analysis, expressed as a decimal
fraction (e.g., if the biogenic fraction of the CO2
emissions is 30 percent, report 0.30).
* * * * *
0
16. Amend Sec.  98.37 by revising paragraphs (b) introductory text,
(b)(9) through (11), (14), (18), (20), (22), and (23) to read as
follows:

Sec.  98.37  Records that must be retained.

* * * * *
    (b) For each stationary fuel combustion source that elects to use
the verification software specified in Sec.  98.5(b) rather than report
data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i),
(e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iv)(A),
(e)(2)(iv)(C), (e)(2)(iv)(F), and (e)(2)(ix)(D) through (F) of this
section, you must keep a record of the file generated by the
verification software for the applicable data specified in paragraphs
(b)(1) through (37) of this section. Retention of this file satisfies
the recordkeeping requirement for the data in paragraphs (b)(1) through
(37) of this section.
* * * * *
    (9) Measured high heat value of each solid fuel, for month (which
may be the arithmetic average of multiple determinations), or, if
applicable, an appropriate substitute data value (mmBtu per ton)
(Equation C-2b of Sec.  98.33). Annual average HHV of each solid fuel
(mmBtu per ton) (Equation C-2a of Sec.  98.33).
    (10) Measured high heat value of each liquid fuel, for month (which
may be the arithmetic average of multiple determinations), or, if
applicable, an appropriate substitute data value (mmBtu per gallons)
(Equation C-2b). Annual average HHV of each liquid fuel (mmBtu per
gallons) (Equation C-2a of Sec.  98.33).
    (11) Measured high heat value of each gaseous fuel, for month
(which may be the arithmetic average of multiple determinations), or,
if applicable, an appropriate substitute data value (mmBtu per scf)
(Equation C-2b). Annual average HHV of each gaseous fuel (mmBtu per
scf) (Equation C-2a of Sec.  98.33).
* * * * *
    (14) Volume of each gaseous fuel combusted during month (scf)
(Equation C-2b, Equation C-5a, Equation C-5b).
* * * * *
    (18) Annual average carbon content of each solid fuel (percent by
weight, expressed as a decimal fraction) (Equation C-3). Where
applicable, monthly carbon content of each solid fuel (which may be the
arithmetic

average of multiple determinations), or, if applicable, an appropriate
substitute data value (percent by weight, expressed as a decimal
fraction) (Equation C-2b--see the definition of ``CC'' in Equation C-
3).
* * * * *
    (20) Annual average carbon content of each liquid fuel (kg C per
gallon of fuel) (Equation C-4). Where applicable, monthly carbon
content of each liquid fuel (which may be the arithmetic average of
multiple determinations), or, if applicable, an appropriate substitute
data value (kg C per gallon of fuel) (Equation C-2b--see the definition
of ``CC'' in Equation C-3).
* * * * *
    (22) Annual average carbon content of each gaseous fuel (kg C per
kg of fuel) (Equation C-5). Where applicable, monthly carbon content of
each gaseous (which may be the arithmetic average of multiple
determinations), or, if applicable, an appropriate substitute data
value (kg C per kg of fuel) (Equation C-5a).
    (23) Annual average molecular weight of each gaseous fuel (kg/kg-
mole) (Equation C-5). Where applicable, monthly molecular weight of
each gaseous (which may be the arithmetic average of multiple
determinations), or, if applicable, an appropriate substitute data
value (kg/kg-mole) (Equation C-5b).
* * * * *
0
17. Amend table C-2 to subpart C of part 98 by revising the entry
``Natural Gas'' to read as follows:
---------------------------------------------------------------------------

    \1\ Reporters subject to subpart W of this part may only use the
default CH4 emission factor for natural gas-fired
combustion units that are not compressor drivers. For natural gas-
fired compressor drivers at facilities subject to subpart W of this
part, reporters must use the applicable CH4 emission
factor from Table W-9 to subpart W of this part.

 Table C-2 to Subpart C of Part 98--Default CH4 and N2O Emission Factors
                        for Various Types of Fuel
------------------------------------------------------------------------
                                      Default CH4         Default N2O
            Fuel type               emission factor     emission factor
                                    (kg CH4/mmBtu)      (kg N2O/mmBtu)
------------------------------------------------------------------------

                              * * * * * * *
Natural Gas \1\.................  1.0 x 10-03.......  1.0 x 10-04

                              * * * * * * *
------------------------------------------------------------------------

* * * * *

Subpart G--Ammonia Manufacturing

0
18. Amend Sec.  98.72 by revising paragraph (a) to read as follows:

Sec.  98.72  GHGs to report.

* * * * *
    (a) CO2 process emissions from steam reforming of a
hydrocarbon or the gasification of solid and liquid raw material,
reported for each ammonia manufacturing unit following the requirements
of this subpart.
* * * * *
0
19. Amend Sec.  98.73 by revising the introductory text and paragraph
(b) to read as follows:

Sec.  98.73  Calculating GHG emissions

    You must calculate and report the annual net CO2 process
emissions from each ammonia manufacturing unit using the procedures in
either paragraph (a) or (b) of this section.
* * * * *
    (b) Calculate and report under this subpart process CO2
emissions using the procedures in paragraphs (b)(1) through (4) of this
section, as applicable.
    (1) Gaseous feedstock. You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from gaseous
feedstock according to Equation G-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.002

Where:

CO2,G = Annual CO2 emissions arising from
gaseous feedstock consumption (metric tons).
Fdstkn = Volume of the gaseous feedstock used in month n
(scf of feedstock).
CCn = Carbon content of the gaseous feedstock, for month
n (kg C per kg of feedstock), determined according to 98.74(c).
MW = Molecular weight of the gaseous feedstock (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month.

    (2) Liquid feedstock. You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from liquid
feedstock according to Equation G-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.003

Where:

CO2,L = Annual CO2 emissions arising from
liquid feedstock consumption (metric tons).
Fdstkn = Volume of the liquid feedstock used in month n
(gallons of feedstock).

CCn = Carbon content of the liquid feedstock, for month n
(kg C per gallon of feedstock) determined according to 98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month.

    (3) Solid feedstock. You must calculate, from each ammonia
manufacturing unit, the CO2 process emissions from solid
feedstock according to Equation G-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.004

Where:

CO2,S = Annual CO2 emissions arising from
solid feedstock consumption (metric tons).
Fdstkn = Mass of the solid feedstock used in month n (kg
of feedstock).
CCn = Carbon content of the solid feedstock, for month n
(kg C per kg of feedstock), determined according to 98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month.

    (4) Net CO2 process emissions. You must calculate the
annual net CO2 process emissions at each ammonia
manufacturing unit according to Equation G-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.005

Where:

CO2,net = Annual net CO2 process emissions
from each ammonia manufacturing unit (metric tons).
CO2,p = Annual CO2 process emissions arising
from feedstock consumption based on feedstock type ``p'' (metric
tons/yr) as calculated in paragraphs (b)(1) through (3) of this
section.
P = Index for feedstock type; 1 indicates gaseous feedstock; 2
indicates liquid feedstock; and 3 indicates solid feedstock.
CO2,urea,n = Amount of carbon dioxide collected from
ammonia production and consumed on site for urea production, in
month n (metric tons).
MeOHn = Mass of methanol intentionally produced as a
desired product for month n (metric tons).
44/32 = Ratio of molecular weights, CO2 to methanol.
* * * * *
0
20. Amend Sec.  98.76 by revising the introductory text and paragraphs
(b)(1) and (13) to read as follows:

Sec.  98.76  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each
annual report must contain the information specified in paragraphs (a)
and (b) of this section, as applicable for each ammonia manufacturing
unit.
* * * * *
    (b) * * *
    (1) Annual net CO2 process emissions (metric tons) for
each ammonia manufacturing unit.
* * * * *
    (13) Annual amount of CO2 collected from ammonia
production (metric tons) and consumed on site for urea production and
the method used to determine the CO2 consumed in urea
production.
* * * * *
0
21. Amend Sec.  98.77 by revising paragraph (c) introductory text and
adding paragraphs (c)(8) and (9) to read as follows:

Sec.  98.77  Records that must be retained.

* * * * *
    (c) You must keep a record of the file generated by the
verification software specified in Sec.  98.5(b) for the applicable
data specified in paragraphs (c)(1) through (9) of this section.
Retention of this file satisfies the recordkeeping requirement for the
data in paragraphs (c)(1) through (9) of this section.
* * * * *
    (8) Quantity of CO2 collected from ammonia production
and consumed on site for urea production in month (Equation G-4 of
Sec.  98.73).
    (9) Quantity of methanol intentionally produced as a desired
product in month (metric tons) (Equation G-4).

Subpart H--Cement Production

0
22. Amend Sec.  98.83 by:
0
a. Revising paragraph (d)(1);
0
b. Revising parameters ``CKDCaO,'' ``CKDCaO,''
``CKDMgO,'' and ``CKDMgO'' of Equation H-4 in
paragraph (d)(2)(ii)(A); and
0
c. Revising paragraph (d)(3).
    The revisions read as follows:

Sec.  98.83  Calculating GHG emissions.

* * * * *
    (d) * * *
    (1) Calculate CO2 process emissions from all kilns at
the facility using Equation H-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP21JN22.006

Where:

CO2 CMF = Annual process emissions of CO2 from
cement manufacturing, metric tons.
CO2 Cli,m = Total annual emissions of CO2 from
clinker production from kiln m, metric tons.
CO2 rm,m = Total annual emissions of CO2 from
raw materials from kiln m, metric tons.
K = Total number of kilns at a cement manufacturing facility.

    (2) * * *
    (ii) * * *
    (A) * * *

CKDCaO = Quarterly total CaO content of CKD not recycled
to the kiln, wt-fraction.
CKDncCaO = Quarterly non-calcined CaO content of CKD not
recycled to the kiln, wt-fraction.
* * * * *
CKDMgO = Quarterly total MgO content of CKD not recycled
to the kiln, wt-fraction.
CKDncMgO = Quarterly non-calcined MgO content of CKD not
recycled to the kiln, wt-fraction.
* * * * *
    (3) CO2 emissions from raw materials from each kiln. Calculate
CO2 emissions from raw materials using Equation H-5 of this
section:

[GRAPHIC] [TIFF OMITTED] TP21JN22.007

Where:

rm = The amount of raw material i consumed annually from kiln m,
tons/yr (dry basis) or the amount of raw kiln feed consumed annually
from kiln m, tons/yr (dry basis).
CO2,rm,m = Annual CO2 emissions from raw materials from
kiln m.
TOCrm = Organic carbon content of raw material i from
kiln m or organic carbon content of combined raw kiln feed (dry
basis) from kiln m, as determined in Sec.  98.84(c) or using a
default factor of 0.2 percent of total raw material weight.
M = Number of raw materials or 1 if calculating emissions based on
combined raw kiln feed.
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
* * * * *
0
23. Amend Sec.  98.86 by adding paragraphs (a)(4) through (13) and
(b)(19) through (28) to read as follows:

Sec.  98.86  Data reporting requirements.

* * * * *
    (a) * * *
    (4) Annual arithmetic average of total CaO content of clinker at
the facility, wt-fraction.
    (5) Annual arithmetic average of non-calcined CaO content of
clinker at the facility, wt-fraction.
    (6) Annual arithmetic average of total MgO content of clinker at
the facility, wt-fraction.
    (7) Annual arithmetic average of non-calcined MgO content of
clinker at the facility, wt-fraction.
    (8) Annual arithmetic average of total CaO content of CKD not
recycled to the kiln(s) at the facility, wt-fraction.
    (9) Annual arithmetic average of non-calcined CaO content of CKD
not recycled to the kiln(s) at the facility, wt-fraction.
    (10) Annual arithmetic average of total MgO content of CKD not
recycled to the kiln(s) at the facility, wt-fraction.
    (11) Annual arithmetic average of non-calcined MgO content not
recycled to the kiln(s) at the facility, wt-fraction.
    (12) Annual facility CKD not recycled to the kiln(s), tons.
    (13) The amount of raw kiln feed consumed annually at the facility,
tons (dry basis).
    (b) * * *
    (19) Annual arithmetic average of total CaO content of clinker at
the facility, wt-fraction.
    (20) Annual arithmetic average of non-calcined CaO content of
clinker at the facility, wt-fraction.
    (21) Annual arithmetic average of total MgO content of clinker at
the facility, wt-fraction.
    (22) Annual arithmetic average of non-calcined MgO content of
clinker at the facility, wt-fraction.
    (23) Annual arithmetic average of total CaO content of CKD not
recycled to the kiln(s) at the facility, wt-fraction.
    (24) Annual arithmetic average of non-calcined CaO content of CKD
not recycled to the kiln(s) at the facility, wt-fraction.
    (25) Annual arithmetic average of total MgO content of CKD not
recycled to the kiln(s) at the facility, wt-fraction.
    (26) Annual arithmetic average of non-calcined MgO content of CKD
not recycled to the kiln(s) at the facility, wt-fraction.
    (27) Annual facility CKD not recycled to the kiln(s), tons.
    (28) The amount of raw kiln feed consumed annually at the facility,
tons (dry basis).

Subpart I--Electronics Manufacturing

0
24. Amend Sec.  98.91 by revising paragraphs (a) introductory text and
(a)(1) through (3), and parameters ``Ei'' and ``i'' of
Equation I-4 in paragraph (a)(4) to read as follows:

Sec.  98.91  Reporting threshold.

    (a) You must report GHG emissions under this subpart if electronics
manufacturing production processes, as defined in Sec.  98.90, are
performed at your facility and your facility meets the requirements of
either Sec.  98.2(a)(1) or (a)(2). To calculate total annual GHG
emissions for comparison to the 25,000 metric ton CO2e per
year emission threshold in Sec.  98.2(a)(2), follow the requirements of
Sec.  98.2(b), with one exception. Rather than using the calculation
methodologies in Sec.  98.93 to calculate emissions from electronics
manufacturing production processes, calculate emissions of each
fluorinated GHG from electronics manufacturing production processes by
using paragraph (a)(1), (2), or (3) of this section, as appropriate,
and then sum the emissions of each fluorinated GHG and account for
fluorinated heat transfer fluid emissions by using paragraph (a)(4) of
this section.
    (1) If you manufacture semiconductors or MEMS you must calculate
annual production process emissions resulting from the use of each
input gas for threshold applicability purposes using either the default
emission factors shown in Table I-1 to this subpart and Equation I-1A
of this subpart, or the consumption of each input gas, the default
emission factors shown in Table I-2 to this subpart, and Equation I-1B
of this subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.008

Where:

Ei = Annual production process emissions of gas i for
threshold applicability purposes (metric tons CO2e).
S = 100 percent of annual manufacturing capacity of a facility as
calculated using Equation I-5 of this subpart (m\2\).
EFi = Emission factor for gas i (kg/m\2\) shown in Table
I-1 to this subpart.
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Emitted gas.
[GRAPHIC] [TIFF OMITTED] TP21JN22.009

Ei = Annual production process emissions resulting from
the use of input gas i for threshold applicability purposes (metric
tons CO2e).
Ci = Annual GHG (input gas i) purchases or consumption
(kg). Only gases that are used in semiconductor or MEMS
manufacturing processes listed at Sec.  98.90(a)(1) through (a)(4)
must be considered for threshold applicability purposes.
(1-Ui), BCF4, and BC2F6
= Default emission factors for the gas consumption-based

threshold applicability determination listed in Table I-2 to this
subpart.
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.

    (2) If you manufacture LCDs, you must calculate annual production
process emissions resulting from the use of each input gas for
threshold applicability purposes using either the default emission
factors shown in Table I-1 to this subpart and Equation I-2 of this
subpart or the consumption of each input gas, the default emission
factors shown in Table I-2 to this subpart, and Equation I-1B of this
subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.010

Where:

Ei = Annual production process emissions of gas i for
threshold applicability purposes (metric tons CO2e).
S = 100 percent of annual manufacturing capacity of a facility as
calculated using Equation I-5 of this subpart (m\2\).
EFi = Emission factor for gas i (g/m\2\).
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.000001 = Conversion factor from g to metric tons.
i = Emitted gas.
[GRAPHIC] [TIFF OMITTED] TP21JN22.011

Where:

Ei = Annual production process emissions resulting from
the use of input gas i for threshold applicability purposes (metric
tons CO2e).
Ci = Annual GHG (input gas i) purchases or consumption
(kg). Only gases that are used in LCD manufacturing processes listed
at Sec.  98.90(a)(1) through (a)(4) must be considered for threshold
applicability purposes.
(1-Ui), BCF4, and BC2F6
= Default emission factors for the gas consumption-based threshold
applicability determination listed in Table I-2 to this subpart.
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.

    (3) If you manufacture PVs, you must calculate annual production
process emissions resulting from the use of each input gas i for
threshold applicability purposes using gas-appropriate GWP values shown
in Table A-1 to subpart A of this part, the default emission factors
shown in Table I-2 to this subpart, and Equation I-3 of this subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.012

Where:

Ei = Annual production process emissions resulting from
the use of input gas i for threshold applicability purposes (metric
tons CO2e).
Ci = Annual fluorinated GHG (input gas i) purchases or
consumption (kg). Only gases that are used in PV manufacturing
processes listed at Sec.  98.90(a)(1) through (a)(4) must be
considered for threshold applicability purposes.
(1-Ui), BCF4, and BC2F6
= Default emission factors for the gas consumption-based threshold
applicability determination listed in Table I-2 to this subpart.
GWPi = Gas-appropriate GWP as provided in Table A-1 to
subpart A of this part.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.

    (4) * * *

Ei = Annual production process emissions of gas i for
threshold applicability purposes (metric tons CO2e), as
calculated in Equations I-1a, I-1b, I-2a, I-2b, or I-3 of this
subpart.
i = Emitted gas.
* * * * *
0
25. Amend Sec.  98.92 by revising paragraph (a) to read as follows:

Sec.  98.92  GHGs to report.

    (a) You must report emissions of fluorinated GHGs (as defined in
Sec.  98.6), N2O, and fluorinated heat transfer fluids (as
defined in Sec.  98.98). The fluorinated GHGs and fluorinated heat
transfer fluids that are emitted from electronics manufacturing
production processes include, but are not limited to, those listed in
Table I-21 to this subpart. You must individually report, as
appropriate:
* * * * *
0
26. Amend Sec.  98.93 by:
0
a. Revising paragraph (a)(1) introductory text;
0
b. Revising parameters ``Eij'' and ``N'' of Equation I-6 in
paragraph (a)(1) introductory text;
0
c. Revising Equation I-7 in paragraph (a)(1) introductory text;
0
d. Revising parameters ``BEijk'' and ``N'' of Equation I-7
in paragraph (a)(1) introductory text;
0
e. Revising paragraphs (a)(1)(i) and (ii) and (a)(2) and (6);
0
f. Adding paragraph (a)(7);
0
g. Revising the introductory text of paragraphs (e) and (i);
0
h. Removing and reserving paragraphs (i)(1) and (2);
0
i. Revising paragraph (i)(3) introductory text and (i)(3)(i), (iii)
through (vi), and (viii)).
0
j. Adding paragraph (i)(3)(ix);
0
k. Revising paragraph (i)(4); and
0
l. Removing paragraph (i)(5).
    The revisions and additions read as follows:

Sec.  98.93  Calculating GHG emissions.

    (a) * * *
    (1) If you manufacture semiconductors, you must adhere to the
procedures in paragraphs (a)(1)(i) through (iii) of this section. You
must calculate annual emissions of each input gas and of each by-
product gas using Equations I-6, I-7, and I-9 of this subpart. If your
fab uses less than 50 kg of a fluorinated GHG in one reporting year,
you may calculate emissions as equal to your fab's annual consumption
for that specific gas as calculated in Equation I-11 of this subpart,
plus any by-product emissions of that gas calculated under paragraph
(a) of this section.
* * * * *
Eij = Annual emissions of input gas i from process sub-
type or process type j as calculated in Equation I-8A of this
subpart (metric tons).
N = The total number of process sub-types j that depends on the
electronics manufacturing fab and emission calculation methodology.
If Eij is calculated for a process type j in Equation I-
8A of this subpart, N = 1.
* * * * *

[GRAPHIC] [TIFF OMITTED] TP21JN22.013

* * * * *
BEkij = Annual emissions of by-product gas k formed from
input gas i used for process sub-type or process type j as
calculated in Equation I-8B of this subpart (metric tons).
N = The total number of process sub-types j that depends on the
electronics manufacturing fab and emission calculation methodology.
If BEkij is calculated for a process type j in Equation
I-8B of this subpart, N = 1.
* * * * *
    (i) You must calculate annual fab-level emissions of each
fluorinated GHG used for the plasma etching/wafer cleaning process type
using default utilization and by-product formation rates as shown in
Table I-3 or I-4 of this subpart, and by using Equations I-8A and I-8B
of this subpart.
[GRAPHIC] [TIFF OMITTED] TP21JN22.014

Where:

Eij = Annual emissions of input gas i from process sub-
type or process type j, on a fab basis (metric tons).
Cij = Amount of input gas i consumed for process sub-type
or process type j, as calculated in Equation I-13 of this subpart,
on a fab basis (kg).
Uij = Process utilization rate for input gas i for
process sub-type or process type j (expressed as a decimal
fraction).
Aij = Fraction of input gas i used in process sub-type or
process type j with abatement systems, on a fab basis (expressed as
a decimal fraction).
Dij = Fraction of input gas i destroyed or removed when
fed into abatement systems by process tools where process sub-type,
or process type j is used, on a fab basis, calculated by taking the
tool weighted average of the claimed DREs for input gas on i on
tools that use process type or process sub-type j (expressed as a
decimal fraction). This is zero unless the facility adheres to the
requirements in Sec.  98.94(f).
UTij = The average uptime factor of all abatement systems
connected to process tools in the fab using input gas i in process
sub-type or process type j, as calculated in Equation I-15 of this
subpart, on a fab basis (expressed as a decimal fraction).
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
j = Process sub-type or process type.
[GRAPHIC] [TIFF OMITTED] TP21JN22.015

Where:

BEkij = Annual emissions of by-product gas k formed from
input gas I from process sub-type or process type j, on a fab basis
(metric tons).
Bijk = By-product formation rate of gas k created as a
by-product per amount of input gas i (kg) consumed by process sub-
type or process type j (kg). For non-carbon containing input gases
used in chamber cleaning process sub-types, this is zero when the
combination of input gas and chamber cleaning process sub-type is
never used to clean chamber walls on equipment that process carbon-
containing films during the year (e.g., when NF3 is used
in remote plasma cleaning processes to only clean chambers that
never process carbon-containing films during the year).
Cij = Amount of input gas i consumed for process sub-
type, or process type j, as calculated in Equation I-13 of this
subpart, on a fab basis (kg).
akij = Fraction of input gas I used for process sub-type,
or process type j with abatement systems, on a fab basis (expressed
as a decimal fraction).
Dkij = Fraction of by-product gas k destroyed or removed
in when fed into abatement systems by process tools where process
sub-type or process type j is used, on a fab basis, calculated by
taking the tool weighted average of the claimed DREs for by-product
gas k on tools that use input gas i in process type or process sub-
type j (expressed as a decimal fraction). This is zero unless the
facility adheres to the requirements in Sec.  98.94(f).
UTkij = The average uptime factor of all abatement
systems connected to process tools in the fab emitting by-product
gas k, formed from input gas I in process sub-type or process type
j, on a fab basis (expressed as a decimal fraction). For this
equation, UTkij is assumed to be equal to UTij
as calculated in Equation I-15 of this subpart.
0.001 = Conversion factor from kg to metric tons.
i = Input gas.
j = Process sub-type or process type.
k = By-product gas.

    (ii) You must calculate annual fab-level emissions of each
fluorinated GHG used for each of the process sub-types associated with
the chamber cleaning process type, including in-situ plasma chamber
clean, remote plasma chamber clean, and in-situ thermal chamber clean,
using default utilization and by-product formation rates as shown in
Table I-3 or I-4 of this subpart, and by using Equations I-8A and I-8B
of this subpart.
* * * * *
    (2) If you manufacture MEMS or PVs and use semiconductor tools and
processes, you may use Sec.  98.3(a)(1) to calculate annual fab-level
emissions for those processes. For all other tools and processes used
to manufacture MEMs, LCD and PV, you must calculate annual fab-level
emissions of each fluorinated GHG used for the plasma etching and
chamber cleaning process types using default utilization and by-product
formation rates as shown in Table I-5, I-6, or I-7 of this subpart, as
appropriate, and by using Equations I-8A and I-8B of this subpart. If
default values are not available for a particular input gas and process
type or sub-type combination in Tables I-5, I-6, or I-7, you must
follow the procedures in paragraph (a)(6) of this section. If your fab
uses less than 50 kg of a fluorinated GHG in one reporting year, you
may calculate emissions as equal to your fab's annual consumption for
that specific gas as calculated in Equation I-11 of this subpart, plus
any by-product emissions of that gas calculated under this paragraph
(a).
* * * * *
    (6) If you are required, or elect, to perform calculations using
default emission factors for gas utilization and by-product formation
rates according to the procedures in paragraph (a)(1) or (a)(2) of this
section, and default values are not available for a particular input
gas and process type or sub-type combination in Tables I-3, I-4, I-5,
I-6, or I-7, you must use a utilization rate (Uij) of 0.2
(i.e., a 1-Uij of 0.8) and by-product formation rates of
0.15 for CF4 and 0.05 for C2F6 and use
Equations I-8A and I-8B of this subpart.

    (7) If your fab employs hydrocarbon-fuel-based emissions control
systems (including, but not limited to, abatement systems as defined at
Sec.  98.98) to control emissions from tools that use either
NF3 in remote plasma cleaning processes or F2 as
an input gas in any process type or sub-type, you must calculate the
amount CF4 produced within and emitted from such systems
using Equation I-9 using default utilization and by-product formation
rates as shown in Table I-3 or I-4 of this subpart. A hydrocarbon-fuel-
based emissions control system is assumed not to form CF4
from F2 if the electronics manufacturer can certify that the
rate of conversion from F2 to CF4 is <0.1% for
that hydrocarbon-fuel-based emissions control system.
[GRAPHIC] [TIFF OMITTED] TP21JN22.016

Where:

EABCF4 = Emissions of CF4 from hydrocarbon-
fuel-based emissions control systems when direct reaction between
hydrocarbon fuel and F2 is not certified not to occur by
the emissions control system manufacturer or electronics
manufacturer, kg.
CF2,j = Amount of F2 consumed for process type
or sub-type j, as calculated in Equation I-13 of this subpart, on a
fab basis (kg).
UF2,j = Process utilization rate for F2 for
process type or sub-type j (expressed as a decimal fraction).
AF2,j = Within process sub-type or process type j,
fraction of F2 used in process tools with hydrocarbon-
fuel-based abatement systems that are not certified not to form
CF4, on a fab basis, where the numerator is the number of
tools that are equipped with hydrocarbon-fuel-based emissions
control systems that are not certified not to form CF4
that use F2 in process type j and the denominator is the
total number of tools in the fab that use F2 in process
type j (expressed as a decimal fraction).
UTF2,j = The average uptime factor of all abatement
systems connected to process tools in the fab using F2 in process
sub-type or process type j (expressed as a decimal fraction).
ABCF4,F2 = Mass fraction of F2 in process
exhaust gas that is converted into CF4 by direct reaction
with hydrocarbon fuel in a combustion abatement system. The default
value of ABCF4,F2=0.116.
CNF3,RPC = Amount of NF3 consumed in remote
plasma cleaning processes, as calculated in Equation I-13 of this
subpart, on a fab basis (kg).
BF2, NF3 = By-product formation rate of F2
created as a by-product per amount of NF3 (kg) consumed
in remote plasma cleaning processes (kg).
aNF3,RPC = Within remote plasma cleaning processes,
fraction of NF3 used in process tools with hydrocarbon-
fuel-based abatement systems that are not certified not to form
CF4, where the numerator is the number of tools running
remote plasma cleaning processes that are equipped with hydrocarbon-
fuel-based emissions control systems that are not certified not to
form CF4 that use NF3 and the denominator is
the total number of tools that run remote plasma clean processes in
the fab that use NF3 (expressed as decimal fraction).
UTNF3,RPC,F2 = The average uptime factor of all abatement
systems connected to process tools in the fab emitting by-product
gas F2, formed from input gas NF3 in remote
plasma cleaning processes, on a fab basis (expressed as a decimal
fraction). For this equation, UTNF3,RPC,F2 is assumed to
be equal to UTNF3,RPC as calculated in Equation I-15 of
this subpart.
j = Process type or sub-type.
* * * * *
    (e) You must calculate the amount of input gas i consumed, on a fab
basis, for each process sub-type or process type j, using Equation I-13
of this subpart. Where a gas supply system serves more than one fab,
Equation I-13 is applied to that gas which has been apportioned to each
fab served by that system using the apportioning factors determined in
accordance with Sec.  98.94(c). If you elect to calculate emissions
using the stack test method in paragraph (i) of this section and to use
this paragraph to calculate the fraction each fluorinated input gas i
exhausted from tools with abatement systems and the fraction of each
by-product gas k exhausted from tools with abatement systems, you may
substitute ``The set of tools with abatement systems'' for ``Process
sub-type or process type'' in the definition of ``j'' in Equation I-13
of this subpart.
* * * * *
    (i) Stack Test Method. As an alternative to the default emission
factor method in paragraph (a) of this section, you may calculate fab-
level fluorinated GHG emissions using fab-specific emission factors
developed from stack testing. In this case, you must comply with the
stack test method specified in paragraph (i)(3) of this section.
    (1)-(2) [Reserved]
    (3) Stack system stack test method. For each stack system in the
fab, measure the emissions of each fluorinated GHG from the stack
system by conducting an emission test. In addition, measure the fab-
specific consumption of each fluorinated GHG by the tools that are
vented to the stack systems tested. Measure emissions and consumption
of each fluorinated GHG as specified in Sec.  98.94(j). Develop fab-
specific emission factors and calculate fab-level fluorinated GHG
emissions using the procedures specified in paragraph (i)(3)(i) through
(viii) of this section. All emissions test data and procedures used in
developing emission factors must be documented and recorded according
to Sec.  98.97.
    (i) You must measure the fab-specific fluorinated GHG consumption
of the tools that are vented to the stack systems during the emission
test as specified in Sec.  98.94(j)(3). Calculate the consumption for
each fluorinated GHG for the test period.
* * * * *
    (iii) You must calculate a fab-specific emission factor for each
fluorinated GHG input gas consumed (in kg of fluorinated GHG emitted
per kg of input gas i consumed) in the tools that vent to stack
systems, as applicable, using Equations I-19A and I-19B or I-19A and I-
19c of this subpart. Use Equation I-19A to calculate the controlled
emissions for each fluorinated GHG that would result during the
sampling period if the utilization rate for the input gas were equal to
0.2 (Eimax,f). If [sum]sEi,s (the
total measured emissions of the fluorinated GHG across all stack
systems, calculated based on the results of Equation I-17) is less than
or equal to Eimax,f calculated in I-19A, use Equation I-19B
to calculate the emission factor for that fluorinated GHG. If
[sum]sEi,s is larger than the Eimax,f
calculated in I-19A, use Equation I-19C to calculate the emission
factor and treat the difference between the total measured emissions
[sum]sEi,s and the maximum expected controlled
emissions Eimax,f as a by-product of the other input gases,
using Equation I-20 of this subpart.

[GRAPHIC] [TIFF OMITTED] TP21JN22.017

Where:

Eimax,f = Maximum expected controlled emissions of gas i
from its use an input gas during the stack testing period, from fab
f (max kg emitted).
Activityif = Consumption of fluorinated GHG input gas i,
for fab f, in the tools vented to the stack systems being tested,
during the sampling period, as determined following the procedures
specified in Sec.  98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab
f, during the sampling period, as calculated in Equation I-23 of
this subpart (expressed as decimal fraction). If the stack system
does not have abatement systems on the tools vented to the stack
system, the value of this parameter is zero.
aif = Fraction of input gas i emitted from tools with
abatement systems in fab f (expressed as a decimal fraction), as
calculated in Equation I-24C.
dif = Fraction of fluorinated GHG input gas i destroyed
or removed when fed into abatement systems by process tools in fab
f, as calculated in Equation I-24A of this subpart (expressed as
decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
[GRAPHIC] [TIFF OMITTED] TP21JN22.018

Where:

EFif = Emission factor for fluorinated GHG input gas i,
from fab f, representing 100 percent abatement system uptime (kg
emitted/kg input gas consumed).
Eis = Mass emission of fluorinated GHG input gas i from
stack system s during the sampling period (kg emitted).
Activityif = Consumption of fluorinated GHG input gas i,
for fab f during the sampling period, as determined following the
procedures specified in Sec.  98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab
f, during the sampling period, as calculated in Equation I-23 of
this subpart (expressed as decimal fraction). If the stack system
does not have abatement systems on the tools vented to the stack
system, the value of this parameter is zero.
aif = Fraction of fluorinated GHG input gas i exhausted
from tools with abatement systems in fab f (expressed as a decimal
fraction), as calculated in Equation I-24C.
dif = Fraction of fluorinated GHG input gas i destroyed
or removed when fed into abatement systems by process tools in fab
f, as calculated in Equation I-24A of this subpart (expressed as
decimal fraction). If the stack system does not have abatement
systems on the tools vented to the stack system, the value of this
parameter is zero.
f = Fab.
i = Fluorinated GHG input gas.
s = Stack system.
[GRAPHIC] [TIFF OMITTED] TP21JN22.019

EFif = Emission factor for input gas i, from fab f,
representing a 20-percent utilization rate and a 100-percent
abatement system uptime (kg emitted/kg input gas consumed).
aif = Fraction of input gas i emitted from tools with
abatement systems in fab f (expressed as a decimal fraction), as
calculated in Equation I-24C.
dif = Fraction of fluorinated GHG input gas i destroyed
or removed when fed into abatement systems by process tools in fab
f, as calculated in Equation I-24A of this subpart (expressed as
decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.

    (iv) You must calculate a fab-specific emission factor for each
fluorinated GHG formed as a by-product (in kg of fluorinated GHG per kg
of total fluorinated GHG consumed) in the tools vented to stack
systems, as applicable, using Equation I-20 of this subpart. When
calculating the by-product emission factor for an input gas for which
[sum]sEi,s equals or exceeds Eimax,f,
exclude the consumption of that input gas from the term
``[sum](Activityif).''
[GRAPHIC] [TIFF OMITTED] TP21JN22.020

Where:

EFkf = Emission factor for fluorinated GHG by-product gas
k, from fab f, representing 100 percent abatement system uptime (kg
emitted/kg of all input gases consumed in tools vented to stack
systems).
Eks = Mass emission of fluorinated GHG by-product gas k,
emitted from stack system s, during the sampling period (kg
emitted).
Activityif = Consumption of fluorinated GHG input gas i
for fab f in tools vented to stack systems during the sampling
period as determined following the procedures specified in Sec.
98.94(j)(3) (kg consumed).
UTf = The total uptime of all abatement systems for fab
f, during the sampling period, as calculated in Equation I-23 of
this subpart (expressed as decimal fraction).
akif = Fraction of by-product k emitted from tools using
input gas i with abatement systems in fab f (expressed as a decimal
fraction), as calculated using Equation I-24D.
dkif = Fraction of fluorinated GHG by-product gas k
generated from input gas i destroyed or removed when fed into
abatement systems by process tools in fab f, as calculated in
Equation I-24B of this subpart (expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
k = Fluorinated GHG by-product gas.
s = Stack system.

    (v) You must calculate annual fab-level emissions of each
fluorinated GHG consumed using Equation I-21 of this section.

[GRAPHIC] [TIFF OMITTED] TP21JN22.021

Where:

Eif = Annual emissions of fluorinated GHG input gas i
(kg/year) from the stack systems for fab f.
EFif = Emission factor for fluorinated GHG input gas i
emitted from fab f, as calculated in Equation I-19 of this subpart
(kg emitted/kg input gas consumed).
Cif = Total consumption of fluorinated GHG input gas i in
tools that are vented to stack systems, for fab f, for the reporting
year, as calculated using Equation I-13 of this subpart (kg/year).
UTf = The total uptime of all abatement systems for fab
f, during the reporting year, as calculated using Equation I-23 of
this subpart (expressed as a decimal fraction).
aif = Fraction of fluorinated GHG input gas i emitted
from tools with abatement systems in fab f (expressed as a decimal
fraction), as calculated using Equation I-24C or I-24D.
dif = Fraction of fluorinated GHG input gas i destroyed
or removed when fed into abatement systems by process tools in fab f
that are included in the stack testing option, as calculated in
Equation I-24A of this subpart (expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.

    (vi) You must calculate annual fab-level emissions of each
fluorinated GHG by-product formed using Equation I-22 of this section.
[GRAPHIC] [TIFF OMITTED] TP21JN22.022

Where:

Ekf = Annual emissions of fluorinated GHG by-product gas
k (kg/year) from the stack for fab f.
EFkf = Emission factor for fluorinated GHG by-product gas
k, emitted from fab f, as calculated in Equation I-20 of this
subpart (kg emitted/kg of all fluorinated input gases consumed).
Cif = Total consumption of fluorinated GHG input gas i in
tools that are vented to stack systems, for fab f, for the reporting
year, as calculated using Equation I-13 of this subpart.
UTf = The total uptime of all abatement systems for fab
f, during the reporting year as calculated using Equation I-23 of
this subpart (expressed as a decimal fraction).
akif = Estimate of fraction of fluorinated GHG by-product
gas k emitted in fab f from tools using input gas i with abatement
systems (expressed as a decimal fraction), as calculated using
Equation I-24D.
dkif = Fraction of fluorinated GHG by-product k generated
from input gas i destroyed or removed when fed into abatement
systems by process tools in fab f that are included in the stack
testing option, as calculated in Equation I-24B of this subpart
(expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
k = Fluorinated GHG by-product
* * * * *
    (viii) When using the stack testing option described in paragraph
(i) of this section and when using more than one DRE for the same input
gas i or by-product gas k, you must calculate the weighted-average
fraction of each fluorinated input gas i and each fluorinated by-
product gas k that has more than one DRE and that is destroyed or
removed in abatement systems for each fab f, as applicable, by using
Equation I-24A (for input gases) and Equation I-24B (for by-product
gases) of this subpart and Table I-18 of this subpart. If default
values are not available in Table I-18 for a particular input gas, you
must use a value of 10.
[GRAPHIC] [TIFF OMITTED] TP21JN22.023

[GRAPHIC] [TIFF OMITTED] TP21JN22.024

Where:

dif = The average weighted fraction of fluorinated GHG
input gas i destroyed or removed when fed into abatement systems by
process tools in fab f (expressed as a decimal fraction).
dkif = The average weighted fraction of fluorinated GHG
by-product gas k generated from input gas i that is destroyed or
removed when fed into abatement systems by process tools in fab f
(expressed as a decimal fraction).
ni,p,DREy = Number of tools that use gas i, that run
chamber cleaning process p, and that are equipped with abatement
systems for gas i that have the DRE DREy.
mi,q,DREz = Number of tools that use gas i, that run etch
and/or wafer cleaning processes, and that are equipped with
abatement systems for gas i that have the DRE DREz.
ni,p,a = Total number of tools that use gas i, run
chamber cleaning process type p, and that are equipped with
abatement systems for gas i.
mi,q,a = Total number of tools that use gas i, run etch
and/or wafer cleaning processes, and that are equipped with
abatement systems for gas i.
nk,i,p,DREy = Number of tools that use gas i, generate
by-product k, that run chamber cleaning process p, and that are
equipped with abatement systems for gas i that have the DRE DREy.
mk,i,q,DREz = Number of tools that use gas i, generate
by-product k, that run etch and/or wafer cleaning processes, and
that are equipped with abatement systems for gas i that have the DRE
DREz.
nk,i,p,a = Total number of tools that use gas i, generate
by-product k, run chamber cleaning process type p, and that are
equipped with abatement systems for gas i.
mk,i,q,a = Total number of tools that use gas i, generate
by-product k, run etch and/or wafer cleaning processes, and that are
equipped with abatement systems for gas i.
[gamma]i,p = Default factor reflecting the ratio of
uncontrolled emissions per tool of input gas i from tools running
process sub-type p processes to uncontrolled emissions per tool of
input gas i from process tools running process type q processes.
[gamma]k,i,p = Default factor reflecting the ratio of
uncontrolled emissions per tool of input gas i from tools running
process sub-type p processes to uncontrolled emissions

per tool of input gas i from process tools running process type q
processes.
DREy = Default or alternative certified DRE for gas i for
abatement systems connected to CVD tool.
DREz = Default or alternative certified DRE for gas i for
abatement systems connected to etching and/or wafer cleaning tool.
p = Chamber cleaning process sub-type.
q = Reference process type. There is one process type q that
consists of the combination of etching and/or wafer cleaning
processes.
f = Fab.
i = Fluorinated GHG input gas.

    (ix) When using the stack testing method described in this
paragraph (i), you must calculate the fraction each fluorinated input
gas i exhausted in fab f from tools with abatement systems and the
fraction of each by-product gas k exhausted from tools with abatement
systems, as applicable, by following either the procedure set forth in
paragraph (i)(3)(ix)(A) of this section or the procedure set forth in
paragraph (i)(3)(ix)(B) of this section.
    (A) Use Equation I-24C (for input gases) and Equation I-24D (for
by-product gases) and Table I-18 of this subpart. If default values are
not available in Table I-18 for a particular input gas, you must use a
value of 10.
[GRAPHIC] [TIFF OMITTED] TP21JN22.025

Where:

aif = Fraction of fluorinated input gas i exhausted from
tools with abatement systems in fab f (expressed as a decimal
fraction).
ni,p,a = Number of tools that use gas i, that run chamber
cleaning process sub-type p, and that are equipped with abatement
systems for gas i.
mi,q,a = Number of tools that use gas i, that run etch
and/or wafer cleaning processes, and that are equipped with
abatement systems for gas i.
ni,p = Total number of tools using gas i and running
chamber cleaning process sub-type p.
mi,q = Total number of tools using gas i and running etch
and/or wafer cleaning processes.
[gamma]i,p = Default factor reflecting the ratio of
uncontrolled emissions per tool of input gas i from tools running
process type p processes to uncontrolled emissions per tool of input
gas i from process tools running process type q processes.
p = Chamber cleaning process sub-type.
q = Reference process type. There is one process type q that
consists of the combination of etching and/or wafer cleaning
processes.
[GRAPHIC] [TIFF OMITTED] TP21JN22.026

Where:

ak,i,f = Fraction of by-product gas k exhausted from
tools using input gas i with abatement systems in fab f (expressed
as a decimal fraction).
nk,i,p,a = Number of tools that exhaust by-product gas k
from input gas i, that run chamber cleaning process p, and that are
equipped with abatement systems for gas k.
mk,i,q,a = Number of tools that exhaust by-product gas k
from input gas i, that run etch and/or wafer cleaning processes, and
that are equipped with abatement systems for gas k.
nk,i,p = Total number of tools emitting by-product k from
input gas i and running chamber cleaning process p.
mk,i,q = Total number of tools emitting by-product k from
input gas i and running etch and/or wafer cleaning processes.
[gamma]k,i,p = Default factor reflecting the ratio of
uncontrolled emissions per tool of by-product gas k from input gas i
from tools running chamber cleaning process p to uncontrolled
emissions per tool of by-product gas k from input gas i from process
tools running etch and/or wafer cleaning processes.
p = Chamber cleaning process sub-type.
q = Reference process type. There is one process type q that
consists of the combination of etching and/or wafer cleaning
processes.

    (B) Use paragraph (e) of this section to apportion consumption of
gas i either to tools with abatement systems and tools without
abatement systems or to each process type or sub-type, as applicable.
If you apportion consumption of gas i to each process type or sub-type,
calculate the fractions of input gas i and by-product gas k formed from
gas i that are exhausted from tools with abatement systems based on the
numbers of tools with and without abatement systems within each process
type or sub-type.
    (4) Method to calculate emissions from fluorinated GHGs that are
not tested. Calculate emissions from consumption of each intermittent
low-use fluorinated GHG as defined in Sec.  98.98 of this subpart using
the default utilization and by-product formation rates provided in
Table I-11, I-12, I-13, I-14, or I-15 of this subpart, as applicable,
and by using Equations I-8A, I-8B, I-9, and I-13 of this subpart. If a
fluorinated GHG was not being used during the stack testing and does
not meet the definition of intermittent low-use fluorinated GHG in
Sec.  98.98, then you must test the stack systems associated with the
use of that fluorinated GHG at a time when that gas is in use at a
magnitude that would allow you to determine an emission factor for that
gas according to the procedures specified in paragraph (i)(3) of this
section.
0
27. Amend Sec.  98.94 by revising paragraphs (c) introductory text,
(e), (f)(3), (f)(4) introductory text, (f)(4)(iii), (j)(1) introductory
text, (j)(1)(i), (j)(3) introductory text, (j)(5)(i), and (j)(5)(ii)
introductory text and by removing and reserving paragraphs (j)(6) and
(j)(8)(v).
    The revisions read as follows:

Sec.  98.94  Monitoring and QA/QC requirements.

* * * * *
    (c) You must develop apportioning factors for fluorinated GHG and
N2O consumption (including the fraction of gas consumed by
process tools connected to abatement systems as in Equations I-8A, I-
8B, I-9, and I-10 of this subpart), to use in the equations of this
subpart for each input gas i, process sub-type, process type, stack
system, and fab as appropriate, using a fab-specific engineering model
that is documented in your site GHG Monitoring Plan as required under
Sec.  98.3(g)(5). This model must be based on a quantifiable metric,
such as wafer passes or wafer starts, or direct measurement of input
gas consumption as specified in paragraph (c)(3) of this section. To
verify your model, you must demonstrate its precision and accuracy by
adhering to the requirements in paragraphs (c)(1) and (2) of this
section.
* * * * *
    (e) If you use hydrocarbon-fuel-based emissions control systems to
control

emissions from tools that use either NF3 as an input gas in
remote plasma cleaning processes or F2 as an input gas in
any process, and if you use a value less than 1 for either
aF2,j or aNF3,RPC in Equation I-9, you must
certify and document that the model for each of the systems for which
you are claiming that it does not form CF4 from
F2 has been tested and verified to produce less than 0.1%
CF4 from F2 and that each of the systems is
installed, operated, and maintained in accordance with the directions
of the emissions control system manufacturer. Hydrocarbon-fuel-based
emissions control systems include but are not limited to abatement
systems as defined in Sec.  98.98 that are hydrocarbon-fuel-based. The
rate of conversion from F2 to CF4 must be
measured using a scientifically sound, industry-accepted method that
accounts for dilution through the abatement device, such as EPA 430-R-
10-003, adjusted to calculate the rate of conversion from F2
to CF4 rather than the DRE. Either the hydrocarbon-fuel-
based emissions control system manufacturer or the electronics
manufacturer may perform the measurement. The flow rate of
F2 into the tested emissions control system(s) may be
metered using a calibrated mass flow controller.
    (f) * * *
    (3) If you use default destruction and removal efficiency values in
your emissions calculations under Sec.  98.93(a), (b), and/or (i), you
must certify and document that the abatement systems at your facility
for which you use default destruction or removal efficiency values are
specifically designed for fluorinated GHG or N2O abatement,
as applicable, and that the abatement system has been tested by the
abatement system manufacturer based on the methods specified in
paragraph (f)(3)(i) of this section and verified to meet (or exceed)
the default destruction or removal efficiency in Table I-16 for the
fluorinated GHG or N2O under worst-case flow conditions as
defined in paragraph (f)(3)(ii) of this section. If you use a verified
destruction and removal efficiency value that is lower than the default
in Table I-16 in your emissions calculations under Sec.  98.93(a), (b),
and/or (i), you must certify and document that the abatement systems at
your facility for which you use the verified destruction or removal
efficiency values are specifically designed for fluorinated GHG or
N2O abatement, as applicable, and that the abatement system
has been tested by the abatement system manufacturer based on the
methods specified in paragraph (f)(3)(i) of this section and verified
to meet or exceed the destruction or removal efficiency value used for
that fluorinated GHG or N2O under worst-case flow conditions
as defined in paragraph (f)(3)(ii) of this section. If you elect to
calculate fluorinated GHG emissions using the stack test method under
Sec.  98.93(i), you must also certify that you have included and
accounted for all abatement systems designed for fluorinated GHG
abatement and any respective downtime in your emissions calculations
under Sec.  98.93(i)(3).
    (i) For purposes of paragraph (f)(3) of this section, destruction
and removal efficiencies must be measured using a scientifically sound,
industry-accepted measurement methodology that accounts for dilution
through the abatement system, such as EPA 430-R-10-003 (incorporated by
reference, see Sec.  98.7).
    (ii) Worst-case flow conditions are defined as the highest total
fluorinated GHG or N2O flows through each model of emissions
control systems (gas by gas and process type by process type across the
facility) and the highest total flow scenarios (with N2
dilution accounted for) across the facility during which the abatement
system is claimed to be operational.
    (4) If you calculate and report controlled emissions using neither
the default destruction or removal efficiency values in Table I-16 of
this subpart nor a manufacturer verified lower destruction or removal
efficiency values per paragraph (f)(3) of this section, you must use an
average of properly measured destruction or removal efficiencies for
each gas and process sub-type or process type combination, as
applicable, determined in accordance with procedures in paragraphs
(f)(4)(i) through (vi) of this section. This includes situations in
which your fab employs abatement systems not specifically designed for
fluorinated GHG or N2O abatement and you elect to reflect
emission reductions due to these systems. You must not use a default
value from Table I-16 of this subpart for any abatement system not
specifically designed for fluorinated GHG and N2O abatement,
for any abatement system not certified to meet the default value from
Table I-16, or for any gas and process type combination for which you
have measured the destruction or removal efficiency according to the
requirements of paragraphs (f)(4)(i) through (vi) of this section.
* * * * *
    (iii) If you elect to take credit for abatement system destruction
or removal efficiency before completing testing on 20 percent of the
abatement systems for that gas and process sub-type or process type
combination, as applicable, you must use default destruction or removal
efficiencies or a verified destruction or removal efficiency, if
verified at a lower value, for a gas and process type combination. You
must not use a default value from Table I-16 of this subpart for any
abatement system not specifically designed for fluorinated GHG and
N2O abatement, and must not take credit for abatement system
destruction or removal efficiency before completing testing on 20
percent of the abatement systems for that gas and process sub-type or
process type combination, as applicable. Following testing on 20
percent of abatement systems for that gas and process sub-type or
process type combination, you must calculate the average destruction or
removal efficiency as the arithmetic mean of all test results for that
gas and process sub-type or process type combination, until you have
tested at least 30 percent of all abatement systems for each gas and
process sub-type or process type combination. After testing at least 30
percent of all systems for a gas and process sub-type or process type
combination, you must use the arithmetic mean of the most recent 30
percent of systems tested as the average destruction or removal
efficiency. You may include results of testing conducted on or after
January 1, 2011 for use in determining the site-specific destruction or
removal efficiency for a given gas and process sub-type or process type
combination if the testing was conducted in accordance with the
requirements of paragraph (f)(4)(i) of this section.
* * * * *
    (j) * * *
    (1) Stack system testing. Conduct an emissions test for each stack
system according to the procedures in paragraphs (j)(1)(i) through (iv)
of this section.
    (i) You must conduct an emission test during which the fab is
operating at a representative operating level, as defined in Sec.
98.98, and with the abatement systems connected to the stack system
being tested operating with at least 90 percent uptime, averaged over
all abatement systems, during the 8-hour (or longer) period for each
stack system, or at no less than 90 percent of the abatement system
uptime rate measured over the previous reporting year, averaged over
all abatement systems. Hydrocarbon-fuel-based emissions control systems
that are not certified not to form CF4 must operate

with at least 90 percent uptime during the test.
* * * * *
    (3) Fab-specific fluorinated GHG consumption measurements. You must
determine the amount of each fluorinated GHG consumed by each fab
during the sampling period for all process tools connected to the stack
systems under Sec.  98.93(i)(3), according to the procedures in
paragraphs (j)(3)(i) and (ii) of this section.
* * * * *
    (5) * * *
    (i) Annual testing. You must conduct an annual emissions test for
each stack system unless you meet the criteria in paragraph (j)(5)(ii)
of this section to skip annual testing. Each set of emissions testing
for a stack system must be separated by a period of at least 2 months.
    (ii) Criteria to test less frequently. After the first 3 years of
annual testing, you may calculate the relative standard deviation of
the emission factors for each fluorinated GHG included in the test and
use that analysis to determine the frequency of any future testing. As
an alternative, you may conduct all three tests in less than 3 calendar
years for purposes of this paragraph (j)(5)(ii), but this does not
relieve you of the obligation to conduct subsequent annual testing if
you do not meet the criteria to test less frequently. If the criteria
specified in paragraphs (j)(5)(ii)(A) and (B) of this section are met,
you may use the arithmetic average of the three emission factors for
each fluorinated GHG and fluorinated GHG byproduct for the current year