[Federal Register Volume 89, Number 81 (Thursday, April 25, 2024)]
[Rules and Regulations]
[Pages 31802-31959]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2024-07413]
[[Page 31801]]
Vol. 89
Thursday,
No. 81
April 25, 2024
Part II
Environmental Protection Agency
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40 CFR Parts 9 and 98
Revisions and Confidentiality Determinations for Data Elements Under
the Greenhouse Gas Reporting Rule; Final Rule
Federal Register / Vol. 89, No. 81 / Thursday, April 25, 2024 / Rules
and Regulations
[[Page 31802]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 9 and 98
[EPA-HQ-OAR-2019-0424; FRL-7230-01-OAR]
RIN 2060-AU35
Revisions and Confidentiality Determinations for Data Elements
Under the Greenhouse Gas Reporting Rule
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: The EPA is amending specific provisions in the Greenhouse Gas
Reporting Rule to improve data quality and consistency. This action
updates the General Provisions to reflect revised global warming
potentials; expands reporting to additional sectors; improves the
calculation, recordkeeping, and reporting requirements by updating
existing methodologies; improves data verifications; and provides for
collection of additional data to better inform and be relevant to a
wide variety of Clean Air Act provisions that the EPA carries out. This
action adds greenhouse gas monitoring and reporting for five source
categories including coke calcining; ceramics manufacturing; calcium
carbide production; caprolactam, glyoxal, and glyoxylic acid
production; and facilities conducting geologic sequestration of carbon
dioxide with enhanced oil recovery. These revisions also include
changes that will improve implementation of the rule such as updates to
applicability estimation methodologies, simplifying calculation and
monitoring methodologies, streamlining recordkeeping and reporting, and
other minor technical corrections or clarifications. This action also
establishes and amends confidentiality determinations for the reporting
of certain data elements to be added or substantially revised in these
amendments.
DATES: This rule is effective January 1, 2025. The incorporation by
reference of certain material listed in this final rule is approved by
the Director of the Federal Register beginning January 1, 2025. The
incorporation by reference of certain other material listed in the rule
was approved by the Director of the Federal Register as of January 1,
2018.
ADDRESSES: The EPA has established a docket for this action under
Docket ID No. EPA-HQ-OAR-2019-0424. All documents in the docket are
listed in the www.regulations.gov index. Although listed in the index,
some information is not publicly available, e.g., confidential business
information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the internet and will be publicly available only in hard
copy. Publicly available docket materials are available either
electronically in www.regulations.gov or in hard copy at the EPA Docket
Center, WJC West Building, Room 3334, 1301 Constitution Ave. NW,
Washington, DC. This Docket Facility is open from 8:30 a.m. to 4:30
p.m., Monday through Friday, excluding legal holidays. The telephone
number for the Public Reading Room is (202) 566-1744 and the telephone
number for the Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Jennifer Bohman, Climate Change
Division, Office of Atmospheric Programs (MC-6207A), Environmental
Protection Agency, 1200 Pennsylvania Ave., NW, Washington, DC 20460;
telephone number: (202) 343-9548; email address: [email protected].
For technical information, please go to the Greenhouse Gas Reporting
Program (GHGRP) website, www.epa.gov/ghgreporting. To submit a
question, select Help Center, followed by ``Contact Us.''
World Wide Web (WWW). In addition to being available in the docket,
an electronic copy of this final rule will also be available through
the WWW. Following the Administrator's signature, a copy of this final
rule will be posted on the EPA's GHGRP website at www.epa.gov/ghgreporting.
SUPPLEMENTARY INFORMATION:
Regulated entities. These final revisions affect certain entities
that must submit annual greenhouse gas (GHG) reports under the GHGRP
(codified at 40 CFR part 98). These are amendments to existing
regulations and will affect owners or operators of certain industry
sectors that are suppliers and direct emitters of GHGs. Regulated
categories and entities include, but are not limited to, those listed
in table 1 of this preamble:
Table 1--Examples of Affected Entities by Category
------------------------------------------------------------------------
North American Examples of
Industry facilities that may
Category Classification be subject to part
System (NAICS) 98:+
------------------------------------------------------------------------
General Stationary Fuel ................. Facilities operating
Combustion Sources. 211 boilers, process
heaters,
incinerators,
turbines, and
internal combustion
engines.
Extractors of crude
petroleum and
natural gas.
321 Manufacturers of
lumber and wood
products.
322 Pulp and paper mills.
325 Chemical
manufacturers.
324 Petroleum refineries,
and manufacturers of
coal products.
316, 326, 339 Manufacturers of
rubber and
miscellaneous
plastic products.
331 Steel works, blast
furnaces.
332 Electroplating,
plating, polishing,
anodizing, and
coloring.
336 Manufacturers of
motor vehicle parts
and accessories.
221 Electric, gas, and
sanitary services.
622 Health services.
611 Educational services.
Electric Power Generation..... 2211 Generation facilities
that produce
electric energy.
Adipic Acid Production........ 325199 All other basic
organic chemical
manufacturing:
Adipic acid
manufacturing.
Aluminum Production........... 331313 Primary aluminum
production
facilities.
Ammonia Manufacturing......... 325311 Anhydrous ammonia
manufacturing
facilities.
Calcium Carbide Production.... 325180 Other basic inorganic
chemical
manufacturing:
calcium carbide
manufacturing.
[[Page 31803]]
Carbon Dioxide Enhanced Oil 211120 Oil and gas
Recovery Projects. extraction projects
using carbon dioxide
enhanced oil
recovery.
Caprolactam, Glyoxal, and 325199 All other basic
Glyoxylic Acid Production. organic chemical
manufacturing.
Cement Production............. 327310 Cement manufacturing.
Ceramics Manufacturing........ 327110 Pottery, ceramics,
327120 and plumbing fixture
manufacturing.
Clay building
material and
refractories
manufacturing.
Coke Calcining................ 299901 Coke; coke,
petroleum; coke,
calcined petroleum.
Electronics Manufacturing..... 334111 Microcomputers
manufacturing
facilities.
334413 Semiconductor,
photovoltaic (PV)
(solid-state) device
manufacturing
facilities.
334419 Liquid crystal
display (LCD) unit
screens
manufacturing
facilities;
Microelectromechanic
al (MEMS)
manufacturing
facilities.
Electrical Equipment 33531 Power transmission
Manufacture or Refurbishment. and distribution
switchgear and
specialty
transformers
manufacturing
facilities.
Electricity generation units 221112 Electric power
that report through 40 CFR generation, fossil
part 75. fuel (e.g., coal,
oil, gas).
Electrical Equipment Use...... 221121 Electric bulk power
transmission and
control facilities.
Electrical transmission and 33361 Engine, Turbine, and
distribution equipment Power Transmission
manufacture or refurbishment. Equipment
Manufacturing.
Ferroalloy Production......... 331110 Ferroalloys
manufacturing.
Fluorinated Greenhouse Gas 325120 Industrial gases
Production. manufacturing
facilities.
Geologic Sequestration........ NA CO2 geologic
sequestration sites.
Glass Production.............. 327211 Flat glass
327213 manufacturing
facilities.
Glass container
manufacturing
facilities.
327212 Other pressed and
blown glass and
glassware
manufacturing
facilities.
HCFC-22 Production............ 325120 Industrial gas
manufacturing:
Hydrochlorofluorocar
bon (HCFC) gases
manufacturing.
HFC-23 destruction processes 325120 Industrial gas
that are not collocated with manufacturing:
a HCFC-22 production facility Hydrofluorocarbon
and that destroy more than (HFC) gases
2.14 metric tons of HFC-23 manufacturing.
per year.
Hydrogen Production........... 325120 Hydrogen
manufacturing
facilities.
Industrial Waste Landfill..... 562212 Solid waste
landfills.
Industrial Wastewater 221310 Water treatment
Treatment. plants.
Injection of Carbon Dioxide... 211 Oil and gas
extraction.
Iron and Steel Production..... 333110 Integrated iron and
steel mills, steel
companies, sinter
plants, blast
furnaces, basic
oxygen process
furnace (BOPF)
shops.
Lead Production............... 331 Primary metal
manufacturing.
Lime Manufacturing............ 327410 Lime production.
Magnesium Production.......... 331410 Nonferrous metal
(except aluminum)
smelting and
refining: Magnesium
refining, primary.
Nitric Acid Production........ 325311 Nitrogenous
fertilizer
manufacturing:
Nitric acid
manufacturing.
Petroleum and Natural Gas 486210 Pipeline
Systems. 221210 transportation of
natural gas.
Natural gas
distribution
facilities.
211120 Crude petroleum
extraction.
211130 Natural gas
extraction.
Petrochemical Production...... 324110 Petrochemicals made
in petroleum
refineries.
Petroleum Refineries.......... 324110 Petroleum refineries.
Phosphoric Acid Production.... 325312 Phosphatic fertilizer
manufacturing.
Pulp and Paper Manufacturing.. 322110 Pulp mills.
322120 Paper mills.
322130 Paperboard mills.
-----------------------------------------
Miscellaneous Uses of Facilities included elsewhere.
Carbonate.
-----------------------------------------
Municipal Solid Waste 562212 Solid waste
Landfills. 221320 landfills.
Sewage treatment
facilities.
Silicon Carbide Production.... 327910 Silicon carbide
abrasives
manufacturing.
Soda Ash Production........... 325180 Other basic inorganic
chemical
manufacturing: Soda
ash manufacturing.
Suppliers of Carbon Dioxide... 325120 Industrial gas
manufacturing
facilities.
Suppliers of Industrial 325120 Industrial greenhouse
Greenhouse Gases. gas manufacturing
facilities.
Titanium Dioxide Production... 325180 Other basic inorganic
chemical
manufacturing:
Titanium dioxide
manufacturing.
Underground Coal Mines........ 212115 Underground coal
mining.
[[Page 31804]]
Zinc Production............... 331410 Nonferrous metal
(except aluminum)
smelting and
refining: Zinc
refining, primary.
Suppliers of Coal-based Liquid 211130 Coal liquefaction at
Fuels. mine sites.
Suppliers of Natural Gas and 221210 Natural gas
Natural Gas Liquids. 211112 distribution
facilities.
Natural gas liquid
extraction
facilities.
Suppliers of Petroleum 324110 Petroleum refineries.
Products.
Suppliers of Carbon Dioxide... 325120 Industrial gas
manufacturing
facilities.
Suppliers of Industrial 325120 Industrial greenhouse
Greenhouse Gases. gas manufacturing
facilities.
Importers and Exporters of Pre- 423730 Air-conditioning
charged Equipment and Closed- 333415 equipment (except
Cell Foams. room units) merchant
wholesalers.
Air-conditioning
equipment (except
motor vehicle)
manufacturing.
423620 Air-conditioners,
room, merchant
wholesalers.
449210 Electronics and
appliance retailers.
326150 Polyurethane foam
products
manufacturing.
335313 Circuit breakers,
power,
manufacturing.
423610 Circuit breakers and
related equipment
merchant
wholesalers.
------------------------------------------------------------------------
Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities likely to be
affected by this action. This table lists the types of facilities that
the EPA is now aware could potentially be affected by this action.
Other types of facilities than those listed in the table could also be
subject to reporting requirements. To determine whether you will be
affected by this action, you should carefully examine the applicability
criteria found in 40 CFR part 98, subpart A (General Provisions) and
each source category. Many facilities that are affected by 40 CFR part
98 have greenhouse gas emissions from multiple source categories listed
in table 1 of this preamble. If you have questions regarding the
applicability of this action to a particular facility, consult the
person listed in the preceding FOR FURTHER INFORMATION CONTACT section.
Acronyms and abbreviations. The following acronyms and
abbreviations are used in this document.
ACE Automated Commercial Environment
AIM American Innovation and Manufacturing Act of 2020
ANSI American National Standards Institute
API American Petroleum Institute
ASME American Society of Mechanical Engineers
ASTM ASTM, International
BAMM best available monitoring methods
BCFCs bromochlorofluorocarbons
BEF byproduct emission factor
BFCs bromofluorocarbons
CAA Clean Air Act
CaO calcium oxide (lime)
CARB California Air Resources Board
CAS Chemical Abstracts Service
CBI confidential business information
CBP U.S. Customs and Border Protection
CCS carbon capture and sequestration
CECS combustion emissions control system
CEMS continuous emissions monitoring system
CFC chlorofluorocarbon
CFR Code of Federal Regulations
CF4 perfluoromethane
CGA cylinder gas audit
CHP combined heat and power
CH4 methane
CKD cement kiln dust
CO2 carbon dioxide
CO2e carbon dioxide equivalent
COF2 carbonic difluoride
CRA Congressional Review Act
CSA CSA Group
DAC direct air capture
DCU delayed coking unit
DOC degradable organic carbon
DOE U.S. Department of Energy
DRE destruction or removal efficiency
EAF electric arc furnace
EDC ethylene dichloride
EF emission factor
EGU electricity generating unit
e-GGRT electronic Greenhouse Gas Reporting Tool
EG emission guidelines
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
EREF Environmental Research and Education Foundation
F-GHG fluorinated greenhouse gas
F-HTF fluorinated heat transfer fluids
FLIGHT Facility Level Information on Greenhouse Gases Tool
FR Federal Register
FTIR Fourier Transform Infrared
GCCS gas collection and capture system
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GIE gas-insulated equipment
GWP global warming potential
HBCFC hydrobromochlorofluorocarbon
HBFC hydrobromofluorocarbon
HC hydrocarbon
HCFC hydrochlorofluorocarbon
HCFE hydrochlorofluoroether
HFC hydrofluorocarbon
HFE hydrofluoroether
HHV high heating value
HTF heat transfer fluid
HTS Harmonized Tariff System
ICR Information Collection Request
IPCC Intergovernmental Panel on Climate Change
ISO International Standards Organization
IVT Inputs Verification Tool
k first order decay rate
kg kilogram
kV kilovolt
LCD liquid crystal display
LDC local distribution company
LMOP Landfill Methane Outreach Program
MEMS Microelectromechanical systems
MgO magnesium oxide
mmBtu million British thermal units
MRV monitoring, reporting, and verification plan
MW molecular weight
MSW municipal solid waste
mt metric tons
mtCO2e metric tons carbon dioxide equivalent
MTBS Mean Time Between Service
NAICS North American Industry Classification System
NIST National Institute of Standards and Technology
NSPS new source performance standards
N2O nitrous oxide
OAR Office of Air and Radiation
OMB Office of Management and Budget
OMP operations management plan
PFC perfluorocarbon
POU point of use
POX partial oxidation
ppmv parts per million volume
PRA Paperwork Reduction Act
PSA pressure swing absorption
psi pounds per square inch
psia pounds per square inch, absolute
PV photovoltaic
QA/QC quality assurance/quality control
[[Page 31805]]
RFA Regulatory Flexibility Act
RPC remote plasma cleaning
RY reporting year
scf standard cubic feet
SEM surface-emissions monitoring
SF6 sulfur hexafluoride
SMR steam methane reforming
SSM startup, shutdown, and malfunction
TSD technical support document
UMRA Unfunded Mandates Reform Act of 1995
UNFCCC United Nations Framework Convention on Climate Change
U.S. United States
VCM vinyl chloride monomer
WGS water gas shift
WMO World Meteorological Organization
WWW World Wide Web
Table of Contents
I. Background
A. How is this preamble organized?
B. Executive Summary
C. Background on This Final Rule
D. Legal Authority
II. Overview of Final Revisions to 40 CFR Part 98 and 40 CFR Part 9
III. Final Revisions to Each Subpart of Part 98 and Summary of
Comments and Responses
A. Subpart A--General Provisions
B. Subpart B--Energy Consumption
C. Subpart C--General Stationary Fuel Combustion
D. Subpart F--Aluminum Production
E. Subpart G--Ammonia Manufacturing
F. Subpart H--Cement Production
G. Subpart I--Electronics Manufacturing
H. Subpart N--Glass Production
I. Subpart P--Hydrogen Production
J. Subpart Q--Iron and Steel Production
K. Subpart S--Lime Production
L. Subpart U--Miscellaneous Uses of Carbonate
M. Subpart X--Petrochemical Production
N. Subpart Y--Petroleum Refineries
O. Subpart AA--Pulp and Paper Manufacturing
P. Subpart BB--Silicon Carbide Production
Q. Subpart DD--Electrical Transmission and Distribution
Equipment Use
R. Subpart FF--Underground Coal Mines
S. Subpart GG--Zinc Production
T. Subpart HH--Municipal Solid Waste Landfills
U. Subpart OO--Suppliers of Industrial Greenhouse Gases
V. Subpart PP--Suppliers of Carbon Dioxide
W. Subpart QQ--Importers and Exporters of Fluorinated Greenhouse
Gases Contained in Pre-Charged Equipment and Closed-Cell Foams
X. Subpart RR--Geologic Sequestration of Carbon Dioxide
Y. Subpart SS--Electrical Equipment Manufacture or Refurbishment
Z. Subpart UU--Injection of Carbon Dioxide
AA. Subpart VV--Geologic Sequestration of Carbon Dioxide With
Enhanced Oil Recovery Using ISO 27916
BB. Subpart WW--Coke Calciners
CC. Subpart XX--Calcium Carbide Production
DD. Subpart YY--Caprolactam, Glyoxal, and Glyoxylic Acid
Production
EE. Subpart ZZ--Ceramics Manufacturing
IV. Final Revisions to 40 CFR Part 9
V. Effective Date of the Final Amendments
VI. Final Confidentiality Determinations
A. EPA's Approach to Assessing Data Elements
B. Final Confidentiality Determinations and Emissions Data
Designations
C. Final Reporting Determinations for Inputs to Emission
Equations
VII. Impacts and Benefits of the Final Amendments
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and
Executive Order 14094: Modernizing Regulatory Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act and 1 CFR
Part 51
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
K. Congressional Review Act
L. Judicial Review
I. Background
A. How is this preamble organized?
Section I. of this preamble contains background information on the
June 21, 2022 proposed rule (87 FR 36920, hereafter referred to as
``2022 Data Quality Improvements Proposal'') and the May 22, 2023
supplemental proposed rule (88 FR 32852, hereafter referred to as
``2023 Supplemental Proposal''). This section also discusses the EPA's
legal authority under the CAA to promulgate (including subsequent
amendments to) the GHG Reporting Rule, codified at 40 CFR part 98
(hereinafter referred to as ``part 98''), and the EPA's legal authority
to make confidentiality determinations for new or revised data elements
corresponding to these amendments or for existing data elements for
which the EPA is finalizing a new determination. Section II. of this
preamble describes the types of amendments included in this final rule.
Section III. of this preamble is organized by part 98 subpart and
contains detailed information on the final new requirements for, or
revisions to, each subpart. Section IV. of this preamble describes the
final revisions to 40 CFR part 9. Section V. of this preamble explains
the effective date of the final revisions and how the revisions are
required to be implemented in reporting year (RY) 2024 and RY2025
reports. Section VI. of this preamble discusses the final
confidentiality determinations for new or substantially revised (i.e.,
requiring additional or different data to be reported) data reporting
elements, as well as for certain existing data elements for which the
EPA is finalizing a new determination. Section VII. of this preamble
discusses the impacts of the final amendments. Finally, section VIII.
of this preamble describes the statutory and Executive order
requirements applicable to this action.
B. Executive Summary
The EPA is finalizing certain proposed revisions to part 98
included in the 2022 Data Quality Improvements Proposal and the 2023
Supplemental Proposal, with some changes made after consideration of
public comments. The final amendments include improvements to
requirements that, broadly, will enhance the quality and the scope of
information collected, clarify elements of the rule, and streamline
elements of reporting and recordkeeping. These final revisions include
a comprehensive update to the global warming potentials (GWPs) in table
A-1 to subpart A of part 98; updates to provide for collection of
additional data to understand new source categories or new emission
sources for specific sectors; updates to emission factors to more
accurately reflect industry emissions; refinements to existing
emissions calculation methodologies to reflect an improved
understanding of emissions sources and end uses of GHGs; additions or
modifications to reporting requirements in order to eliminate data gaps
and improve verification of reported emissions; revisions that address
prior commenter concerns or clarify requirements; and editorial
corrections that are intended to improve the public's understanding of
the rule. The final amendments also include streamlining measures such
as revisions to applicability for certain industry sectors to account
for changes in usage of certain GHGs or instances where the current
applicability estimation methodology may overestimate emissions;
revisions that provide flexibility for or simplify monitoring and
calculation methods; and revisions to streamline reported data elements
or recordkeeping where the current requirements are redundant, where
reported data are not currently useful for verification or analysis, or
for which continued collection of the data at the same frequency would
not likely
[[Page 31806]]
provide new insights or knowledge of the industry sector, emissions, or
trends at this time. This action also finalizes confidentiality
determinations for the reporting of data elements added or
substantially revised in these final amendments, and for certain
existing data elements for which no confidentiality determination has
been made previously or for which the EPA proposed to revise the
existing determination.
In some cases, and as further described in section III. of this
preamble, the EPA is not taking final action in this final rule on
certain proposed revisions included in the 2022 Data Quality
Improvements Proposal and the 2023 Supplemental Proposal. For example,
after review of comments received in response to the proposed
requirements to report purchased electricity and thermal energy
consumption information under the proposed subpart B (Energy
Consumption), the EPA is not taking action at this time on those
proposed provisions. The EPA believes additional time is needed to
consider the comments received before taking final action. Similarly,
the EPA is not taking final action at this time on certain proposed
changes for some subparts. In some cases, e.g., for subparts G (Ammonia
Production), P (Hydrogen Production), S (Lime Production), and HH
(Municipal Solid Waste Landfills), we are not taking final action at
this time on certain revisions to the calculation or monitoring
methodologies that would have revised how data are collected and
reported in the EPA's electronic greenhouse gas reporting tool (e-
GGRT). In several cases, we are also not taking final action at this
time on proposed revisions to add reporting requirements. For example,
under subpart C (General Stationary Fuel Combustion), we are not taking
final action at this time on proposed revisions to the requirements for
units in either an aggregation of units or common pipe configuration
that would have required reporters to provide additional information
such as the unit type, maximum rated heat input capacity, and fraction
of the actual total heat input for each unit in the aggregation or the
common pipe configuration. Also under subpart C, we are not taking
final action at this time on proposed requirements that would have
required reporters to identify, for any configuration, whether the unit
is an electricity generating unit, and, for group configurations (i.e.,
common stack/duct, common pipe, and aggregation of units) that contain
an electricity generating unit, the estimated decimal fraction of total
emissions attributable to the electricity generating unit. Similarly,
we are not taking final action at this time on certain data elements
that were proposed to be added to subparts A (General Provisions), F
(Aluminum Production), G, H (Cement Production), P, S, HH, OO
(Suppliers of Industrial Greenhouse Gases), and QQ (Importers and
Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged
Equipment and Closed-Cell Foams). Additional proposed revisions that
EPA is not taking final action on at this time are discussed in section
III. of this preamble.
This final rule also includes an amendment to 40 CFR part 9 to
include the Office of Management and Budget (OMB) control number issued
under the Paperwork Reduction Act (PRA) for the information collection
request for the GHGRP.
The final amendments will become effective on January 1, 2025. As
provided under the existing regulations in subpart A of part 98, the
GWP amendments to table A-1 to subpart A will apply to reports
submitted by current reporters that are submitted in calendar year 2025
and subsequent years (i.e., starting with reports submitted for RY2024
on March 31, 2025). All other final revisions, which apply to both
existing and new reporters, will be implemented for reports prepared
for RY2025 and submitted March 31, 2026. Reporters who are newly
subject to the rule will be required to implement all requirements to
collect data, including any required monitoring and recordkeeping, on
January 1, 2025.
These final amendments are anticipated to result in an overall
increase in burden for part 98 reporters in cases where the amendments
expand current applicability, add or revise reporting requirements, or
require additional emissions data to be reported. The primary burden
associated with the final rule is due to revisions to applicability,
including revisions to the global warming potentials in table A-1 to
subpart A of part 98, that will change the number of reporters
currently at or near the 25,000 metric tons carbon dioxide equivalent
(mtCO2e) threshold; revisions to establish requirements for
new source categories for coke calcining, calcium carbide, caprolactam,
glyoxal, and glyoxylic acid production, ceramics manufacturing, and
facilities conducting geologic sequestration of carbon dioxide with
enhanced oil recovery; and revisions to expand reporting to include new
emission sources for specific sectors, such as the addition of captive
(non-merchant) hydrogen production facilities. The final revisions will
affect approximately 254 new reporters across 13 source categories,
including the hydrogen production, petroleum and natural gas systems,
petroleum refineries, electrical transmission and distribution systems,
industrial wastewater treatment, municipal solid waste landfills,
fluorinated GHG suppliers, and industrial waste landfills source
categories, as well as the new source categories added in these final
revisions. The EPA anticipates some decrease in burden where the final
revisions will adjust or improve the estimation methodologies for
determining applicability, simplify calculation methodologies or
monitoring requirements, or simplify the data that must be reported. In
several cases, we are also finalizing changes where we anticipate
increased clarity or more flexibility for reporters that could result
in a potential decrease in burden. The incremental implementation labor
costs for all subparts include $2,684,681 in RY2025, and $2,671,831 in
each subsequent year (RY2026 and RY2027). The incremental
implementation labor costs over the next three years (RY2025 through
RY2027) total $8,028,343. There is an additional incremental burden of
$2,733,937 for capital and operation and maintenance (O&M) costs in
RY2025 and in each subsequent year (RY2026 and RY2027), which reflects
changes to applicability and monitoring for subparts with new or
additional reporters. The incremental non-labor costs for RY2025
through RY2027 total $8,201,812 over the next three years.
C. Background on This Final Rule
The GHGRP requires annual reporting of GHG data and other relevant
information from large facilities and suppliers in the United States.
In its 2022 Data Quality Improvements Proposal, the EPA proposed
amendments to specific provisions of part 98 where we identified
opportunities to improve the quality of the data collected under the
rule. This included revisions that would provide for the collection of
additional data that may be necessary to better understand emissions
from specific sectors or inform future policy decisions under the CAA;
update emission factors; and refine emissions estimation methodologies.
The proposed rule also included revisions that provided for the
collection of additional data that would be useful to improve
verification of collected data and complement or
[[Page 31807]]
inform other EPA programs. These proposed revisions included the
incorporation of a new source category to add calculation and reporting
requirements for quantifying geologic sequestration of CO2
in association with enhanced oil recovery (EOR) operations. In several
cases, the 2022 Data Quality Improvements Proposal included revisions
that would resolve gaps in the current coverage of the GHGRP that leave
out potentially significant sources of GHG emissions or end uses. The
EPA also proposed revisions that clarified or updated provisions that
may be unclear, and that would streamline calculation, monitoring, or
reporting in specific provisions in part 98 to provide flexibility or
increase the efficiency of data collection. The EPA included a request
for comment on expanding the GHGRP to include several new source
categories (see section IV. of the preamble to the 2022 Data Quality
Improvements Proposal at 87 FR 37016) and requested comment on
potential future amendments to add new calculation, monitoring, and
reporting requirements for these categories. The EPA also proposed
confidentiality determinations for new or substantially revised data
reporting elements that would be amended under the proposed rule, as
well as for certain existing data elements for which the EPA proposed a
new or revised determination. The EPA received comments on the 2022
Data Quality Improvements Proposal from June 21, 2022, through October
6, 2022.
The EPA subsequently proposed additional amendments to part 98
where the Agency had received or identified new information to further
improve the data collected under the GHGRP. The 2023 Supplemental
Proposal included amendments that were informed by a review of comments
and information provided by stakeholders on the 2022 Data Quality
Improvements Proposal, as well as newly proposed amendments that the
EPA had identified from program implementation, e.g., where additional
data would improve verification of data reported to the GHGRP or would
further aid our understanding of changing industry emission trends. The
2023 Supplemental Proposal included a proposed comprehensive update to
the GWPs in table A-1 to subpart A of part 98; proposed amendments to
establish new subparts with specific reporting provisions under part 98
for five new source categories; and several proposed revisions where
the EPA had identified new data supporting improvements to the
calculation, monitoring, and recordkeeping requirements. The 2023
Supplemental Proposal also clarified or corrected specific proposed
provisions of the 2022 Data Quality Improvements Proposal. The
amendments included in the 2023 Supplemental Proposal were proposed as
part of the EPA's continued efforts to address potential data gaps and
improve the quality of the data collected in the GHGRP. The EPA also
proposed confidentiality determinations for new or substantially
revised data reporting elements that would be revised under the
supplemental proposed amendments. The EPA received comments on the 2023
Supplemental Proposal from May 22, 2023, through July 21, 2023.
The revisions included in the 2022 Data Quality Improvements
Proposal and the 2023 Supplemental Proposal were based on the EPA's
assessment of advances in scientific understanding of GHG emissions
sources, updated guidance on GHG estimation methods, and a review of
the data collected and emissions trends established following more than
10 years of implementation of the program. The EPA is finalizing
amendments and confidentiality determinations in this action, with
certain changes from the proposed rules following consideration of
comments submitted and based on the EPA's updated assessment. The
revisions reflect the EPA's efforts to update and improve the GHGRP by
better capturing the changing landscape of GHG emissions, providing for
more complete coverage of U.S. GHG emission sources, and providing a
more comprehensive approach to understanding GHG emissions. Responses
to major comments submitted on the proposed amendments from the 2022
Data Quality Improvement Proposal and the 2023 Supplemental Proposal
considered in the development of this final rule can be found in
sections III. and VI. of this preamble. Documentation of all comments
received as well as the EPA's responses can be found in the document
``Summary of Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule,'' available in the docket to this rulemaking,
Docket ID. No. EPA-HQ-OAR-2019-0424.
This final rule does not address implementation of provisions of
the Inflation Reduction Act, which was signed into law on August 16,
2022. Section 60113 of the Inflation Reduction Act amended the CAA by
adding section 136, ``Methane Emissions and Waste Reduction Incentive
Program for Petroleum and Natural Gas Systems.'' Although the EPA
proposed amendments to subpart W of part 98 (Petroleum and Natural Gas
Systems) in the 2022 Data Quality Improvements Proposal, these were
developed prior to the Congressional direction provided in CAA section
136. The EPA noted in the preamble to the 2023 Supplemental Proposal
(see section I.B., 88 FR 32855) that we intend to issue one or more
separate actions to implement the requirements of CAA section 136,
including revisions to certain requirements of subpart W. Subsequently,
the EPA published a proposed rule for subpart W on August 1, 2023 (88
FR 50282, hereinafter referred to as the ``2023 Subpart W Proposal''),
as well as a proposed rule to implement CAA section 136(c), ``Waste
Emissions Charge,'' that was signed by the Administrator on January 12,
2024 and published on January 26, 2024 (89 FR 5318),\1\ to comply with
CAA section 136. As discussed in the 2023 Subpart W Proposal, the EPA
considered the 2022 Data Quality Improvements Proposal as well as
additional proposed revisions in the development of the 2023 Subpart W
Proposal. Accordingly, the EPA is not taking final action on the
revisions to subpart W, including harmonizing revisions to subparts A
(General Provisions) and C (General Stationary Fuel Combustion Sources)
related to subpart W, that were proposed in the 2022 Data Quality
Improvements Proposal in this final rule.
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\1\ CAA section 136(c), ``Waste Emissions Charge,'' directs the
Administrator to impose and collect a charge on methane
(CH4) emissions that exceed statutorily specified waste
emissions thresholds from an owner or operator of an applicable
facility that reports more than 25,000 metric tons carbon dioxide
equivalent pursuant to the Greenhouse Gas Reporting Rule's
requirements for the petroleum and natural gas systems source
category (codified as subpart W in EPA's Greenhouse Gas Reporting
Rule regulations).
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D. Legal Authority
The EPA is finalizing these rule amendments under its existing CAA
authority provided in CAA section 114. As stated in the preamble to the
Mandatory Reporting of Greenhouse Gases final rule (74 FR 56260,
October 30, 2009), CAA section 114(a)(1) provides the EPA authority to
require the information gathered by this rule because such data will
inform and are relevant to the EPA's carrying out of a variety of CAA
provisions. Thus, when promulgating amendments to the GHGRP, the EPA
has assessed the reasonableness of requiring the information to be
provided and explained how the data are relevant to the EPA's ability
to carry out the provisions of the CAA. See the preambles to the
proposed GHG
[[Page 31808]]
Reporting Rule (74 FR 16448, April 10, 2009) and the final GHG
Reporting Rule (74 FR 56260, October 30, 2009) for further discussion
of this authority. Additionally, in enacting CAA section 136 (discussed
above in preamble section I.C.), Congress implicitly recognized EPA's
appropriate use of CAA authority in promulgating the GHGRP. The
provisions of CAA section 136 reference and are in part based on the
Greenhouse Gas Reporting Rule requirements under subpart W for the
petroleum and natural gas systems source category and require further
revisions to subpart W for purposes of supporting implementation of
section 136.
The Administrator has determined that this action is subject to the
provisions of section 307(d) of the CAA (see also section VIII.L. of
this preamble). Section 307(d) contains a set of procedures relating to
the issuance and review of certain CAA rules.
In addition, pursuant to sections 114, 301, and 307 of the CAA, the
EPA is publishing final confidentiality determinations for the new or
substantially revised data elements required by these amendments.
Section 114(c) requires that the EPA make information obtained under
section 114 available to the public, except for information (excluding
emission data) that qualifies for confidential treatment.
II. Overview of Final Revisions to 40 CFR Part 98 and 40 CFR Part 9
Relevant to this final rule, the EPA previously proposed revisions
to part 98 in two separate documents: the 2022 Data Quality
Improvements Proposal (June 21, 2022, 87 FR 36920) and the 2023
Supplemental Proposal (May 22, 2023, 88 FR 32852). In the proposed
rules, the EPA identified two primary categories of revisions that we
are finalizing in this rule. First, the EPA identified revisions that
would modify the rule to improve the quality of the data collected and
better inform the EPA's understanding of U.S. GHG emissions sources.
Specifically, the EPA identified six types of revisions to improve the
quality of the data collected under part 98 that we are finalizing in
this rule, as follows:
Revisions to table A-1 to the General Provisions of part
98 to update GWPs to reflect advances in scientific knowledge and
better characterize the climate impacts of certain GHGs, by including
values agreed to under the United Nations Framework Convention on
Climate Change, and to maintain comparability and consistency with the
Inventory of U.S. Greenhouse Gas Emissions and Sinks (hereafter
referred to as ``the Inventory'') and other analyses produced by the
EPA;
Revisions to expand source categories or add new source
categories to address potential gaps in reporting of data on U.S. GHG
emissions or supply in order to improve the accuracy and completeness
of the data provided by the GHGRP;
Amendments to update emission factors to incorporate new
measurement data that more accurately reflect industry emissions;
Revisions to refine existing emissions calculation
methodologies to reflect an improved understanding of emissions sources
and end uses of GHGs, or to incorporate more recent research on GHG
emissions or formation;
Additions or modifications to reporting requirements to
eliminate data gaps and improve verification of emissions estimates;
and
Revisions that clarify requirements that reporters have
previously found vague to ensure that accurate data are being
collected, and editorial corrections or harmonizing changes that will
improve the public's understanding of the rule.
Second, the EPA identified revisions that would streamline the
calculation, monitoring, or reporting requirements of part 98 to
provide flexibility or increase the efficiency of data collection. In
the 2022 Data Quality Improvements Proposal and the 2023 Supplemental
Notice, the EPA identified several streamlining revisions that we are
finalizing in this rule, as follows:
Revisions to applicability criteria for certain industry
sectors without the 25,000 mtCO2e per year reporting
threshold to account for changes in usage of certain GHGs, or where the
current applicability estimation methodology may overestimate
emissions;
Revisions that provide flexibility for and simplify
monitoring and calculation methods where further monitoring and data
collection will not likely significantly improve our understanding of
emission sources at this time, or where we currently allow similar less
burdensome methodologies for other sources; and
Revisions to reported data elements or recordkeeping where
the current requirements are redundant or where reported data are not
currently useful for verification or analysis, or for which continued
collection of the data at the same frequency will not likely provide
new insights or knowledge of the industry sector, emissions, or trends
at this time.
The revisions included in this final rule will advance the EPA's
goal of updating the GHGRP to reflect advances in scientific knowledge,
better reflect the EPA's current understanding of U.S. GHG emissions
and trends and improve data collection and reporting to better
understand emissions from specific sectors or inform future policy
decisions under the CAA. The types of streamlining revisions we are
finalizing will simplify requirements while maintaining the quality of
the data collected under part 98, where continued collection of
information assists in evaluation and support of EPA programs and
policies.
The EPA has frequently considered and relied on data collected
under the GHGRP to carry out provisions of the CAA; to inform policy
options; and to support regulatory and non-regulatory actions. For
example, GHGRP landfill data from subpart HH of part 98 (Municipal
Solid Waste Landfills) were previously analyzed to inform the
development of the 2016 new source performance standards (NSPS) and
emission guidelines (EG) for landfills (89 FR 59322; August 29, 2016).
Specifically, the EPA used data from part 98 reporting to update the
characteristics and technical attributes of over 1,200 landfills in the
EPA's landfills data set, as well as to estimate emission reductions
and costs, to inform the revised performance standards. Most recently,
the EPA used GHGRP data collected under subparts RR (Geologic
Sequestration of Carbon Dioxide) and UU (Injection of Carbon Dioxide)
of part 98 to inform the development of the proposed NSPS and EG for
GHG emissions from fossil fuel-fired electric generating units (EGUs)
(88 FR 33240, May 23, 2023, hereafter ``EGU NSPS/EG proposed rule''),
including to assess the geographic availability of geologic
sequestration and enhanced oil recovery. These final revisions to the
GHGRP will, as discussed herein, improve the GHG emissions data and
supplier data that is collected under the GHGRP to better inform the
EPA in carrying out provisions of the CAA (such as providing a better
understanding of upstream production, downstream emissions, and
potential impacts) and otherwise supporting the continued development
of climate and air quality standards under the CAA.
As the EPA has explained since the GHGRP was first promulgated, the
data also will inform the EPA's implementation of CAA section 103(g)
regarding improvements in nonregulatory strategies and technologies for
preventing or reducing air pollutants (e.g., EPA's voluntary
[[Page 31809]]
GHG reduction programs such as the non-CO2 partnership
programs and ENERGY STAR) (74 FR 56265). The final rule will support
the overall goals of the GHGRP to collect high-quality GHG data and to
incorporate metrics and methodologies that reflect scientific updates.
For example, we are finalizing revisions to table A-1 to subpart A of
part 98 to update the chemical-specific GWP values of certain GHGs to
(1) reflect GWPs from the Intergovernmental Panel on Climate Change
(IPCC) Fifth Assessment Report (hereinafter referred to as ``AR5'');
\2\ (2) for certain GHGs that do not have chemical-specific GWPs listed
in AR5, to adopt GWP values from the IPCC Sixth Assessment Report
(hereinafter referred to as ``AR6''); \3\ and (3) to revise and expand
the set of default GWPs which are applied to GHGs for which peer-
reviewed chemical-specific GWPs are not available.
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\2\ IPCC, 2013: Climate Change 2013: The Physical Science Basis.
Contribution of Working Group I to the Fifth Assessment Report of
the Intergovernmental Panel on Climate Change [Stocker, T.F., D.
Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels,
Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press,
Cambridge, United Kingdom and New York, NY, USA, 1535 pp. The GWPs
are listed in table 8.A.1 of Appendix 8.A: Lifetimes, Radiative
Efficiencies and Metric Values, which appears on pp. 731-737 of
Chapter 8, ``Anthropogenic and Natural Radiative Forcing.''
\3\ Smith, C., Z.R.J. Nicholls, K. Armour, W. Collins, P.
Forster, M. Meinshausen, M.D. Palmer, and M. Watanabe, 2021: The
Earth's Energy Budget, Climate Feedbacks, and Climate Sensitivity
Supplementary Material. In Climate Change 2021: The Physical Science
Basis. Contribution of Working Group I to the Sixth Assessment
Report of the Intergovernmental Panel on Climate Change [Masson-
Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. P[eacute]an, S.
Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K.
Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield,
O. Yelek[ccedil]i, R. Yu, and B. Zhou (eds.)]. Available from
www.ipcc.ch/ The AR6 GWPs are listed in table 7.SM.7, which appears
on page 16 of the Supplementary Material.
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In several cases, we are finalizing updates to emissions and
default factors where we have received or identified updated
measurement data. For example, we are finalizing updates to the default
biogenic fraction for tire combustion in subpart C of part 98 (General
Stationary Fuel Combustion) based on updated data obtained by the EPA
on the weighted average composition of natural rubber in tires,
allowing for the estimation of an emission factor that is more
representative of these sources. Similarly, we are finalizing updates
to the emission factors and default destruction and removal efficiency
values in subpart I of part 98 (Electronics Manufacturing). The updated
emission factors are based on newly submitted data from the 2017 and
2020 technology assessment reports submitted under the GHGRP with
RY2016 and RY2019 annual reports, as well as consideration of new
emission factors available in the 2019 Refinement to the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories (hereafter ``2019
Refinement'').\4\
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\4\ Intergovernmental Panel on Climate Change. 2019 Refinement
to the 2006 IPCC Guidelines for National Greenhouse Gas Inventories,
Calvo Buendia, E., Tanabe, K., Kranjc, A., Baasansuren, J., Fukuda,
M., Ngarize, S., Osako, A., Pyrozhenko, Y., Shermanau, P. and
Federici, S. (eds). Published: IPCC, Switzerland. 2019. https://www.ipcc-nggip.iges.or.jp/public/2019rf/index.html.
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In other cases, we are finalizing updates to calculation
methodologies to incorporate updates that are based on an improved
understanding of emission sources. For example, for subpart I of part
98 (Electronics Manufacturing), the EPA is implementing emissions
estimation improvements from the 2019 Refinement such as updates to the
method used to calculate the fraction of fluorinated input gases and
byproducts exhausted from tools with abatement systems during stack
tests; revising equations that calculate the weighted average DREs for
individual fluorinated greenhouse gases (F-GHGs) across process types;
requiring that all stack systems be tested if the stack test method is
used; and updating a set of equations that will more accurately account
for emissions when pre-control emissions of a F-GHG approach or exceed
the consumption of that gas during the test period. For subpart Y
(Petroleum Refineries), we are amending the calculation methodology for
delayed coking units to more accurately reflect the activities
conducted at certain facilities that were not captured by the current
emissions estimation methodology, which relies on a steam generation
model. The incorporation of updated metrics and methodologies will
improve the quality and accuracy of the data collected under the GHGRP,
increase the Agency's understanding of the relative distribution of
GHGs that are emitted, and better inform EPA policy and programs under
the CAA.
The improvements to part 98 will further provide a more
comprehensive, nationwide GHG emissions profile reflective of the
origin and distribution of GHG emissions in the United States and will
more accurately inform EPA policy options for potential regulatory or
non-regulatory CAA programs. The EPA is finalizing several amendments
that will reduce gaps in the reporting of GHG emissions and supply from
specific sectors, including the broadening of existing source
categories; and establishing new source categories that will add
calculation, monitoring, reporting, and recordkeeping requirements for
certain sectors of the economy. The final revisions add five new source
categories, including coke calcining; ceramics manufacturing; calcium
carbide production; caprolactam, glyoxal, and glyoxylic acid
production; and facilities conducting geologic sequestration of carbon
dioxide with enhanced oil recovery. These source categories were
identified upon evaluation of emission sources that potentially
contribute significant GHG emissions that are not currently reported or
where facilities representative of these source categories may
currently report under another part 98 source category using
methodologies that may not provide complete or accurate emissions.
Additionally, the inclusion of certain source categories will improve
the completeness of the emissions estimates presented in the Inventory,
such as collection of data on ceramics manufacturing; calcium carbide
production; and caprolactam, glyoxal, and glyoxylic acid production.
The EPA is also finalizing updates to certain subparts to add reporting
of new emissions or emissions sources for existing sectors to address
potential gaps in reporting. For example, we are adding requirements
for the monitoring, calculation, and reporting of F-GHGs other than
sulfur hexafluoride (SF6) and perfluorocarbons (PFCs) under
subparts DD (Electrical Equipment and Distribution Equipment Use) and
SS (Electrical Equipment Manufacture or Refurbishment) to account for
the introduction of alternative technologies and replacements for
SF6.
Likewise, we are finalizing revisions that will improve reporting
under subpart HH to better account for CH4 emissions from
these facilities. Following review of recent studies indicating that
CH4 emissions from landfills may be considerably higher than
what is currently reported to part 98 due in part to emissions from
poorly operating gas collection systems or destruction devices, we are
revising the calculation methodologies in subpart HH to better account
for these scenarios. These changes are necessary for the EPA to
continue to analyze the relative emissions and distribution of
emissions from specific industries, improve the overall quality of the
data collected under the GHGRP, and better inform future EPA policy and
programs under the CAA. For example, the final revisions to subpart HH
will be used to further improve the data in the EPA's landfills data
set by providing more
[[Page 31810]]
comprehensive and accurate information on landfill emissions and the
efficacy of gas collection systems and destruction devices.
The final revisions also help ensure that the data collected in the
GHGRP can be compared to the data collected and presented by other EPA
programs under the CAA. For example, we are finalizing several
revisions to the reporting requirements for subpart HH, including more
clearly identifying reporting elements associated with each gas
collection system, each measurement location within a gas collection
system, and each control device associated with a measurement location
in subpart HH of part 98. These revisions can be used to estimate the
relative volume of gas flared versus sent to landfill-gas-to-energy
projects to better understand the amount of recovered CH4
that is beneficially used in energy recovery projects. Understanding
the energy recovery of these facilities is critical for evaluating and
identifying progress towards renewable energy targets. Specifically,
these data will allow the Agency to identify industry-specific trends
of beneficial use of landfill gas, communicate best operating practices
for reducing GHG emissions, and evaluate options for expanding the use
of these best practices or other potential policy options under the
CAA.
Similarly, we are finalizing revisions to clarify subpart RR
(Geologic Sequestration of Carbon Dioxide) and add subpart VV (Geologic
Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO
27916) to part 98. Subpart VV provides for the reporting of incidental
CO2 storage associated with enhanced oil recovery based on
the CSA Group (CSA)/American National Standards Institute (ANSI)
International Standards Organization (ISO) 27916:19.
In the EGU NSPS/EG proposed rule, the EPA proposed that any
affected EGU that employs CCS technology that captures enough
CO2 to meet the proposed standard and injects the
CO2 underground must assure that the CO2 is
managed at a facility reporting under subpart RR or new subpart VV of
part 98. As such, this final rule complements the EGU NSPS/EG proposed
rule.
In other cases, the revisions include collection of data that could
be compared to other national and international inventories, improving,
for example, the estimates provided to the Inventory. For instance, we
are finalizing revisions to subpart N (Glass Production) to require
reporting of the annual quantities of cullet (i.e., recycled scrap
glass) used as a raw material. Because differences in the quantities of
cullet used can lead to variations in emissions from the production of
different glass types, the annual quantities of cullet used will
provide a useful metric for understanding variations and differences in
emissions estimates as well as improve the analysis, transparency, and
accuracy of the glass manufacturing sector in the Inventory and other
EPA programs. Likewise, the addition of reporting for new source
categories will improve the completeness of the emissions estimates
presented in the Inventory, such as collection of data on ceramics
manufacturing, calcium carbide production, and caprolactam, glyoxal,
and glyoxylic acid production.
The EPA is finalizing several amendments to improve verification of
the annual GHG reports. For example, we are finalizing amendments to
subpart H (Cement Production) to collect additional data including
annual averages for certain chemical composition input data on a
facility-basis, which the Agency will use to build verification checks.
These edits will provide the EPA the ability to check reported
emissions data from subpart H reporters using both the mass balance and
direct measurement estimation methods, allowing the EPA to back-
estimate process emissions, which will result in more accurate
reporting. Similarly, we are amending subparts OO (Suppliers of
Industrial Greenhouse Gases) and QQ (Importers and Exporters of
Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment or
Closed-Cell Foams) of part 98 to require reporting of the Harmonized
Tariff System code for each F-GHG, fluorinated heat transfer fluid (F-
HTF), or nitrous oxide (N2O) shipped, which will reduce
instances of reporting where the data provided is unclear or unable to
be compared to outside data sources for verification.
Lastly, the changes in this final rule will further advance the
ability of the GHGRP to provide access to quality data on greenhouse
gas emissions. Since its implementation, the collection of data under
the GHGRP has allowed the Agency and relevant stakeholders to identify
changes in industry and emissions trends, such as transitions in
equipment technology or use of alternative lower-GWP greenhouses gases,
that may be beneficial for informing other EPA programs under the CAA.
The GHGRP provides an important data resource for communities and the
public to understand GHG emissions. Since facilities are required to
use prescribed calculation and monitoring methods, emissions data can
be compared and analyzed, including locations of emissions sources.
GHGRP data are easily accessible to the public via the EPA's online
data publication tool, also known as FLIGHT at: https://ghgdata.epa.gov/ghgp/main.do. FLIGHT allows users to view and sort GHG
data for every reporting year starting with 2010 from over 8,000
entities in a variety of ways including by location, industrial sector,
and type of GHG emitted. This powerful data resource provides a
critical tool for communities to identify nearby sources of GHGs and
provide information to state and local governments. Overall, the final
revisions in this action will improve the quality of the data collected
under the program and available to communities.
These final revisions will, as such, maximize the effectiveness of
part 98. Section III. of this preamble describes the specific changes
that we are finalizing for each subpart to part 98 in more detail.
Additional discussion of the benefits of the final rule are in section
VII. of this preamble.
Additionally, we are finalizing a technical amendment to 40 CFR
part 9 to update the table that lists the OMB control numbers issued
under the PRA to include the information collection request (ICR) for
40 CFR part 98. This amendment satisfies the display requirements of
the PRA and OMB's implementing regulations at 5 CFR part 1320 and is
further described in section IV. of this preamble.
III. Final Revisions to Each Subpart of Part 98 and Summary of Comments
and Responses
This section summarizes the final amendments to each part 98
subpart, as generally described in section II. of this preamble. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The amendments to each subpart are followed
by a summary of the major comments on those amendments, and the EPA's
responses to those comments. Other minor corrections and clarifications
are reflected in the final redline regulatory text in the docket for
this rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424).
A. Subpart A--General Provisions
The EPA is finalizing several amendments to subpart A of part 98
(General Provisions) as proposed. In some cases, we are finalizing the
proposed amendments with revisions. Section III.A.1. of this preamble
discusses the final revisions to subpart A. The EPA received several
comments on the proposed subpart A revisions which are discussed in
section III.A.2.
[[Page 31811]]
of this preamble. We are not finalizing the proposed confidentiality
determinations for data elements that were included in the proposed
revisions to subpart A, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart A
This section summarizes the final amendments to subpart A. Major
changes in this final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other
changes to 40 CFR part 98, subpart A can be found in section III.A.2.
of this preamble. Additional information for these amendments and their
supporting basis is available in the preamble to the 2022 Data Quality
Improvements Proposal and 2023 Supplemental Proposal.
a. Revisions to Global Warming Potentials
As proposed, we are revising table A-1 to subpart A of part 98 to
reflect more accurate GWPs to better characterize the climate impacts
of individual GHGs and to ensure continued consistency with other U.S.
climate programs, including the Inventory. The amendments to the GWPs
in table A-1 that we are finalizing in this document are discussed in
this section of this preamble. The EPA's response to comments received
on the proposed revisions to table A-1 are in section III.A.2.a. of
this preamble.
In the 2022 Data Quality Improvements Proposal, the EPA proposed
two updates to table A-1 to subpart A of part 98 to update GWP values
to reflect advances in scientific knowledge. First, we proposed to
adopt a chemical-specific GWP of 0.14 for carbonic difluoride
(COF2) using the atmospheric lifetime and radiative
efficiency published by the World Meteorological Organization (WMO) in
its Scientific Assessment of Ozone Depletion.\5\ We also proposed to
expand one of the F-GHG groups to which a default GWP is assigned.
Default GWPs are applied to GHGs for which peer-reviewed chemical-
specific GWPs are not available. Specifically, we proposed to expand
the ninth F-GHG group in table A-1 to subpart A of part 98, which
includes unsaturated PFCs, unsaturated HFCs, unsaturated
hydrochlorofluorocarbons (HCFCs), unsaturated halogenated ethers,
unsaturated halogenated esters, fluorinated aldehydes, and fluorinated
ketones, to include additional unsaturated fluorocarbons. Given the
very short atmospheric lifetimes of unsaturated GHGs and review of
available evaluations of individual unsaturated chlorofluorocarbons and
unsaturated bromofluorocarbons in the 2018 WMO Scientific Assessment,
we proposed to add unsaturated bromofluorocarbons, unsaturated
chlorofluorocarbons, unsaturated bromochlorofluorocarbons, unsaturated
hydrobromofluorocarbons, and unsaturated hydrobromochlorofluorocarbons
to this F-GHG group, which will apply a default GWP of 1 to these
compounds. Additional information on these amendments and their
supporting basis is available in section III.A.1. of the preamble to
the 2022 Data Quality Improvements Proposal.
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\5\ WMO. Scientific Assessment of Ozone Depletion: 2018, Global
Ozone Research and Monitoring Project-Report No. 58, 588 pp.,
Geneva, Switzerland, 2018. www.esrl.noaa.gov/csd/assessments/ozone/2018/downloads/018OzoneAssessment.pdf. Retrieved July 29, 2019.
Available in the docket for this rulemaking, Docket ID. No. EPA-HQ-
OAR-2019-0424.
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As the 2022 Data Quality Improvements Proposal was nearing
publication, the Parties to the United Nations Framework Convention on
Climate Change (UNFCCC) fully specified which GWPs countries should use
for purposes of GHG reporting.\6\ The EPA subsequently proposed a
comprehensive update to table A-1 to subpart A of part 98 in the 2023
Supplemental Proposal, consistent with recent science and the UNFCCC
decision. This update carried out the intent that the EPA expressed at
the time the GHGRP was first promulgated and in subsequent updates to
part 98 to periodically update table A-1 as science and UNFCCC
decisions evolve. Specifically, the EPA proposed revisions to table A-1
to update the chemical-specific GWPs values of certain GHGs to reflect
values from the IPCC AR5 \7\ and, for certain GHGs that do not have
chemical-specific GWPs listed in AR5, to adopt GWP values from the IPCC
AR6.\8\ We proposed to adopt the AR5 and AR6 GWPs based on a 100-year
time horizon. We also proposed to revise and expand the set of default
GWPs in table A-1 for GHGs for which peer-reviewed chemical-specific
GWPs are not available, including adding two new fluorinated GHG groups
for saturated chlorofluorocarbons (CFCs) and for cyclic forms of
unsaturated halogenated compounds, modifying the ninth F-GHG group to
more clearly apply to non-cyclic unsaturated halogenated compounds, and
updating the existing default GWP values to reflect values estimated
from the chemical-specific GWPs that we proposed to adopt from AR5 and
AR6. See sections II.A. and III.A.1. of the preamble to the 2023
Supplemental Proposal for additional information.
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\6\ As explained in section III.A.1. of the preamble to the 2023
Supplemental Proposal, the Parties to the UNFCCC specified the
agreed-on GWPs in November 2021, which was too late to allow the EPA
to consider proposing a comprehensive GWP update in the 2022 Data
Quality Improvement Proposal.
\7\ IPCC, 2013: Climate Change 2013: The Physical Science Basis.
Contribution of Working Group I to the Fifth Assessment Report of
the Intergovernmental Panel on Climate Change [Stocker, T.F., D.
Qin, G.-K. Plattner, M. Tignor, S.K. Allen, J. Boschung, A. Nauels,
Y. Xia, V. Bex and P.M. Midgley (eds.)]. Cambridge University Press,
Cambridge, United Kingdom and New York, NY, USA, 1535 pp. The GWPs
are listed in table 8.A.1 of Appendix 8.A: Lifetimes, Radiative
Efficiencies and Metric Values, which appears on pp. 731-737 of
Chapter 8, ``Anthropogenic and Natural Radiative Forcing.''
\8\ Smith, C., Z.R.J. Nicholls, K. Armour, W. Collins, P.
Forster, M. Meinshausen, M.D. Palmer, and M. Watanabe, 2021: The
Earth's Energy Budget, Climate Feedbacks, and Climate Sensitivity
Supplementary Material. In Climate Change 2021: The Physical Science
Basis. Contribution of Working Group I to the Sixth Assessment
Report of the Intergovernmental Panel on Climate Change [Masson-
Delmotte, V., P. Zhai, A. Pirani, S.L. Connors, C. Pe[acute]an, S.
Berger, N. Caud, Y. Chen, L. Goldfarb, M.I. Gomis, M. Huang, K.
Leitzell, E. Lonnoy, J.B.R. Matthews, T.K. Maycock, T. Waterfield,
O. Yelek[ccedil]i, R. Yu, and B. Zhou (eds.)]. Available from:
www.ipcc.ch/. The AR6 GWPs are listed in table 7.SM.7, which appears
on page 16 of the Supplementary Material.
---------------------------------------------------------------------------
As proposed, we are amending table A-1 to subpart A of part 98 to
update and add chemical-specific and default GWPs. Consistent with the
2021 UNFCCC decision, we are updating table A-1 to use, for GHGs with
GWPs in AR5, the AR5 GWP values in table 8.A.1 (that reflect the
climate-carbon feedbacks of CO2 but not the GHG whose GWP is
being evaluated), and for CH4, the GWP that is not the GWP
for fossil CH4 in table 8.A.1 (i.e., the GWP for
CH4 that does not reflect either the climate-carbon
feedbacks for CH4 or the atmospheric CO2 that
would result from the oxidation of CH4 in the atmosphere).
We are also updating table A-1 to adopt AR6 GWP values for 31 F-GHGs
that have GWPs listed in AR6 but not AR5. Table 2 of this preamble
lists the final GWP values for each GHG.
[[Page 31812]]
Table 2--Revised Chemical-Specific GWPs for Compounds in Table A-1
----------------------------------------------------------------------------------------------------------------
Name CAS No. Chemical formula GWP (100-year)
----------------------------------------------------------------------------------------------------------------
Chemical-Specific GWPs
----------------------------------------------------------------------------------------------------------------
Carbon dioxide............................... 124-38-9 CO2........................... 1
Methane...................................... 74-82-8 CH4........................... 28
Nitrous oxide................................ 10024-97-2 N2O........................... 265
----------------------------------------------------------------------------------------------------------------
Fully Fluorinated GHGs
----------------------------------------------------------------------------------------------------------------
Sulfur hexafluoride.......................... 2551-62-4 SF6........................... 23,500
Trifluoromethyl sulphur pentafluoride........ 373-80-8 SF5CF3........................ 17,400
Nitrogen trifluoride......................... 7783-54-2 NF3........................... 16,100
PFC-14 (Perfluoromethane).................... 75-73-0 CF4........................... 6,630
PFC-116 (Perfluoroethane).................... 76-16-4 C2F6.......................... 11,100
PFC-218 (Perfluoropropane)................... 76-19-7 C3F8.......................... 8,900
Perfluorocyclopropane........................ 931-91-9 c-C3F6........................ 9,200
PFC-3-1-10 (Perfluorobutane)................. 355-25-9 C4F10......................... 9,200
PFC-318 (Perfluorocyclobutane)............... 115-25-3 c-C4F8........................ 9,540
Perfluorotetrahydrofuran..................... 773-14-8 c-C4F8O....................... 13,900
PFC-4-1-12 (Perfluoropentane)................ 678-26-2 C5F12......................... 8,550
PFC-5-1-14 (Perfluorohexane, FC-72).......... 355-42-0 C6F14......................... 7,910
PFC-6-1-12................................... 335-57-9 C7F16; CF3(CF2)5CF3........... 7,820
PFC-7-1-18................................... 307-34-6 C8F18; CF3(CF2)6CF3........... 7,620
PFC-9-1-18................................... 306-94-5 C10F18........................ 7,190
PFPMIE (HT-70)............................... NA CF3OCF(CF3)CF2OCF2OCF3........ 9,710
Perfluorodecalin (cis)....................... 60433-11-6 Z-C10F18...................... 7,240
Perfluorodecalin (trans)..................... 60433-12-7 E-C10F18...................... 6,290
Perfluorotriethylamine....................... 359-70-6 N(C2F5)3...................... 10,300
Perfluorotripropylamine...................... 338-83-0 N(CF2CF2CF3)3................. 9,030
Perfluorotributylamine....................... 311-89-7 N(CF2CF2CF2CF3)3.............. 8,490
Perfluorotripentylamine...................... 338-84-1 N(CF2CF2CF2CF2CF3)3........... 7,260
----------------------------------------------------------------------------------------------------------------
Saturated Hydrofluorocarbons (HFCs) With Two or Fewer Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
(4s,5s)-1,1,2,2,3,3,4,5- 158389-18-5 trans-cyc (-CF2CF2CF2CHFCHF-). 258
octafluorocyclopentane.
HFC-23....................................... 75-46-7 CHF3.......................... 12,400
HFC-32....................................... 75-10-5 CH2F2......................... 677
HFC-125...................................... 354-33-6 C2HF5......................... 3,170
HFC-134...................................... 359-35-3 C2H2F4........................ 1,120
HFC-134a..................................... 811-97-2 CH2FCF3....................... 1,300
HFC-227ca.................................... 220732-84-8 CF3CF2CHF2.................... 2,640
HFC-227ea.................................... 431-89-0 C3HF7......................... 3,350
HFC-236cb.................................... 677-56-5 CH2FCF2CF3.................... 1,210
HFC-236ea.................................... 431-63-0 CHF2CHFCF3.................... 1,330
HFC-236fa.................................... 690-39-1 C3H2F6........................ 8,060
HFC-329p..................................... 375-17-7 CHF2CF2CF2CF3................. 2,360
HFC-43-10mee................................. 138495-42-8 CF3CFHCFHCF2CF3............... 1,650
----------------------------------------------------------------------------------------------------------------
Saturated Hydrofluorocarbons (HFCs) With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
1,1,2,2,3,3-hexafluorocyclopentane........... 123768-18-3 cyc (-CF2CF2CF2CH2CH2-)....... 120
1,1,2,2,3,3,4-heptafluorocyclopentane........ 1073290-77-4 cyc (-CF2CF2CF2CHFCH2-)....... 231
HFC-41....................................... 593-53-3 CH3F.......................... 116
HFC-143...................................... 430-66-0 C2H3F3........................ 328
HFC-143a..................................... 420-46-2 C2H3F3........................ 4,800
HFC-10732.................................... 624-72-6 CH2FCH2F...................... 16
HFC-10732a................................... 75-37-6 CH3CHF2....................... 138
HFC-161...................................... 353-36-6 CH3CH2F....................... 4
HFC-245ca.................................... 679-86-7 C3H3F5........................ 716
HFC-245cb.................................... 1814-88-6 CF3CF2CH3..................... 4,620
HFC-245ea.................................... 24270-66-4 CHF2CHFCHF2................... 235
HFC-245eb.................................... 431-31-2 CH2FCHFCF3.................... 290
HFC-245fa.................................... 460-73-1 CHF2CH2CF3.................... 858
HFC-263fb.................................... 421-07-8 CH3CH2CF3..................... 76
HFC-272ca.................................... 420-45-1 CH3CF2CH3..................... 144
HFC-365mfc................................... 406-58-6 CH3CF2CH2CF3.................. 804
----------------------------------------------------------------------------------------------------------------
Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) With One Carbon-Hydrogen Bond
----------------------------------------------------------------------------------------------------------------
HFE-125...................................... 3822-68-2 CHF2OCF3...................... 12,400
HFE-227ea.................................... 2356-62-9 CF3CHFOCF3.................... 6,450
HFE-329mcc2.................................. 134769-21-4 CF3CF2OCF2CHF2................ 3,070
HFE-329me3................................... 428454-68-6 CF3CFHCF2OCF3................. 4,550
1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2- 3330-15-2 CF3CF2CF2OCHFCF3.............. 6,490
tetrafluoroethoxy)-propane.
----------------------------------------------------------------------------------------------------------------
Saturated HFEs and HCFEs With Two Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-134 (HG-00).............................. 1691-17-4 CHF2OCHF2..................... 5,560
HFE-236ca.................................... 32778-11-3 CHF2OCF2CHF2.................. 4,240
HFE-236ca12 (HG-10).......................... 7807322-47-1 CHF2OCF2OCHF2................. 5,350
HFE-236ea2 (Desflurane)...................... 57041-67-5 CHF2OCHFCF3................... 1,790
HFE-236fa.................................... 20193-67-3 CF3CH2OCF3.................... 979
[[Page 31813]]
HFE-338mcf2.................................. 156053-88-2 CF3CF2OCH2CF3................. 929
HFE-338mmz1.................................. 26103-08-2 CHF2OCH(CF3)2................. 2,620
HFE-338pcc13 (HG-01)......................... 188690-78-0 CHF2OCF2CF2OCHF2.............. 2,910
HFE-43-10pccc (H-Galden 1040x, HG-11)........ E1730133 CHF2OCF2OC2F4OCHF2............ 2,820
HCFE-235ca2 (Enflurane)...................... 13838-16-9 CHF2OCF2CHFCl................. 583
HCFE-235da2 (Isoflurane)..................... 26675-46-7 CHF2OCHClCF3.................. 491
HG-02........................................ 205367-61-9 HF2C-(OCF2CF2)2-OCF2H......... 2,730
HG-03........................................ 173350-37-3 HF2C-(OCF2CF2)3-OCF2H......... 2,850
HG-20........................................ 249932-25-0 HF2C-(OCF2)2-OCF2H............ 5,300
HG-21........................................ 249932-26-1 HF2C-OCF2CF2OCF2OCF2O-CF2H.... 3,890
HG-30........................................ 188690-77-9 HF2C-(OCF2)3-OCF2H............ 7,330
1,1,3,3,4,4, 6,6,7,7,9,9, 10,10,12,12, 173350-38-4 HCF2O(CF2CF2O)4CF2H........... 3,630
13,13,15, 15-eicosafluoro-2,5,8,11,14-
Pentaoxapentadecane.
1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane.. 84011-06-3 CHF2CHFOCF3................... 1,240
Trifluoro(fluoromethoxy)methane.............. 2261-01-0 CH2FOCF3...................... 751
----------------------------------------------------------------------------------------------------------------
Saturated HFEs and HCFEs With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-143a..................................... 421-14-7 CH3OCF3....................... 523
HFE-245cb2................................... 22410-44-2 CH3OCF2CF3.................... 654
HFE-245fa1................................... 84011-15-4 CHF2CH2OCF3................... 828
HFE-245fa2................................... 1885-48-9 CHF2OCH2CF3................... 812
HFE-254cb1................................... 425-88-7 CH3OCF2CHF2................... 301
HFE-263fb2................................... 460-43-5 CF3CH2OCH3.................... 1
HFE-263m1; R-E-143a.......................... 690-22-2 CF3OCH2CH3.................... 29
HFE-347mcc3 (HFE-7000)....................... 375-03-1 CH3OCF2CF2CF3................. 530
HFE-347mcf2.................................. 171182-95-9 CF3CF2OCH2CHF2................ 854
HFE-347mmy1.................................. 2200732-84-2 CH3OCF(CF3)2.................. 363
HFE-347mmz1 (Sevoflurane).................... 2807323-86-6 (CF3)2CHOCH2F................. 216
HFE-347pcf2.................................. 406-78-0 CHF2CF2OCH2CF3................ 889
HFE-356mec3.................................. 382-34-3 CH3OCF2CHFCF3................. 387
HFE-356mff2.................................. 333-36-8 CF3CH2OCH2CF3................. 17
HFE-356mmz1.................................. 13171-18-1 (CF3)2CHOCH3.................. 14
HFE-356pcc3.................................. 160620-20-2 CH3OCF2CF2CHF2................ 413
HFE-356pcf2.................................. 50807-77-7 CHF2CH2OCF2CHF2............... 719
HFE-356pcf3.................................. 35042-99-0 CHF2OCH2CF2CHF2............... 446
HFE-365mcf2.................................. 2200732-81-9 CF3CF2OCH2CH3................. 58
HFE-365mcf3.................................. 378-16-5 CF3CF2CH2OCH3................. 0.99
HFE-374pc2................................... 512-51-6 CH3CH2OCF2CHF2................ 627
HFE-449s1 (HFE-7100) Chemical blend.......... 163702-07-6 C4F9OCH3...................... 421
163702-08-7 (CF3)2CFCF2OCH3...............
HFE-569sf2 (HFE-7200) Chemical blend......... 163702-05-4 C4F9OC2H5..................... 57
163702-06-5 (CF3)2CFCF2OC2H5..............
HFE-7300..................................... 132182-92-4 (CF3)2CFCFOC2H5CF2CF2CF3...... 405
HFE-7500..................................... 297730-93-9 n-C3F7CFOC2H5CF(CF3)2......... 13
HG'-01....................................... 73287-23-7 CH3OCF2CF2OCH3................ 222
HG'-02....................................... 485399-46-0 CH3O(CF2CF2O)2CH3............. 236
HG'-03....................................... 485399-48-2 CH3O(CF2CF2O)3CH3............. 221
Difluoro(methoxy)methane..................... 359-15-9 CH3OCHF2...................... 144
2-Chloro-1,1,2-trifluoro-1-methoxyethane..... 425-87-6 CH3OCF2CHFCl.................. 122
1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane.... 22052-86-4 CF3CF2CF2OCH2CH3.............. 61
2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5- 920979-28-8 C12H5F19O2.................... 56
bis[1,2,2,2-tetrafluoro-1-
(trifluoromethyl)ethyl]-furan.
1-Ethoxy-1,1,2,3,3,3-hexafluoropropane....... 380-34-7 CF3CHFCF2OCH2CH3.............. 23
Fluoro(methoxy)methane....................... 460-22-0 CH3OCH2F...................... 13
1,1,2,2-Tetrafluoro-3-methoxy-propane; Methyl 60598-17-6 CHF2CF2CH2OCH3................ 0.49
2,2,3,3-tetrafluoropropyl ether.
1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane.. 37031-31-5 CH2FOCF2CF2H.................. 871
Difluoro(fluoromethoxy)methane............... 461-63-2 CH2FOCHF2..................... 617
Fluoro(fluoromethoxy)methane................. 462-51-1 CH2FOCH2F..................... 130
----------------------------------------------------------------------------------------------------------------
Saturated Chlorofluorocarbons (CFCs)
----------------------------------------------------------------------------------------------------------------
E-R316c...................................... 3832-15-3 trans-cyc (-CClFCF2CF2CClF-).. 4,230
Z-R316c...................................... 3934-26-7 cis-cyc (-CClFCF2CF2CClF-).... 5,660
----------------------------------------------------------------------------------------------------------------
Fluorinated Formates
----------------------------------------------------------------------------------------------------------------
Trifluoromethyl formate...................... 85358-65-2 HCOOCF3....................... 588
Perfluoroethyl formate....................... 313064-40-3 HCOOCF2CF3.................... 580
1,2,2,2-Tetrafluoroethyl formate............. 481631-19-0 HCOOCHFCF3.................... 470
Perfluorobutyl formate....................... 197218-56-7 HCOOCF2CF2CF2CF3.............. 392
Perfluoropropyl formate...................... 271257-42-2 HCOOCF2CF2CF3................. 376
1,1,1,3,3,3-Hexafluoropropan-2-yl formate.... 856766-70-6 HCOOCH(CF3)2.................. 333
2,2,2-Trifluoroethyl formate................. 32042-38-9 HCOOCH2CF3.................... 33
3,3,3-Trifluoropropyl formate................ 1344118-09-7 HCOOCH2CH2CF3................. 17
----------------------------------------------------------------------------------------------------------------
Fluorinated Acetates
----------------------------------------------------------------------------------------------------------------
Methyl 2,2,2-trifluoroacetate................ 431-47-0 CF3COOCH3..................... 52
1,1-Difluoroethyl 2,2,2-trifluoroacetate..... 1344118-13-3 CF3COOCF2CH3.................. 31
Difluoromethyl 2,2,2-trifluoroacetate........ 2024-86-4 CF3COOCHF2.................... 27
[[Page 31814]]
2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate.. 407-38-5 CF3COOCH2CF3.................. 7
Methyl 2,2-difluoroacetate................... 433-53-4 HCF2COOCH3.................... 3
Perfluoroethyl acetate....................... 343269-97-6 CH3COOCF2CF3.................. 2
Trifluoromethyl acetate...................... 74123-20-9 CH3COOCF3..................... 2
Perfluoropropyl acetate...................... 1344118-10-0 CH3COOCF2CF2CF3............... 2
Perfluorobutyl acetate....................... 209597-28-4 CH3COOCF2CF2CF2CF3............ 2
Ethyl 2,2,2-trifluoroacetate................. 383-63-1 CF3COOCH2CH3.................. 1
----------------------------------------------------------------------------------------------------------------
Carbonofluoridates
----------------------------------------------------------------------------------------------------------------
Methyl carbonofluoridate..................... 1538-06-3 FCOOCH3....................... 95
1,1-Difluoroethyl carbonofluoridate.......... 1344118-11-1 FCOOCF2CH3.................... 27
----------------------------------------------------------------------------------------------------------------
Fluorinated Alcohols Other Than Fluorotelomer Alcohols
----------------------------------------------------------------------------------------------------------------
Bis(trifluoromethyl)-methanol................ 920-66-1 (CF3)2CHOH.................... 182
2,2,3,3,4,4,5,5-Octafluorocyclopentanol...... 16621-87-7 cyc (-(CF2)4CH(OH)-).......... 13
2,2,3,3,3-Pentafluoropropanol................ 422-05-9 CF3CF2CH2OH................... 19
2,2,3,3,4,4,4-Heptafluorobutan-1-ol.......... 375-01-9 C3F7CH2OH..................... 34
2,2,2-Trifluoroethanol....................... 75-89-8 CF3CH2OH...................... 20
2,2,3,4,4,4-Hexafluoro-1-butanol............. 382-31-0 CF3CHFCF2CH2OH................ 17
2,2,3,3-Tetrafluoro-1-propanol............... 76-37-9 CHF2CF2CH2OH.................. 13
2,2-Difluoroethanol.......................... 359-13-7 CHF2CH2OH..................... 3
2-Fluoroethanol.............................. 371-62-0 CH2FCH2OH..................... 1.1
4,4,4-Trifluorobutan-1-ol.................... 461-18-7 CF3(CH2)2CH2OH................ 0.05
----------------------------------------------------------------------------------------------------------------
Non-Cyclic, Unsaturated Perfluorocarbons (PFCs)
----------------------------------------------------------------------------------------------------------------
PFC-1114; TFE................................ 116-14-3 CF2=CF2; C2F4................. 0.004
PFC-1216; Dyneon HFP......................... 116-15-4 C3F6; CF3CF=CF2............... 0.05
Perfluorobut-2-ene........................... 360-89-4 CF3CF=CFCF3................... 1.82
Perfluorobut-1-ene........................... 357-26-6 CF3CF2CF=CF2.................. 0.10
Perfluorobuta-1,3-diene...................... 685-63-2 CF2=CFCF=CF2.................. 0.003
----------------------------------------------------------------------------------------------------------------
Non-Cyclic, Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs)
----------------------------------------------------------------------------------------------------------------
HFC-1132a; VF2............................... 75-38-7 C2H2F2, CF2=CH2............... 0.04
HFC-1141; VF................................. 75-02-5 C2H3F, CH2=CHF................ 0.02
(E)-HFC-1225ye............................... 5595-10-8 CF3CF=CHF(E).................. 0.06
(Z)-HFC-1225ye............................... 507328-43-8 CF3CF=CHF(Z).................. 0.22
Solstice 1233zd(E)........................... 102687-65-0 C3H2ClF3; CHCl=CHCF3.......... 1.34
HCFO-1233zd(Z)............................... 99728-16-2 (Z)-CF3CH=CHCl................ 0.45
HFC-1234yf; HFO-1234yf....................... 754-12-1 C3H2F4; CF3CF=CH2............. 0.31
HFC-1234ze(E)................................ 1645-83-6 C3H2F4; trans-CF3CH=CHF....... 0.97
HFC-1234ze(Z)................................ 29118-25-0 C3H2F4; cis-CF3CH=CHF; 0.29
CF3CH=CHF.
HFC-1243zf; TFP.............................. 677-21-4 C3H3F3, CF3CH=CH2............. 0.12
(Z)-HFC-1336................................. 692-49-9 CF3CH=CHCF3(Z)................ 1.58
HFO-1336mzz(E)............................... 66711-86-2 (E)-CF3CH=CHCF3............... 18
HFC-1345zfc.................................. 374-27-6 C2F5CH=CH2.................... 0.09
HFO-1123..................................... 359-11-5 CHF=CF2....................... 0.005
HFO-1438ezy(E)............................... 14149-41-8 (E)-(CF3)2CFCH=CHF............ 8.2
HFO-1447fz................................... 355-08-8 CF3(CF2)2CH=CH2............... 0.24
Capstone 42-U................................ 19430-93-4 C6H3F9, CF3(CF2)3CH=CH2....... 0.16
Capstone 62-U................................ 2073291-17-2 C8H3F13, CF3(CF2)5CH=CH2...... 0.11
Capstone 82-U................................ 2160732-58-4 C10H3F17, CF3(CF2)7CH=CH2..... 0.09
(e)-1-chloro-2-fluoroethene.................. 460-16-2 (E)-CHCl=CHF.................. 0.004
3,3,3-trifluoro-2-(trifluoromethyl)prop-1-ene 382-10-5 (CF3)2C=CH2................... 0.38
----------------------------------------------------------------------------------------------------------------
Non-Cyclic, Unsaturated CFCs
----------------------------------------------------------------------------------------------------------------
CFC-1112..................................... 598-88-9 CClF=CClF..................... 0.13
CFC-1112a.................................... 79-35-6 CCl2=CF2...................... 0.021
----------------------------------------------------------------------------------------------------------------
Non-Cyclic, Unsaturated Halogenated Ethers
----------------------------------------------------------------------------------------------------------------
PMVE; HFE-216................................ 1187-93-5 CF3OCF=CF2.................... 0.17
Fluoroxene................................... 406-90-6 CF3CH2OCH=CH2................. 0.05
Methyl-perfluoroheptene-ethers............... N/A CH3OC7F13..................... 15
----------------------------------------------------------------------------------------------------------------
Non-Cyclic, Unsaturated Halogenated Esters
----------------------------------------------------------------------------------------------------------------
Ethenyl 2,2,2-trifluoroacetate............... 433-28-3 CF3COOCH=CH2.................. 0.008
Prop-2-enyl 2,2,2-trifluoroacetate........... 383-67-5 CF3COOCH2CH=CH2............... 0.007
----------------------------------------------------------------------------------------------------------------
Cyclic, Unsaturated HFCs and PFCs
----------------------------------------------------------------------------------------------------------------
PFC C-1418................................... 559-40-0 c-C5F8........................ 2
Hexafluorocyclobutene........................ 697-11-0 cyc (-CF=CFCF2CF2-)........... 126
1,3,3,4,4,5,5-heptafluorocyclopentene........ 1892-03-1 cyc (-CF2CF2CF2CF=CH-)........ 45
1,3,3,4,4-pentafluorocyclobutene............. 374-31-2 cyc (-CH=CFCF2CF2-)........... 92
3,3,4,4-tetrafluorocyclobutene............... 2714-38-7 cyc (-CH=CHCF2CF2-)........... 26
----------------------------------------------------------------------------------------------------------------
[[Page 31815]]
Fluorinated Aldehydes
----------------------------------------------------------------------------------------------------------------
3,3,3-Trifluoro-propanal..................... 460-40-2 CF3CH2CHO..................... 0.01
----------------------------------------------------------------------------------------------------------------
Fluorinated Ketones
----------------------------------------------------------------------------------------------------------------
Novec 1230 (perfluoro (2-methyl-3-pentanone)) 756-13-8 CF3CF2C(O)CF(CF3)2............ 0.1
1,1,1-trifluoropropan-2-one.................. 421-50-1 CF3COCH3...................... 0.09
1,1,1-trifluorobutan-2-one................... 381-88-4 CF3COCH2CH3................... 0.095
----------------------------------------------------------------------------------------------------------------
Fluorotelomer
----------------------------------------------------------------------------------------------------------------
3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-ol 185689-57-0 CF3(CF2)4CH2CH2OH............. 0.43
3,3,3-Trifluoropropan-1-ol................... 2240-88-2 CF3CH2CH2OH................... 0.35
3,3,4,4,5,5,6,6,7,7,8,8,9,9,9- 755-02-2 CF3(CF2)6CH2CH2OH............. 0.33
Pentadecafluorononan-1-ol.
3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11- 87017-97-8 CF3(CF2)8CH2CH2OH............. 0.19
Nonadecafluoroundecan-1-ol.
----------------------------------------------------------------------------------------------------------------
Fluorinated GHGs With Carbon-Iodine Bond(s)
----------------------------------------------------------------------------------------------------------------
Trifluoroiodomethane......................... 2314-97-8 CF3I.......................... 0.4
----------------------------------------------------------------------------------------------------------------
Remaining Fluorinated GHGs with Chemical-Specific GWPs
----------------------------------------------------------------------------------------------------------------
Dibromodifluoromethane (Halon 1202).......... 75-61-6 CBr2F2........................ 231
2-Bromo-2-chloro-1,1,1-trifluoroethane (Halon- 151-67-7 CHBrClCF3..................... 41
2311/Halothane).
Heptafluoroisobutyronitrile.................. 42532-60-5 (CF3)2CFCN.................... 2,750
Carbonyl fluoride............................ 353-50-4 COF2.......................... 0.14
----------------------------------------------------------------------------------------------------------------
As proposed, we are also amending table A-1 to subpart A of part 98
to revise the default GWPs. We are modifying the default GWP groups to
add a group for saturated CFCs and a group for cyclic forms of
unsaturated halogenated compounds. Based on the numerical differences
between the GWP for cyclic unsaturated halogenated compounds and non-
cyclic unsaturated halogenated compounds, we are also modifying the
ninth F-GHG group to reflect non-cyclic forms of unsaturated
halogenated compounds. The amendments update the default GWPs of each
group based on the average of the updated chemical-specific GWPs
(adopted from either the IPCC AR5 or AR6) for the compounds that belong
to that group. We are also finalizing our proposal to rename the
fluorinated GHG group ``Other fluorinated GHGs'' to ``Remaining
fluorinated GHGs.'' The new and revised fluorinated GHG groups and
their new and revised GWPs are listed in table 3 of this preamble.
Table 3--Fluorinated GHG Groups and Default GWPs for Table A-1
------------------------------------------------------------------------
Fluorinated GHG group GWP (100-year)
------------------------------------------------------------------------
Fully fluorinated GHGs.................... 9,200
Saturated hydrofluorocarbons (HFCs) with 3,000
two or fewer carbon-hydrogen bonds.
Saturated HFCs with three or more carbon- 840
hydrogen bonds.
Saturated hydrofluoroethers (HFEs) and 6,600
hydrochlorofluoroethers (HCFEs) with one
carbon-hydrogen bond.
Saturated HFEs and HCFEs with two carbon- 2,900
hydrogen bonds.
Saturated HFEs and HCFEs with three or 320
more carbon-hydrogen bonds.
Saturated chlorofluorocarbons (CFCs)...... 4,900
Fluorinated formates...................... 350
Cyclic forms of the following: unsaturated 58
perfluorocarbons (PFCs), unsaturated
HFCs, unsaturated CFCs, unsaturated
hydrochlorofluorocarbons (HCFCs),
unsaturated bromofluorocarbons (BFCs),
unsaturated bromochlorofluorocarbons
(BCFCs), unsaturated
hydrobromofluorocarbons (HBFCs),
unsaturated hydrobromochlorofluorocarbons
(HBCFCs), unsaturated halogenated ethers,
and unsaturated halogenated esters.
Fluorinated acetates, carbonofluoridates, 25
and fluorinated alcohols other than
fluorotelomer alcohols.
Fluorinated aldehydes, fluorinated 1
ketones, and non-cyclic forms of the
following: unsaturated PFCs, unsaturated
HFCs, unsaturated CFCs, unsaturated
HCFCs, unsaturated BFCs, unsaturated
BCFCs, unsaturated HBFCs, unsaturated
HBCFCs, unsaturated halogenated ethers,
and unsaturated halogenated esters.
Fluorotelomer alcohols.................... 1
Fluorinated GHGs with carbon-iodine 1
bond(s).
Remaining fluorinated GHGs................ 1,800
------------------------------------------------------------------------
b. Other Revisions To Improve the Quality of Data Collected for Subpart
A
The EPA is finalizing several revisions to improve the quality of
data collected for subpart A as proposed. In some cases, we are
finalizing the proposed amendments with revisions. First, we are
clarifying in 40 CFR 98.2(i)(1) and (2), as proposed, that the
provision to allow cessation of reporting or ``off-ramping,'' due to
meeting either the 15,000 mtCO2e level or the 25,000
mtCO2e level for the number of years specified in 40 CFR
98.2(i), is based on the CO2e reported, calculated in
accordance with 40 CFR 98.3(c)(4)(i) (i.e., the annual emissions report
value as specified in that provision). The final amendments also
clarify that after an
[[Page 31816]]
owner or operator off-ramps, the owner or operator must use equation A-
1 to subpart A and follow the requirements of 40 CFR 98.2(b)(4) (the
emission estimation methods used for determination of applicability) in
subsequent years to determine if emissions exceed the 25,000
mtCO2e applicability threshold and whether the facility or
supplier must resume reporting.
Additionally, the EPA is amending 40 CFR 98.2(f)(1) and adding new
paragraph (k) as proposed to clarify the calculation of GHG quantities
for comparison to the 25,000 mtCO2e threshold for importers
and exporters of industrial greenhouse gases. The final amendments to
40 CFR 98.2(f)(1) state that importers and exporters must include the
F-HTFs that are imported or exported during the year. New paragraph (k)
specifies how to calculate the quantities of F-GHGs and F-HTFs
destroyed for purposes of comparing them to the 25,000
mtCO2e threshold for stand-alone industrial F-GHG or F-HTF
destruction facilities. The EPA is also finalizing as proposed
revisions to 40 CFR 98.3(h)(4) to limit the total number of days a
reporter can request to extend the time period for resolving a
substantive error, either by submitting a revised report or providing
information demonstrating that the previously submitted report does not
contain the substantive error, to 180 days. Specifically, the
Administrator will only approve extension requests for a total of 180
days from the initial notification of a substantive error. See section
III.A.1. of the preamble to the 2022 Data Quality Improvements Proposal
for additional information on these revisions and their supporting
basis.
We are finalizing minor clarifications to the reporting and special
provisions for best available monitoring methods in 40 CFR 98.3(k) and
(l) as proposed, which apply to owners or operators of facilities or
suppliers that first become subject to any subpart of part 98 due to
amendment(s) to table A-1 to subpart A. The final requirements revise
the term ``published'' to add ``in the Federal Register as a final
rulemaking'' to clarify the EPA's intent that the requirements apply to
facilities or suppliers that are first subject to the GHGRP in the year
after the year the GWP is published as part of a final rule.
The EPA is finalizing an additional edit to subpart A to the
electronic reporting provisions of 40 CFR 98.5(b). The revisions
clarify that 40 CFR 98.5(b) applies to any data that is specified as
verification software records in a subpart's applicable recordkeeping
section.
The EPA is finalizing several revisions to subpart A to incorporate
new and revised source categories. We are revising tables A-3 and A-4
to subpart A to clarify the reporting applicability for facilities
included in the new source categories of coke calcining; ceramics
manufacturing; calcium carbide production; caprolactam, glyoxal, and
glyoxylic acid production; and facilities conducting geologic
sequestration of carbon dioxide with enhanced oil recovery. We are
revising table A-3 to subpart A to add new subparts that are ``all-in''
source categories, including subpart VV (Geologic Sequestration of
Carbon Dioxide with Enhanced Oil Recovery Using ISO 27916) (section
III.AA. of this preamble), subpart WW (Coke Calciners) (section III.BB.
of this preamble), subpart XX (Calcium Carbide Production) (section
III.CC. of this preamble), and subpart YY (Caprolactam, Glyoxal, and
Glyoxylic Acid Production) (section III.DD. of this preamble). We are
revising table A-4 to add new subpart ZZ (Ceramics Manufacturing) and
assign a threshold of 25,000 mtCO2e, as proposed. As
discussed in section III.EE. of this preamble, subpart ZZ to part 98
applies to certain ceramics manufacturing processes that exceed a
minimum production level (i.e., annually consume at least 2,000 tons of
carbonates, either as raw materials or as a constituent in clay, heated
to a temperature sufficient to allow the calcination reaction to occur)
and that exceed the 25,000 mtCO2e threshold. The revisions
to tables A-3 and A-4 to subpart A clarify that these new source
categories apply in RY2025 and future years.
The EPA is finalizing several revisions to defined terms in 40 CFR
98.6 as proposed to provide further clarity. These revisions to
definitions include:
Revising the definition of ``bulk'' to clarify that the
import and export of gas includes small containers and does not exclude
a minimum container size below which reporting will not be required
(except for small shipments (i.e., those including less than 25
kilograms)), and to align with the definition of ``bulk'' under the
American Innovation and Manufacturing Act of 2020 (AIM) regulations at
40 CFR part 84.
Revising the definition of ``greenhouse gas or GHG'' to
clarify the treatment of fluorinated greenhouse gases by removing the
partial list of fluorinated GHGs currently included in the definition
and to simply refer to the definition of ``fluorinated greenhouse gas
(GHG).''
Adding the acronym ``(GHGs)'' after the term ``fluorinated
greenhouse gas'' both in the definition of ``greenhouse gas or GHG''
and in the definition of ``fluorinated greenhouse gas'' to avoid
redundancy and potential confusion between the definitions of
``greenhouse gas'' and ``fluorinated greenhouse gas.''
Consistent with the revisions of the fluorinated GHG
groups used to assign default GWPs discussed in section III.A.1.a. of
this preamble, adding a definition of ``cyclic'' as it applies to
molecular structures of various fluorinated GHGs; adding definitions of
``unsaturated chlorofluorocarbons (CFCs),'' ``saturated
chlorofluorocarbons (CFCs),'' ``unsaturated bromofluorocarbons
(BFCs),'' ``unsaturated bromochlorofluorocarbons (BCFCs),''
``unsaturated hydrobromofluorocarbons (HBFCs),'' and ``unsaturated
hydrobromochlorofluorocarbons (HBCFCs)''; and revising the definition
of ``fluorinated greenhouse (GHG) group'' to include the new and
revised groups.
Revising the term ``other fluorinated GHGs'' to
``remaining fluorinated GHGs'' and to revise the definition of the term
to reflect the new and revised fluorinated GHG groups discussed in
section III.A.1.a. of this preamble.
Revising the definition of ``fluorinated heat transfer
fluids'' and moving it from 40 CFR 98.98 to 98.6 to harmonize with
changes to subpart OO of part 98 (Suppliers of Industrial Greenhouse
Gases) (see section III.U. of this preamble). The revised definition
(1) explicitly includes industries other than electronics
manufacturing, and (2) excludes most HFCs which are widely used as heat
transfer fluids outside of electronics manufacturing and are regulated
under the AIM regulations at 40 CFR part 84.
Consistent with final revisions to subpart PP (Suppliers
of Carbon Dioxide) (see section III.V. of this preamble), we are
finalizing revisions to 40 CFR 98.6 to add a definition for ``Direct
air capture'' and to amend the definition of ``Carbon dioxide stream.''
The EPA is making one revision to the definitions in the final rule
from proposed to correct the definition of ``ASTM''. This change
updates the definition to include the current name of the standards
organization, ``ASTM, International''.
Consistent with final revisions to subparts Q (Iron and Steel
Production), VV (Geologic Sequestration of Carbon Dioxide with Enhanced
Oil Recovery Using ISO 27916), WW (Coke Calciners), and XX (Calcium
Carbide Production), we are finalizing revisions to 40 CFR
[[Page 31817]]
98.7 to incorporate by reference ASTM International (ASTM) E415-17,
Standard Test Method for Analysis of Carbon and Low-Alloy Steel by
Spark Atomic Emission Spectrometry (2017) (subpart Q); CSA/ANSI ISO
27916:19, Carbon dioxide capture, transportation and geological
storage--Carbon dioxide storage using enhanced oil recovery
(CO2-EOR) (2019) (subpart VV) (as proposed in the 2023
Supplemental Proposal); ASTM D3176-15 Standard Practice for Ultimate
Analysis of Coal and Coke (2015), ASTM D5291-16 Standard Test Methods
for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants (2016), ASTM D5373-21 Standard Test
Methods for Determination of Carbon, Hydrogen, and Nitrogen in Analysis
Samples of Coal and Carbon in Analysis Samples of Coal and Coke (2021),
and NIST HB 44-2023: Specifications, Tolerances, and Other Technical
Requirements For Weighing and Measuring Devices, 2023 edition (subpart
WW); and ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal (2008) and ASTM C25-06, Standard Test Methods for Chemical
Analysis of Limestone, Quicklime, and Hydrated Lime (2006) (subpart
XX). The EPA has revised the regulatory text of 40 CFR 98.7 from
proposal to incorporate these revisions and to reorganize the existing
referenced ASTM standards in alphanumeric order.
The EPA is not finalizing proposed amendments to subpart A from the
2022 Data Quality Improvements Proposal that correlate with proposed
amendments to subpart W of part 98 (Petroleum and Natural Gas Systems)
from the 2022 Data Quality Improvements Proposal in this action. As
noted in section I.C. of this preamble, the EPA has issued a subsequent
proposed rule for subpart W on August 1, 2023, and has reproposed
related amendments to subpart A in that action. Additionally, the EPA
is not taking final action at this time on proposed amendments to
subpart A from the 2023 Supplemental Proposal that were proposed
harmonizing revisions intended to integrate proposed subpart B (Energy
Consumption), including proposed reporting and recordkeeping under 40
CFR 98.2(a)(1), 98.3(c)(4), and 98.3(g)(5). Finally, we are not taking
final action, at this time, on proposed amendments to 40 CFR 98.7 to
incorporate by reference standards for electric metering. As discussed
in section III.B. of this document, the EPA is not taking final action
on subpart B at this time.
c. Revisions To Streamline and Improve Implementation for Subpart A
The EPA is finalizing several revisions to subpart A proposed in
the 2022 Data Quality Improvements Proposal that will streamline and
improve implementation for part 98. First, we are revising tables A-3
and table A-4 to subpart A to revise the applicability of subparts DD
(Electrical Transmission and Distribution Equipment Use) and SS
(Electrical Equipment Manufacture of Refurbishment) of part 98 as
proposed. For subpart DD, the final revisions to table A-3 change the
threshold such that facilities must account for the total estimated
emissions from F-GHGs, as determined under 40 CFR 98.301 (subpart DD),
for comparison to a threshold equivalent to 25,000 mtCO2e or
more per year. We are also moving subpart SS from table A-3 to table A-
4 to subpart A and specifying that subpart SS facilities must account
for emissions of F-GHGs, as determined under the requirements of 40 CFR
98.451 (subpart SS), for comparison to a threshold equivalent to 25,000
mtCO2e or more per year. The final rule updates the
threshold of subparts DD and SS to be consistent with the threshold set
for the majority of subparts under part 98, and accounts for additional
fluorinated gases (including F-GHG mixtures) reported by industry. For
subpart DD, these final changes also focus Agency resources on the
substantial emission sources within the sector by excluding facilities
or operations that may report emissions that are consistently and
substantially below 25,000 mtCO2e per year. See sections
III.Q. and III.Y. of this preamble for additional information.
2. Summary of Comments and Responses on Subpart A
This section summarizes the major comments and responses related to
the proposed amendments to subpart A. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart A.
a. Comments on Revisions To Global Warming Potentials
Comment: Several commenters supported the proposed revisions to
table A-1 to subpart A to update the GWP values to use values from
table 8.A.1 from the IPCC AR5, and for certain GHGs without GWP values
listed in AR5, to adopt values from the IPCC AR6. Commenters remarked
that the updates to the GWP values will be more accurate, align with
UNFCCC guidance and the Inventory, and provide consistency to reporters
who may also report under various voluntary standards, such as the GHG
Protocol or Sustainability Accounting Standards Board.
Some commenters requested that the EPA clarify the effects of
changing the GWP (particularly for CH4) on the reported
total CO2e emissions, despite any actual change in mass
emissions. The commenters asserted that it is important to inform
stakeholders that future increases in CO2e emissions due to
the change in GWP are not reflective of any actual mass emission
increases and may obscure decreases in annual mass emissions. The
commenters also recommended that the EPA acknowledge how combustion
CO2e emissions will be affected.
Response: In the final rule, the EPA is finalizing its proposal (in
the 2023 Supplemental Proposal) to adopt the 100-year GWPs from AR5,
and for certain GHGs without GWPs listed in AR5, to adopt values from
AR6. Regarding the commenters' concern that the change in GWPs may
result in apparent, but not real, upward or downward trends in the
data, the EPA has always published emissions using consistent GWPs for
every year and will continue to do so. Prior to publication, the EPA
updates all reported CO2e values to reflect the current GWP
values in table A-1 to subpart A of part 98. The CO2e
published by the EPA are based on the same GWP values across all
reporting years. Hence, there will be no apparent upward or downward
trend in emissions that are due only to a change in a GWP value.
Comment: A number of commenters supported the continued use of a
100-year GWP; one commenter stated that the 100-year GWP is consistent
with Article 2 of the UNFCCC and that any movement to a framework that
reduces the mitigation focus on CO2 emissions and adds to
long-term warming potential compared to the 100-year GWP framework
would not be well justified. Several commenters specifically commented
on the proposed GWP for CH4; a number of commenters
generally supported revising the CH4 GWP value from 25 to 28
using the 100-year GWP. Other commenters recommended that the EPA
consider incorporating GWP values on multiple time horizons in the
reporting requirement, or when publicizing reported emissions. One
[[Page 31818]]
commenter stated that the 100-year GWP does not capture the near-term
potency of short-lived gases like methane and hydrogen and is
insufficient to reflect a pollutant's warming power over time.
Commenters requested that the EPA incorporate the use of additional
time horizons, such as the 20-year GWP, to acknowledge the near-term
warming potency of short-lived gases such as CH4, because
they play a critical role in driving the rate of warming for the near
future. Commenters argued that the 20-year GWP more accurately
represents the powerful, short-term impact of methane on the
atmosphere. Commenters noted that this would also align with several
state regulatory programs, including California, New York, and New
Jersey, that currently consider 20-year GWPs. Commenters stressed that
adopting short-lived climate pollutant strategies and emissions
controls to limit near-term warming is critical from a policy
perspective and directly relevant to the EPA's efforts under the Clean
Air Act. Commenters also requested that historic inventories be updated
to reflect the role that short-lived climate pollutants play and to
demonstrate that near-term CH4 emissions reductions are as
important as long-term CO2 reductions.
Response: As has been the case since the inception of the GHGRP, we
are finalizing 100-year GWPs for all GHGs. As noted in the ``Response
to Comments on Final Rule, Volume 3: General Monitoring Approach, the
Need for Detailed Reporting, and Other General Rationale Comments''
(see Docket ID. No. EPA-HQ-OAR-2008-0508-2260), the EPA selected the
100-year GWPs because these values are the internationally accepted
standard for reporting GHG emissions. For example, the parties to the
UNFCCC agreed to use GWPs that are based on a 100-year time period for
preparing national inventories, and the reports submitted by other
signatories to the UNFCCC use GWPs based on a 100-year time period,
including the GWP for CH4 and certain GHGs identified as
short-lived climate pollutants. These values were subsequently adopted
and used in multiple EPA climate initiatives, including the EPA's
Significant New Alternatives Policy (SNAP) program and the Inventory,
as well as EPA voluntary reduction partnerships (e.g., Natural Gas
STAR). Human-influenced climate change occurs on both short (decadal)
and long (millennial) time scales. While there is no single best way to
value both short- and long-term impacts in a single metric, the 100-
year GWP is a reasonable approach that has been widely accepted by the
international community. If the EPA were to adopt a 20-year GWP solely
for CH4, or for certain other compounds, it would introduce
a metric that is inconsistent with both the GWPs used for the remaining
table A-1 gases and with the reporting guidelines issued by the UNFCCC
and used by the Inventory and other EPA programs. Additionally, the EPA
and other Federal agencies, which calculate the impact of short-lived
GHGs using 100-year GWPs, are making reduction of short-lived GHGs a
priority, such as through the U.S. Global Methane Initiative. In
addition, it is beneficial for both regulatory agencies and industry to
use the same GWP values for these GHG compounds because it allows for
more efficient review of data collected through the GHGRP and other
U.S. climate programs, reduces potential errors that may arise when
comparing multiple data sets or converting GHG emissions or supply
based on separate GWPs, and reduces the burden for reporters and
agencies to keep track of separate GWPs. For the reasons described
above, the EPA is retaining a 100-year time horizon as the standard
metric for defining GWPs in the GHGRP.
b. Comments on Other Revisions To Improve the Quality of Data Collected
for Subpart A
Comment: Several commenters opposed the EPA's proposed revisions to
40 CFR 98.3(h)(4) to limit the total number of days a reporter can
request to extend the time period for resolving a substantive error,
either by submitting a revised report or providing information
demonstrating that the previously submitted report does not contain the
substantive error, to 180 days. Commenters requested that the Agency
not put an inflexible cap on the number of days to resolve reporting
issues; the commenters asserted that the extensions can be helpful for
newly affected sources, when there is a change in facility ownership,
and in other situations. One commenter stated that the proposed
revision may result in arbitrarily short time-periods in which an
operator may correct an error, especially in cases where the correction
may not be accepted. The commenter contended that the EPA must add
additional language to clarify that the 180-day limit will restart if
the correction is not accepted. Commenters also requested that the EPA
increase the limit of the total number of days a reporter can request
an extension beyond the proposed 180 days to provide reporters more
time to work through the new provisions in the program. One commenter
requested the EPA restart the 180-day extension request opportunity for
each instance in which an operator is notified of a substantive error
or rejected correction (e.g., if a correction is rejected, if
additional corrections are requested, if corrections span more than one
reporting year, or if EPA responses to operator questions are delayed).
Response: The EPA expects that 180 days is a reasonable amount of
time for a facility to examine company records, gather additional data,
and/or perform recalculations to submit a revised report or provide the
necessary information such that the report may be verified. This
represents more than four 30-day additional extensions beyond the
initial 45-day period. As noted in the preamble to the final rule
promulgated on October 30, 2009 (74 FR 52620, hereafter referred to as
the ``2009 Final Rule''), the EPA concluded that this initial 45-day
period would be sufficient since facilities have three months from the
end of a reporting period to submit the initial annual report and have
already collected and retained data needed for the analyses, so
revisions to address a known error would likely require less time (see
74 FR 56278). A subsequent series of extensions of up to an additional
135 days is a reasonable amount of time to accommodate any additional
changes that may be needed to the revision.
B. Subpart B--Energy Consumption
The EPA is not taking final action on the proposed addition of
subpart B of part 98 (Energy Consumption) in this final rule. The EPA
received a number of comments for proposed subpart B. See the document
``Summary of Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to proposed
subpart B.
In the 2022 Data Quality Improvements Proposal, the EPA requested
comment on collecting data on energy consumption in order to improve
the quality of the data collected under the GHGRP. Specifically, we
provided background on the EPA's original request for comment on the
collection of data related to electricity consumption in the
development of part 98 and the EPA's response in the 2009 Final Rule,
and requested comment on whether and how the EPA should collect energy
consumption data in order to support data analyses related to informing
voluntary energy efficiency
[[Page 31819]]
programs, provide information on industrial sectors where currently
little data are reported to GHGRP, and inform quality assurance/quality
control (QA/QC) of the Inventory. We requested comment on specific
considerations for the potential addition of the energy consumption
source category (see section IV.F. of the preamble to the 2022 Data
Quality Improvements Proposal for additional information).
Following consideration of comments received in response to the
EPA's request for comment, we subsequently proposed, in the 2023
Supplemental Proposal, the addition of subpart B to part 98. At that
time, we reiterated our interest in collecting data on energy
consumption to gain an improved understanding of the energy intensity
(i.e., the amount of energy required to produce a given level of
product or activity, both through on-site energy produced from fuel
combustion and purchased energy) of specific facilities or sectors, and
to better inform our understanding of energy needs and the potential
indirect GHG emissions associated with certain sectors. The proposed
rule included specific monitoring and reporting requirements for direct
emitting facilities that report under part 98 and purchase metered
electricity or metered thermal energy products. In the proposed rule,
the EPA outlined a source category definition, rationale for the
proposed applicability of the subpart to direct emitting facilities in
lieu of a threshold, and specific monitoring, missing data,
recordkeeping, and reporting requirements. The EPA did not propose
requirements for facilities to calculate or report indirect emissions
estimates associated with purchased metered electricity or metered
thermal energy products. Additional information on the proposed
amendments is available in the preamble to the 2023 Supplemental
Proposal.
In response to the 2022 Data Quality Improvements Proposal and the
2023 Supplemental Proposal, the EPA received many comments on the
proposed subpart from a variety of stakeholders providing input on the
definition, applicability criteria, monitoring, reporting,
recordkeeping, and additional requirements of the source category, as
proposed, as well as a number of comments on the EPA's authority to
collect the energy consumption data proposed under subpart B. The EPA
is not taking final action on proposed subpart B at this time. The EPA
intends to further review and consider these comments and other
relevant information and may consider any next steps on the collection
of data related to energy consumption in a future rulemaking.
Therefore, none of the proposed requirements related to subpart B are
included in this final rule. The EPA is also not taking final action on
related amendments to subpart A (General Provisions) of part 98 that
were proposed harmonizing changes for the implementation subpart B,
including reporting requirements, as discussed in section III.A.1.b. of
this preamble.
C. Subpart C--General Stationary Fuel Combustion
The EPA is finalizing several amendments to subpart C of part 98
(General Stationary Fuel Combustion) as proposed. In some cases, we are
finalizing the proposed amendments with revisions. In other cases, we
are not taking final action on the proposed amendments. Section
III.C.1. of this preamble discusses the final revisions to subpart C.
The EPA received several comments on the proposed subpart C revisions
which are discussed in section III.C.2. of this preamble. We are also
finalizing as proposed confidentiality determinations for new data
elements resulting from the final revisions to subpart C, as described
in section VI. of this preamble.
1. Summary of Final Amendments to Subpart C
This section summarizes the final amendments to subpart C. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other
changes to 40 CFR part 98, subpart C can be found in this section and
section III.C.2. of this preamble. Additional rationale for these
amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal and 2023 Supplemental Proposal.
a. Revisions To Improve the Quality of Data Collected for Subpart C
The EPA is finalizing several revisions to improve the quality of
data collected for subpart C. First, the EPA is finalizing
modifications to the Tier 3 calculation methodology, including
revisions to 40 CFR 98.33(a)(3)(iii) to provide new equations C-5A and
C-5B, as proposed. The updated equations provide for calculating a
weighted annual average carbon content and a weighted annual average
molecular weight, respectively, and correct the calculation method for
Tier 3 gaseous fuels. The new equations incorporate the molar volume
conversion factor at standard conditions (as defined at 40 CFR 98.6)
and, for annual average carbon content, the measured molecular weight
of the fuel, in order to convert the fuel flow to the appropriate units
of measure. The final rule includes corrections to the proposed
paragraph references included in the definition of the variable ``MW''
(i.e., molecular weight) to equation C-5.
The EPA is also finalizing as proposed revisions to provisions
pertaining to the calculation of biogenic emissions from tire
combustion. These revisions include:
Removing the additional provision in 40 CFR
98.33(b)(1)(vii) on how to apply the threshold to only municipal solid
waste (MSW) fuel when MSW and tires are both combusted and the reporter
elects not to separately calculate and report biogenic CO2
emissions from the combustion of tires, since biogenic CO2
emissions from tire combustion must now be calculated and reported in
all cases;
Removing the language in 40 CFR 98.33(e) and
98.36(e)(2)(xi) referring to optional biogenic CO2 emissions
reporting from tire combustion;
Removing the restriction in 40 CFR 98.33(e)(3)(iv) that
the default factor that is used to determine biogenic CO2
emissions may only be used to estimate the annual biogenic
CO2 emissions from the combustion of tires if the combustion
of tires represents ``no more than 10 percent annual heat input to a
unit'';
Revising 40 CFR 98.33(e)(3)(iv)(A) so that total annual
CO2 emissions will be calculated using the applicable
methodology in 40 CFR 98.33(a)(1) through (3) for units using Tier 1
through 3 for purposes of 40 CFR 98.33(a), and using the Tier 1
calculation methodology in 40 CFR 98.33(a)(1) for units using the Tier
4 or part 75 calculation methodologies for purposes of 40 CFR 98.33(a),
when determining the biogenic component of MSW and/or tires under 40
CFR 98.33(e)(3)(iv);
Revising 40 CFR 98.33(e)(3)(iv)(B) to update the default
factor that is used to determine biogenic CO2 emissions from
the combustion of tires from 0.20 to 0.24; and
Correcting 40 CFR 98.34(d) to reference 40 CFR
98.33(e)(3)(iv) instead of 40 CFR 98.33(b)(1)(vi) and (vii) and
correcting 40 CFR 98.33(e)(1) to delete the parenthetical clause
``(except MSW and tires).''
These final revisions will update the default factor to be based on
more recent data collected on the average composition of natural rubber
in tires, remove potentially confusing or conflicting requirements, and
result in a more accurate characterization of biogenic emissions from
these sources.
[[Page 31820]]
See section III.B.1. of the preamble to the 2022 Data Quality
Improvements Proposal for additional information on these revisions and
their supporting basis. The EPA is also finalizing one additional
revision related to the estimation of biogenic emissions after
consideration of comments received on the 2022 Data Quality
Improvements Proposal. Commenters requested that the EPA expand the
monitoring requirements at 40 CFR 98.34(e) to include all combined
biomass and fossil fuels and to allow for testing at one source when a
common fuel is combusted. The EPA agrees that testing one emission
source is reasonable when multiple combustion units are fed from a
common fuel source. Accordingly, the EPA is revising 40 CFR 98.34(e) to
allow for quarterly ASTM D6866-16 and ASTM D7459-08 testing of one
representative unit for a common fuel source for all combined biomass
(or fuels with a biomass component) and fossil fuels. See section
III.C.2. of this preamble for additional information on related
comments and the EPA's response.
We are finalizing corrections to the variable ``R'' in equation C-
11. The term ``R'' is currently defined as ``The number of moles of
CO2 released upon capture of one mole of the acid gas
species being removed (R = 1.00 when the sorbent is CaCO3
and the targeted acid gas species is SO2)'' and is being
amended to ``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).'' We are finalizing
amendments to 40 CFR 98.33(c)(6)(i), (ii), (ii)(A), and (iii)(C), and
to remove and reserve 40 CFR 98.33(c)(6)(iii)(B) (to clarify the
methods used to calculate CH4 and N2O emissions
for blended fuels when heat input is determined after the fuels are
mixed and combusted), as proposed.
The EPA identified one additional minor correction to subpart C in
review of changes for the final rule. Subsequently, we are correcting
the definition of the term emission factor ``EF'' in equation C-10 from
``Fuel-specific emission factor for CH4 or N2O,
from table C-2 of this section'' to ``Fuel-specific emission factor for
CH4 or N2O, from table C-2 to this subpart.''
The EPA is finalizing as proposed two additional clarifications to
the reporting and recordkeeping requirements. We are revising the first
sentence of 40 CFR 98.36(e)(2)(ii)(C) to clarify that both the annual
average, and where applicable, monthly high heat values are required to
be reported. This change clarifies that the annual average high heat
value is also a reporting requirement (for reporters who do not use the
electronic inputs verification tool (IVT) within the e-GGRT). We are
finalizing revisions to the 40 CFR 98.37(b) introductory paragraph and
paragraphs (b)(9) through (11), (14), (18), (20), (22), and (23) to
specify recordkeeping data that is currently contained in the file
generated by the verification software that is already required to be
retained by reporters under 40 CFR 98.37(b). These revisions correct
omissions that currently exist in the verification software
recordkeeping requirements specific to equations C-2a, C-2b, C-3, C-4,
and C-5. They also align the verification software recordkeeping
requirements with the final revisions to equation C-5 at 40 CFR
98.33(a)(3)(iii).
In the 2022 Data Quality Improvements Proposal, we proposed
additional reporting requirements, for each unit greater than or equal
to 10 mmBtu/hour in either an aggregation of units or common pipe
configuration. The proposed reporting included, for each individual
unit with maximum rated heat input capacity greater than or equal to 10
mmBtu/hour included in the group, the unit type, maximum rated heat
input capacity, and an estimate of the fraction of the total group
annual heat input attributable to each unit (proposed 40 CFR
98.36(c)(1)(ii) and (c)(3)(xi)). Following consideration of public
comments, the EPA is not taking final action on the proposed reporting
requirements (i.e., identifying the unit type, maximum rated heat input
capacity, and fraction of the total annual heat input for each unit in
the aggregation of unit or common pipe). See section III.C.2. of this
preamble for a summary of the related comments and the EPA's response.
In the 2023 Supplemental Proposal, the EPA proposed to add a
requirement to report whether the unit is an EGU for each configuration
that reports emissions, under either the individual unit provisions at
40 CFR 98.36(b)(12) or the multi-unit provisions at 40 CFR
98.36(c)(1)(xii), (c)(2)(xii), and (c)(3)(xii). For multi-unit
reporting configurations, we also proposed adding a requirement for
facilities to report an estimated decimal fraction of total emissions
from the group that are attributable to EGU(s) included in the group.
Following consideration of public comments, the EPA is not taking final
action on the proposed revisions to the reporting requirements in this
rule. See section III.C.2. of this preamble for a summary of the
related comments and the EPA's response.
The EPA is also not taking final action in this final rule on
proposed revisions to subpart C correlated with proposed amendments to
subpart W (Petroleum and Natural Gas Systems). As noted in section I.C.
of this preamble, the EPA has issued a subsequent proposed rule for
subpart W on August 1, 2023 and has reproposed related amendments to
subpart C in that separate action.
b. Revisions To Streamline and Improve Implementation for Subpart C
The EPA is finalizing all revisions to streamline and improvement
implementation for subpart C as proposed. Specifically, the EPA is
finalizing (1) amendments to 40 CFR 98.34(c)(6) to allow cylinder gas
audits (CGAs) to be performed using calibration gas concentrations of
40-60 percent and 80-100 percent of CO2 span, whenever the
required CO2 span value for a flue gas does is not
appropriate for the prescribed audit ranges in appendix F of 40 CFR
part 60; and (2) amendments to provisions in 40 CFR 98.36(c)(1)(vi) and
98.36(c)(3)(vi) to remove language requiring that facilities with the
aggregation of units or common pipe configuration types report the
total annual CO2 mass emissions from all fossil fuels
combined. See section III.B.2. of the preamble to the 2022 Data Quality
Improvements Proposal for additional information on these changes and
their supporting basis.
2. Summary of Comments and Responses on Subpart C
This section summarizes the major comments and responses related to
the proposed amendments to subpart C. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart C.
Comment: One commenter provided a correction to the proposed
revisions to equation C-5 related to the revisions to the Tier 3
calculation methodology. The commenter noted that the proposed
revisions to variable ``MW'' of equation C-5 which specify the
procedures to be used to determine the annual average molecular weight
included an incorrect reference to paragraphs (a)(3)(iii)(A)(3) and
(4), and should point to (a)(3)(iii)(B)(1) and (2).
Response: We agree that the proposal inadvertently contained
incorrect cross-references for the variable ``MW'' of equation C-5, and
the EPA has corrected these cross-references in the final rule.
Comment: Commenters generally supported the EPA's proposed
revisions
[[Page 31821]]
to update the calculation methodology for biogenic emissions from tire
combustion. One commenter requested that the EPA consider expanding the
requirements of 40 CFR 98.34(e), which requires quarterly testing to
determine biogenic CO2 when biomass and non-biogenic fuels
are co-fired in a unit. The commenter noted that 40 CFR 98.34(e)
currently allows for testing of a single representative unit for
facilities with multiple units in which tires are the primary fuel
combusted and the units are fed from a common fuel source. The
commenter noted that for facilities with multiple units combusting the
same fuel, testing each source quarterly imposes an additional burden
without enhancing the accuracy of reported emissions. The commenter
requested that the EPA expand the provisions to include all combined
biomass and fossil fuels and to allow for testing one representative
unit when fuel from a common fuel source is combusted.
Response: The EPA acknowledges the commenter's support for the
proposed revisions. The EPA agrees with the commenter that testing one
emission source when multiple emission sources are fed from a common
fuel source should be allowed for all combined biomass (or fuels with a
biomass component) and fossil fuels. Accordingly, the EPA has finalized
quarterly ASTM D6866-16 and ASTM D7459-08 testing of one representative
unit for multiple units fed from a common fuel source, for all combined
biomass (or fuels with a biomass component) and fossil fuels.
Comment: Some commenters supported the EPA's proposal to revise 40
CFR 98.36(c)(1) and (3) to require reporting of additional information
for each unit in either an aggregation of units or common pipe
configuration (excluding units with maximum rated heat input capacity
less than 10 mmBtu/hour), including the unit type, maximum rated heat
input capacity, and an estimate of the fraction of the total annual
heat input to the unit. These commenters agreed that unit-specific data
is necessary to understand both the distribution of emissions across
unit types and sizes, but also the abatement potential through various
decarbonization strategies (e.g., certain abatement strategies may be
better suited for certain unit types and uses). The commenters stated
that the requested data could assist the EPA in the development of NSPS
or EG under CAA section 111. The commenters noted that, given the
prevalence of reporting using combined configurations, this data would
fill large data gaps in the current characterization of industrial
sectors. One commenter asserted that the requirement should be extended
to facilities that report using the common stack configuration or the
alternative part 75 configuration, which would ensure that all
emissions under the subpart are similarly affected by the proposed
revisions and would provide a full picture of the GHG abatement
potential of various source categories. Commenters also requested the
EPA consider lowering or eliminate the size threshold below 10 mmBtu/
hour; the commenter stated that although smaller units do not account
for a large share of total capacity, they often present the most viable
opportunities for greenhouse gas emissions abatement such as
electrification with heat pump technology.
Other commenters opposed the proposed requirements. Opposing
commenters stated that the EPA's explanation for collecting the data
was ambiguous and did not sufficiently explain what data gaps are
missing or how the collection of the additional information would
resolve issues within the currently collected data. One commenter
opposed disaggregating total emissions from the grouped combustion
equipment, asserting that aggregating the emissions by individual
equipment (excluding units rated less than 10 mmBtu/hour) using
estimation techniques would not provide useful information. Several
commenters asserted that the proposed approach could not reliably
provide accurate estimates of actual heat input and is likely not to be
technically feasible. For example, one commenter stated that the
physical configuration of certain lime plants would preclude accurate
unit-specific estimates of actual heat input, as the facilities lack
certified calibrated meters on a kiln-by-kiln basis and rely on
quantifying solid fuel usage based on surveys of on-site stockpiles.
The commenter added that facility-wide reporting of combustion
emissions satisfies the EPA's objective of developing facility-wide
emissions information, and additional unit-level information is
superfluous and of limited value. Other commenters stated that
individual fuel meters are not common, asserting that annual heat input
for individual units is often estimated based on the maximum high heat
input rating and operating hours. One commenter stated that the heat
input records maintained by facilities do not necessarily correspond to
the actual heat input of a unit, especially for industries that use
batching with different process equipment for different products. That
commenter asserted that actual heat input may vary based on age of the
unit; how it is utilized in processes for steam, cooling, or other
purposes; and the high heating value of fuel during certain operating
periods. Another commenter questioned whether the estimation technique
proposed would likely undermine the reported data or compromise the
integrity of actual values that are currently reported. Commenters
asserted that the requirements would have potentially very limited
value and may detract from the GHG emission estimates that regulated
facilities produce for the EPA or other proposed Federal rules.
Commenters also expressed that the proposed requirements would be
overly burdensome and significantly increase the recordkeeping and
reporting burden. One commenter specifically referred to the
requirement for facilities to estimate the total annual input of each
unit expressed as a decimal fraction based on the actual heat input of
each unit compared to the whole; the commenter stated that this
requirement would essentially negate the time efficiencies gained by
reporting the aggregated group, especially for reporters using the
common pipe configuration. The commenter stated that this would
essentially require that heat inputs be calculated for each piece of
equipment each year and could result in a ten-fold increase in burden
for reporters using the common pipe method. Commenters urged that the
maximum rated heat input of each unit in the aggregated group and
operating hours should provide enough information for the EPA to
reasonably approximate emissions for individual equipment.
Response: Upon careful consideration, the EPA has decided not to
take final action on the proposed reporting requirements for each unit
greater than or equal to 10 mmBtu/hour in either an aggregation of
units or common pipe configuration (the unit type, maximum rated heat
input capacity, and an estimate of the fraction of the total annual
heat input attributable to each unit in the group) (proposed 40 CFR
98.36(c)(1)(ii) and (c)(3)(xi)) at this time. We note that the EPA
disagrees that estimating the fraction of the actual total annual heat
input for each unit in the group, based on company records, will be
overly burdensome to reporters. ``Company records'' is defined in the
existing part 98 regulations at 40 CFR 98.6 to mean, ``in reference to
the amount of fuel consumed by a stationary combustion unit (or by a
group of such units), a complete record of the methods used, the
measurements made, and the calculations performed to quantify fuel
[[Page 31822]]
usage. Company records may include, but are not limited to, direct
measurements of fuel consumption by gravimetric or volumetric means,
tank drop measurements, and calculated values of fuel usage obtained by
measuring auxiliary parameters such as steam generation or unit
operating hours. Fuel billing records obtained from the fuel supplier
qualify as company records.'' The broad definition of company records
would afford reporters considerable flexibility when it comes to
estimating the fraction of the actual total annual heat input for each
unit in the group. The EPA may consider such reporting requirements in
future rulemakings.
Comment: Two commenters stated that EGUs should not be reported
under subpart C and are already reported under subpart D (Electricity
Generation); one commenter asserted that it is unclear from the
proposal how reporting these emissions under subpart C would not be
duplicative. One of the two commenters additionally stated that EGUs
are not specifically defined in subparts A or C of part 98, and that
the EPA should provide clarification on the definition of EGUs. The
commenter added that the proposed requirement would impose burden and
regulatory confusion because of the conflicting definitions in, and
applicability of, other EPA regulatory programs which traditionally
have regulated EGUs separately from non-EGU combustion sources. The
commenter stated that 40 CFR 98.36(f) already requires sources to
identify if they are tied to an entity regulated by any public utility
commission.
Another commenter suggested a definition for EGUs that aligns with
a footnote to table A-7 to subpart A that defines EGUs for sources
reporting under subpart C as ``a fuel-fired electric generator owned or
operated by an entity that is subject to regulation of customer billing
rates by the public utilities commission (excluding generators
connected to combustion units subject to 40 CFR part 98, subpart D) and
that are located at a facility for which the sum of the nameplate
capacities for all such electric generators is greater than or equal to
1 megawatt electric output.''
One commenter requested clarification that waste heat generation is
not included; the commenter added that requiring facilities to report
emissions from the generation of electricity using waste heat recovery
would be double counting. Other commenters requested clarification that
emergency generators are exempt from the proposed requirements.
Two commenters supported the EPA's proposed requirement to allow
operators to use an engineering estimate of the percentage of
combustion emissions attributable to facility electricity generation.
However, another commenter disagreed, stating that the EPA did not
describe how a reporter would identify such a fraction. The commenter
added that the EPA failed to take into account that emissions from a
single combustion unit might provide steam to multiple consumers for
multiple purposes, only a portion of which includes on-site electricity
generation. The commenter expressed concerns that, if the rule is
finalized as proposed, the methods to determine electricity-related
emissions by fraction could become subject to numerous other
requirements, such as calculations for GHG emissions, monitoring and
QA/QC requirements, data reporting, and record retention obligations.
Response: The EPA is not taking final action on the proposed
addition of a new indicator that would identify units as electricity
generating units at this time. Furthermore, the EPA is not taking final
action on the additional requirement for reporting an estimate of a
group's total reported emissions attributable to electricity generation
at this time. As discussed in the preamble to the 2023 Supplemental
Proposal, under the current subpart C reporting requirements, the EPA
cannot currently determine the quantity of EGU emissions included in
the reported total emissions for the subpart. Although some facilities
currently indicate whether certain stationary fuel combustion sources
are connected to a fuel-fired electric generator in 40 CFR 98.36(f),
this requirement only captures a subset of subpart C EGU emissions. The
EPA therefore intended the proposed reporting requirements to identify
other EGUs reporting under subpart C in order to improve our
understanding of subpart C EGU GHG emissions and the attribution of GHG
emissions to the power plant sector. However, we agree with commenters
that the proposed requirements could require additional burden not
contemplated by the proposed rule. Specifically, as noted by
commenters, we recognize that there could be scenarios in which a
single combustion unit or group of units may provide steam for multiple
purposes, only a portion of which includes on-site electricity
generation. In this case, although a facility may know the quantity of
electricity generated and could estimate the quantity of steam required
to generate the electricity, determination of the portion of GHG
emissions that are attributable to the combustion unit(s) producing the
steam that is used in an on-site EGU (among other processes) would
additionally require the estimation of the type and quantity of fuel
used by each combustion unit for the purposes of producing the steam
used to generate electricity. For this reason we are not taking final
action on these requirements in this rule.
D. Subpart F--Aluminum Production
We are not taking final action on any proposed amendments to
subpart F of part 98 (Aluminum Production) in this action. In the 2022
Data Quality Improvements Proposal, the EPA requested comment on
several issues related to determining emissions from aluminum
production. Specifically, the EPA requested information on the extent
to which low voltage emissions have been characterized, if data are
available to develop guidance on low voltage emission measurements, and
on the use of the non-linear method as an alternative to the slope
coefficient and overvoltage methods currently allowed in subpart F. The
EPA received comments on these issues but is not taking final action on
any changes to the measurement methodology for subpart F at this time.
In the 2023 Supplemental Proposal, the EPA proposed revisions to
the reporting requirements at 40 CFR 98.66(a) and (g) to require that
facilities report the facility's annual production capacity and annual
days of operation for each potline. We noted at that time that the
capacity of the facility and capacity utilization would provide useful
information for understanding variations in annual emissions and
emission trends across the sector. The EPA received several comments on
the proposed subpart F revisions. Following consideration of comments
received, we are not taking final action on the proposed revisions at
this time. However, the EPA may consider similar changes to reporting
requirements in a future rulemaking. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart F.
E. Subpart G--Ammonia Manufacturing
We are finalizing amendments to subpart G of part 98 (Ammonia
Manufacturing) as proposed. In some cases, we are finalizing the
proposed
[[Page 31823]]
amendments with revisions. In other cases, we are not taking final
action on the proposed amendments. This section discusses the final
revisions to subpart G. The EPA received only supportive comments for
the proposed revisions to subpart G. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart G.
Additional rationale for these amendments is available in the preamble
to the 2022 Data Quality Improvements Proposal and 2023 Supplemental
Proposal.
In the 2022 Data Quality Improvements Proposal, the EPA proposed
several revisions to subpart G to require reporters to report the GHG
emissions that occur directly from the ammonia manufacturing process
(i.e., net CO2 process emissions) after subtracting out
carbon or CO2 captured and used in other products. The
proposed revisions included combining equation G-4 and equation G-5
into a new equation G-4 and several harmonizing revisions to 40 CFR
98.72(a); revisions to the introductory paragraph of 40 CFR 98.73; the
removal of Sec. 98.73(b)(5); revisions to the introductory paragraph
of 40 CFR 98.76; and revisions to the reported data elements at 40 CFR
98.76(b)(1) and (13), as described in section III.C. of the preamble to
the 2022 Data Quality Improvements Proposal.
The EPA is finalizing minor edits to 40 CFR 98.72(a), the
introductory paragraph of 40 CFR 98.73, the introductory paragraph to
40 CFR 98.76, and 40 CFR 98.76(b)(1) to clarify the term ``ammonia
manufacturing unit,'' as well as clarifying edits to 40 CFR
98.76(b)(13) to clearly identify any CO2 used in the
production of urea and carbon bound in methanol that is intentionally
produced as a desired product. Additionally, we are finalizing
clarifying amendments to equation G-1, equation G-2, and equation G-3
to simplify the equations by removing the process unit ``k''
designation in the terms ``CO2,G,k,''
``CO2,L,k,'' and ``CO2,S,k.'' We are also
finalizing the removal of Sec. 98.73(b)(5) and equation G-5,
consistent with our intent at proposal to require reporting of
emissions by ammonia manufacturing unit.
Following consideration of comments received on similar changes
proposed for subpart S (Lime Manufacturing), the EPA is not taking
final action at this time on the proposed revisions to allow facilities
to subtract out carbon or CO2 captured and used in other
products. We have revised new equation G-4 in the final rule to remove
the proposed equation terms related to CO2 collected and
consumed on-site for urea production and the mass of methanol
intentionally produced as a desired product, and removed text related
to ``net'' CO2 process emissions. The EPA is also not taking
final action at this time on the addition of related monthly
recordkeeping data elements that were proposed as verification software
records. See section III.K.2. of this preamble for a summary of related
comments and the EPA's response.
We are finalizing as proposed one amendment to subpart G from the
2023 Supplemental Proposal to include a requirement for facilities to
report the annual quantity of excess hydrogen produced that is not
consumed through the production of ammonia at 40 CFR 98.76(b)(16). This
is a harmonizing change to ensure that the final revisions to subpart P
(Hydrogen Production) to exclude reporting from any process unit for
which emissions are reported under another subpart of part 98,
including ammonia production units that report emissions under subpart
G (see section III.I. of this preamble), will not result in the
exclusion of reporting of any excess hydrogen production at facilities
that are subject to subpart G.
We are also finalizing as proposed related confidentiality
determinations for data elements resulting from the revisions to
subpart G, as described in section VI. of this preamble.
F. Subpart H--Cement Production
We are finalizing several amendments to subpart H of part 98
(Cement Production) as proposed. In some cases, we are finalizing the
proposed amendments with revisions. Section III.F.1. of this preamble
discusses the final revisions to subpart H. The EPA received several
comments on the proposed subpart H revisions which are discussed in
section III.F.2. of this preamble. We are also finalizing
confidentiality determinations for new data elements resulting from the
revisions to subpart H, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart H
This section summarizes the final amendments to subpart H. Major
changes in this final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other
changes to 40 CFR part 98, subpart H can be found in this section and
section III.F.2. of this preamble. Additional rationale for these
amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal.
The EPA is finalizing several revisions to improve the quality of
data collected for subpart H. First, we are finalizing the addition of
several new data reporting elements to subpart H under 40 CFR 98.86(a)
and (b) to enhance the quality and accuracy of the data collected. In
the 2022 Data Quality Improvements Proposal, the EPA proposed to add
several data reporting elements based on annual average chemical
composition data for facilities using either the direct measurement
(using a continuous emission monitoring system (CEMS)) methodology or
the mass balance methodology, in order to assist in improving
verification of reported data. The proposed data elements included (for
both facilities that report CEMS data and those that report using a
mass balance method) the annual arithmetic average weight fraction of:
the total calcium oxide (CaO) content, non-calcined CaO content, total
magnesium oxide (MgO) content, and non-calcined MgO content of clinker
at the facility (proposed 40 CFR 98.86(a)(4) through (a)(7) and (b)(19)
through (b)(22)); and the total CaO content of cement kiln dust (CKD)
not recycled to the kiln(s), non-calcined CaO content of CKD not
recycled to the kiln(s), total MgO content of CKD not recycled to the
kiln(s), and non-calcined MgO content of CKD not recycled to the
kiln(s) at the facility (proposed 40 CFR 98.86(a)(8) through (11) and
(b)(23) through (26)). The EPA also proposed to collect other data
(from both facilities using CEMS and those that report using the mass
balance method), including annual facility CKD not recycled to the
kiln(s) in tons (proposed 40 CFR 98.86(a)(12) and (b)(27)) and raw kiln
feed consumed annually at the facility in tons (dry basis) (proposed 40
CFR 98.86(a)(13) and (b)(28)), for both verification and to improve the
methodologies of the Inventory.
The EPA is finalizing the proposed requirements to report the
annual arithmetic average weight fraction of the total CaO content,
non-calcined CaO content, total MgO content, and non-calcined MgO
content of clinker at the facility (proposed 40 CFR 98.86(a)(4) through
(7) and (b)(19) through (22)), and the annual facility CKD not recycled
to the kiln(s) (proposed 40 CFR 98.86(a)(12) and (b)(27), finalized as
40 CFR 98.86(a)(8) and (b)(27), respectively), for both facilities that
use CEMS and those that report using the mass balance method. We are
also finalizing, for facilities using the mass
[[Page 31824]]
balance method, the total CaO content of CKD not recycled to the
kiln(s), non-calcined CaO content of CKD not recycled to the kiln(s),
total MgO content of CKD not recycled to the kiln(s), and non-calcined
MgO content of CKD not recycled to the kiln(s) at the facility
(proposed 40 CFR 98.86(b)(23) through (26)), and the amount of raw kiln
feed consumed annually (proposed 40 CFR 98.86(b)(28)). Finalizing these
data elements will improve the EPA's ability to verify reported
emissions (e.g., the EPA will be able to create a rough estimate of
process emissions at the facility and compare that to the reported
total emissions, and check whether the ratio is within expected
ranges). For facilities using CEMS, the finalized data elements will
enable the EPA to estimate process emissions from facilities to provide
a more accurate national-level cement emissions profile and the
Inventory. Following consideration of public comments, we are not
taking final action on certain proposed data elements for facilities
that report using CEMS. Specifically, the EPA is not taking final
action on the proposed requirements to report the annual arithmetic
average of the total CaO content of CKD not recycled to the kiln(s),
non-calcined CaO content of CKD not recycled to the kiln(s), total MgO
content of CKD not recycled to the kiln(s), and non-calcined MgO
content of CKD not recycled to the kiln(s) at the facility (proposed 40
CFR 98.86(a)(8) through (11)). We are also not taking final action on
the reporting of the amount of raw kiln feed consumed annually
(proposed 40 CFR 98.86(a)(13)). See section III.F.2. of this preamble
for a summary of the related comments and the EPA's response.
The EPA is finalizing as proposed several clarifications and
corrections to equations H-1, H-4, and H-5 included in the 2022 Data
Quality Improvements Proposal. The final revisions to equation H-1 add
brackets to clarify the summation of clinker and raw material emissions
for each kiln, and update the definition of parameter
``CO2 rm'' to ``CO2 rm,m'' and clarify the raw
material input is on a per-kiln basis. The final revisions to equation
H-5 revise the inputs ``rm,'' ``CO2 rm'' (revised to
``CO2 rm,m''), and ``TOCrm,'' and add brackets to
clarify that emissions are calculated as the sum of emissions from all
raw materials or raw kiln feed used in the kiln. The final revisions to
equation H-4 correct the defined parameters for the quarterly non-
calcined CaO content and the quarterly non-calcined MgO content of CKD
not recycled to ``CKDncCaO'' and ``CKDncMgO,''
respectively, to align with the parameters defined in the equation.
2. Summary of Comments and Responses on Subpart H
This section summarizes the major comments and responses related to
the proposed amendments to subpart H. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart H.
Comment: One commenter objected to the EPA's proposed addition of
data reporting requirements for facilities reporting using the CEMS
methodology. The commenter asserted that the new data requirements
would add unnecessary burden without providing additional insight into
cement industry GHG emissions or improving the quality or accuracy of
the emissions data provided. The commenter stated that, under the new
provisions, the EPA would essentially be requiring kilns that are
currently using CEMS to report their emissions to verify their data by
using the mass balance method, with associated reporting and
recordkeeping. The commenter noted that CEMS are already required to
meet extensive quality assurance and quality control requirements and
have been determined as the most accurate means of measuring stack
emissions. Further, the commenter reasoned that the EPA can accurately
determine process emissions using already reported data, total kiln
stack emissions data, and combustion emissions data, which they stated
is included in the confidential monthly clinker production data and
fuel use data provided using the Tier 4 methodology in subpart C. The
commenter stated that it is well established by the scientific
community that process emissions represent 60 percent of CO2
emissions from the kiln based on the standard chemistry of the cement
manufacturing process, and that the currently reported data should be
sufficient.
The commenter also opposed the EPA's proposed data reporting
elements for facilities using the mass balance (non-CEMS) methodology,
likewise insisting that the EPA can readily determine both process and
combustion emissions from the existing reporting requirements. The
commenter explained that (1) the reporting of total and non-calcined
CaO and MgO is irrelevant to calculating CO2 process
emissions as they are inherently non-carbonate; and (2) in reference to
the proposed CKD reporting requirement, calculating the CKD not
recycled and the quantity of raw kiln feed at all kilns within a
facility would add burden without providing any additional information
about industry GHG emissions. The commenter also questioned the need
for the additional data, stating that the EPA did not provide an
explanation of how the additional data would be used separately from
potentially verifying process emissions. The commenter also expressed
concern that the addition of these data elements would justify
regulatory overreach from other programs.
Response: We disagree with the commenter's statement that reporting
additional data from facilities using CEMS will not enhance the EPA's
verification of the facility reported values. The EPA has encountered
occasional instances of mistakes in reported CEMS data (e.g., from data
entry mistakes), resulting in significant errors in reported emissions.
Fuel use data are not provided to the EPA for cement plants that report
emissions using CEMS. Currently, fuel use data are entered into the IVT
to calculate CH4 and N2O emissions from
combustion for kilns with CEMS, as the process and combustion emissions
are both vented through the same stack. These IVT data are not directly
reported to the EPA, so the EPA cannot use them to verify the accuracy
of reported emissions.
Furthermore, we are not persuaded by the commenter's assertion that
process emissions represent 60 percent of kiln emissions. Cement kilns
can have very different process and combustion emissions depending on
the input materials, the fuel or energy source used, etc., and an
average process emissions factor would not be representative of all
facilities in subpart H. Furthermore, the commenter does not provide
additional information about how this statistic was calculated and
whether it is representative of cement manufacturing plants in the
United States. The commenter did not specify where this statistic can
be found in the cited source (``Getting the Numbers Right Database,
Global Cement and Concrete Association'' \9\) and did not provide the
underlying data to the EPA for review. Importantly, this database
contains information on global cement production, and emissions
profiles at facilities in the United States can differ widely from
those in other countries due to differences in input
[[Page 31825]]
materials, fuels used, and emission control systems that may be in
place. The EPA has reviewed data, such as those from the UNFCCC, which
suggest that implied emissions rates may vary from 49-57 percent and
change by country.\10\
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\9\ Available at https://gccassociation.org/sustainability-innovation/gnr-gcca-in-numbers/. Accessed January 9, 2024.
\10\ United Nations Framework Convention on Climate Change.
(2023). National inventory submissions 2023. https://unfccc.int/ghg-inventories-annex-i-parties/2023.
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Upon careful review and consideration, the EPA has decided not to
adopt the proposed changes to require the chemical composition data for
CKD and amount of raw kiln feed consumed annually for facilities
reporting with CEMS (proposed 40 CFR 98.86(a)(8) through (11) and
(a)(13)). We are not taking final action on these elements after
consideration of the comments and in an effort to reduce potential
burden. The EPA is finalizing the remaining proposed reporting
requirements as these data elements will improve verification of
reported emissions. For example, the EPA will be able to create a rough
estimate of process emissions at the facility and compare that to the
reported total emissions, and check whether the ratio is within
expected ranges. We will also be able to build evidence-based
verification checks on the clinker composition data that is entered by
facilities that do not use CEMS (we currently have very little
information on what chemical compositions are typical in cement kilns).
The final reporting elements will also enable the EPA to estimate
process emissions from CEMS facilities to provide a more accurate
national-level emissions profile for the cement industry and the
Inventory. Reporting average chemical composition data for the clinker
is expected to be less burdensome for facilities, as this data is
likely collected as a part of normal business operations, while
collection of CKD data may be less common. Furthermore, we do not
believe these additional data elements constitute regulatory overreach
as they are similar to other data already collected under subpart H and
will be important for verification and our understanding of process and
combustion emissions.
We also disagree that collecting additional data from facilities
using the mass balance method will not enhance the EPA's verification
of the facility reported values. Currently clinker composition data are
entered into the IVT and are not included in the annual report that is
submitted to the EPA. Reporting of these and additional data elements
will improve verification of reported emissions and the mass balance
calculations (e.g., by allowing us to create evidence-based
verification checks for clinker composition data). The final reporting
elements will also provide a more accurate national-level emissions
profile for the cement industry and the Inventory. With respect to the
burden associated with these added reporting elements for reporters
using the mass balance reporting method, these data elements are the
annual arithmetic averages of either monthly or quarterly data elements
that these reporters already input into e-GGRT through the IVT. These
data elements are currently entered into the IVT and used for equations
H-2 through H-5; but they are not reported to the EPA. Thus, the
burden, if any, is expected to be minimal. There are no changes, as
compared to the proposal, to the final reporting requirements for
facilities using the mass balance methodology after consideration of
this comment.
G. Subpart I--Electronics Manufacturing
We are finalizing several amendments to subpart I of part 98
(Electronics Manufacturing) as proposed. In some cases, we are
finalizing the proposed amendments with revisions. In other cases, we
are not taking final action on the proposed amendments. Section
III.G.1. of this preamble discusses the final revisions to subpart I.
The EPA received several comments on the proposed subpart I revisions
which are discussed in section III.G.2. of this preamble. We are also
finalizing as proposed related confidentiality determinations for data
elements resulting from the revisions to subpart I as described in
section VI. of this preamble.
1. Summary of Final Amendments to Subpart I
This section summarizes the final amendments to subpart I. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other
changes to 40 CFR part 98, subpart I can be found in this section and
section III.G.2. of this preamble. Additional rationale for these
amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal and 2023 Supplemental Proposal.
a. Revisions To Improve the Quality of Data Collected for Subpart I
In the 2022 Data Quality Improvements Proposal, the EPA proposed
several revisions to subpart I to improve data quality, including
revising the stack testing calculation method, updating the calculation
methods used to estimate emission factors in the technology assessment
report, updating existing default emission factors and destruction or
removal efficiencies (DREs) based on new data, adding a calculation
method for calculating byproducts produced in abatement systems,
amending data reporting requirements, and providing clarification on
reporting requirements. In the 2023 Supplemental Proposal, the EPA
subsequently proposed corrections to specific revisions from the 2022
Data Quality Improvements Proposal, including DRE values in table I-16
and gamma factors in proposed new table I-18 to subpart I of part 98.
The EPA is finalizing several revisions to 40 CFR 98.93(i) to
improve the calculation methodology for stack testing. These revisions
include:
Adding new equations I-24C and I-24D and a table of
default weighting factors (new table I-18) to calculate the fraction of
fluorinated input gases exhausted from tools with abatement systems,
ai,f, for use in equations I-19A through I-19C and I-21, and
the fraction of byproducts exhausted from tools with abatement systems,
ak,i,f, for use in equations I-20 and I-22.
Revising equations I-24A and I-24B, which calculate the
weighted average DREs for individual F-GHGs across process types in
each fab.
Revising 40 CFR 98.93(i)(3) to require that all stacks be
tested if the stack test method is used.
Replacing equation I-19 with a set of equations (i.e.,
equations I-19A, I-19B, and I-19C) that will more accurately account
for emissions when pre-control emissions of an F-GHG come close to or
exceed the consumption of that F-GHG during the stack testing period.
Clarifying the definitions of the variables dif
and dkif, the average DREs for input gases and byproduct
gases respectively, in equations I-19A, I-19B, I-19C, and I-19D, in
equations I-20 through I-22, in equations I-24A and B, and in equation
I-28 to subpart I.
These revisions will remove the current requirements to apportion
gas consumption to different process types, to manufacturing tools
equipped versus not equipped with abatement systems, and to tested
versus untested stacks. Equations I-24C and I-24D add the option to
calculate the fraction of each input gas ``i'' and byproduct gas ``k''
exhausted from tools with abatement systems based on the number of
tools that are equipped versus not equipped with abatement systems,
along with weighting factors that account for the
[[Page 31826]]
different per-tool emission rates that apply to different process
types. The weighting factors ([gamma]i,p for input gases and
[gamma]k,i,p for byproduct gases, provided in table I-18)
are based on data submitted by semiconductor manufacturers during the
process of developing the 2019 Refinement (as corrected in the 2023
Supplemental Proposal). We are finalizing revisions to equations I-24A
and I-24B, used to calculate the average DRE for each input gas ``i''
and byproduct gas ``k,'' based on tool counts and the same weighting
factors that will be used in equations I-24C and I-24D; this accounts
for operations in which a facility uses one or more abatement systems
with a certified DRE value that is different from the default to
calculate and report controlled emissions. We are finalizing the
requirement that all stack systems be tested by removing 40 CFR
98.93(i)(1); this removes not only the need to apportion gas usage to
tested versus untested stack systems, but also the requirement to
perform a preliminary calculation of the emissions from each stack
system. We are finalizing new equations I-19A, I-19B, and I-19C, with a
clarification, which will more accurately account for emissions when
emissions of an F-GHG prior to entering any abatement system (i.e.,
pre-control emissions) would approach or exceed the consumption of that
F-GHG during the stack testing period. We are clarifying that the 0.8
maximum for the 1-U value only applies to carbon-containing F-GHGs. As
discussed in the proposal, the modification to the stack testing method
was intended to accurately account for the source of emissions when the
measured emissions exceed the consumption of the F-GHG during the stack
testing period, which may occur in situations where the input gas is
also generated in significant quantities as a by-product by the other
input gases. However, it is not expected that NF3 or
SF6 could be generated as a by-product by a fluorocarbon
used as an input gas. Therefore, this modification is not appropriate
and was not intended to apply to SF6 or NF3
emissions when calculating emissions using the stack test method. The
revised equations improve upon the current equations because they
account both for any control of the emissions and for some utilization
of the input gas. Finally, we are finalizing revisions to the
definitions of the variables dif and dkif in
equations I-19A, I-19B, I-19C, and I- 19D, in equations I-20 through I-
22, in equations I-24A and B, and in equation I-28 to clarify that
these variables reflect the fraction of gas i (or byproduct gas k) that
is destroyed once gas i (or byproduct gas k) is fed into abatement
systems. See section III.E.1.a. of the preamble to the 2022 Data
Quality Improvements Proposal for additional information on these
revisions and their supporting basis.
With some changes, the EPA is finalizing revisions to improve the
quality of the data submitted in the technology assessment reports in
40 CFR 98.96(y) as proposed in the 2022 Data Quality Improvements
Proposal. Specifically, the EPA proposed to require that reporters who
submit a technology assessment report would use three methods (the
``all-input gas method,'' the ``dominant gas method,'' and the
``reference emission factor method'') to report the results of each
emissions test to estimate utilization and byproduct formation emission
rates. The EPA is finalizing a requirement to report the results using
two of the three methods proposed, including the all-input gas method,
with a clarification, and the reference emission factor method, and is
allowing use of a third method of the reporter's choice, as follows:
All-input gas method. For input gas emission rates, this
method attributes all emissions of each F-GHG that is an input gas to
the input gas emission factor (1-U) factor for that gas, if the input
gas does not contain carbon or until that 1-U factor reaches 0.8 if the
input gas does contain carbon, after which emissions of the F-GHG are
attributed to the other input gases. For byproduct formation rates,
this method attributes emissions of F-GHG byproducts that are not also
input gases to all F-GHG input gases (kilogram (kg) of byproduct
emitted/kg of all F-GHGs used).
Reference emission factor method. This method estimates
emissions using the 1-U and the byproduct formation rates that are
observed in single gas recipes and then adjusts both emission factors
based on the ratio between the emissions calculated based on the
factors and the emissions actually observed in the multi-gas process.
The EPA is finalizing an option for reporters to use, in
addition to the utilization and byproduct formation rates calculated
according to the required all-input gas method and the reference
emission factor method, an alternative method of their choice to
calculate and report the utilization or byproduct formation rates based
on the collected data.
These revisions will ensure that the emission factors submitted in
the technology assessment reports are robust (for example, not unduly
affected by changing ratios of input gases) and are comparable to each
other and to the emission factors already in the EPA's database. The
EPA proposed, and is finalizing with a clarification, modifications to
the all-input gas method to avoid an input gas emission factor greater
than 0.1 when multiple gases are used. The modified method uses 0.8 as
the maximum 1-U value, and as such, attributes emissions of each F-GHG
used as an input gas to that input gas until the mass emitted equals 80
percent of the mass fed into the process (i.e., until the 1-U factor
equals 0.8). The all-input gas method assigns the remaining emissions
of the F-GHG to the other input gases as a byproduct in proportion to
the quantity of each input gas used in the process. We are finalizing
this modified method with the clarification that the 0.8 maximum for
the 1-U value only applies to carbon-containing F-GHGs. As discussed in
the proposal, the modification to the all-input method was intended to
avoid the situations where the historical methods would violate the
conservation of mass or fail to reflect the fact that some fraction of
the input gas reacts with the film it is being used to etch or clean,
which may occur in situations where the input gas is also generated in
significant quantities as a by-product by the other input gases.
However, it is not expected that NF3 or SF6 could
be generated as a by-product by a fluorocarbon used as an input gas.
Therefore, this modification is not appropriate and was not intended to
apply to SF6 or NF3 emissions when calculating
emission factors. The EPA is requiring use of the all-input gas method
to facilitate comparisons of new data to historical data; the all-input
gas method was the most commonly used method in the submitted data sets
included in technology assessment reports from 2013 and earlier.
Following consideration of comments received and to reduce burden, the
EPA is not taking final action on the proposed requirement to report
emission factors using the dominant gas method. The dominant gas method
calculates 1-U factors in the same way as the all-input gas method, but
it calculates byproduct formation rates differently, attributing all
emissions of F-GHG byproducts to the carbon-containing F-GHG input gas
accounting for the largest share by mass of the input gases. Additional
information on each of the three methods is available in section
III.E.1.b. of the preamble to the 2022 Data Quality Improvements
Proposal and in the memorandum ``Technical Support for Modifications to
the Fluorinated
[[Page 31827]]
Greenhouse Gas Emission Estimation Method Option for Semiconductor
Facilities under Subpart I,'' available in the docket to this
rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424. As noted in the
proposed rule, the EPA intends to make available a calculation workbook
for the technology assessment report that will calculate the two sets
of emission factors based on each of the final methods using a single
set of data entered by the reporter. The option to calculate the
emission factors using an additional method provides flexibility for
reporters while enabling comparison between the results of the
additional method and the results of the two required methods. Where
reporters choose to submit emission factors using the additional
method, we will be able to evaluate the reliability and robustness of
emission factors calculated using all three methods. Additional
information on comments related to the calculation methods and the
EPA's response can be found in section III.G.2.a. of this preamble.
The EPA is also finalizing two additional requirements for the
submitted technology assessment reports including requiring reporters
to specify (1) the method used to calculate the reported utilization
and byproduct formation rates and assign and provide an identifying
record number for each data set; and (2) for any DRE data submitted,
whether the abatement system used for the measurement is specifically
designed to abate the gas measured under the operating condition used
for the measurement. For reporters who opt to additionally provide
utilization and byproduct formation rates using an alternative method
of their choice, reporters must provide this information and a
description of the alternative method used.
The EPA is finalizing revisions to update the default emission
factors and DREs in subpart I based on new data submitted as part of
the 2017 and 2020 technology assessment reports and the 2019
Refinement, as proposed in the 2022 Data Quality Improvements Proposal
and corrected in the 2023 Supplemental Proposal. These revisions
include:
Updates to the utilization rates and byproduct emission
factors (BEFs) for F-GHGs used in semiconductor manufacturing in tables
I-3, I-4, I-11 and I-12;
Removal of byproduct emission factors from tables I-3 and
I-4 where there is a combination of both a low BEF and a low GWP
resulting in very low reported emissions per metric ton of input gas
used (removes the BEF for C4F6 and
C5F8 for all input gases used in wafer cleaning
or plasma etching processes, and results in not adding BEFs for
COF2 and C2F4 for any input gas/
process combination from the new data submitted as part of the 2017 and
2020 technology assessment reports).
In cases where neither the input gas nor the films being
processed in the tool contain carbon, setting the BEF for the carbon-
containing byproducts to zero. These provisions apply at the process
subtype level. For example, a BEF of zero will only be used for a
combination of input gas and chamber cleaning process subtype (e.g.,
NF3 in remote plasma cleaning (RPC)) if no carbon-containing
materials were removed using that combination of input gas and chamber
cleaning process subtype during the year and no carbon-containing input
gases were used on those tools. Otherwise, the default BEF will be used
for that combination of input gas and chamber cleaning process subtype
for all of that gas consumed for that subtype in the fab for the year.
The EPA is making one modification to the proposed equation to clarify
that the carbon-containing byproduct emission factors are zero when the
combination of input gas and etching and wafer cleaning process type
uses only non-carbon containing input gases (SF6,
NF3, F2 or other non-carbon input gases) and
etches or cleans only films that do not contain carbon.
Updates to the default emission factors for N2O
used in all electronics manufacturing in table I-8, including distinct
utilization rates for semiconductor manufacturing and LCD manufacturing
and, for semiconductor manufacturing, utilization rates by wafer size;
Revisions to the calculation methodology for MEMS and PV
manufacturing to allow use of 40 CFR 98.93(a)(1), the current
methodology for semiconductor manufacturing, for manufacture of MEMS
and PV using semiconductor tools and processes, which applies the
default emission factors in tables I-3 and I-4 to these processes;
Revisions to 40 CFR 98.93(a)(6) to revise the utilization
rate and byproduct emission factor values assigned to gas/process
combinations where no default utilization rate is available; these
revisions account for the likely partial conversion of the input gas
into CF4 and C2F6. The final rule
requires, for a gas/process combination where no default input gas
emission factor is available in tables I-3, I-4, I-5, I-6, and I-7,
reporters will use an input gas emission factor (1-U) equal to 0.8
(i.e., a default utilization rate or U equal to 0.2) with BEFs of 0.15
for CF4 and 0.05 for C2F6.
Revisions to the default DREs in table I-16 to subpart I
to reflect new data and strengthening of abatement system certification
requirements. The final revisions assign chemical-specific DREs to all
commonly used F-GHGs for the semiconductor manufacturing sub-sector
without distinguishing between process types.
Additional information on the EPA's derivation of the final
emission factors and DREs is available in section III.E.1.c. of the
preamble to the 2022 Data Quality Improvements Proposal and in the
revised technical support document, ``Revised Technical Support for
Revisions to Subpart I: Electronics Manufacturing,'' available in the
docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424).
The EPA is also finalizing revisions to the conditions under which
the default DRE may be claimed, with some revisions from the proposal
so that the new documentation requirements apply only to abatement
systems purchased and installed on or after January 1, 2025. For all
abatement systems for which a DRE is being claimed, including abatement
systems purchased and installed during or after 2025 and older
abatement systems, the EPA is maintaining the current certification and
documentation requirements and is finalizing the proposed additional
requirement that the certification must contain a manufacturer-verified
DRE value. If the abatement system is certified to abate the F-GHG or
N2O at a value equal to or higher than the default DRE, the
facility may claim the default DRE. If the abatement system is
certified to abate the F-GHG or N2O but at a value lower
than the default DRE, the facility may not claim the default; however,
the facility may claim the lower manufacturer-verified value. (Site-
specific measurements by the electronics manufacturer are still
required to claim a DRE higher than the default.) Based on annual
reports submitted through RY2022, facilities have historically been
able to provide manufacturer-verified DRE values for all abatement
systems for which emission reductions have been claimed.
Additional requirements apply to abatement systems purchased and
installed on or after January 1, 2025. Specifically, the EPA is
finalizing revisions to the definition of operational mode in 40 CFR
98.98 to specify that for abatement systems purchased and installed
during or after January 1, 2025, operational mode means that the system
is operated within the range of parameters as specified in the DRE
certification documentation. The specified parameters must include the
[[Page 31828]]
highest total F-GHG or N2O flows and highest total gas flows
(with N2 dilution accounted for) through the emissions
control systems. Systems operated outside the range of parameters
specified in the documentation supporting the DRE certification may
rely on a measured site-specific DRE according to 40 CFR 98.94(f)(4) to
be considered operational within the range of parameters used to
develop a site-specific DRE.
The EPA is also finalizing revisions to 40 CFR 98.94(f)(3) to
modify the conditions under which the default or lower DRE may be
claimed for abatement systems purchased and installed on or after
January 1, 2025. For systems purchased and installed on or after
January 1, 2025, reporters are required to: (1) certify that the
abatement device is able to achieve, under the worst-case flow
conditions during which the facility is claiming that the system is in
operational mode, a DRE equal to or greater than either the default DRE
value, or if the DRE claimed is lower than the default DRE value, a
manufacturer-verified DRE equal to or greater than the DRE claimed; and
(2) provide supporting documentation. Specifically, for POU abatement
devices purchased and installed on or after January 1, 2025, reporters
must certify and document under 40 CFR 98.94(f)(3)(i) and (ii) that the
abatement system has been tested by the abatement system manufacturer
using a scientifically sound, industry-accepted measurement methodology
that accounts for dilution through the abatement system, such as EPA
430-R-10-003,\11\ and that the system has been verified to meet (or
exceed) the destruction or removal efficiency used for that fluorinated
GHG or N2O under worst-case flow conditions (the highest
total F-GHG or N2O flows and highest total gas flows, with
N2 dilution accounted for). Because manufacturers routinely
conduct DRE testing and are familiar with the protocols of EPA 430-R-
10-003, we anticipate this information will be readily available for
abatement systems purchased in calendar year 2025 or later. The EPA is
finalizing that the new DRE requirements will be implemented for
reports prepared for RY2025 and submitted March 31, 2026, which
provides over a year for reporters to acquire the necessary
documentation. Reporters are not required to maintain documentation of
the DRE on abatement systems for which a DRE is not being claimed.
---------------------------------------------------------------------------
\11\ Protocol for Measuring Destruction or Removal Efficiency of
Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing, Version 1, March 2010 (``EPA DRE Protocol''), as
incorporated at 40 CFR 98.7.
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We are also clarifying that the list of abatement system
manufacturer specifications within which the abatement system must be
operated at 40 CFR 98.96(q)(2) is intended to be exemplary, adding
``which may include, for example,'' before the list. This clarifies
that some of the listed specifications or parameters may not be
specified by all abatement system manufacturers for all abatement
systems, and leaves open the possibility that some abatement system
manufacturers may include other specifications within which the
abatement system must be operated.
Additionally, following consideration of comments received, we are
clarifying how reporters account for uptime of the abatement device if
suitable backup emissions control equipment or interlocking with the
process tool is implemented for each emissions control system. The EPA
is revising the definition of the term ``UTij'' in equation
I-15 and the definition of ``UTf'' in equation I-23 to
clarify that if all the abatement systems for the relevant input gas
and process type are interlocked with all the tools feeding them, the
uptime may be set to one (1). We are also clarifying equations I-15 and
I-23 to reference the provisions in 40 CFR 98.94(f)(4)(vi) when
accounting for uptime when redundant abatement systems are used. See
section III.G.2.a. of this preamble for additional information on
related comments and the EPA's response.
The EPA is finalizing the addition of a calculation methodology
that estimates the emissions of CF4 produced in hydrocarbon-
fuel based combustion emissions control systems (``HC fuel CECs'') that
are not certified not to generate CF4. Following
consideration of public comments, the calculation will be required only
for HC fuel CECs purchased and installed on or after January 1, 2025.
To implement the new calculation methodology, we are adding a new
equation I-9 and renumbering the previous equation I-9 as equation I-
8B. Equation I-9 only applies to processes that use F2 as an
input gas or to remote plasma cleaning processes that use
NF3 as an input gas. Equation I-9 estimates the emissions of
CF4 from generation in emissions control systems by
calculating the mass of the fluorine entering uncertified HC fuel CECs
(the product of the consumption of the input gas, the emission factor
for fluorine, and ai, where ai is the ratio of
the number of tools with uncertified abatement devices for the gas-
process combination to the total number of process tools for the gas-
process combination) and multiplying that mass by a CF4
emission factor, ABCF4,F2, which has a value of 0.116. In
related changes, the EPA is finalizing a BEF for F2 from
NF3 used in remote plasma clean processes of 0.5. For other
gas and process combinations where no data are available (listed as
``NA'' in tables I-3 and I-4), the EPA is finalizing a BEF of 0.8 be
used for F2 in equation I-9 for all process types.
The EPA is requiring that reporters estimate CF4
emissions from all HC fuel CECs that are purchased and installed on or
after January 1, 2025 and that are not certified not to produce
CF4, even if reporters are not claiming DREs for those
systems. However, as noted above, the requirements apply only to HC
fuel CECs used on processes that use F2 as an input gas or
to remote plasma cleaning processes that use NF3 as an input
gas. We are also finalizing a related definition of ``hydrocarbon-fuel-
based combustion emissions control system (HC fuel CECS),'' which we
have revised from the proposed ``hydrocarbon-fuel-based emissions
control system,'' to align with the 2019 Refinement and to clarify that
the term includes systems used on processes that have the potential to
emit F2 or fluorinated GHGs, as recommended by commenters.
As noted above, we have also revised the final rule from proposal to
require these estimates from HC fuel CECS purchased and installed on or
after January 1, 2025. We are also finalizing corresponding monitoring,
reporting, and recordkeeping requirements (see 40 CFR 98.94(e), 40 CFR
98.96(o), and 40 CFR 98.97(b), respectively) for facilities that use HC
fuel CECS purchased and installed during or after 2025 to control
emissions from tools that use either NF3 as an input gas in
RPC processes or F2 as an input gas in any process and
assume in equation I-9 that one or more of those systems do not form
CF4 from F2. Under these requirements facilities
must certify and document that the model for each of the systems that
the facility assumes does not form CF4 from F2
has been tested and verified to produce less than 0.1 percent
CF4 from F2, and that each of these systems is
installed, operated, and maintained in accordance with the directions
of the HC fuel CECS manufacturer. The facility may perform the testing
itself, or it may supply documentation from the HC fuel CECS
manufacturer that supports the certification. Because the requirement
to quantify emissions of CF4 from F2 is being
applied only to HC fuel CECS purchased and installed on or after
[[Page 31829]]
January 1, 2025, we anticipate that most HC fuel CECS will be tested by
the HC fuel CECS manufacturer. If the facility performs the testing, it
is required to measure the rate of conversion from F2 to
CF4 using a scientifically sound, industry-accepted method
that accounts for dilution through the abatement device, such as the
EPA DRE Protocol, adjusted to calculate the rate of conversion from
F2 to CF4 rather than the DRE.
The EPA is also finalizing related amendments to 40 CFR
98.94(j)(1)(i) to require that the uptime (i.e., the fraction of time
that abatement system is operational and maintained according to the
site maintenance plan for abatement systems) during the stack testing
period average at least 90 percent for uncertified HC fuel CECS.
Following consideration of comments received, we are clarifying in the
final rule that these provisions are limited to only those HC fuel CECS
that were purchased and installed on or after January 1, 2025, that are
used 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, and that are not certified not to form
CF4. See section III.G.2.a. of this preamble for additional
information on related comments on HC fuel CECS and the EPA's response.
Finally, the EPA is not taking final action on proposed revisions
to the calibration requirements for abatement systems. In the 2022 Data
Quality Improvements Proposal, the EPA proposed that a vacuum pump's
purge flow indicators are calibrated every time a vacuum pump is
serviced or exchanged, with the expectation that this requirement would
require calibrations every one to six months, depending on the process.
Following review of input provided by commenters, we are not taking
final action on the proposed revisions. Removal of the proposed
requirements is anticipated to reduce the potential burden on reporters
without any large effects on data quality. Section III.G.2.a. of this
preamble provides additional information on the comments received
related to vacuum pump purge flow calibration and the EPA's response.
b. Revisions To Streamline and Improve Implementation for Subpart I
In the 2022 Data Quality Improvements Proposal, the EPA proposed
several revisions intended to streamline the calculation, monitoring,
or reporting in specific provisions in subpart I to provide flexibility
or increase the efficiency of data collection. The EPA is finalizing
these changes as proposed. First, the final rule revises the
applicability of subpart I as follows:
Adds a second option in 40 CFR 98.91(a)(1) and (2) for
estimating GHG emissions for semiconductor, MEMS, and LCD
manufacturers, for comparison to the 25,000 mtCO2e per year
emissions threshold in 40 CFR 98.2(a)(2), that is based on gas
consumption in lieu of production capacity. The revisions include new
equations I-1B and I-2B to multiply gas consumption by a simple set of
emission factors, the gas GWPs, and a factor to account for heat
transfer fluid to estimate emissions. The emission factors are included
in new table I-2 to subpart I of part 98 and are the same as the
emission factors for gas and process combinations for which there is no
default in tables I-3, I-4, or I-5 to subpart I. Facilities that choose
to use this option for their calculation method will be required to
track annual gas consumption by GHG but are not required to apportion
consumption by process type for the purposes of assessing rule
applicability.
Revises the current applicability calculation for PV
manufacturers to revise equation I-3 and refer to new table I-2, and
delete the phrase ``that have listed GWP values in table A-1,'' to
increase the accuracy of the estimated emissions for determining
applicability; and
Updates the emission factors in table I-1 to subpart I of
part 98 used in the current applicability calculations for MEMS and LCD
manufacturers based on new Tier 1 emission factors in the 2019
Refinement.
Additional information on the EPA's revisions to applicability and
the final emission factors is available in section III.E.2.a. of the
preamble to the 2022 Data Quality Improvements Proposal.
The EPA additionally proposed, and is finalizing, to revise the
frequency and applicability of the technology assessment report
requirements in 40 CFR 98.96(y), which applies to semiconductor
manufacturing facilities with GHG emissions from subpart I processes
greater than 40,000 mtCO2e per year. First, we are
finalizing amendments to 40 CFR 98.96(y) to decrease the frequency of
submission of the reports from every three years to every five years.
As we noted in the preamble to the 2022 Data Quality Improvements
Proposal, revising the frequency of submission to every five years will
increase the likelihood that reports will include updates in technology
rather than conclusions that technology has not changed. At the time of
proposal, this would have moved the due date for the next technology
assessment, from March 31, 2023, to March 31, 2025. Because the EPA is
not implementing the revisions in this final rule until January 1,
2025, we have revised the provision in the final rule to clarify that
the first technology assessment report due after January 1, 2025 is due
on March 31, 2028. Section III.G.2.b. of this preamble provides
additional information on the comments received related to the
frequency of submittal of the technology assessment report and the
EPA's response.
We are also finalizing revisions to restrict the reporting
requirement in 40 CFR 98.96(y) to facilities that emitted greater than
40,000 mtCO2e and produced wafer sizes greater than 150 mm
(i.e., 200 mm or larger) during the period covered by the technology
assessment report, as well as explicitly state that semiconductor
manufacturing facilities that manufacture only 150 mm or smaller wafers
are not required to prepare and submit a technology assessment report.
The final provisions also clarify that a technology assessment report
need not be submitted by a facility that has ceased (and has not
resumed) semiconductor manufacturing before the last reporting year
covered by the technology assessment report (i.e., no manufacturing at
the facility for the entirety of the year immediately before the year
during which the technology assessment report is due).
2. Summary of Comments and Responses on Subpart I
This section summarizes the major comments and responses related to
the proposed amendments to subpart I. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart I.
a. Comments on Revisions To Improve the Quality of Data Collected for
Subpart I
Comment: The EPA received several comments related to the proposed
revisions to the stack testing calculation methodology in subpart I.
Largely, commenters objected to the EPA's proposal that ``all stacks''
be tested. The commenters questioned the use of the terminology ``all
stacks'' within the proposed preamble and disagreed with the EPA's
assumption that the number of stacks at each fab is expected to be
small (e.g., one to two). The commenters provided input from an
industry survey of 33 fabs, suggesting that over 250
[[Page 31830]]
stacks would require testing, as well as an additional 170 process
stacks that do not contain F-GHGs (e.g., general fab exhausts). The
commenters urged that adding stacks that do not have the potential to
emit F-GHGs to the stack testing scope would add an additional $60,000
to $200,000 per testing event and as much as $400,000 for large sites.
The commenters requested the EPA clarify that the testing is required
for all operating stacks or stack systems that have the potential to
emit F-GHGs, and that the rule retain the current terminology of
``stack system.''
Response: Even though the EPA referred to ``all stacks'' in the
proposal preamble, we agree that the testing is required only for all
operating stack systems. The proposed and final regulatory text
continue to use the term ``stack system,'' which is defined as ``one or
more stacks that are connected by a common header or manifold, through
which a fluorinated GHG-containing gas stream originating from one or
more fab processes is, or has the potential to be, released to the
atmosphere. For purposes of this subpart, stack systems do not include
emergency vents or bypass stacks through which emissions are not
usually vented under typical operating conditions.'' We are finalizing
the proposed requirement that all stack systems must be tested in
accordance with 40 CFR 98.93(i)(3)(ii).
Comment: The EPA received comments objecting to proposed revisions
to the technology assessment report to require use of three proposed
calculation methods (i.e., the dominant input gas method, all-input gas
method, and reference emission factor method) to develop utilization
and byproduct emission factors. The commenters expressed that each of
EPA's proposed methods fails to meet the agency's goals for consistent
implementation of emission factors across facilities and to allow for
comparability across the industry and in industry emission rates.
Specifically, the commenters asserted that the dominant input gas
method and all-input gas method violate the physical reality of
conservation of mass for plasma etch/wafer cleaning processes when
using multiple gases and may lead to byproduct emission factors greater
than 1. The commenters continued that the dominant input gas method
does not clearly define what gas would be dominant in situations where
gases of equal or near-equal mass are used. For both of the all-input
gas method and the dominant input gas method, the commenters criticized
the use of a ``cap'' value of 0.8 as inconsistent with the agency's
goal to calculate emission factors consistently with those already in
the EPA's data set. For the all-input gas method, commenters added that
the cap of 0.8 for individual testing does not align with the maximum
seen within historical test data submitted by industry, but is instead
aligned with the maximum average emission factor across all gases.
Commenters stated that the modification to both methods may amplify or
obfuscate technology changes by setting an artificial maximum emissions
value.
The commenters also stated that it is unclear how the reference
emission factor method would be implemented. Specifically, commenters
questioned whether 1-U or the byproduct emission factors would be held
constant, maintaining that the method increases the difficulty in
comparing individual tests depending on what is held constant, and
adding that if new gases or byproducts are used or measured, the
methodology will not have a reference emission basis to apply.
Commenters expressed that the additional burden and complexity of
calculating technology emission factors three different ways could be a
disincentive to facility testing and would not improve overall
emissions accuracy.
The commenters requested that in lieu of the three calculation
methods, the EPA consider use of the ``multi-gas method,'' which
attributes all non-carbon-containing GHGs, such as SF6 and
NF3, to the input of these non-carbon-containing GHGs and
attributes all carbon-containing F-GHG emissions across all carbon-
based input F-GHGs. The commenters believe that the multi-gas method
would appropriately assign emissions (especially for recipes running
more than two gases at once), would eliminate concerns regarding
emission factors that do not meet conservation of mass principles, and
is not reliant on past or assumed data to calculate emission factors or
byproduct emission factors. Commenters explained that high variability
in single-gas emission factors is due to a variety of factors,
including the amount or concentration of input gases, as well as plasma
and manufacturing tool variables, and suggested that use of the multi-
gas method would generate emission factors consistent and within the
range of the existing emission factor data, while also being able to
accommodate new gases and changes in technology.
Response: The EPA disagrees with the commenter's assessment of the
three proposed emission factor methods. We also disagree that the
proposed requirements are overly burdensome. However, following
consideration of the comments raised, we are revising the final rule to
require reporters to estimate emission factors using two of the three
proposed methods (the all-input gas method and the reference emission
factor method) and to allow reporters to submit results using an
additional method of their choice. As noted in the preamble to the
proposed rule, we plan to provide a spreadsheet that will automatically
perform the calculations for the two required methods using a single
data set entered by the reporters, minimizing burden. As explained in
both section III.E.1.b. to the preamble to the 2022 Data Quality
Improvements proposal and the subpart I technical support document,\12\
the all-input gas method is quite consistent with the historically used
methods, differing from the historically used methods only under
circumstances where the historically used methods are likely to yield
unrealistic results (e.g., where CF4 is used as an input gas
and accounts for a small fraction of the mass of all input gases,
yielding CF4 input gas emission factors over 0.8). Of the
three methods proposed, the reference emission factor method is
somewhat less consistent with the historically used methods, but is
expected to be more robust in that its results are less affected by
changing ratios of input gases. As discussed further below, both of
these methods are more consistent with the historical methods and less
affected by changing input gas ratios than the method favored by the
commenter, the multi-gas method.
---------------------------------------------------------------------------
\12\ See document ``Technical Support for Proposed Revisions to
Subpart I (2022),'' available in the docket for this rulemaking,
Docket ID. No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
After consideration of comments, the EPA is not taking final action
on the proposed requirement to report emission factors calculated using
the dominant gas method for several reasons. First, the dominant gas
method estimates the input gas emission rate in the same way as the
all-input gas method, making it redundant with the all-input gas method
for calculation of input gas emission rates. Second, the dominant gas
method estimates the byproduct emission rate by assigning all emissions
of F-GHG byproducts to the carbon-containing F-GHG input gas accounting
for the largest share by mass of the input gases, which is anticipated,
as noted by commenters, to be less accurate in cases where input gases
of equal or near-equal mass are used. Third, in the historical data
sets submitted to the EPA, the all-input gas method was the most
commonly used
[[Page 31831]]
method; therefore, retaining this approach rather than the dominant gas
method will allow the EPA to more reliably compare the new data
submitted to the historical data set. Finally, not requiring use of the
dominant gas method will reduce burden on facilities that are required
to submit technology assessment reports.
As noted in the preamble to the 2022 Data Quality Improvements
proposal, receiving results based on multiple methods will enable the
EPA: (1) to directly compare the new emission factor data to the
emission factor data that are already in the EPA's database and that
were calculated using the historical method; and (2) to compare the
results across the available emission factor calculation methods and to
identify any systematic differences in the results of the different
methods for each gas and process type. By identifying and quantifying
systematic differences in the results of the different methods, we will
be better able to distinguish these differences from differences
attributable to technology changes. Knowledge of these systematic
differences will also be useful in the event that we ultimately require
facilities to submit emission factors using one method only,
particularly if that method is not closely related to one of the
methods used historically. We will also be able to evaluate how much
the results of each method vary for each gas and process type; high
variability may indicate that the results of a method are being
affected by varying input gas proportions rather than differences in
gas behavior. On the other hand, extremely low variability may also
indicate that a method is affected by input gas proportions. For
example, if the all-input-gas method yields a large number of input gas
emission factors equal to 0.8, the maximum allowed value for input gas
emission factors under this method, this implies that some of the
emissions being attributed to the input gas are actually being
generated as byproducts from other input gases that are collectively
more voluminous, conditions under which the reference emission factor
method may yield the most reliable results. Ultimately, these analyses
will enable us to more accurately characterize emissions from
semiconductor manufacturing by selecting the most robust emission
factor data for updating the default emission factors in tables I-3 and
I-4. Note that the EPA would update the default emission factors using
the rulemaking process, providing an opportunity for industry to
comment on the data and methodology used to develop any proposed
factors.
Regarding the comment that the proposed rule did not clarify how
the reference emission factor would be implemented, including whether
the 1-U or by-product emission factors would be adjusted, the proposed
rule made it clear that both the 1-U and byproduct emission factors
would be adjusted where the emitted gas was also an input gas. The
preamble to the proposed rule stated, ``the reference emission factor
method calculates emissions using the 1-U and the BEFs [by-product
emission factors] that are observed in single gas recipes and then
adjusts both factors based on the ratio between the emissions
calculated based on the factors and the emissions actually observed in
the multi-gas process. This approach uses all the information available
on utilization and by-product generation rates from single-gas recipes
while avoiding assumptions about which of these are changing in the
multi-gas recipe'' (87 FR 36947). The proposed equations I-31A (for 1-U
factors, finalized as equation I-30A) and I-31B (for by-product
factors, finalized as equation I-30B) showed this in mathematical terms
and also showed how the method would apply where more than two input
gases were used. The proposed rule also clearly indicated that where a
by-product gas was not also an input gas, proposed equation I-30B
(finalized as equation I-29B) was to be used. Equation I-29B is the
equation used in the all-input-gas method as well as the reference
emission factor method for by-products that are not also input gases.
Equation I-29B would apply to newly observed as well as previously
observed by-product gases that were not also input gases.
This leaves only the situation where an input gas is used in a
process type for the first time along with other input gases. While we
expect that this situation will be rare, we agree that it should be
addressed. We are clarifying in the final rule that where an input gas
is used in a process type with other input gases and there is no 1-U
factor for that input gas in table I-19 or I-20, as applicable, the
Reference Emission Factor Method will not be used to estimate the
emission factors for that process.
We are not specifying the multi-gas method as the sole method for
calculating emission factors submitted in the technology assessment
report. As noted in the proposed rule, one of the EPA's goals in
collecting emission factor data through the technology assessment
report is to better understand how emission factors may be changing as
a result of technological changes in the semiconductor industry, and
whether the changes to the emission factors may justify further data
collection to comprehensively update the default emission factors in
tables I-3 and I-4. To meet this goal, the emission factors submitted
in the technology assessment reports should be calculated using methods
that are similar to the methods used to calculate the emission factors
already in the EPA's database; otherwise, differences attributable to
differences in calculation methods may amplify or obscure differences
attributable to technology changes. The multi-gas method assigns
emissions of all carbon-containing F-GHGs to all carbon-containing F-
GHG input gases, regardless of species, yielding input gas emission
factors that are equal to byproduct gas formation factors for each
emitted F-GHG. These input gas and byproduct gas emission factors are
significantly different from the input gas and byproduct gas emission
factors yielded by the historically used methods, making it difficult
to discern the impact of technology changes as opposed to calculation
method changes on the emission factors. In addition, our analysis
indicated that the multi-gas method results are highly sensitive to the
ratios of the masses of input gases fed into the process, which appears
likely to affect the robustness and reliability of emission factors
calculated using that method.\13\ For these reasons, we have concluded
that it would not be appropriate to require submission of emission
factors using only the multi-gas method.
---------------------------------------------------------------------------
\13\ Id. The EPA has included in the docket a memo and
spreadsheet showing the results of the different emission factor
calculation methods using the same data (see Docket ID. No. EPA-HQ-
OAR-2019-0424-0142, memorandum and attachment 3 Excel spreadsheet).
---------------------------------------------------------------------------
However, we are providing an option in the final rule for reporters
to use, in addition to the required all-input gas method and the
reference emission factor method, an alternative method of their choice
to calculate and report updated utilization or byproduct formation
rates based on the collected data. Reporters will therefore have the
opportunity to provide emission factor data that are calculated using
the multi-gas method or other methodologies, provided the reporter
provides a complete, mathematical description of the alternative
calculation method and labels the data calculated using that method
consistent with the requirements for the all-input gas method and the
reference emission factor method. Submitting emission factors
calculated using the multi-gas
[[Page 31832]]
method along with the other two methods would allow us to compare the
results of the multi-gas method to the results of the other two (one of
which is very similar to the primary historically used method) and to
identify any systematic differences. As noted above, by identifying and
quantifying systematic differences in the results of the different
methods, we will be better able to distinguish these differences from
differences attributable to technology changes. We may also be able to
relate the results of the historical methods to the results of methods
that differ from those used historically. Receiving emission factors
calculated using three methods would also allow us to better assess the
robustness and reliability of the emission factors calculated using all
three methods, e.g., by seeing which methods yield highly variable
emission factors within each input gas-process type combination.
Because the final rule does not require reporters to submit emission
factors calculated using an alternative methodology, the requirement to
provide a complete, mathematical description of the alternative
calculation method used is not anticipated to add significant burden.
Comment: Commenters supported the proposal to remove BEFs for
C4F6 and C5F8 and the
decision to not add COF2 and C2F4, as
byproduct emissions of them account for <<0.001% of overall GHG
emissions from semiconductor manufacturing operations. One commenter
also requested the EPA clarify that carbon-containing byproduct
emission factors are zero when calculating emissions from non-carbon
containing input gases (SF6, NF3, F2,
or other non-carbon input gases) and when the film being etched or
cleaned does not contain carbon, as this would align the EPA final rule
with the 2019 Refinement.
Response: The EPA is finalizing the rule as proposed to remove the
BEFs for C4F6 and C5F8. The
EPA is also not adding BEFs for COF2 or
C2F4. For non-carbon containing input gases used
in cleaning processes, we proposed to set carbon-containing byproduct
emission factors to zero when the combination of input gas and chamber
cleaning process sub-type is never used to clean chamber walls on
manufacturing tools 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). We agree with the commenter that non-carbon-
containing input gases used in etching processes are similarly not
expected to give rise to carbon-containing byproducts if neither the
input gases nor the films being etched contain carbon. We are therefore
finalizing an expanded version of the proposed provision, setting
carbon-containing byproduct emission factors to zero for etching and
wafer cleaning processes as well as chamber-cleaning processes when
these conditions are met. The revisions align the rule requirements
with the 2019 Refinement.
Comment: Commenters expressed several concerns regarding the EPA's
proposed revisions to the conditions under which the default DRE may be
claimed. One commenter requested the EPA remove the requirement to
provide supporting documentation for all abatement units using
certified default or lower than default DREs. The commenter also
requested the EPA clarify that reporters are not required to maintain
supporting documentation on abatement units for which a DRE is not
being claimed.
Commenters also contended that the existing language in subpart I
is sufficient to ensure proper point-of-use (POU) device performance
while being consistent with the 2019 Refinement, and the requirement to
provide supporting documentation of manufacturer certified POU DREs,
including testing method, is burdensome and may be unachievable,
especially for older abatement units. One commenter expressed concern
that the proposed increase in certification and documentation
requirements beyond existing POU operational requirements will dissuade
semiconductor companies from accounting for DREs from installed POU,
resulting in an over-estimate of emissions from the semiconductor
industry. The commenter also stated that adding operational elements of
fuel and oxidizer settings, fuel gas flows and pressures, fuel
calorific values, and water quality, flow, and pressures to the POU DRE
requirements are outside the manufacturer-specified requirements for
emissions control and are not necessary to ensure accurate POU DREs.
Commenters stated that abatement equipment installed across the
industry does not have manufacturer specifications for all listed
parameters, or the capability to track all listed parameters.
Commenters concluded that these and other POU default DRE certification
and documentation requirements go above and beyond the 2019 Refinement
and will make it more difficult for U.S. reporters to take credit for
installed and future emissions control devices, resulting in a less
accurate, overestimated GHG emissions inventory. One commenter
supported applying the requirements only to equipment purchased after
the reporting rule becomes effective. The commenter stated that
verification testing would be especially burdensome; the commenter
estimated testing to take approximately 20 weeks per chemistry and
stated it could take up to 2+ years for individual vendors to have
required documentation. The commenter also expressed concern that the
proposed requirements could have cascading impacts to facility
manufacturing and operating permits based on state implementation of
the Tailoring Rule, which typically rely on GHGRP protocols. Commenters
supported aligning the emission control device operational requirements
for default POU DREs with the following 2019 Refinement language: ``. .
. obtain a certification by the emissions control system manufacturers
that their emissions control systems are capable of removing a
particular gas to at least the default DRE in the worst-case flow
conditions, as defined by each reporting site.''
The commenter also requested the EPA include language supporting
full uptime for emission control devices interlocked with manufacturing
tools or with abatement redundancy. The commenter supported 2019
Refinement language that: ``Inventory compilers should also note that
UT [uptime] may be set to one (1) if suitable backup emissions control
equipment or interlocking with the process tool is implemented for each
emissions control system. Thus, using interlocked process tools or
backup emissions control systems reduces uncertainty by eliminating the
need to estimate UT for the reporting facility.'' The commenter
contended that such language will drive further use of manufacturing
tool interlocks or emission control system redundancy while having the
added benefit of simplifying uptime tracking of individual POU.
Response: The EPA is clarifying in this response that reporters are
not required to maintain documentation of the DRE on abatement units
for which a DRE is not being claimed. However, no regulatory changes
are needed to reflect this clarification. For abatement units for which
a DRE is being claimed, reporters are still required to provide
certification that the abatement systems for which emissions are being
reported were specifically designed for fluorinated GHG or
N2O abatement, as applicable, and support the certification
by providing abatement system supplier documentation stating that the
system was designed for fluorinated GHG or N2O abatement.
The facility must certify
[[Page 31833]]
that the DRE provided by the abatement system manufacturer is greater
than or equal to the DRE claimed (either the default, if the certified
DRE is greater than or equal to the default, or the manufacturer-
verified DRE itself, if the certified DRE is lower than the default
DRE). To use the default or lower manufacturer-verified destruction or
removal efficiency values, operation of the abatement system must be
within the manufacturer's specifications. It was not the EPA's intent
to require that certified abatement systems that operate within the
manufacturer's specifications must meet all the operational parameters
listed, and we are revising the final rule at 40 CFR 98.96(q)(2) to add
``which may include, for example,'' to clarify that, in order to use
the default or lower manufacturer-verified destruction or removal
efficiency values, operation of the abatement system must be within
those manufacturer's specifications that apply for the certification.
In the final rule, the EPA is maintaining the current certification
and documentation requirements for older POU abatement devices,
although the certification must contain a manufacturer-verified DRE
value that is equal to or higher than the default in order to claim the
default DRE; facilities are allowed to claim a lower manufacturer-
verified value if the provided certified DRE is lower than the default.
The EPA concurs that some older POU abatement systems may not have full
documentation from the manufacturer of the test methods used and
whether testing was conducted under worst-case flow conditions;
however, we believe this documentation should be available for most
newer abatement systems. As a result, reporters with the older POU
abatement devices will not have any additional documentation
requirements beyond those currently in place, except to provide the
certified DRE. Following a review of annual reports submitted under
subpart I, we determined that facilities have historically provided
manufacturer-verified DRE values for all abatement systems for which
emission reductions have been claimed. Therefore, we have determined
that these final requirements are reasonable. The EPA is finalizing the
new documentation requirements for POU abatement devices purchased on
or after January 1, 2025 under 40 CFR 98.94(f)(3)(i) and (ii), these
additional requirements include that the manufacturer-verified DREs
reflect that the abatement system has been tested by the manufacturer
using a scientifically sound, industry-accepted measurement methodology
that accounts for dilution through the abatement system, such as the
EPA DRE Protocol (EPA 430-R-10-003), and verified to meet (or exceed)
the default destruction or removal efficiency for the fluorinated GHG
or N2O under worst-case flow conditions. Since manufacturers
routinely conduct DRE testing and are familiar with the protocols of
EPA 430-R-10-003, this information would be readily available for
abatement systems purchased in calendar year 2025 or later. Further,
these final rule requirements will be implemented for reports prepared
for RY2025 and submitted March 31, 2026, providing adequate time for
reporters to acquire documentation.
The EPA agrees with the recommendation to align the rule with the
2019 Refinement with respect to the uptime factor for interlocked tools
and abatement systems and is making this change in the final rule. The
use of interlocked tools is already accounted for in the current rule
in the definition of terms ``UTijp'' and ``UTpf''
in equations I-15 and I-23 (the total time in minutes per year in which
the abatement system has at least one associated tool in operation),
which state that ``[i]f you have tools that are idle with no gas flow
through the tool for part of the year, you may calculate total tool
time using the actual time that gas is flowing through the tool.''
However, to clarify and simplify the calculation of uptime where
interlocked tools are used, the EPA is revising the definition of the
term ``UTij'' in equation I-15 to say that if all the
abatement systems for the relevant input gas and process type are
interlocked with all the tools feeding them, the uptime may be set to
one (1). The revised text specifies that ``all'' tools and abatement
systems for the relevant input gas and process sub-type or type are
interlocked because the numerator and denominator of the uptime
calculation in equations I-15 and I-23 are separately summed across
abatement systems for input gas ``i'' and process sub-type or type
``j.'' Similar changes are made for the same reasons in the definition
of ``UTf'' in equation I-23. With the use of an interlock
between the process tool and abatement device, the process tool should
never be operating when the abatement device is not operating.
The current rule also accounts for the use of redundant abatement
systems. Section 98.94(f)(4)(vi) currently states, ``If your fab uses
redundant abatement systems, you may account for the total abatement
system uptime (that is, the time that at least one abatement system is
in operational mode) calculated for a specific exhaust stream during
the reporting year.'' This provision achieves nearly the same objective
as suggested by the commenters. To clarify this point, the EPA is
revising the definition of the terms ``Tdijp'' in equation
I-15 and ``Tdpf'' in equation I-23 to reference the
provision in 40 CFR 98.94(f)(4)(vi) when accounting for uptime when
redundant abatement systems are used.
Comment: Commenters objected to the EPA's proposed requirements to
include a calculation methodology to estimate emissions of
CF4 produced in hydrocarbon-fuel based combustion emissions
control systems (HC fuel CECS) that are not certified not to generate
CF4. The commenters claimed that the CF4
byproduct emissions from HC fuel CEC abatement of F2 gas
(from etch or remote plasma chamber cleaning processes) are based on
limited and unverified data. Specifically, the commenters expressed
concern that the values documented within the 2019 Refinement and
referenced within the proposal are based on a single, confidential data
set from one abatement supplier. One commenter stated that developing
regulatory language around this single, unverified data set does not
accurately represent the CF4 byproduct emissions from the
uses or generation of F2 and may deliver an advantage to the
single emissions control system supplier that provided the data.
The commenters also listed the following concerns with the
information provided within the 2019 Refinement and the proposed rule
supporting documentation upon which the CF4 byproduct
(ABCF4,F2 and BF2,NF3) is based:
The F2 emission values presented in ``Influence
of CH4-F2 mixing on CF4 byproduct
formation in the combustive abatement of F2'' by Gray & Banu
(2018) are based on testing conducted in a lab under conditions that
are not found in actual semiconductor abatement installations. Test
methods do not appear to adhere to those specified in industry standard
test methods or the EPA DRE Protocol. F2 results are
measured from a device, the MST Satellite XT, designed to provide
``nominal'' F2 concentrations meant for health and safety
risk management and not for environmental emissions measurement.
``FTIR spectrometers measure scrubber abatement
efficiencies'' by Li, et al. (2002) and ``Thermochemical and Chemical
Kinetic Data for Fluorinated Hydrocarbons'' by Burgess, et al. (1996)
provide anecdotal and hypothetical emission pathways for the combustion
of fluorinated gases, but do not confirm
[[Page 31834]]
reliable and peer reviewed CF4 emission results from current
semiconductor manufacturing use or generation of F2.
EPA references a single, confidential data set from
Edwards, Ltd. (2018) upon which numerical ABCF4,F2 and
BF2,NF3 values are based. This single data set of 15
measurements refers to an RPC NF3 to F2 emission
value based on mass balance. The commenter opposed using the data
provided by Edwards confidentially without the ability to review the
underlying data and experimental procedure of the 15 measurements upon
which the RPC NF3 to F2 emission factor was
based. Mass balance has shown to be a highly conservative method in
estimating emission factors and this confidential data set lacks
visibility into repeatability, experimental design, and semiconductor
process applicability.
The commenters further contended that the requirement to calculate
CF4 emissions from HC fuel CECS abatement of F2,
based on equation I-9 if the HC fuel CECS is not certified to not
convert F2 at less than 0.1%, adds complexity to
apportioning RPC NF3 and F2 to both <0.1%
certified and uncertified HC fuel CECS and will require time and cost
investments which are not justified by data. One commenter added that
this could disincentivize the use of low emission NF3 cleans
or potentially slow implementation of F2 processes with
zero-GWP potential due to the requirement to report CF4 BEF
generation with tools with POU abatement. Another commenter added that
this requirement appears to apply to all relevant HC fuel CECS
regardless of whether a default or measured DRE is claimed for the
abatement device. The commenter stated that if HC fuel CECS abatement
suppliers and device manufacturers are not able to provide the required
certification to exempt systems from this added emission, for every
kilogram of RPC NF3 used, CO2e emissions out of
the HC fuel CECS will increase more than 600% for 200 mm and more than
400% for 300 mm processes. Commenters added that this jump in
CF4 emissions will result in a time series inconsistency for
semiconductor industry greenhouse gas reporting.
One commenter also stated that, if EPA maintains this requirement,
it is unclear if equation I-9 applies in addition to or in place of
existing CF4 byproduct emission factors. The commenter
requested that CF4 emissions from the HC fuel CECS abatement
of F2, as calculated by equation I-9, are applied instead
of, not in addition to, default CF4 BEFs for RPC
NF3. Commenters requested the removal of equation I-9 and
associated ABCF4,F2 and BF2,NF3 data elements;
one commenter added that an alternative would be to make changes to HC
fuel CECS requirements to remove confusion and double counting of
emissions.
Response: The EPA disagrees with the commenter after a thorough
review of the issue, as documented in detail in a memorandum in the
docket for the final rulemaking.\14\ The analysis conducted for the EPA
demonstrated that: (1) the formation of CF4 by reaction of
CH4 and F2 in POU combustion systems is
thermodynamically favored and that there is no question that
CF4 emissions can be observed if mixing of CH4
and F2 is allowed to occur; (2) that a revised
BF2,NF3 default emission factor of 0.5 is well supported by
scientific peer-reviewed evidence to describe the formation of
F2 from NF3-based RPC processes; (3) that the
proposed default value for ABCF4,F2 of 0.116, describing the
rate of formation of CF4 from F2, is well
supported by experimental evidence under conditions that are
representative of the designs and use of commercially available POU
emissions control systems in production conditions; (4) that there is
strong prima facie evidence of the formation of CF4 from
within POU emissions control systems during the production of
semiconductor devices; and (5) that not reporting such CF4
emissions could lead to a significant underestimation of GHG emissions
from semiconductor manufacturing facilities.
---------------------------------------------------------------------------
\14\ Memorandum from Sebastien Raoux to U.S. EPA.
``CF4 byproduct formation from the combustion of
CH4 and F2 in Point of Use emissions control
systems in the electronics industry.'' Prepared for the U.S. EPA.
May 2023, available in the docket for this rulemaking, Docket ID.
No. EPA-HQ-OAR-2019-0424.
---------------------------------------------------------------------------
Based on the evidence documented in the memorandum, the EPA is
finalizing as proposed the requirement that the electronic
manufacturers estimate and report CF4 byproduct emissions
from hydrocarbon-fuel-based POU emissions control systems that abate
F2 processes or NF3-based RPC processes.
The EPA is also requiring that reporters estimate CF4
emissions from all POU abatement devices that are not certified not to
produce CF4, even if they are not claiming a DRE from those
devices, because the CF4 emissions from HC fuel combustion
in the abatement of F2 or F-GHG is a separate issue from
whether or not a DRE is claimed for the same devices. The EPA disagrees
that the rule is adding unnecessary complexity to apportion RPC
NF3 and F2 between POU abatement systems that are
certified not to convert F2 to CF4 and those that
are not certified. Reporters will use tool counts in this case rather
than the usual gas apportioning model. This should be straightforward
because it requires the reporters to: (1) count the total number of
tools running the process type of interest (either RPC NF3
or F2 in any process type); (2) count the number of tools
running that process type that are equipped with HC fuel CECs that are
not certified not to form CF4; and (3) divide (2) by (1).
The EPA is revising the final rule to require that reporters must
only provide estimates of CF4 emissions from HC fuel CECS
purchased and installed on or after January 1, 2025. We recognize that
applying the testing, certification, and emissions estimation
requirements to older equipment would have expanded the set of
equipment for which testing would need to be performed and/or emissions
would need to be estimated, which may have posed logistical challenges,
particularly for older equipment that may no longer be manufactured.
Making the requirements applicable only to HC fuel CECs purchased and
installed on or after January 1, 2025 ensures that abatement system
manufacturers and/or electronics manufacturers can test the equipment
and measure its CF4 generation rate from F2 by
March 31, 2026, by which time facilities must either certify that the
HC fuel CECS do not generate CF4 or quantify CF4
emissions from the HC fuel CECS.
The EPA recognizes that the new requirement to report
CF4 emissions from HC fuel CECS could lead to a time series
inconsistency in reported emissions. However, such an inconsistency is
not in conflict with the overall purpose of the GHGRP to accurately
estimate GHG emissions. Nor would it be unique to the electronics
industry, because other GHGRP subparts have been revised in ways that
altered the time series of the emissions as new source types were added
or more accurate methods were adopted. For example, in 2015, subpart W
was updated to include a new source, completions and workovers of oil
wells with hydraulic fracturing, in the existing Onshore Petroleum and
Natural Gas Production segment and also added two entirely new
segments, the Onshore Petroleum and Natural Gas Gathering and Boosting
and Onshore Natural Gas Transmission Pipelines segments. Such changes
in reported emissions are often documented in the public data,
including in the EPA's sector profiles.
The EPA is clarifying in this response to comment that equation I-9
is in addition to, rather than in place of, CF4 byproduct
factors for RPC NF3, because the CF4 byproduct
factors for RPC NF3
[[Page 31835]]
represent emissions from the process before abatement, and these
emissions were measured without abatement equipment running.
Comment: One commenter supported using the term ``hydrocarbon-fuel-
based combustion emissions control systems'' (HC fuel CECS) because it
aligns with the nomenclature within 2019 Refinement rather than the
less used ``hydrocarbon-fueled abatement systems'' or other terms. The
commenter explained that semiconductor facilities widely implement
large, facility-level volatile organic compound abatement devices to
eliminate and control criteria volatile and non-volatile organic
compounds, with no expectation of fluorinated greenhouse gas emissions.
The commenter expressed concern that the broad definition of HC fuel
CECS may be interpreted to include all hydrocarbon-based fuel control
systems, not just tool-level POU abatement. The commenter added that,
although not currently implemented, future facility-level F-GHG
abatement systems could be incorrectly included in the scope of
equation I-9 as it is written. The commenter requested that all
emissions control systems language is updated to be consistent. The
commenter also specifically requested the definition of ``hydrocarbon-
fuel-based combustion emission control systems'' be tailored to specify
HC fuel CECS connected to manufacturing tools, and include the
following language: ``and have the potential to emit fluorinated
greenhouse gases.''
Response: The EPA agrees with the commenter and has revised the
proposed language to include the term, ``hydrocarbon-fuel-based
combustion emissions control systems'' (HC fuel CECS) to align with the
nomenclature within 2019 Refinement. The EPA is also clarifying in the
final rule that these requirements apply only to equipment that is
connected to manufacturing tools that have the potential to emit
F2 or F-GHGs. It is important to include emissions of
F2 as well as F-GHGs since it is F2 that may
combine with hydrocarbon fuels to generate CF4 emissions.
These changes include revising ``hydrocarbon fuel-based emissions
control systems'' to ``HC fuel CECS'' in the terms
``EABCF4,'' aF2,j,'' ``UTF2,j,''
``ABCF4,F2,'' ``aNF3,RPC,'' ``and
``UTNF3,RPC,F2'' defined in equation I-9.
Comment: One commenter requested the EPA specify that HC fuel CECS
uptime during stack testing is ``representative of the emissions
stream'' and the EPA specify that HC fuel CECS uptime during stack
testing applies to RPC NF3 or input F2 processes
only. The commenter questioned the EPA's proposed requirement that the
uptime during the stack testing period must average at least 90 percent
for uncertified hydrocarbon-fueled emissions control systems. The
commenters asserted that uptime tracking for uncertified abatement
devices is excessive, goes beyond the 2019 Refinement requirements, and
does not improve the accuracy of emissions estimates. The commenter
requested language to limit this requirement to ``at least 90% uptime
of NF3 remote plasma clean HC fuel CECS devices that are not
certified to not form CF4 during the test.'' The commenter
also requested EPA clarify that equation I-9 does not apply in addition
to stack testing requirements. The commenter requested that
CF4 emissions from the HC fuel CECS abatement of
F2, as calculated by equation I-9, be specifically exempted
from the stack testing method as it would double count CF4
emissions.
Response: The EPA agrees with the commenter that it would be
helpful to clarify of the applicability of the 90-percent uptime
requirement for HC fuel CECS. The EPA is revising the rule language at
40 CFR 98.94(j)(1) to further limit the HC fuel CECS 90-percent uptime
requirement to systems that were purchased and installed on or after
January 1, 2025 and that are used 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. Either
of these input gas-process type combinations may exhaust F2
into HC fuel CECS, potentially leading to the formation of
CF4. The qualification ``that are not certified not to form
CF4'' is being finalized as proposed.
Regarding the commenters' concerns related to the uptime tracking
requirements for uncertified abatement devices during stack testing, we
reiterate that the uptime tracking requirement during stack testing is
for hydrocarbon-fueled abatement devices that are not certified to not
form CF4, because these reporters still need to account for
CF4 emissions even if not accounting the abatement device's
F-GHG DRE.
The EPA is also clarifying in this response that equation I-9 is
not in addition to stack test calculations. The emissions from HC fuel
CECS, should they occur, will be captured by the stack testing
measurements. Because equation I-9 is not included in or referenced by
the stack testing section, the regulatory text in 40 CFR 98.93(i) as
currently drafted does not need any additional revision. However, the
header paragraph 40 CFR 98.93(a) has been revised to clarify that
paragraph (a)(7), which includes equation I-9, is one of the paragraphs
used to calculate emissions based on default gas utilization rates and
byproduct formations rates.
Comment: One commenter objected to the EPA's proposed calibration
requirements for abatement systems, specifically for vacuum pump purge
systems. The commenter urged that this would have significant impacts
on the semiconductor industry and would drive a major increase in pump
replacement and tool downtime. The commenter explained that POU
abatement devices and their connected vacuum pumps are separate
systems, and while physically connected, POU maintenance and pump
replacement schedules are independent of one another. Further, the
commenter asserted that pump purge flow calibration is technically and
operationally infeasible for device manufacturers to perform. The
commenter explained that purge flow indicators are factory calibrated
and are part of the pump installation and commissioning; if there is a
flow indicator failure, the vacuum pump is replaced with a factory-
calibrated pump. The commenter stated that pump maintenance and repair
is not typically performed at the manufacturing tool and requires pump
disconnection and physical removal, and thus pumps are often repaired
off-site. The commenter stressed that pump manufacturers do not provide
recommendations or specifications for re-calibration of these pumps.
The commenter added that there is no pump redundancy installed on a
tool, and to check the calibration and potentially replace the flow
transducer, the vacuum pump must be shutdown to safely work on it. The
commenter noted that any replacement of the pump would require a tool
shutdown and therefore 12 to 48 hours of downtime for manufacturing
requalification.
The commenter stated that pumps remain continually in service on
the order of years and asserted that pump vendors indicate that pumps
can remain in service for many years without requiring calibration of
the pump purge. The commenter provided that pump changes and
refurbishment costs can be over $5,000 per occurrence and noted that
pump repair or calibration activities can require significant
coordination with factory and site operations due to the highly
specialized equipment and resources needed. The commenter estimated
that semiconductor manufacturing sites can have 2,000+ POU abatement
devices as well as 4,000+ vacuum pumps in a high-volume-manufacturing
site. The
[[Page 31836]]
commenter subsequently estimated that the EPA's proposed revisions
could result in pump downtime, process equipment tool downtime, and
maintenance costs to the U.S. semiconductor industry of about $40
million annually.
The commenter also stated that they believe the existing
performance certification of POU emissions control devices based on
high flow conditions are highly protective of POU system reliability.
The commenter reiterated that high flow POU certification is based on
maximum device flows, which, for multi-chamber tools, includes all
chambers running at once. The commenter urged that significant
variations in pump purge flows are unlikely and the magnitude of these
variations would be a small component of overall POU flow volumes. As
such, the commenter urged that pump purge flows are not necessary to
calibrate after initial pump commissioning.
Response: The EPA agrees with the commenter that calibration of
N2 purge flows is normally done during pump service or
maintenance, when the pumps are typically: (1) disconnected from the
process tool; (2) replaced by a new or refurbished pump; and (3)
brought to a ``service center'' for refurbishment (sometimes on-site,
sometimes off-site). The EPA also concurs with commenters that
requiring N2 pump purge calibration could be disruptive if
done outside of ``normal'' service periods. Consequently, the EPA
proposed to require that pump purge flow indicators be calibrated
``each time a vacuum pump is serviced or exchanged'' rather than more
frequently. The anticipated frequency of calibration mentioned in the
preamble, every six months, was intended to be descriptive rather than
prescriptive. Thus, the EPA does not believe that the proposed
requirement would have the large economic impacts cited by the
commenter. Nevertheless, because it appears that pumps are typically
factory calibrated when commissioned and are replaced with factory-
calibrated pumps when the flow indicator fails, a calibration
requirement is not required. Therefore, the EPA is not taking final
action on the proposed calibration requirement.
b. Comments on Revisions To Streamline and Improve Implementation for
Subpart I
Comment: One commenter supported finalizing the amendment to 40 CFR
98.96(y) decreasing the frequency of submission of technology
assessment reports, before the due date for the next technology
assessment report.
Response: The EPA acknowledges the commenter's support and is
finalizing revisions to 40 CFR 98.96(y) to decrease the frequency of
submission of technology assessment reporters to every 5 years, as
proposed. However, because the EPA is not implementing the final
revisions until January 1, 2025 (see section V. of this preamble), we
have revised the provision to clarify that the first technology
assessment report due after January 1, 2025 is due on March 31, 2028.
Subsequent reports must be submitted every 5 years no later than March
31 of the year in which it is due.
H. Subpart N--Glass Production
We are finalizing several amendments to subpart N of part 98 (Glass
Production) as proposed. The EPA received only supportive comments for
the proposed revisions to subpart N. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart N. We
are also finalizing as proposed related confidentiality determinations
for data elements resulting from the revisions to subpart N, as
described in section VI. of this preamble.
The EPA is finalizing two revisions to the recordkeeping and
reporting requirements of subpart N of part 98 (Glass Production) as
proposed in the 2022 Data Quality Improvement Proposal. The revisions
apply to both CEMS and non-CEMS reporters and require that facilities
report and maintain records of annual glass production by glass type
(e.g., container, flat glass, fiber glass, specialty glass).
Specifically, the final amendments revise (1) 40 CFR 98.146(a)(2) and
(b)(3) to require the annual quantity of glass produced in tons, by
glass type, from each continuous glass melting furnace and from all
furnaces combined; and (2) 40 CFR 98.147(a)(1) and (b)(1), to add that
records must also be kept on the basis of glass type. Differences in
the composition profile of raw materials, use of recycled material, and
other factors lead to differences in emissions from the production of
different glass types. Collecting data on the annual quantities of
glass produced by type will improve the EPA's understanding of
emissions variations and industry trends, and improve verification for
the GHGRP, as well as provide useful information to improve analysis of
this sector in the Inventory. The EPA is also finalizing revisions to
the recordkeeping and reporting requirements of subpart N as proposed
in the 2023 Supplemental Proposal. The final revisions add reporting
provisions at 40 CFR 98.146(a)(3) and (b)(4) to require the annual
quantity (in tons), by glass type (e.g., container, flat glass, fiber
glass, or specialty glass), of cullet charged to each continuous glass
melting furnace and in all furnaces combined, and revises 40 CFR
98.146(b)(9) to require the number of times in the reporting year that
missing data procedures were used to measure monthly quantities of
cullet used. The final revisions also add recordkeeping provisions to
40 CFR 98.147(a)(3) and (b)(3) to require the monthly quantity of
cullet (in tons) charged to each continuous glass melting furnace by
product type (e.g., container, flat glass, fiber glass, or specialty
glass). Differences in the quantities of cullet used in the production
of different glass types can lead to variations in emissions, and, due
to lower melting temperatures, can reduce the amount of energy and
combustion required to produce glass. As such, the annual quantities of
cullet used will further improve the EPA's understanding of variations
and differences in emissions estimates, industry trends, and
verification, as well as improve analysis for the Inventory. Additional
rationale for these amendments is available in the preamble to the 2022
Data Quality Improvements Proposal and 2023 Supplemental Proposal.
I. Subpart P--Hydrogen Production
We are finalizing several amendments to subpart P of part 98
(Hydrogen Production) as proposed. In some cases, we are finalizing the
proposed amendments with revisions. In other cases, we are not taking
final action on the proposed amendments. Section III.I.1. of this
preamble discusses the final revisions to subpart P. The EPA received
several comments on the proposed subpart P revisions which are
discussed in section III.I.2. of this preamble. We are also finalizing
related confidentiality determinations for data elements resulting from
the revisions to subpart P, as described in section VI. of this
preamble.
1. Summary of Final Amendments to Subpart P
This section summarizes the final amendments to subpart P. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other final
revisions to 40 CFR part 98, subpart P can be found in this
[[Page 31837]]
section and section III.I.2. of this preamble. Additional rationale for
these amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal and 2023 Supplemental Proposal.
a. Revisions To Improve the Quality of Data Collected for Subpart P
In the 2023 Supplemental Proposal, the EPA proposed several
amendments to subpart P of part 98 to expand and clarify the source
category definition. First, to increase the GHGRP's coverage of
facilities in the hydrogen production sector, we are amending, as
proposed, the source category definition in 40 CFR 98.160 to include
all facilities that produce hydrogen gas regardless of whether the
hydrogen gas is sold. The final revisions will address potential gaps
in applicability and reporting, allowing the EPA to better understand
and track emissions from facilities that do not sell hydrogen gas to
other entities. As proposed, these amendments categorically exempt any
process unit for which emissions are currently reported under another
subpart of part 98, including, but not necessarily limited to, ammonia
production units that report emissions under subpart G of part 98
(Ammonia Manufacturing), catalytic reforming units located at petroleum
refineries that produce hydrogen as a byproduct for which emissions are
reported under subpart Y of part 98 (Petroleum Refineries), and
petrochemical production units that report emissions under subpart X of
part 98 (Petrochemical Production). As proposed, we are also exempting
process units that only separate out diatomic hydrogen from a gaseous
mixture and are not associated with a unit that produces diatomic
hydrogen created by transformation of feedstocks.
The EPA is also amending the source category definition at 40 CFR
98.160 as proposed to clarify that stationary combustion sources that
are part of the hydrogen production unit (e.g., reforming furnaces and
hydrogen production process unit heaters) are part of the hydrogen
production source category and that their emissions are to be reported
under subpart P. These amendments, which include a harmonizing change
at 40 CFR 98.162(a), clarify that these furnaces or process heaters are
part of the hydrogen production process unit regardless of where the
emissions are exhausted (through the same stack or through separate
stacks). Similarly, we are finalizing a clarification for hydrogen
production units with separate stacks for ``process'' emissions and
``combustion'' emission that use a CEMS to quantify emissions from the
process emissions stack. The final amendments at 40 CFR 98.163(c)
require reporters to calculate and report the CO2 emissions
from the hydrogen production unit's fuel combustion using the mass
balance equations (equations P-1 through P-3) in addition to
calculating and reporting the process CO2 emissions measured
by the CEMS. Additional information on these revisions and their
supporting basis may be found in section III.G. of the preamble to the
2023 Supplemental Proposal. We are adding one additional revision to
address the monitoring of stationary combustion units directly
associated with hydrogen production (e.g., reforming furnaces and
hydrogen production process unit heaters), following a review of
comments received. Based on the EPA's analysis of reported data, there
may be a small number of reporters that may not currently measure the
fuel use to these combustion units separately. We have decided to add
new Sec. 98.164(c) to provide the use of best available monitoring
methods (BAMM) for those facilities that may still need to install
monitoring equipment to measure the fuel used by each stationary
combustion unit directly associated with the hydrogen production
process unit. To be eligible to use BAMM, the stationary combustion
unit must be directly associated with hydrogen production; the unit
must not have a measurement device installed as of January 1, 2025; the
hydrogen production unit and the stationary combustion unit are
operated continuously; and the installation of a measurement device
must require a planned process equipment or unit shutdown or only be
able to be done through a hot tap. BAMM can be the use of supplier
data, engineering calculation methods, or other company records. We are
not requiring facilities to provide an application to use BAMM that
would require EPA review and approval to measure the fuel used in the
hydrogen production process combustion unit. However, we are adding a
new requirement at 40 CFR 98.166(d)(10) to require each facility to
indicate in their annual report, for each stationary combustion unit
directly associated with hydrogen production, whether they are using
BAMM, the date they began using BAMM, and the anticipated or actual end
date of BAMM use. Providing the use of BAMM is intended to reduce the
burden associated with installation of new equipment, and we do not
anticipate that the requirement to report the required indicators of
BAMM will add significant burden. See section III.I.2. of this preamble
for additional information on related comments and the EPA's response.
In the 2022 Data Quality Improvements Proposal, the EPA proposed
several amendments to subpart P to allow the subtraction of the mass of
carbon contained in products (other than CO2 or methanol)
and the carbon contained in intentionally produced methanol from the
carbon mass balance used to estimate CO2 emissions. The
proposed revisions included new equation P-4 to allow facilities to
adjust the calculated emissions from fuel and feedstock consumption in
order to calculate net CO2 process emissions, as well as
harmonizing revisions to the introductory paragraph of 40 CFR 98.163
and 98.163(b) and the reporting requirements at 40 CFR 98.167(b)(7).
Following review of comments received on similar changes proposed for
subpart S (Lime Manufacturing), the EPA is not taking final action at
this time on the proposed revisions to allow facilities to subtract out
carbon contained in products other than CO2 or methanol and
the carbon contained in methanol. See sections III.E., III.I.2., and
III.K.2. of this preamble for additional information on the comments
related to subparts G, P and S and the EPA's response. However, the EPA
is finalizing the proposed reporting requirement at 40 CFR 98.166(b)(7)
(now 40 CFR 98.166(d)(7)), with minor revisions as a result of comments
received. See the discussion in this section regarding subpart P
reporting requirements for additional information as to why EPA is
making revisions as a result of comments received.
The EPA is finalizing several additional revisions to the subpart P
reporting requirements to improve the quality of the data collected
based on the 2022 Data Quality Improvements Proposal and the 2023
Supplemental Proposal. The final reporting requirements are reorganized
to accommodate the final amendments at 40 CFR 98.163(c), which require
reporters using CEMS that do not include combustion emissions from the
hydrogen production unit to calculate and report the CO2
emissions from fuel combustion using the material balance equations
(equations P-1 through P-3) in addition to the process CO2
emissions measured by the CEMS. The revisions to 40 CFR 98.166 clarify
the reporting elements that must be provided for each hydrogen
production process unit based on the calculation methodologies used.
Reporters using CEMS to measure combined CO2 process and
fuel combustion emissions will be required
[[Page 31838]]
to meet the requirements at 40 CFR 98.166(b); reporters using only the
material balance method will be required to meet the requirements at 40
CFR 98.166(c); and reporters using CEMS to measure CO2
process emissions and the material balance method to calculate
emissions from fuel combustion emissions using equations P-1 through P-
3 will be required to meet the requirements of 40 CFR 98.166(b) and
(c). If a common stack CEMS is used to measure emissions from either a
common stack for multiple hydrogen production units or a common stack
for hydrogen production unit(s) and other source(s), reporters must
also report the estimated fraction of CO2 emissions
attributable to each hydrogen production process unit. All other
reporting requirements for each hydrogen production process unit
(regardless of the calculation method) are consolidated under 40 CFR
98.166(d).
As proposed, we are finalizing the addition of requirements for
facilities to report the process type for each hydrogen production unit
(i.e., steam methane reforming (SMR), SMR followed by water gas shift
reaction (SMR-WGS), partial oxidation (POX), partial oxidation followed
by WGS (POX-WGS), Water Electrolysis, Brine Electrolysis, or Other
(specify)), and the purification type for each hydrogen production unit
(i.e., pressure swing adsorption (PSA), Amine Adsorption, Membrane
Separation, Other (specify), or none); the final requirements have been
moved to 40 CFR 98.166(d)(1) and (2) and paragraph (d)(1) has been
revised to include ``autothermal reforming only'' and ``autothermal
reforming followed by WGS'' as additional unit types.
We are amending, as proposed, requirements to clarify that the
annual quantity of hydrogen produced is the quantity of hydrogen that
is produced ``. . . by reforming, gasification, oxidation, reaction, or
other transformations of feedstocks,'' and to add reporting for the
annual quantity of hydrogen that is only purified by each hydrogen
production unit; the final requirements have been moved to 40 CFR
98.166(d)(3) and (4).
We are finalizing a requirement at 40 CFR 98.166(c) (proposed 40
CFR 98.166(b)(5)), to report the name and annual quantity (metric tons
(mt)) of each carbon-containing fuel and feedstock (formerly 40 CFR
98.166(b)(7)). For clarity, we have revised the text of the requirement
at 40 CFR 98.166(c) from proposal to specify that the information is
required whenever equations P-1 through P-3 are used to calculate
CO2 emissions. We are finalizing revisions that renumber 40
CFR 98.166(c) and (d) (now 40 CFR 98.166(d)(6) and (7)), and are
finalizing paragraph (d)(7) with revisions from those proposed to
require reporting, on a unit-level: (1) the quantity of CO2
that is collected and transferred off-site; and (2) the quantity of
carbon other than CO2 or methanol collected and transferred
off-site, or transferred to a separate process unit within the facility
for which GHG emissions associated with the carbon is being reported
under other provisions of part 98. The final rule also requires at 40
CFR 98.166(d)(9) the reporting of the annual net quantity of steam
consumed by the unit (proposed as 40 CFR 98.166(c)(9)). This value will
be a positive quantity if the hydrogen production unit is a net steam
user (i.e., uses more steam than it produces) and a negative quantity
if the hydrogen production unit is a net steam producer (i.e., produces
more steam than it uses).
Finally, for consistency with the final revisions to the reporting
requirements for facilities subject to revised 40 CFR 98.163(c), we are
making a harmonizing change to the recordkeeping requirements at 40 CFR
98.167(a) to specify that, if the facility CEMS measures emissions from
a common stack for multiple hydrogen production units or emissions from
a common stack for hydrogen production unit(s) and other source(s),
reporters must maintain records used to estimate the decimal fraction
of the total annual CO2 emissions from the CEMS monitoring
location attributable to each hydrogen production unit. We are also
finalizing as proposed clarifying edits in 40 CFR 98.167(e) that
retention of the file required under that provision satisfies the
recordkeeping requirements for each hydrogen production unit. See
section III.G.1. of the preamble to the 2022 Data Quality Improvements
Proposal and section III.G. of the preamble to the 2023 Supplemental
Proposal for additional information on these revisions and their
supporting basis.
In the 2023 Supplemental Proposal, the EPA also requested comment
on, but did not propose, other potential revisions to subpart P,
including revisions that would remove the 25,000 mtCO2e
threshold under 40 CFR 98.2(a)(2), which would result in a requirement
that any facility meeting the definition of the hydrogen production
category in 40 CFR 98.160 report annual emissions to the GHGRP. The EPA
considered these changes in order to collect information on facilities
that use electrolysis or other production methods that may have small
direct emissions, but that may use relatively large amounts of off-site
energy to power the process (i.e., the emissions occurring on-site at
these hydrogen production facilities may fall below the existing
applicability threshold, while the combined direct emissions (i.e.,
``scope 1'' emissions) and emissions attributable to energy consumption
(i.e., ``scope 2'' emissions) could be relatively large), as collecting
information from these kinds of facilities as well is especially
important in understanding hydrogen as a fuel source. To reduce the
burden on small producers, the EPA requested comment on applying a
minimum annual production quantity within the source category
definition to limit the applicability of the source category to larger
hydrogen production facilities, such as defining the source category to
only include those hydrogen production processes that exceed a 2,500
metric ton (mt) hydrogen production threshold. The EPA also requested
comment on potential options to require continued reporting from
hydrogen production facilities that use electrolysis or other
production methods that may have small direct emissions (i.e., scope 1
emissions) that would likely qualify to cease reporting after three to
five years under the part 98 ``off-ramp'' provisions of 40 CFR 98.2(i)
(i.e., facilities may stop reporting after three years if their
emissions are under 15,000 mtCO2e or after five years if
their emissions are between 15,000 and 25,000 mtCO2e), to
enable collection of a more comprehensive data set over time. Following
consideration of comments received, the EPA is not taking final action
on these potential revisions in this rule. See section III.I.2. of this
preamble for additional information on related comments and the EPA's
responses. The EPA also considered, but did not propose, further
expanding the reporting requirements to include the quantity of
hydrogen provided to each end-user (including both on-site use and
delivered hydrogen) and, if the end-user reports to GHGRP, the e-GGRT
identifier for that customer. The EPA requested comment on the approach
to collecting this sales information and the burden such a requirement
may impose in the 2023 Supplemental Proposal. Following review of
comments received, the EPA is not taking final action on these
potential revisions in this rule.
b. Revisions To Streamline and Improve Implementation for Subpart P
The EPA is finalizing several revisions to subpart P to streamline
the requirements of this subpart and improve flexibility for reporters.
To
[[Page 31839]]
address the recent use of low carbon content feedstocks, the EPA is
finalizing, with revisions from those proposed, revisions to 40 CFR
98.164(b)(2) and (3) to allow the use of product specification
information annually as specified in the final provisions for (1)
gaseous fuels and feedstocks that have carbon content less than or
equal to 20 parts per million by weight (i.e., 0.00002 kg carbon per kg
of gaseous fuel or feedstock) (rather than at least weekly sampling and
analysis), and (2) for liquid fuels and feedstocks that have a carbon
content of less than or equal to 0.00006 kg carbon per gallon of liquid
fuel or feedstock (rather than monthly sampling and analysis). As
explained in the 2022 Data Quality Improvements Proposal, the fuels and
feedstocks below these concentrations have very limited GHG emission
potential and are currently an insignificant contribution to the GHG
emissions from hydrogen production. The revisions from those proposed
were included to remove the term ``non-hydrocarbon'' because it is not
necessary since the maximum hydrocarbon concentrations that qualify for
the revised monitoring requirements are included in 40 CFR 98.164(b)(2)
and (3).
The EPA is finalizing, with revisions from those proposed, the
addition of new 40 CFR 98.164(b)(5)(xix) to allow the use of
modifications of the methods listed in 40 CFR 98.164(b)(5)(i) through
(xviii) or use of other methods that are applicable to the fuel or
feedstock if the methods currently in 40 CFR 98.164(b)(5) are not
appropriate because the relevant compounds cannot be detected, the
quality control requirements are not technically feasible, or use of
the method would be unsafe. The revisions from those proposed were
harmonizing changes to remove the term ``non-hydrocarbon'' and tie the
proposed revisions back more clearly to the specifications in
paragraphs (b)(2) and (3).
The final rule also finalizes as proposed, revisions to Sec.
98.164(b)(2) through (4) to specifically state that the carbon content
must be determined ``. . . using the applicable methods in paragraph
(b)(5) of this section'' to clarify the linkage between the
requirements in Sec. 98.164(b)(2) through (4) and Sec. 98.164(b)(5).
Finally, the EPA is finalizing revisions to the recordkeeping
requirements at 40 CFR 98.167(b) to refer to paragraph (b) of 40 CFR
98.166. For facilities using the alternatives at 40 CFR 98.164(b)(2),
(3) or (5)(xix), these requirements include retention of product
specification sheets, records of modifications to the methods listed in
40 CFR 98.164(b)(5)(i) through (xviii) that are used, and records of
the alternative methods used, as applicable. We are also finalizing a
revision to remove and reserve redundant recordkeeping requirements in
40 CFR 98.167(c). See section III.G.2. of the preamble to the 2022 Data
Quality Improvements Proposal and section III.G. of the preamble to the
2023 Supplemental Proposal for additional information on these
revisions and their supporting basis.
2. Summary of Comments and Responses on Subpart P
This section summarizes the major comments and responses related to
the proposed amendments to subpart P. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart P.
Comment: Two commenters recommended expanding the source category
to include all hydrogen production facilities; this would include non-
merchant producers, facilities that use electrolysis or renewable
energy, and include process units that do not report to other subparts.
Other commenters did not oppose expanding the source category to non-
merchant facilities. One commenter on the 2022 Data Quality
Improvements Proposal stated that the existing definition may cause
confusion in situations where the hydrogen produced is used on-site or
otherwise not ``sold as a product to other entities'' and suggested
specific revisions to expand the source category to include other types
of hydrogen production plants, including those using electrolysis. One
commenter stated that reporting energy consumption by hydrogen
production sources is necessary to inform decarbonization strategies,
e.g., whether producing excessive amounts of green hydrogen may risk
delaying fossil fuel retirement by diverting renewable energy from
other uses. The commenter recommended a threshold for these facilities
based on energy input. The commenter added that any hydrogen production
facilities using carbon capture and sequestration technology should be
required to report in all instances, as emissions data and energy
consumption data from these facilities will be highly relevant to
future regulatory action.
Multiple commenters commented on the EPA's request for comment
regarding removing the threshold for the hydrogen production source
category. One commenter strongly urged the EPA to make subpart P an
``all-in'' subpart to ensure all hydrogen production facilities are
covered by reporting requirements, including the requirements proposed
to report purchased energy consumption under proposed subpart B to part
98. The commenter pointed to hydrogen electrolysis facilities that may
consume very large amounts of grid electricity that could have
significant upstream emissions impacts; the commenter stated that many
or most of these facilities will already be tracking the attributes of
the energy they consume to qualify for Federal incentives and
investment, and will therefore have this information readily available.
The commenter stressed that understanding this information and the
lifecycle emissions of hydrogen production will be critical to
informing future actions under the CAA. The commenter also supported a
production-based reporting threshold to ensure reporting for high
production facilities with lower direct emissions and suggested the
production threshold should at least include at least the top 75
percent of production facilities. One commenter suggested a hydrogen
production threshold of 5,000 mt/year. Another commenter recommended
that the EPA should implement a threshold to limit the applicability of
the subpart to larger hydrogen production facilities. One commenter
opposed a hydrogen production threshold, and recommended that the EPA
retain the existing emissions-based threshold of 25,000
mtCO2e; the commenter suggested this would further
incentivize the implementation of low GHG hydrogen manufacturing
processes over higher emitting processes such as steam methane
reformers.
Several commenters also opposed revisions that would remove the
ability of sources to off-ramp. One commenter offered the following
recommendations: (1) hydrogen production process units which produce
hydrogen but emit no direct GHG emissions should become eligible to
cease reporting starting January 1 of the following year after the
cessation of direct GHG emitting activities associated with the
process; (2) if the direct GHG emissions remain below 15,000
mtCO2e or between 15,000 and 25,000 mtCO2e,
reporting would be required for 3 or 5 years respectively, consistent
with the existing off-ramp provisions; or (3) if the EPA establishes
[[Page 31840]]
a hydrogen production threshold for reporting, then falling below the
production threshold should be the trigger for cessation of reporting,
either starting January 1 of the following year or on a parallel
structure to the three and five year off-ramp emission thresholds. Two
other commenters stated that the EPA ignores that the ``off-ramp'' is
intended for entities that should no longer be subject to reporting
requirements by virtue of the fact that their emissions fall below a
reasonable threshold. One commenter stated that it is unclear how the
EPA would have authority to continue to require reporting for these
entities, and the commenters said that the EPA should justify excluding
hydrogen production facilities from the off-ramp. The commenters added
that the EPA could use other methods to collect this data, including
proposing a separate standard addressing emissions from hydrogen
production under CAA section 111.
Response: We agreed with commenters that the language regarding
``hydrogen gas sold as a product to other entities'' could cause
confusion, as we intended to require non-merchant hydrogen production
units to now report under subpart P. As such, we are finalizing, as
proposed in the 2023 Supplemental Proposal, the language in 40 CFR
98.160(a) to focus on hydrogen gas production without referring to the
disposition of the hydrogen produced. In the 2023 Supplemental
Proposal, we also proposed to significantly revise Sec. 98.160(b) and
(c). The supplemental proposal revisions appear to address most of the
commenter's suggested revisions, except that we are not including
``electrolysis'' in the list of types of transformations in 40 CFR
98.160(b) because we consider electrolysis as already included under
``. . . reaction, or other transformations of feedstocks.'' This is
also supported by the inclusion of water electrolysis and brine
electrolysis in the list of hydrogen production unit types in the
proposed 40 CFR 98.166(b)(1)(i) (now 40 CFR 98.166(d)(1)). We agree
with commenters that subpart P should be applicable to non-merchant
facilities and are finalizing the proposed revisions.
The EPA has considered comments both supporting and not supporting
changes related to the EPA's request for information regarding removing
the emissions-based threshold or introducing an alternative production-
based threshold for the hydrogen production source category, including
options to require continued reporting from hydrogen production
facilities by amending the emissions-based off-ramp provisions at 40
CFR 98.2(i)(1) and (2). The EPA did not propose or provide for review
specific revisions to part 98 to expand the source category, beyond the
inclusion of non-merchant facilities as discussed in section III.I.1.
of this preamble. Therefore, we are not including any revisions to the
threshold to subpart P or to the ability of hydrogen production
facilities to off-ramp in this final rule. However, the EPA may further
consider these comments and the information provided as we evaluate
next steps concerning the collection of information from hydrogen
production facilities and consider approaches to improving our
understanding of hydrogen as a fuel source, including to inform any
potential future rulemakings.
Comment: Three commenters did not support the requirement to report
combustion from hydrogen production process units under subpart P in
lieu of subpart C as proposed in 40 CFR 98.160(c). Two commenters
stated that these units may not be metered separately from other
combustion units located at an integrated facility, which would require
additional metering to comply with subpart P reporting of combustion
emissions directly associated with the hydrogen production process.
These commenters stated that if combustion emissions directly
associated with the hydrogen production process must be reported under
subpart P, engineering estimations for fuel consumption should be
allowed. One commenter recommended that EPA implement a threshold to
limit the applicability of the subpart to larger hydrogen production
facilities.
Response: Steam methane reforming (SMR) is an endothermic process,
and heating and reheating of fuels and feedstocks to maintain reaction
temperatures is an integral part of the steam methane reforming
reaction. Therefore, subpart P has always required the reporting of
``fuels and feedstocks'' used in the hydrogen production unit and
subpart C should only be used for ``. . . each stationary combustion
unit other than hydrogen production process units'' (40 CFR 98.162(c)).
We have long noted that the emissions from most SMR furnaces include a
mixture of process and combustion emissions.\15\ For more accurate
comparison of CEMS measured emissions with those estimated using the
mass balance method, we required reporting of the combustion emissions
from the SMR furnace as part of the subpart P emissions. Our proposed
revisions, therefore, were not a new requirement, but a further
clarification of the existing requirements in subpart P, as we
interpret them. Based on previous reviews of the emissions intensities
from hydrogen production as compiled from subpart P reported data, we
estimate that there are only a few facilities that do not include the
SMR furnace or process heaters combustion emissions in their subpart P
emission totals. To allow time for those facilities to measure fuel
used in stationary combustion units associated with hydrogen production
(e.g., reforming furnaces and hydrogen production process unit
heaters), we decided to include in this final rule a limited allowance
for BAMM for those facilities that may still need to add appropriate
monitoring equipment (as demonstrated through meeting the specified
criteria in the final provision). We also note that subpart C units
reporting under the common pipe reporting configuration at 40 CFR
98.36(c)(3) may use company records to subtract out the portion of the
fuel diverted to other combustion unit(s) prior to performing the GHG
emissions calculations for the group of units using the common pipe
option. Regarding the recommendation to implement a threshold to limit
applicability to larger hydrogen production facilities, we are not
taking final action on any revisions to the threshold to subpart P,
therefore, facilities with hydrogen production plants will continue to
determine applicability to part 98 based on the existing requirements
of 40 CFR 98.2(a). A facility that contains a source category listed in
table A-4 to subpart A of part 98 (which includes hydrogen production)
must report only if the estimated combined annual emissions from
stationary fuel combustion units, miscellaneous uses of carbonate, and
all applicable source categories in tables A-3 and table A-4 of part 98
are 25,000 mtCO2e or more. Therefore, the applicability of
the subpart is already limited to larger hydrogen production
facilities.
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\15\ See, e.g., https://ccdsupport.com/confluence/pages/viewpage.action?pageId=173080691.
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Comment: One commenter stated that EPA's proposed mass balance
equation under 40 CFR 98.163(d), equation P-4, requires further
revision to ensure that it is accurate for refineries that have non-
merchant hydrogen plants (such as those currently reporting under
subpart Y). The commenter added that to ensure proper accounting, the
variable ``Coftsite,n'' should be further revised to include
language for non-merchant hydrogen plants as follows: ``Mass of carbon
other than CO2 or methanol collected from the hydrogen
production
[[Page 31841]]
unit and transferred off site or reported elsewhere by the facility
under this part, from company records for month n (metric tons
carbon).''
Response: Following consideration of comments on similar proposed
revisions in other subparts, as discussed in section III.K.2. of this
preamble, we are not taking final action at this time on proposed
amendments to equation P-4 to allow the subtraction of carbon contained
in products other than CO2 or methanol and the carbon
contained in methanol from the carbon mass balance used to estimate
CO2 emissions. However, we acknowledge this concern and
agree that an analogous scenario may also occur within a facility that
contains a captive (non-merchant) hydrogen production process unit. For
example, some hydrogen production processes may operate without the
water-gas-shift reaction and produce a syngas of hydrogen and carbon
monoxide. For merchant plants, this syngas would be sold as a product
for use as a fuel or as a feedstock for chemical production process.
For a non-merchant plant, the syngas may be used on-site as a fuel or
feedstock rather than sold off-site as a product. If a captive hydrogen
production unit produces syngas for use as a fuel for an on-site
stationary combustion unit, for example, the rule as proposed would not
have allowed the subtraction of the carbon in the syngas from the
emissions from the hydrogen production unit, resulting in double
counting the CO2 emissions related to this carbon (from both
the hydrogen production unit and from the stationary combustion
source). Most refineries with captive hydrogen production units seek to
produce hydrogen for use in their refining process units and,
therefore, use the water-gas-shift reaction to make pure hydrogen
rather than syngas. However, production of syngas is possible under
some circumstances. Although we are not finalizing equation P-4 as
proposed, because the rule currently requires the reporting of carbon
other than CO2 or methanol that is transferred off site, we
have revised the reporting requirements to clarify that the reported
value, for non-merchant hydrogen production facilities, should include
the quantity of carbon other than CO2 or methanol that is
transferred to a separate process unit within the facility for which
GHG emissions associated with this carbon are being reported under
other provisions of part 98.
Comment: One commenter supported the separate reporting of hydrogen
that is produced and hydrogen that is only purified, but requested that
the EPA provide sufficient implementation time and allow for best
available monitoring methods to be used until installation of necessary
monitoring equipment could occur.
Another commenter was supportive of reporting steam consumption
data (i.e., annual net quantity of steam consumed). However, the
commenter added that there may be situations where steam is sourced
from equipment (e.g., a stand-alone boiler) distinct from a waste heat
boiler associated with the SMR process; the commenter stated the rule
should allow for flexibility in how the steam production and
consumption is measured and quantified, including the ability to
utilize best available monitoring methods.
Other commenters opposed reporting steam consumption data. One
commenter opposing the requirements stated it could result in
duplicative reporting based on what is proposed to be reported under
subpart B. Two commenters stated that the EPA failed to provide
justification for the requirement. Two commenters stated that it may be
necessary for the EPA to issue an additional supplemental notice of
proposed rulemaking to take comment on any such justification.
Response: Subpart P only provides monitoring requirements for fuels
and feedstocks, it does not specify monitoring requirements for other
reported data, for example, ammonia and methanol production. There are
often cases in part 98 where there are reporting elements, but not
specific monitoring requirements. In such cases, company records,
engineering estimates, and similar approaches may be used (in addition
to direct measurement methods) to report these quantities. As such,
there is no need for BAMM provisions related to additional reporting
requirements that require separately reporting produced and purified
hydrogen quantities and net steam consumption.
We also note that the subpart P requirement is process unit
specific, which is not duplicative of the proposed subpart B facility-
or subpart-level reporting requirements. We also disagree that we did
not provide rationale for the proposed requirements. These requirements
(as with many of the other proposed requirements for subpart P) are
aimed to obtain better information to verify reported emissions. For
example, if a facility is a net steam purchaser, some emissions
resulting from activities that support the hydrogen production process
may occur at the steam production site. Thus, knowing the net steam
consumption may help explain why the emissions to production ratios for
these facilities based on reported data do not fall within the expected
ranges. Understanding this could result in less correspondence from the
EPA to verify these facilities' reports and therefore reduce the burden
to these facilities.
J. Subpart Q--Iron and Steel Production
We are finalizing the amendments to subpart Q of part 98 (Iron and
Steel Production) as proposed. This section discusses the final
revisions to subpart Q. The EPA received comments on the proposed
requirements for subpart Q; see the document ``Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of
all comments and responses related to subpart Q. Additional rationale
for these amendments is available in the preamble to the 2022 Data
Quality Improvements Proposal. We are also finalizing as proposed
confidentiality determinations for new data elements resulting from the
revisions to subpart Q as described in section VI. of this preamble.
1. Revisions To Improve the Quality of Data Collected for Subpart Q
The EPA is finalizing revisions to subpart Q, as proposed in the
2022 Data Quality Improvements Proposal, to enhance the quality and
accuracy of the data collected. First, we are revising 40 CFR 98.176(g)
for all unit types (taconite indurating furnace, basic oxygen furnace,
non-recovery coke oven battery, sinter process, EAF, decarburization
vessel, and direct reduction furnace) and all calculation methods
(direct measurement using CEMS, carbon mass balance methodologies, or
site-specific emission factors) to require that facilities report the
type of unit, the annual production capacity, and the annual operating
hours for each unit.
The EPA is also finalizing revisions to correct equation Q-5 in 40
CFR 98.173(b)(1)(v) to remove an error introduced into the equation in
prior revisions (81 FR 89188, December 9, 2016). The final rule
corrects the equation to remove an unnecessary fraction symbol. See
section III.H.1. of the preamble to the 2022 Data Quality Improvements
Proposal for additional information on these revisions and their
supporting basis.
2. Revisions To Streamline and Improve Implementation for Subpart Q
The EPA is finalizing two revisions to subpart Q to streamline
monitoring. First, we are revising 40 CFR
[[Page 31842]]
98.174(b)(2) to provide the option for facilities to determine the
carbon content of process inputs and outputs by use of analyses
provided by material recyclers that manage process outputs for sale or
use by other industries. Material recyclers conduct testing on their
inputs and products to provide to entities using the materials
downstream, and therefore perform carbon content analyses using similar
test methods and procedures as suppliers. The final revisions include a
minor harmonizing change to 40 CFR 98.176(e)(2) to require reporters to
indicate if the carbon content was determined from information supplied
by a material recycler.
The EPA is also finalizing revisions to 40 CFR 98.174(b)(2) to
incorporate a new test method, ASTM E415-17, Standard Test Method for
Analysis of Carbon and Low-Alloy Steel by Spark Atomic Emission
Spectrometry (2017), for carbon content analysis of low-alloy steel.
The new method is incorporated by reference in 40 CFR 98.7 and
98.174(b)(2) for use for steel, as applicable. The addition of this
alternative test method will provide additional flexibility for
reporters. We are also finalizing one harmonizing change to the
reporting requirements of 40 CFR 98.176(e)(2), to clarify that the
carbon content analysis methods available to report are those methods
listed in 40 CFR 98.174(b)(2). See section III.H.2. of the preamble to
the 2022 Data Quality Improvements Proposal for additional information
on these revisions and their supporting basis.
K. Subpart S--Lime Production
We are finalizing several amendments to subpart S of part 98 (Lime
Production) as proposed. In some cases, we are finalizing the proposed
amendments with revisions. Section III.K.1. of this preamble discusses
the final revisions to subpart S. The EPA received several comments on
the proposed subpart S revisions which are discussed in section
III.K.2. of this preamble. We are also finalizing as proposed related
confidentiality determinations for data elements resulting from the
revisions to subpart S, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart S
The EPA is finalizing several revisions to subpart S of part 98
(Lime Manufacturing) as proposed to improve the quality of the data
collected from this subpart. First, we are finalizing the addition of
reporting requirements for reporters using the CEMS methodology, in
order to improve our understanding of source category emissions and our
ability to verify reported data. The EPA is adding data elements under
40 CFR 98.196(a) to collect annual averages of the chemical composition
input data on a facility-basis, including the annual arithmetic average
calcium oxide content (mt CaO/mt tons lime) and magnesium oxide content
(mt MgO/mt lime) for each type of lime produced, for each type of
calcined lime byproduct and waste sold, and for each type of calcined
lime byproduct and waste not sold. These data elements rely on an
arithmetic average of the measurements rather than requiring reporters
to weight by quantities produced in each month. Collecting average
chemical composition data for CEMS facilities will provide the EPA the
ability to develop a process emission estimation methodology for CEMS
reporters, which can be used to verify the accuracy of the reported
CEMS emission data.
The EPA is also finalizing additional data elements for reporters
using the mass balance methodology (i.e., reporters that comply using
the requirements at 40 CFR 98.193(b)(2)). The final rule includes new
data elements under 40 CFR 98.196(b) to collect the annual average
results of the chemical composition analysis of all lime byproducts or
wastes not sold (e.g., a single facility average calcium oxide content
calculated from the calcium oxide content of all lime byproduct types
at the facility), and the annual quantity of all lime byproducts or
wastes not sold (e.g., a single facility total calculated as the sum of
all quantities, in tons, of all lime byproducts at the facility not
sold during the year). These amendments will allow the EPA to build
verification checks for the actual inputs entered (e.g., MgO content).
Because the final data elements rely on annual averages of the chemical
composition measurements and an annual quantity of all lime byproducts
or wastes at the facility, they are distinct from the data entered into
the EPA's verification software tool. Additional information on these
revisions and their supporting basis may be found in section III.I. of
the preamble to the 2022 Data Quality Improvements Proposal.
In the 2022 Data Quality Improvements Proposal, the EPA proposed to
improve the methodology for calculation of annual CO2
process emissions from lime production to account for CO2
that is captured from lime kilns and used on-site. Specifically, we
proposed to modify equation S-4 to subtract the CO2 that is
captured and used in on-site processes, with corresponding revisions to
the recordkeeping requirements in 40 CFR 98.197(c) (to record the
monthly amount of CO2 from the lime manufacturing process
that is captured for use in all on-site processes), minor amendments to
the reporting elements in 40 CFR 98.196(b)(1) (to clarify reporting of
annual net emissions), 40 CFR 98.196(b)(17) (to clarify reporters do
not need to account for CO2 that was not captured but was
used on-site), and to clarify that reporters must account for
CO2 usage from all on-site processes, including for
manufacture of other products, in the total annual amount of
CO2 captured. Following consideration of comments received,
the EPA is not taking final action at this time on the proposed
revisions to equation S-4, or the corresponding revisions to 40 CFR
98.196(b)(1) and 98.197(c). We are finalizing the clarifying revisions
to 40 CFR 98.196(b)(17), as proposed. We are also finalizing an
editorial correction to equation S-4 to add a missing equation symbol.
See section III.K.2. of this preamble for additional information on
related comments and the EPA's response.
2. Summary of Comments and Responses on Subpart S
This section summarizes the major comments and responses related to
the proposed amendments to subpart S. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart S.
Comment: One commenter opposed the proposed modifications to
equation S-4 requiring monthly subtraction of CO2 used on-
site, stating it would be considerably more burdensome for lime
producers that currently track and report this usage on an annual
basis. The commenter requested that the EPA continue to allow the
annual reporting of CO2 usage, and thus implement an annual
subtraction from total process emissions from all lime kilns combined.
Response: The EPA proposed revisions to subparts G (Ammonia
Manufacturing), P (Hydrogen Production), and S (Lime Manufacturing)
that would have required monthly measurement of captured CO2
used to manufacture other products on-site or non-CO2 carbon
sent off-site to external users. It would also have modified the
subpart-level equations to require that these amounts
[[Page 31843]]
be subtracted from the emissions total. However, the EPA needs
additional time to consider these comments and whether a consistent
approach across these three subparts should be required or whether
there are circumstances where alternative approaches might be
warranted. Therefore, the EPA is not taking final action on these
proposed revisions to subparts G, P, and S for at this time but may
consider implementing these or similar revisions in future rulemakings.
L. Subpart U--Miscellaneous Uses of Carbonate
The EPA is finalizing one minor change to subpart U of part 98
(Miscellaneous Uses of Carbonate). The revision in this final rule is a
harmonizing change following review of comments received on proposed
subpart ZZ to part 98 (Ceramics Manufacturing) (see section III.EE. of
this preamble for additional information on the related comments and
the EPA's response). We are revising the source category definition for
subpart U at 40 CFR 98.210(b) to clarify that ceramics manufacturing is
excluded from the source category. Section 98.210(b) excludes equipment
that uses carbonates or carbonate-containing materials that are
consumed in production of cement, glass, ferroalloys, iron and steel,
lead, lime, phosphoric acid, pulp and paper, soda ash, sodium
bicarbonate, sodium hydroxide, or zinc. We are adding the text ``or
ceramics'' to ensure that there is no duplicative reporting between
subpart U and new subpart ZZ.
M. Subpart X--Petrochemical Production
We are finalizing several amendments to subpart X of part 98
(Petrochemical Production) as proposed. This section summarizes the
final revisions to subpart X. The EPA received only minor comments on
the proposed requirements for subpart X. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart X.
We are finalizing as proposed several amendments to subpart X to
improve the quality of data reported and to clarify the calculation,
recordkeeping, and reporting requirements. First, we are finalizing a
clarification to the emissions calculation requirements for flares in
40 CFR 98.243(b)(3) and (d)(5) to cross-reference 40 CFR 98.253(b) of
subpart Y; these revisions clarify that subpart X reporters are not
required to report emissions from combustion of pilot gas and from gas
released during startup, shutdown, and malfunction (SSM) events of
<500,000 standard cubic feet (scf)/day that are excluded from equation
Y-3.
Next, we are finalizing as proposed the addition of new reporting
requirements intended to improve the quality of the data collected
under the GHGRP. First, we are finalizing reporting a new data element
in 40 CFR 98.246(b)(7) and (c)(3). For each flare that is reported
under the CEMS and optional ethylene combustion methodologies,
facilities must report the estimated fractions of the total
CO2, CH4, and N2O emissions from each
flare that are due to combusting petrochemical off-gas. The final rule
will allow the fractions attributed to each petrochemical process unit
that routes emissions to the flare to be estimated using engineering
judgment. This change will allow more accurate quantification of
emissions both from individual petrochemical process units and from the
industry sector as a whole. Next, the EPA is finalizing addition of a
requirement in 40 CFR 98.246(c)(6) to report the names and annual
quantity (in metric tons) of each product produced in each ethylene
production process for emissions estimated using the optional ethylene
combustion methodology; this improves consistency with the product
reporting requirements under the CEMS and mass balance reporting
options.
We are finalizing, as proposed, a number of amendments that are
intended to remove redundant or overlapping requirements and to clarify
the data to be reported, as follows:
For facilities that use the mass balance approach, we are
finalizing amendments to 40 CFR 98.246(a)(2) to remove the requirement
to report feedstock and product names, which previously overlapped with
reporting requirements in 40 CFR 98.246(a)(12) and (13).
We are finalizing revisions to 40 CFR 98.246(a)(5) to
clarify the petrochemical and product reporting requirements for
integrated ethylene dichloride/vinyl chloride monomer (EDC/VCM) process
units. The amendments clarify the rule for facilities with an
integrated EDC/VCM process unit that withdraw small amounts of the EDC
as a separate product stream. The final rule is revised at 40 CFR
98.246(a)(5) to specify that (1) the portion of the total amount of EDC
produced that is an intermediate in the production of VCM may be either
a measured quantity or an estimate; (2) the amount of EDC withdrawn
from the process unit as a separate product (i.e., the portion of EDC
produced that is not utilized in the VCM production) is to be measured
in accordance with 40 CFR 98.243(b)(2) or (3); and (3) the sum of the
two values is to be reported under 40 CFR 98.246(a)(5) as the total
quantity of EDC petrochemical from an integrated EDC/VCM process unit.
We are finalizing a change in 40 CFR 98.246(a)(13) to
clarify that the amount of EDC product to report from an integrated
EDC/VCM process unit should be only the amount of EDC, if any, that is
withdrawn from the integrated process unit and not used in the VCM
production portion of the integrated process unit.
For facilities that use CEMS, we are finalizing amendments
to 40 CFR 98.246(b)(8) to clarify the reporting requirements for the
amount of EDC petrochemical when using an integrated EDC/VCM process
unit, by removing language related to considering the petrochemical
process unit to be the entire integrated EDC/VCM process unit.
For facilities that use the optional ethylene combustion
methodology to determine emissions from ethylene production process
units, we are finalizing revisions to 40 CFR 98.246(c)(4) to clarify
that the names and annual quantities of feedstocks that must be
reported will be limited to feedstocks that contain carbon.
We are finalizing changes to 40 CFR 98.246(a)(15) to more
clearly specify that molecular weight must be reported for gaseous
feedstocks and products only when the quantity of the gaseous feedstock
or product used in equation X-1 is in standard cubic feet; the
molecular weight does not need to be reported when the quantity of the
gaseous feedstock or product is in kilograms.
Additional information on the EPA's rationale for these revisions
may be found in section III.K. of the preamble to the 2022 Data Quality
Improvements Proposal.
We are also finalizing as proposed confidentiality determinations
for new data elements resulting from the revisions to subpart X, as
described in section VI. of this preamble.
N. Subpart Y--Petroleum Refineries
We are finalizing several amendments to subpart Y of part 98
(Petroleum Refineries) as proposed. This section summarizes the final
revisions to subpart Y. The EPA received several comment letters on the
proposed
[[Page 31844]]
requirements for subpart Y. See the document ``Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of
all comments and responses related to subpart Y.
We are also finalizing as proposed confidentiality determinations
for new data elements resulting from the revisions to subpart Y, as
described in section VI. of this preamble.
1. Revisions To Improve the Quality of Data Collected for Subpart Y
The EPA is finalizing as proposed several amendments to subpart Y
of part 98 to improve data collection, clarify rule requirements, and
correct an error in the rule. First, we are finalizing amendments to
the provisions for delayed coking units (DCU) to add reporting
requirements for facilities using mass measurements from company
records to estimate the amount of dry coke at the end of the coking
cycle in 40 CFR 98.256(k)(6)(i) and (ii). These new paragraphs will
require facilities to additionally report, for each DCU: (1) the
internal height of the DCU vessel; and (2) the typical distance from
the top of the DCU vessel to the top of the coke bed (i.e., coke drum
outage) at the end of the coking cycle (feet). These new elements will
allow the EPA to estimate and verify the reported mass of dry coke at
the end of the cooling cycle as well as the reported DCU emissions.
We are also finalizing revisions to equation Y-18b in 40 CFR
98.253(i)(2), to include a new variable ``fcoke'' to allow
facilities that do not completely cover the coke bed with water prior
to venting or draining to accurately estimate the mass of water in the
drum. The ``fcoke'' variable is defined as the fraction of
coke-filled bed that is covered by water at the end of the cooling
cycle just prior to atmospheric venting or draining, where a value of
one (1) represents cases where the coke is completely submerged in
water. The second term in equation Y-18b represents the volume of coke
in the drum, and is subtracted from the water-filled coke bed volume to
determine the volume of water. We are also finalizing revisions to the
equation terms ``Mwater'' and ``Hwater'' to add
the phase ``or draining'' to specify that these parameters reflect the
mass of water and the height of water, respectively, at the end of the
cooling cycle just prior to atmospheric venting or draining. We are
finalizing harmonizing revisions to the recordkeeping requirements at
40 CFR 98.257(b)(45) and (46) and a corresponding recordkeeping
requirement at 40 CFR 98.257(b)(53).
To help clarify that the calculation methodologies in 40 CFR
98.253(c) and 98.253(e) are specific to coke burn-off emissions, we are
finalizing the addition of ``from coke burn-off'' immediately after the
first occurrence of ``emissions'' in the introductory text of 40 CFR
98.253(c) and 98.253(e).
We are also finalizing corrections to an inconsistency
inadvertently introduced into subpart Y by amendments published on
December 9, 2016 (81 FR 89188), which created an apparent inconsistency
about whether to include or exclude SSM events less than 500,000 scf/
day in equation Y-3. This final rule clarifies in 40 CFR 98.253(b) that
SSM events less than 500,000 scf/day may be excluded, but only if
reporters are using the calculation method in 40 CFR 98.253(b)(1)(iii).
We are also finalizing revisions to remove the recordkeeping
requirements in existing 40 CFR 98.257(b)(53) through (56) and to
reserve 40 CFR 98.257(b)(54) through (56). These requirements should
have been removed in the December 9, 2016 amendments, which removed the
corresponding requirement in 40 CFR 98.253(j) to calculate
CH4 emissions from DCUs using the process vent method
(equation Y-19). The EPA is also finalizing corrections to an erroneous
cross-reference in 40 CFR 98.253(i)(5), which inaccurately defines the
term ``Mstream'' in equation Y-18f for DCUs, to correct the
cross-reference to Sec. 98.253(i)(4) instead of Sec. 98.253(i)(3).
Additional information on the EPA's rationale for these revisions may
be found in section III.L.1. of the preamble to the 2022 Data Quality
Improvements Proposal.
The EPA is finalizing as proposed one additional revision to
improve data quality from the 2023 Supplemental Proposal. Specifically,
we are finalizing the addition of a requirement to report the capacity
of each asphalt blowing unit, consistent with the existing reporting
requirements for other emissions units under subpart Y. The final rule
requires that facilities provide the maximum rated unit-level capacity
of the asphalt blowing unit, measured in mt of asphalt per day, in 40
CFR 98.256(j)(2). Additional information on the EPA's rationale for
these revisions may be found in section III.H. of the preamble to the
2023 Supplemental Proposal.
2. Revisions To Streamline and Improve Implementation for Subpart Y
The EPA is finalizing one change to subpart Y to streamline
monitoring. We are finalizing an option for reporters to use mass
spectrometer analyzers to determine gas composition and molecular
weight without the use of a gas chromatograph. The final rule adds the
inclusion of direct mass spectrometer analysis as an allowable gas
composition method in 40 CFR 98.254(d). This change will allow
reporters to use the same analyzers used for process control or for
compliance with continuous sampling which are proposed to be provided
under the National Emissions Standards for Hazardous Air Pollutants
from Petroleum Refineries (40 CFR part 63, subpart CC), to comply with
GHGRP requirements in subpart Y. Additional information on these
revisions and their supporting basis may be found in section III.L.2.
of the preamble to the 2022 Data Quality Improvements Proposal.
Consistent with changes we are finalizing to subpart P of part 98
(Hydrogen Production) from the 2023 Supplemental Proposal, we are
finalizing revisions to remove references to non-merchant hydrogen
production plants in 40 CFR 98.250(c) and to delete and reserve 40 CFR
98.252(i), 98.255(d), and 98.256(b). We are also finalizing as proposed
revisions to remove references to coke calcining units in 40 CFR
98.250(c) and 98.257(b)(16) through (19) and to remove and reserve 40
CFR 98.252(e), 98.253(g), 98.254(h), 98.254(i), 98.256(i), and
98.257(b)(27) through (31). As proposed in the 2023 Supplemental
Proposal, we are finalizing the addition of new subpart WW to part 98
(Coke Calciners), and these provisions are no longer necessary under
subpart Y. Additional information on these revisions and their
supporting basis may be found in section III.H. of the preamble to the
2023 Supplemental Proposal.
O. Subpart AA--Pulp and Paper Manufacturing
We are finalizing the amendments to subpart AA of part 98 (Pulp and
Paper Manufacturing) as proposed. The EPA received no comments
regarding the proposed revisions to subpart AA. Additional rationale
for these amendments is available in the preamble to the 2023
Supplemental Proposal. The EPA is revising 40 CFR 98.273 to add a
biogenic calculation methodology for estimation of CH4,
N2O, and biogenic CO2 emissions for units that
combust biomass fuels (other
[[Page 31845]]
than spent liquor solids) from table C-1 to subpart C of part 98 or
that combust biomass fuels (other than spent liquor solids) with other
fuels. We are also revising 40 CFR 98.276(a) to remove incorrect
references to biogenic CH4 and N2O and correcting
a typographical error at 40 CFR 98.277(d), as proposed. Additional
rationale for these amendments is available in the preamble to the 2023
Supplemental Proposal.
P. Subpart BB--Silicon Carbide Production
We are finalizing the amendments to subpart BB of part 98 (Silicon
Carbide Production) as proposed. The EPA received no comments regarding
the proposed revisions to subpart BB. Additional rationale for these
amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal. The EPA is finalizing a reporting requirement at
40 CFR 98.286(c) such that if CH4 abatement technology is
used at silicon carbide production facilities, then facilities must
report: (1) the type of CH4 abatement technology used and
the date of installation for each technology; (2) the CH4
destruction efficiency (percent destruction) for each CH4
abatement technology; and (3) the percentage of annual operating hours
that CH4 abatement technology was in use for all silicon
carbide process units or production furnaces combined. For each
CH4 abatement technology, reporters must either use the
manufacturer's specified destruction efficiency or the destruction
efficiency determined via a performance test; if the destruction
efficiency is determined via a performance test, reporters must also
report the name of the test method that was used during the performance
test. Following the initial annual report containing this information,
reporters will not be required to resubmit this information unless the
information changes during a subsequent reporting year, in which case,
the reporter must update the information in the submitted annual
report. The final revisions to subpart BB also add a recordkeeping
requirement at 40 CFR 98.287(d) for facilities to maintain a copy of
the reported information. Additional rationale for these amendments is
available in the preamble to the 2022 Data Quality Improvements
Proposal. The EPA is also finalizing, as proposed, confidentiality
determinations for the additional data elements to be reported as
described in section VI. of this preamble.
Q. Subpart DD--Electrical Transmission and Distribution Equipment Use
We are finalizing several amendments to subpart DD of part 98
(Electrical Transmission and Distribution Equipment Use) as proposed.
In some cases, we are finalizing the proposed amendments with
revisions. Section III.Q.1. of this preamble discusses the final
revisions to subpart DD. The EPA received several comments on the
proposed subpart DD revisions which are discussed in section III.Q.2.
of this preamble. We are also finalizing as proposed confidentiality
determinations for new data elements resulting from the final revisions
to subpart DD, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart DD
This section summarizes the final amendments to subpart DD. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other final
revisions to 40 CFR part 98, subpart DD can be found in this section
and section III.Q.2. of this preamble. Additional rationale for these
amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal.
a. Revisions To Improve the Quality of Data Collected for Subpart DD
The EPA is finalizing several revisions to subpart DD to improve
the quality of the data collected under this subpart. First, we are
generally finalizing the proposed revisions to the calculation,
monitoring, and reporting requirements of subpart DD to require
reporting of additional F-GHGs, except insulating gases with weighted
average GWPs less than or equal to one will remain excluded from
reporting under subpart DD. These final amendments will help to account
for use and emissions of replacements for SF6, including
fluorinated gas mixtures, with lower but still significant GWPs. We are
revising 40 CFR 98.300(a) to redefine the source category to include
equipment containing ``fluorinated GHGs (F-GHGs), including but not
limited to sulfur-hexafluoride (SF6) and perfluorocarbons
(PFCs).'' These changes include:
Revising the threshold determination in 40 CFR 98.301 by
adding new equations DD-1 and equation DD-2 (see section III.Q.1.b. of
this preamble).
Revising the GHGs to report at 40 CFR 98.302 by adding a
new equation DD-3, which is also used in the definition of ``reportable
insulating gas,'' discussed below.
Redesignating equation DD-1 as equation DD-4 at 40 CFR
98.303 and revising the equation to estimate emissions from all F-GHGs
within the existing calculation methodology, including F-GHG mixtures.
Equation DD-4 will maintain the facility-level mass balance approach of
tracking and accounting for decreases, acquisitions, disbursements, and
net increase in total nameplate capacity for the facility each year,
but will apply the weight fraction of each F-GHG to determine the user
emissions by gas. In the final rule, we are making two clarifications
to equation DD-4 in addition to the revisions that were proposed. These
are discussed further below.
Updating the monitoring and quality assurance requirements
at 40 CFR 98.304(b) to account for emissions from additional F-GHGs.
To address references to F-GHGs and F-GHG mixtures, we are
finalizing the term ``insulating gas'' which is defined as ``any
fluorinated GHG or fluorinated GHG mixture, including but not limited
to SF6 and PFCs, that is used as an insulating and/or arc
quenching gas in electrical equipment.''
To clarify which insulating gases are subject to reporting
requirements, we are adding the term ``reportable insulating gas,''
which is defined as ``an insulating gas whose GWP, as calculated in
equation DD-3, is greater than one. A fluorinated GHG that makes up
either part or all of a reportable insulating gas is considered to be a
component of the reportable insulating gas.'' In many though not all
cases, we are replacing occurrences of the proposed phrase
``fluorinated GHGs, including PFCs and SF6'' with
``fluorinated GHGs that are components of reportable insulating
gases.''
Adding harmonizing requirements to the term ``facility''
in the definitions section at 40 CFR 98.308 and the requirements at 40
CFR 98.302, 98.305, and 98.306 to require reporters to account for the
mass of each F-GHG for each electric power system.
As noted above, following consideration of comments received, the
EPA is revising these requirements from proposal to continue to exclude
insulating gases with weighted average 100-year GWPs of less than one.
Based on a review of the subpart DD data submitted to date, the EPA has
concluded that excluding insulating gases with GWPs of less than one
from reporting under subpart DD will have little effect on the accuracy
or completeness of the GWP-weighted totals reported under subpart DD or
[[Page 31846]]
under the GHGRP generally at this time, and will decrease the reporting
burden for facilities. See section III.Q.2. of this preamble for a
summary of the related comments and the EPA's response.
Also as noted above, we are making two clarifications to equation
DD-4 in addition to the revisions that were proposed. First, to account
for the possibility that the same fluorinated GHG could be a component
of multiple reportable insulating gases, we are inserting a summation
sign at the beginning of the right side of equation DD-4 to ensure that
emissions of each fluorinated GHG ``i'' are summed across all
reportable insulating gases ``j.'' Second, upon further consideration
of equation DD-4 and its relationship to the newly defined terms ``new
equipment'' and ``retiring equipment,'' we are modifying the terms for
acquisitions and disbursements of reportable insulating gas j to
account for acquisitions and disbursements of reportable insulating gas
that are linked to the acquisition or sale of all or part of an
electric power system. These include acquisitions or disbursements of
reportable insulating gas inside equipment that is transferred while in
use, acquisitions or disbursements of insulating gas inside equipment
that is transferred from or to entities other than electrical equipment
manufacturers and distributors while the equipment is not in use, and
acquisitions or disbursements of insulating gas in bulk from or to
entities other than chemical producers or distributors. Accounting for
these acquisitions and disbursements in equation DD-4 ensures that the
terms for acquisitions and disbursements of reportable insulating gas
will be mathematically consistent with other terms in the equation,
including the terms for the net increase in total nameplate capacity
and the quantity of gas stored in containers at the end of the year.
The term for the net increase in the total nameplate capacity will
reflect the new definitions of ``new equipment'' and ``retiring
equipment,'' which include transfers of equipment while in use.
Similarly, the term for the quantity of reportable insulating gas
stored in containers at the end of the year will reflect acquisitions
or disbursements of reportable insulating gas stored in containers from
or to all other entities, including other electric power systems. If
these acquisitions or disbursements of gas in equipment or in bulk are
not accounted for in the equation, the result will be incorrect. The
revised terms are consistent with the definitions of ``new'' and
``retired'' in their treatment of hermetically sealed pressure
equipment, with such equipment being included in terms related to
equipment that is transferred while not in use, but excluded from terms
related to equipment that is transferred while in use. We are also
making harmonizing changes to the reporting requirements at 40 CFR
98.306, revising paragraphs (f), (g), and (i) (to be redesignated as
paragraph (k)), and adding paragraphs (i), (n), and (o). These
harmonizing revisions do not substantively change the reporting
requirements as proposed and therefore would not substantively impact
the burden to reporters.
With minor changes, we are finalizing the proposed requirements in
40 CFR 98.303(b) for users of electrical equipment to follow certain
procedures when they elect to measure the nameplate capacities (in
units of mass of insulating gas) of new and retiring equipment rather
than relying on the rated nameplate capacities provided by equipment
manufacturers. As proposed, this option will be available only for
closed pressure equipment with a voltage capacity greater than 38
kilovolts (kV), not for hermetically sealed pressure equipment or
smaller closed-pressure equipment. These procedures are intended to
ensure that the nameplate capacity values that equipment users measure
match the full and proper charges of insulating gas in the electrical
equipment. These procedures are similar to and compatible with the
procedures for measuring nameplate capacity adopted by the California
Air Resources Board (CARB) in its Regulation for Reducing Greenhouse
Gas Emissions from Gas Insulated Switchgear.\16\
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\16\ See https://ww2.arb.ca.gov/sites/default/files/barcu/regact/2020/sf6/fro.pdf.
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Specifically, electrical equipment users electing to measure the
nameplate capacities of any new or retiring equipment will be required
at 40 CFR 98.303(b)(1) to measure the nameplate capacities of all
eligible new and retiring equipment in that year and in all subsequent
years. For each piece of equipment, the electrical equipment user will
be required to calculate the difference between the user-measured and
rated nameplate capacities, verifying that the rated nameplate capacity
was the most recent available from the equipment manufacturer. Where a
user-measured nameplate capacity differs from the rated nameplate
capacity by two percent or more, the electrical equipment user will be
required at 40 CFR 98.303(b)(2) to adopt the user-measured nameplate
capacity for that equipment for the remainder of the equipment's life.
Where a user-measured nameplate capacity differs from the rated
nameplate capacity by less than two percent, the electrical equipment
user will have the option at 40 CFR 98.303(b)(3) to adopt the user-
measured nameplate capacity, but if they chose to do so, they must
adopt the user-measured nameplate capacities for all new and retiring
equipment whose user-measured nameplate capacity differed from the
rated nameplate capacity by less than two percent.
With minor changes, the EPA is finalizing the proposed requirements
at 40 CFR 98.303(b)(4) and (5) for when electrical equipment users
measure the nameplate capacity of new equipment that they install and
for when they measure the nameplate capacity of retiring equipment.
These final requirements ensure that electrical equipment users:
Correctly account for the mass of insulating gas contained
in new equipment upon delivery from the manufacturer (i.e., the holding
charge), and correctly account for the mass of insulating gas contained
in equipment upon retirement, measuring the actual temperature-adjusted
pressure and comparing that to the temperature-adjusted pressure that
reflects the correct filling density of that equipment.
Use flowmeters or weigh scales that meet certain accuracy
and precision requirements to measure the mass of insulating gas added
to or recovered from the equipment;
Use pressure-temperature charts and pressure gauges and
thermometers that meet certain accuracy and precision requirements to
fill equipment to the density specified by the equipment manufacturer
or to recover the insulating gas from the equipment to the correct
blank-off pressure, allowing appropriate time for temperature
equilibration; and
Ensure that insulating gas remaining in the equipment,
hoses and gas carts is correctly accounted for.
After consideration of comments, we are including a requirement to
follow the procedure specified by the equipment manufacturer to ensure
that the measured temperature accurately reflects the temperature of
the insulating gas, e.g., by measuring the insulating gas pressure and
vessel temperature after allowing appropriate time for the temperature
of the transferred gas to equilibrate with the vessel temperature. Also
after consideration of comments, we are (1) adding a requirement that
facilities that use flow meters to measure the mass of insulating gas
added to new equipment must keep the
[[Page 31847]]
mass flow rate within the range specified by the flowmeter
manufacturer, and (2) not finalizing the option to use mass flowmeters
to measure the mass of the insulating gas recovered from equipment. We
are making both changes because the accuracy and precision of
flowmeters can decrease significantly when the mass flow rate declines
below the minimum specified by the flow meter manufacturer for accurate
and precise measurements.
As proposed, we are allowing equipment users to account for any
leakage from the equipment using one of two approaches. In both
approaches, users must measure the temperature-compensated pressure of
the equipment before they remove the insulating gas from that equipment
and compare the measured temperature-compensated pressure to the
temperature-compensated pressure corresponding to the full and proper
charge of the equipment (the design operating pressure). If the
measured temperature-compensated pressure is different from the
temperature-compensated pressure corresponding to the full and proper
charge of the equipment, the equipment user may either (1) add or
remove insulating gas to or from the equipment until the equipment
reaches its full and proper charge; recover the gas until the equipment
reached a pressure of 0.068 pounds per square inch, absolute (psia)
(3.5 Torr) or less; and weigh the recovered gas (charge adjustment
approach), or (2) if (a) the starting pressure of the equipment is
between its temperature-compensated design operating pressure and five
(5) pounds per square inch (psi) below that pressure, and (b) the
insulating gas is recovered to a pressure no higher than 5 psia (259
Torr),\17\ recover the gas that was already in the equipment; weigh it;
and account mathematically for the difference between the quantity of
gas recovered from the equipment and the full and proper charge
(mathematical adjustment approach, equation DD-5).
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\17\ While the mathematical adjustment approach is expected to
yield accurate results if the final pressure is 5 psia or less,
facilities are encouraged to recover the insulating gas until they
reach the blank-off pressure of the gas cart, which is generally
expected to fall below 5 psia. Note that where the final pressure is
equal to or less than 0.068 psia, the gas remaining in the equipment
is estimated to account for a negligible share of the total and
therefore facilities are not required to use the Mathematical
Adjustment Method to account for it.
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In the final rule, we are allowing use of the mathematical
adjustment approach in somewhat more limited circumstances than
proposed. We proposed that to use the mathematical adjustment approach
to calculate the nameplate capacity, facilities would need to recover a
quantity of insulating gas equivalent to at least 90 percent of the
full manufacturer-rated nameplate capacity of the equipment, which
would have provided more flexibility on the starting and ending
pressures of the equipment during the recovery process. The proposed
requirement was based on an analysis of the proposed accuracies and
precisions of measuring devices and their impacts on the accuracy and
precision of the mathematical adjustment approach, which indicated that
90 percent of the gas must be recovered to limit the uncertainty of the
calculation to below 2 percent. We also recognized that departures from
the ideal gas law could result in additional, systematic errors in the
mathematical adjustment approach and therefore requested comment on the
option of adding compressibility factors, which account for these
departures, to equation DD-5 (proposed as equation DD-4). Such
compressibility factors are not constant but are functions of the
pressure and temperature of the insulating gas based on an equation of
state specific to that insulating gas. We did not receive any comment
on this option, and after considering the matter further, we believe
that performing calculations using compressibility factors would prove
too complex to implement in the field to obtain accurate nameplate
capacity values. Without compressibility factors, departures of the
insulating gas from the ideal gas law limit the reliability of the
mathematical adjustment approach except within the ranges of starting
and ending pressures described above. Consequently, we are finalizing
the mathematical adjustment method as proposed but are restricting its
use to the specified ranges of starting and ending pressures. Under
these circumstances, any systematic errors in the mathematical
adjustment approach are generally expected to fall below 0.5 percent,
leading to maximum total errors (accounting for both departures from
the ideal gas law and limits on the accuracy and precision of measuring
devices) of approximately two percent. (For more discussion of this
issue, see ``Update to the Technical Support for Proposed Revisions to
Subpart DD, Electrical Transmission and Distribution Equipment Use,''
included in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-
2019-0424).
Given these restrictions, the mathematical adjustment approach
cannot be used to calculate the nameplate capacity of equipment that
cannot have the insulating gas inside of it recovered below atmospheric
pressure. However, as noted above, the approach can still be used for
situations where the blank-off pressure of a gas cart is above 3.5 Torr
(0.068 psia) but below 5 psia and/or where the starting pressure of the
electrical equipment is no more than 5 psi lower than its temperature-
compensated design operating pressure. (Note that equipment whose
starting pressure is above the temperature-compensated design operating
pressure will need to have the excess gas recovered until it reaches
the design operating pressure, at which point the nameplate capacity
measurement can begin.)
We are finalizing as proposed requirements at 40 CFR 98.303(b)(6)
that allow users to measure the nameplate capacity of electrical
equipment earlier during maintenance activities that require opening
the gas compartment. The equipment user will still be required to
follow the measurement procedures required for retiring equipment at 40
CFR 98.303(b)(5) to measure the nameplate capacity, and the measured
nameplate capacity must be recorded, but will not be used in equation
DD-3 until that equipment is actually retired.
We are finalizing as proposed requirements at 40 CFR 98.303(b)(7)
and (8) to require that, where the electrical equipment user is
adopting the user-measured nameplate capacity, the user must affix a
revised nameplate capacity label showing the revised nameplate value
and the year the nameplate capacity adjustment process was performed to
the device by the end of the calendar year in which the process was
completed. For each piece of electrical equipment whose nameplate
capacity is adjusted during the reporting year, the revised nameplate
capacity value must be used in all rule provisions wherein the
nameplate capacity is required to be recorded, reported, or used in a
calculation.
To ensure that the mass balance method is based on consistent
nameplate capacity values throughout the life of the equipment, we are
finalizing at 40 CFR 98.303(b)(9) that electrical equipment users are
allowed to measure and revise the nameplate capacity value of any given
piece of equipment only once, unless the nameplate capacity itself is
likely to have changed due to changes to the equipment (e.g.,
replacement of the equipment bushings).
To help ensure that electrical equipment users obtain accurate
measurements of their equipment's nameplate capacities, we are
finalizing requirements at 40 CR 98.303(b)(10) that
[[Page 31848]]
electrical equipment users must use measurement devices that meet the
following accuracy and precision requirements when they measure the
nameplate capacities of new and retiring equipment:
Flow meters must be certified by the manufacturer to be
accurate and precise to within one percent of the largest value that
the flow meter can, according to the manufacturer's specifications,
accurately record.
Pressure gauges must be certified by the manufacturer to
be accurate and precise to within 0.5 percent of the largest value that
the gauge can, according to the manufacturer's specifications,
accurately record.
Temperature gauges must be certified by the manufacturer
to be accurate and precise to within 1.0 [deg]F; and
Scales must be certified by the manufacturer to be
accurate and precise to within one percent of the true weight.
Additional information on these revisions and their supporting
basis may be found in section III.N.1. of the preamble to the 2022 Data
Quality Improvements Proposal.
We are finalizing at 40 CFR 98.306(r) and (s) (proposed as 40 CFR
98.306(o) and (p)) requirements for equipment users who measure and
adopt nameplate capacity values to report the total rated and measured
nameplate capacities across all the equipment whose nameplate
capacities were measured and for which the measured nameplate
capacities have been adopted in that year.
We are finalizing requirements in 40 CFR 98.307(b) as proposed for
equipment users to keep records of certain identifying information for
each piece of equipment for which they measure the nameplate capacity:
the rated and measured nameplate capacities, the date of the nameplate
capacity measurement, the measurements and calculations used to obtain
the measured nameplate capacity (including the temperature-pressure
curve and/or other information used to derive the initial and final
temperature adjusted pressures of the equipment), and whether or not
the measured nameplate capacity value was adopted for that piece of
equipment.
To clarify the mass balance methodology in 40 CFR 98.303, we are
adding definitions for ``energized,'' ``new equipment,'' and ``retired
equipment,'' at 40 CFR 98.308 as proposed. We are finalizing the
definition of ``energized'' as proposed to mean ``connected through
busbars or cables to an electrical power system or fully-charged, ready
for service, and being prepared for connection to the electrical power
system. Energized equipment does not include spare gas insulated
equipment (including hermetically-sealed pressure switchgear) in
storage that has been acquired by the facility, and is intended for use
by the facility, but that is not being used or prepared for connection
to the electrical power system.'' The final definition more clearly
designates what equipment is considered to be installed and functioning
as opposed to being in storage.
With two minor changes, we are finalizing the proposed definition
for ``new equipment.'' ``New equipment'' is defined as ``either (1) any
gas insulated equipment, including hermetically-sealed pressure
switchgear, that is not energized at the beginning of the reporting
year but is energized at the end of the reporting year, or (2) any gas
insulated equipment other than hermetically-sealed pressure switchgear
that has been transferred while in use, meaning it has been added to
the facility's inventory without being taken out of active service
(e.g., when the equipment is sold to or acquired by the facility while
remaining in place and continuing operation).'' Similarly, we are
finalizing the definition for ``retired equipment'' with two minor
changes. ``Retired Equipment'' is defined as ``either (1) any gas
insulated equipment, including hermetically-sealed pressure switchgear,
that is energized at the beginning of the reporting year but is not
energized at the end of the reporting year, or (2) any gas insulated
equipment other than hermetically-sealed pressure switchgear that has
been transferred while in use, meaning it has been removed from the
facility's inventory without being taken out of active service (e.g.,
when the equipment is acquired by a new facility while remaining in
place and continuing operation).'' The proposed definitions both
included two sentences, where the first sentence specified that the
equipment changed from ``not energized'' to ``energized'' (or vice
versa), and the second sentence preceded the phrase ``that has been
transferred while in use'' with ``This includes.'' Upon review of the
proposed definitions, we realized that they could lead to confusion
because equipment that is transferred while in use does not change from
``not energized'' to ``energized'' or vice versa, and therefore cannot
be ``included'' in the sets of equipment that change from ``not
energized'' to ``energized'' or vice versa. We therefore replaced
``This includes'' with ``or.'' We also realized that including
hermetically-sealed pressure switchgear in equipment that is
transferred while in use would trigger requirements to inventory the
acquired (new) or disbursed (retired) hermetically-sealed pressure
switchgear for purposes of the mass balance calculation (equation DD-4)
and the reporting requirements at 40 CFR 98.306(a)(2) and (4). We did
not intend to trigger these requirements for hermetically sealed
pressure equipment that is transferred during use. Such requirements
would be inconsistent with the intent and effect of the current
provision at 40 CFR 98.306(a)(1), which excludes existing hermetically-
sealed pressure switchgear from the requirement to report the existing
nameplate capacity total at the beginning of the year. We therefore
excepted hermetically sealed switchgear from equipment that is
transferred while in use in both definitions. With these minor changes,
the definitions clarify how the terms ``new'' and ``retired'' should be
interpreted for purposes of equation DD-3.
b. Revisions To Streamline and Improve Implementation for Subpart DD
The EPA is finalizing several revisions to subpart DD to streamline
requirements. First, we are revising the applicability threshold of
subpart DD at 40 CFR 98.301 largely as proposed, in order to align with
revisions to include additional F-GHGs in subpart DD. However, as
discussed above, insulating gases with weighted average GWPs less than
or equal to 1 will remain excluded from reporting under subpart DD. We
are replacing the existing nameplate capacity threshold with an
emissions threshold of 25,000 mtCO2e per year of F-GHGs that
are components of reportable insulating gases (i.e., insulating gases
whose weighted average GWPs, as calculated in equation DD-3, are
greater than one (1)). To calculate their F-GHG emissions for
comparison with the threshold, electrical equipment users will use one
of two new equations finalized in subpart DD at 40 CFR 98.301,
equations DD-1 and DD-2. The equations explicitly include not only the
nameplate capacity of the equipment but also an updated default
emission factor and the GWP of each insulating gas.
We are also finalizing revisions to the existing calculation,
monitoring, and reporting requirements of subpart DD to require
reporting of additional F-GHGs beyond SF6 and PFCs that are
components of reportable insulating gases. The new equations DD-1 and
DD-2 that we are finalizing for the applicability threshold require
potential
[[Page 31849]]
reporters to account for the total nameplate capacity of all equipment
containing reportable insulating gases (located on-site and/or under
common ownership or control), including equipment containing F-GHG
mixtures, and multiply by the weight fraction of each F-GHG (for gas
mixtures), the GWP for each F-GHG, and an emission factor of 0.10
(representing an emission rate of 10 percent).
We are finalizing harmonizing changes in multiple sections of
subpart DD to renumber equation DD-1 and maintain cross-references to
the equation. We are also finalizing revisions to the existing
threshold in 40 CFR 98.301 and table A-3 to subpart A (General
Provisions). Additional information on these revisions and their
supporting basis may be found in section III.N.2. of the preamble to
the 2022 Data Quality Improvements Proposal.
Finally, we are removing an outdated monitoring provision at 40 CFR
98.304(a), which reserves a prior requirement for use of BAMM that
applied solely for RY2011.
2. Summary of Comments and Responses on Subpart DD
This section summarizes the major comments and responses related to
the proposed amendments to subpart DD. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart DD.
a. Comments on Revisions To Improve the Quality of Data Collected for
Subpart DD
Comment: One commenter asked for clarification regarding whether
the equipment user needs to account for insulating gas remaining inside
gas-insulated equipment (GIE) that are transferred to another entity
(vendor) for repair or salvage. The commenter asserted that since the
equipment is leaving the inventory with gas inside, it should be
counted as both retired equipment and a gas disbursement. The commenter
suggested the ``Disbursements'' term in equation DD-3 be modified to
include similar language to the ``Acquisitions'' term, to clarify that
gas inside equipment that is transferred to another entity for repair
or salvage, in addition to equipment that is sold, counts as a
disbursement.
Response: The EPA agrees with the commenter and is revising the
``Disbursements'' term in equation DD-3 (being finalized as equation
DD-4) to account for gas ``transferred'' as well as ``sold'' to ``other
entities.'' As discussed in section III.Q.1. of this preamble, we are
making a number of clarifications to the ``Acquisitions'' and
``Disbursements'' terms in equation DD-4 to accommodate the full range
of possible acquisitions and disbursements by electric power systems,
which will improve the accuracy and completeness of equation DD-4 and
the associated reporting and recordkeeping requirements.
Comment: One commenter suggested that the EPA revise the nameplate
capacity adjustment text as follows: first, to remove the word
``covered'' prior to ``insulating gas'' in 40 CFR 98.303(b)(4)(ii)(A),
since ``covered'' is not included in the EPA's definition of insulating
gas.
Response: The EPA agrees with the commenter and is revising 40 CFR
98.303(b)(4)(ii)(A) as suggested to reflect the language which is used
in the definitions and to minimize confusion. As discussed in section
III.Q.1. of this preamble, we are introducing the term ``reportable
insulating gas'' to distinguish between insulating gas that is included
in subpart DD (``reportable'') because it has a weighted average GWP
greater than 1 and insulating gas that is not reportable because it has
a weighted average GWP of 1 or less.
Comment: Two commenters suggested the EPA change the language in 40
CFR 98.303(b)(5)(ii), which was proposed as a requirement to ``convert
the initial system pressure to a temperature-compensated initial system
pressure by using the temperature/pressure curve for that insulating
gas.'' The commenters stated that the temperature/pressure curve is not
intended for conversions of initial system pressure to temperature-
compensated pressure. The commenters suggested that the requirement
should be to compare the measured initial system pressure and vessel
temperature to the equipment manufacturer's temperature-pressure curve
specific for the equipment to confirm the equipment is at the proper
operating pressure, prior to recovery of the insulating gas. One
commenter recommended two options for measuring initial gas pressure:
(1) use external pressure and temperature gauges according to 40 CFR
98.303(b)(5)(i); or (2) if an integrated temperature-compensated gas
pressure gauge was used for the initial gas fill and to monitor and
maintain the gas at the proper operating pressure over the service life
of the circuit breaker, use the same gauge to determine whether the
circuit breaker is at the proper operating pressure.
Response: The EPA agrees with the commenters regarding the language
at 40 CFR 98.303(b)(5)(ii) and is finalizing the requirement as
follows: ``Compare the initial system pressure and temperature to the
equipment manufacturer's temperature/pressure curve for that equipment
and insulating gas.'' Regarding allowing use of an integrated
temperature-compensated gas pressure gauge, use of such a gauge is
allowed if the gauge is certified by the gauge manufacturer to be
accurate and precise to within 0.5 percent of the largest value that
the gauge can, according to the manufacturer's specifications,
accurately record. It is EPA's understanding that many gauges that are
built into the electrical equipment do not meet these accuracy and
precision requirements. However, if they do, the rule does not prohibit
their use in nameplate capacity measurements.
Comment: One commenter objected to the proposed requirement to
recover the insulating gas to a blank-off pressure not greater than 3.5
Torr during the nameplate capacity measurement. The commenter noted
that not all facilities own gas carts capable of reaching 3.5 Torr,
and, for some GIE, that level of pressure is not necessary for an
accurate reading. The commenter recommended that the GIE recovery be
performed to allow for 99.1 percent or greater recovery of the
insulating gas.
Response: As discussed above, the EPA is finalizing a requirement
that facilities measuring the nameplate capacity of their equipment
recover the gas to a pressure of at most 5 psia (258.6 Torr). This will
accommodate gas carts that are not capable of reaching 3.5 Torr. To
ensure that the gas remaining in the equipment at pressures above 3.5
Torr is accounted for, facilities that recover the gas to a pressure
between 5 psia and 3.5 Torr will be required to use the mathematical
adjustment approach (equation DD-5) to calculate the full nameplate
capacity. As discussed in the preamble to the proposed rule, the EPA
estimates that 0.1 percent of the full and proper charge of insulating
gas would remain in the equipment at 3.5 Torr (assuming that a full and
proper charge has a pressure of 3800 Torr), a negligible fraction.
However, the fraction of gas remaining after recovery of 99.1 percent
of the gas, 0.9%, is not negligible, but represents a significant
systematic underestimate compared to the 2% tolerance for nameplate
capacity measurements. Since it is straightforward to correct for this
systematic underestimate by using the
[[Page 31850]]
mathematical adjustment approach, we are requiring use of equation DD-5
in such situations.
Comment: One commenter representing manufacturers of electrical
equipment recommended that after insulating gas was added to a piece of
electrical equipment, facilities should allow at least 24 hours to
allow the gas to condition itself to its container in order to confirm
the correct density has been met.
Response: The EPA is adding a requirement to 40 CFR
98.303(b)(4)(ii) that facilities follow the procedure specified by the
electrical equipment manufacturer to ensure that the measured
temperature accurately reflects the temperature of the insulating gas,
e.g., by measuring the insulating gas pressure and vessel temperature
after allowing appropriate time for the temperature of the transferred
gas to equilibrate with the vessel temperature. This allows for the
possibility that some electrical equipment, e.g., electrical equipment
with smaller charge sizes, may require less than 24 hours for the
insulating gas temperature to equilibrate with the temperature of the
vessel. Because achieving the correct density of the insulating gas in
the equipment is important to the proper functioning of the equipment,
the guidance provided by the equipment manufacturer should be
sufficient to ensure that the appropriate density is achieved for
purposes of the nameplate capacity measurement.
Comment: Commenters representing electrical equipment users and
manufacturers provided input on the use of mass flow meters to measure
the nameplate capacities of new and retiring electrical equipment. One
commenter provided recommended edits to the proposed text to add
requirements to ensure that a minimum gas flow is maintained while
measuring the mass of insulating gas being added to new equipment. The
commenter stated that to ensure that the flowmeter was properly
configured for its application, the maximum and minimum flow rates of
the meter, as well as the displacement of the pumps and compressors on
the gas cart being used, must be taken into consideration. The
commenter added that, in general, mass flow meters designed for high
flow applications will not be suitable for low flow conditions and
meters designed for low flow applications will not be suitable for high
flow conditions. This commenter also recommended adding the use of an
in-calibration cylinder scale as an alternative option for measuring
the gas transferred during the equipment filling process. Two
commenters recommended removing the option to use a mass flow meter to
measure the mass of insulating gas recovered from retiring equipment
due to the potential for errors when a mass flow meter is used in this
process. The commenters stated that use of a mass flow meter to measure
the insulating gas recovered is not recommended since a mass flow meter
does not accurately measure gas at low flow rates. Instead, the
commenters recommended that the gas container weighing method should be
used to accurately measure the total weight of insulating gas recovered
from the equipment. One commenter added that the process of weighing
all gas removed from a GIE and transferred into a cylinder includes
weighing all the gas trapped in hoses and in gas cart, which would not
be accounted for by the flow meter; the commenter pointed out that the
gas (trapped in hoses and in the gas cart) would need to be moved into
cylinders to be accurately weighed with a cylinder scale.
Response: After consideration of these comments, the EPA is
finalizing the proposed provisions for measuring the nameplate
capacities of new and retiring equipment with two changes. First, we
are requiring that facilities that use mass flow meters to measure the
mass of insulating gas added to new equipment must keep the mass flow
rate within the range specified by the mass flow meter manufacturer to
assure an accurate and precise mass flow meter reading. Second, we are
removing the option to use mass flow meters to measure the quantity of
gas recovered from retiring equipment. We have analyzed the impact of
the uncertainty of flowmeters at low flow rates on overall nameplate
capacity measurements, and we have concluded that this impact may lead
to large errors under some circumstances. As noted by the commenters,
the relative error for flowmeters can increase when the flowmeter is
used to measure mass flow rates below a certain fraction of the maximum
full-scale value, and the mass flow rate will gradually decline as the
insulating gas is transferred from the container to the equipment or
vice versa, reducing the density of the gas inside the source vessel.
For measuring the quantity of insulating gas added to new equipment,
this issue can be addressed by requiring that the mass flow rate be
kept within the range specified by the mass flow meter manufacturer,
which can be accomplished by, e.g., switching to a full container when
the density of the insulating gas in the current container falls below
the minimum level. However, for measuring the quantity of insulating
gas recovered from retiring equipment, the insulating gas is being
transferred from the equipment itself, and the recovery process
therefore inevitably lowers the mass flow rate below the minimum level.
For this reason, we are not taking final action on the option to use
flowmeters to measure the quantity of insulating gas recovered from
retiring equipment.
In our analysis of this issue, we reviewed our proposal at 40 CFR
98.303(b)(10) that mass flow meters must be accurate and precise to
within one percent of the largest value that the flow meter can,
according to the manufacturer's specifications, accurately record,
i.e., the maximum full-scale value. This means that the relative error
of the flowmeter could rise hyperbolically from one percent of the
measured value (when the measured value equals the maximum value) to
much higher levels at lower flow rates, e.g., 2 percent of the flow
rate at half the maximum, 4 percent of the flow rate at one quarter of
the maximum, 10 percent of the flow rate at one tenth the maximum, etc.
These rising relative errors lead to overall errors in the mass flow
measurement that are far above one percent. Even if the flow meter is
accurate to within one percent of the measured value over a ten-fold
range of flow rates, errors at lower flow rates can be significant. In
an example provided to us by a company that provides insulating gas
recovery equipment (gas carts) and insulating gas recovery services to
electric power systems, the relative error of the measurement of the
flow rate rose by a factor of five when the flow rate fell below 10
percent of the maximum full-scale value. If the error of a flowmeter
climbed from 1 percent to 5 percent when the flow rate fell below 10
percent of the maximum full-scale value, the measurement of the total
mass recovered would have a maximum uncertainty of 1.4 percent, which
can result in overall errors above 2 percent in the nameplate capacity
measurement as a whole (accounting also for the uncertainties of
measured pressures, etc.).
Regarding one commenter's recommendation that we allow weigh scales
to be used to measure the quantity of gas filled into new equipment, we
are finalizing our proposal at 40 CFR 98.303(b)(4)(ii)(A) to allow use
of weigh scales for this measurement.
Comment: Two commenters requested the EPA remove the term
``precise'' from proposed 40 CFR 98.303(b)(10). Both commenters
stressed that accuracy is more important. One commenter stated that
equipment certified to be accurate
[[Page 31851]]
and precise may be difficult to find, and another additionally asserted
there is little value in precision.
Response: In the final rule, we are finalizing as proposed the
accuracy and precision requirements for gauges, flow meters, and weigh
scales used to measure nameplate capacities. To obtain an accurate
measurement of the nameplate capacity of a piece of equipment,
measurement devices must be both accurate and precise. As discussed in
the technical support document for the proposed rule,\18\ the term
``accurate'' indicates that multiple measurements will yield an average
that is near the true value, while the term ``precise'' indicates that
multiple measurements will yield consistent results. A measurement
device that is accurate without being precise may show inconsistent
results from measurement to measurement, and these individual
inconsistent results may be significantly different from the true value
even if their average is not. Since measurements of nameplate capacity
are generally expected to be taken only once for a particular piece of
equipment, the devices on which the individual measurements are taken
must be both accurate and precise for the measurements to yield results
that are near the true values.
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\18\ See ``Technical Support for Proposed Revisions to Subpart
DD (2021),'' available in the docket to this rulemaking, Docket ID.
No. EPA-HQ-OAR-2019-0424.
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Comment: One commenter suggested redefining the definition of
``insulating gas'' to including any gas with a GWP greater than one (1)
and not any fluorinated GHG or fluorinated GHG mixture. The commenter
urged that the proposed definition ignores other potential gases that
may come onto the market that are not fluorinated but still have a GWP.
The commenter stated that defining insulating gas to include any gas
with a GWP greater than 1 used as an insulating gas and/or arc
quenching gas in electrical equipment would mirror the threshold
implemented by the California Air Resources Board and would provide
consistency for reporters across Federal and State reporting rules.
Response: In the final rule, the EPA is not requiring electric
power systems to track or report emissions of insulating gases with
weighted average 100-year GWPs of one or less. Based on a review of the
subpart DD data submitted to date, the EPA has concluded that excluding
insulating gases with weighted average GWPs of one or less from
reporting under subpart DD will have little effect on the accuracy or
completeness of the GWP-weighted totals reported under subpart DD or
under the GHGRP generally. Between 2011 and 2021, the highest emitting
facilities reporting under subpart DD reported SF6 emissions
ranging from 8 to 23 mt (unweighted) or 190,000 to 540,000
mtCO2e. Over the same period, total emissions across all
facilities have ranged from 96 to 171 mt (unweighted) or 2.3 to 4.1
million mtCO2e. At GWPs of one, these weighted totals would
be equivalent to the unweighted quantities reported, which constitute
approximately 0.004% (1/23,500) of the GWP-weighted totals. This does
not account for the fact that for the first few years it is sold,
equipment containing insulating gases with weighted average GWPs of one
or less will make up a small fraction of the total nameplate capacity
of the electrical equipment in use. (Electrical equipment has a
lifetime of about 40 years, so only a small fraction of the total stock
of equipment is retired and replaced each year.) Even in a worst-case
scenario where the annual emission rate of the equipment containing a
very low-GWP insulating gas was assumed to equal the total nameplate
capacity of all the equipment installed (implying an emission rate of
100 percent, higher than any ever reported under the GHGRP), the total
GWP-weighted emissions reported under subpart DD would be considerably
smaller than those reported under any other subpart: total unweighted
nameplate capacities reported across all facilities to date have ranged
between 4,847 and 6,996 mt. At GWPs of 1, these totals would fall under
the 15,000 and 25,000 mtCO2e quantities below which
individual facilities are eventually allowed to exit the program under
the off-ramp provisions, as applicable.
To monitor trends in the replacement of SF6 by
insulating gases with weighted average GWPs less than one, the EPA will
continue to track supplies of such insulating gases under subparts OO
and QQ and will track deliveries of such insulating gases in equipment
or containers under subpart SS.
b. Comments on Revisions To Streamline and Improve Implementation for
Subpart DD
Comment: One commenter supported the proposed threshold for subpart
DD but wanted the EPA to clarify that reporters that do not think they
will fall below the revised reporting threshold or are not otherwise
using F-GHGs other than SF6 do not need to recalculate their
emissions to show they must report.
Response: The applicability threshold is for determining whether
entities must initially begin reporting to the GHGRP. Facilities that
have reported have calculated their emissions more precisely using the
mass balance approach. If those calculations have shown that they are
eligible to exit the program under the off-ramp provisions of subpart A
of part 98 (40 CFR 98.2(i)), they do not need to report again unless
facility emissions exceed 25,000 mtCO2e. On the other hand,
if the calculations have shown that the facility does not meet the
existing off-ramp conditions to exit the program, they must continue
reporting regardless of the results of the threshold calculation at 40
CFR 98.301.
R. Subpart FF--Underground Coal Mines
We are finalizing the amendments to subpart FF of part 98
(Underground Coal Mines) as proposed. The EPA received no comments
objecting to the proposed revisions to subpart FF; therefore, there are
no changes from the proposal to the final rule. The EPA is finalizing
two technical corrections to: (1) correct the term ``MCFi''
in equation FF-3 to subpart FF to revise the term ``1-
(fH2O)1'' to ``1-(fH2O)i'', and (2) to correct 40
CFR 98.326(t) to add the word ``number'' after the word
``identification'' to clarify the reporting requirement. Additional
rationale for these amendments is available in the preamble to the 2022
Data Quality Improvements Proposal.
S. Subpart GG--Zinc Production
This section discusses the final revisions to subpart GG. We are
finalizing amendments to subpart GG of part 98 (Zinc Production) as
proposed. The EPA received only supportive comments for the proposed
revisions to subpart GG. See the document ``Summary of Public Comments
and Responses for 2024 Final Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of
all comments and responses related to subpart GG. Additional rationale
for these amendments is available in the preamble to the 2022 Data
Quality Improvements Proposal.
The EPA is finalizing one revision to add a reporting requirement
at 40 CFR 98.336(a)(6) and (b)(6) for the total amount of electric arc
furnace (EAF) dust annually consumed by all Waelz kilns at zinc
production facilities. The final data elements will only require
segregation and reporting of the mass of EAF dust consumed for all
kilns. These requirements apply to reporters using either the CEMS
direct measurement or mass balance calculation
[[Page 31852]]
methodologies. Reporters currently collect information on the EAF dust
consumed on a monthly basis as part of their existing operations as a
portion of the inputs to equation GG-1 to subpart GG; reporters will
only be required to sum all EAF dust consumed on a monthly basis for
each kiln and then for all kilns at the facility for reporting and
entering the information into e-GGRT. Additional rationale for these
amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal. We are also finalizing as proposed
confidentiality determinations for new data elements resulting from the
final revisions to subpart GG, as described in section VI. of this
preamble.
T. Subpart HH--Municipal Solid Waste Landfills
We are finalizing several amendments to subpart HH of part 98
(Municipal Solid Waste Landfills) as proposed. In some cases, we are
finalizing the proposed amendments with revisions. In other cases, we
are not taking final action on the proposed amendments. Section
III.T.1. of this preamble discusses the final revisions to subpart HH.
The EPA received several comments on proposed subpart HH revisions
which are discussed in section III.T.2. of this preamble. We are also
finalizing as proposed confidentiality determinations for new data
elements resulting from the final revisions to subpart HH, as described
in section VI. of this preamble.
1. Summary of Final Amendments to Subpart HH
This section summarizes the final amendments to subpart HH. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other
changes to 40 CFR part 98, subpart HH can be found in this section and
section III.T.2. of this preamble. Additional rationale for these
amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal and 2023 Supplemental Proposal.
The EPA is finalizing several revisions to subpart HH to improve
the quality of data collected under the GHGRP. First, the EPA is
finalizing revisions to update the factors used in modeling
CH4 generation from waste disposed at landfills in table HH-
1 to subpart HH. As explained in the 2022 Data Quality Improvements
Proposal, subpart HH uses a model to estimate CH4 generation
that considers the quantity of MSW landfilled, the degradable organic
carbon (DOC) content of that MSW, and the first order decay rate (k) of
the DOC. Table HH-1 to subpart HH provides DOC and k values that a
reporter must use to calculate their CH4 generation based on
the different categories of waste disposed at that landfill and the
climate in which the landfill is located. The EPA previously conducted
a multivariate analysis of data reported under subpart HH to estimate
updated DOC and k values for each waste characterization option.
Details of this analysis are available in the memorandum from Meaghan
McGrath, Kate Bronstein, and Jeff Coburn, RTI International, to Rachel
Schmeltz, EPA, ``Multivariate analysis of data reported to the EPA's
Greenhouse Gas Reporting Program (GHGRP), Subpart HH (Municipal Solid
Waste Landfills) to optimize DOC and k values,'' (June 11, 2019),
available in the docket for this rulemaking, Docket ID. No. EPA-HQ-OAR-
2019-0424. The EPA is finalizing the following changes as proposed:
For the Bulk Waste option, amending the bulk waste DOC
value in table HH-1 from 0.20 to 0.17.
For the Modified Bulk Waste option, for bulk MSW waste
without inerts and (C&D) waste, amending the DOC value from 0.31 to
0.27.
For the Waste Composition option, adding a DOC for
uncharacterized MSW of 0.32, and revising 40 CFR 98.343(a)(2) to
reference using this uncharacterized MSW DOC value rather than the bulk
MSW value for waste materials that could not be specifically assigned
to the streams listed in table HH-1 for the Waste Composition option.
The EPA is also revising the default decay rate values in table HH-
1 for the Bulk Waste option and the Modified Bulk MSW option and adding
k value ranges for uncharacterized MSW for the Waste Composition
Option. The final k values, which have been revised from those
proposed, are shown in table 4 of this preamble. The revised defaults
represent the average optimal k values derived through an additional
optimization analysis conducted in response to comments where the bulk
waste DOC value was set to the revised value of 0.17 and optimal k
values were determined for each precipitation category.
Table 4--Revised Default k Values
------------------------------------------------------------------------
Factor Subpart HH default Units
------------------------------------------------------------------------
k values for Bulk Waste option and ..............
Modified Bulk MSW option.
k (precipitation plus recirculated 0.033.............. yr-1.
leachate <20 inches/year).
k (precipitation plus recirculated 0.067.............. yr-1.
leachate 20-40 inches/year).
k (precipitation plus recirculated 0.098.............. yr-1.
leachate >40 inches/year).
k value range for Waste Composition ..............
option.
k (uncharacterized MSW)............ 0.033 to 0.098..... yr-1.
------------------------------------------------------------------------
The revisions to the DOC and k values in table HH-1 reflect the
compositional changes in materials that are disposed at landfills.
These updated factors will allow MSW landfills to more accurately model
their CH4 generation. We are also clarifying in the final
rule that starting in RY2025 these new DOC and k values are to be
applied for disposal years 2010 and later, consistent with when the
compositional changes occurred. Additional information on these
revisions and their supporting basis may be found in section III.Q. of
the preamble to the 2022 Data Quality Improvements Proposal and in the
memorandum ``Revised Analysis and Calculation of Optimal k Values for
Subpart HH MSW Landfills Using a 0.17 DOC Default and Timing
Considerations'' included in Docket ID. No. EPA-HQ-OAR-2019-0424.
We are also finalizing, as proposed, revisions to account for
CH4 emission events that are not well quantified under the
GHGRP including: (1) a poorly operating or non-operating gas collection
system; and (2) a poorly operating or non-operating destruction device.
The EPA is finalizing, as proposed, revisions and additions to address
these scenarios as follows:
Revising equations HH-7 and HH-8 to more clearly indicate
that the ``fRec'' term is dependent on the gas collection
system, to clarify how the equation
[[Page 31853]]
applies to landfills that may have more than one gas collection system
and may have multiple measurement locations associated with a single
gas collection system.
Clarifying in ``fRec'' that the recovery system
operating hours only include those hours when the system is operating
normally. Facilities should not include hours when the system is shut
down or when the system is poorly operating (i.e., not operating as
intended). Poorly operating systems can be identified when pressure,
temperature, or other parameters indicative of system performance are
outside of normal variances for a significant portion of the system's
gas collection wells.
For equations HH-6, HH-7, and HH-8, revising the term
``fDest'' to clarify that the destruction device operating
hours exclude periods when the destruction device is poorly operating.
Facilities should only include those periods when flow was sent to the
destruction device and the destruction device was operating at its
intended temperature or other parameter that is indicative of effective
operation. For flares, periods when there is no flame present must be
excluded from the annual operating hours.
Following consideration of comments received, the EPA is finalizing
two minor clarifications of the term ``fDest,n'' in
equations HH-7 and HH-8. First, we are removing the redundant phrase
``as measured at the nth measurement location.'' Second, we are
removing the word ``pilot'' to clarify that for flares used as a
destruction device, the annual operating hours must exclude any period
in which no flame is present, either pilot or main. These changes
account for variances in flare operation, e.g., flares which may only
use a pilot on startup. See section III.T.2. of this preamble for
additional information on related comments and the EPA's response.
In the 2023 Supplemental Proposal, we proposed that facilities that
conduct surface-emissions monitoring must use that data and correct the
emissions calculated in equations HH-6, HH-7, and HH-8 to account for
excess emissions when the measured surface methane concentration
exceeded 500 ppm based on a correction term added to those equations.
We also proposed for facilities not conducting surface-emissions
monitoring to use collection efficiencies that are 10-percentage points
lower than the historic collection efficiencies in table HH-3 to
subpart HH. Following consideration of comments received, we are not
taking final action on the surface-emissions monitoring correction term
that was proposed. Instead, we are finalizing the proposed lower
collection efficiencies in table HH-3 to subpart HH, but applying the
reduced collection efficiencies for all reporters under subpart HH. See
section III.T.2. of this preamble for additional information on related
comments and the EPA's response.
The EPA is also finalizing several revisions to the reporting
requirements for subpart HH, including more clearly identifying
reporting elements associated with each gas collection system, each
measurement location within a gas collection system, and each control
device associated with a measurement location. First, we are finalizing
revisions to landfills with gas collection systems consistent with the
proposed revisions in the methodology, i.e., to separately require
reporting for each gas collection systems and for each measurement
location within a gas collection system. We are requiring, for each
measurement location that measures gas to an on-site destruction
device, certain information be reported about the destruction device,
including: type of destruction device; the total annual hours where gas
was sent to the destruction device; a parameter indicative of effective
operation, such as the annual operating hours where active gas flow was
sent to the destruction device and the destruction device was operating
at its intended temperature; and the fraction of the recovered methane
reported for the measurement location directed to the destruction
device. We are also requiring reporting of identifying information for
each gas collection system, each measurement location within a gas
collection system, and each destruction device. We are also finalizing
reporting requirements for landfills with gas collection systems to
indicate the applicability of the NSPS (40 CFR part 60, subparts WWW or
XXX), state plans implementing the EG (40 CFR part 60, subparts Cc or
Cf), and Federal plans (40 CFR part 62, subparts GGG and OOO).
In the 2023 Supplemental Proposal, the EPA also sought comment on
how other CH4 monitoring technologies, e.g., satellite
imaging, aerial measurement, vehicle-mounted mobile measurement, or
continuous sensor networks, might enhance subpart HH emissions
estimates. The EPA did not propose, and therefore is not taking final
action on, any amendments to subpart HH to this effect. However, the
EPA did seek comment on the availability of existing monitoring
technologies, and regulatory approaches and provisions necessary to
incorporate such data into subpart HH for estimating annual emissions.
We will continue to review the comments received along with other
studies and may amend subpart HH to allow the incorporation of
additional measurement or monitoring methodologies in the future.
2. Summary of Comments and Responses on Subpart HH
This section summarizes the major comments and responses related to
the proposed amendments to subpart HH. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart HH.
Comment: Numerous commentors stated that methane detection
technology, specifically top-down direct measurement from aerial
studies, has greatly improved the ability to observe and quantify
emissions from landfills (e.g., Krautwurst, et al., 2017; Cusworth, et
al., 2022).19 20 Some commenters noted that, among several
studies in California, Maryland, Texas, and Indiana, there are
discrepancies between observed data collected from these new detection
technologies and the estimated emissions from the models that the EPA
currently uses. Several commenters pointed to a recent study (Nesser,
et al., 2023) using satellite data that highlighted that at 33 of 70
landfills studied, U.S. GHG Inventory landfill emissions are
underestimated by 50 percent when compared to the current top-down
approaches.\21\ These discrepancies indicate methane emissions from
landfills may be considerably higher than currently recorded. Some
commenters stated that advanced methane monitoring technology has
improved significantly in effectiveness and cost, and provided specific
input regarding advanced methane monitoring technologies available for
landfills and how their data might enhance subpart
[[Page 31854]]
HH emissions reporting. The commenters pointed to both screening and
close-range technologies that would be beneficial for pinpointing leaks
or emission sources, and outlined several technologies including
satellite imaging, aerial measurements, vehicle-mounted mobile
measurement, and continuous sensor networks. The commenters recommended
comprehensive monitoring with both screening and close-range
technologies to provide full coverage. The commenters suggested the use
of these technologies to catch large emission events that are not
accounted for in the existing reporting requirements. Commenters noted
that the EPA could review submitted reports and activity data to
determine how to best quantify the observed large release events as
compared to annual reported emissions (e.g., updating fRec
or fDest values to account for periods of downtime or poor
performance not captured that contributed to a large discrepancy).
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\19\ Krautwurst, S., et al., (2017). ``Methane emissions from a
Californian landfill, determined from airborne remote sensing and in
situ measurements.'' Atmos. Meas. Tech. 10:3429-3452. https://doi.org/10.5194/amt-10-3429-2017.
\20\ Cusworth, D., et al., (2020). ``Using remote sensing to
detect, validate, and quantify methane emissions from California
solid waste operations.'' Environ. Res. Lett. 15: 054012.
\21\ Nesser, H., et al. 2023. High-resolution U.S. methane
emissions inferred from an inversion of 2019 TROPOMI satellite data:
contributions from individual states, urban areas, and landfills,
EGUsphere [preprint], https://doi.org/10.5194/egusphere-2023-946,
2023.
---------------------------------------------------------------------------
Other commenters recommended that the EPA create a mechanism under
subpart HH for receiving and considering third-party observational data
that the EPA could then use to revise reported emissions as necessary.
Some commenters suggested the EPA base a threshold for these sources of
100 kg/hour. Commenters also recommended setting assumptions for the
duration of the emissions similar to those proposed for subpart W of
part 98 (Petroleum and Natural Gas Systems). Some commenters suggested
the EPA should embrace for landfills the same tiered methane emissions
monitoring approach as is utilized in its proposed rulemaking for the
oil and gas sector. Commenters also suggested a tiered approach that
combines continuous monitoring ground systems with periodic remote
sensing along with approaches for translating methane concentrations
from top-down sources to source-specific emission rates. Commenters
urged that the sooner the EPA can move toward top-down or facility-wide
measurement of emissions for reporting or validation of reported
values, the sooner reported and measured emissions would be
reconcilable and verifiable. A few commenters also recommended that the
EPA facilitate the flow of information from other agencies (the
National Aeronautics and Space Administration (NASA), National Oceanic
and Atmospheric Administration (NOAA), National Institute of Standards
and Technology (NIST), and U.S. Department of Energy (DOE)), third
parties, and operators to find and mitigate plumes faster.
Several commenters provided recommendations for additional
reporting requirements such as gas collection and capture system (GCCS)
type and design, destruction device type and characteristics,
monitoring technologies, site cover type, construction periods, and
compliance issues which may relate to closures of control devices.
Response: The EPA agrees that recent aerial studies indicate
methane emissions from landfills may be considerably higher than
bottom-up emissions reported under subpart HH for some landfills.
Emissions may be considerably higher due to emissions from poorly
operating gas collection systems or destruction devices and leaking
cover systems. The supplemental proposal included revisions to the
monitoring and calculation methodologies in subpart HH to account for
these scenarios. In particular, proposed equations HH-6, HH-7, and HH-8
included modifications to incorporate direct measurement data collected
from methane surface-emissions monitoring. In the supplemental
proposal, we also requested information about other direct measurement
technologies and how their data may enhance emissions reporting under
subpart HH. We received many responses to our request. Based on the
comments received, we are not taking final action at this time
regarding the incorporation of other direct measurement technologies
for the following reasons. First, most top-down, facility measurements
are taken over limited durations (a few minutes to a few hours)
typically during the daylight hours and limited to times when specific
meteorological conditions exist (e.g., no cloud cover for satellites;
specific atmospheric stability and wind speed ranges for aerial
measurements). These direct measurement data taken at a single moment
in time may not be representative of the annual CH4
emissions from the facility, given that many emissions are episodic. If
emissions are found during a limited duration sampling, that does not
necessarily mean they are present for the entire year. And if emissions
are not found during a limited duration sampling, that does not mean
significant emissions are not occurring at other times. Extrapolating
from limited measurements to an entire year therefore creates risk of
either over or under counting actual emissions. Second, while top-down
measurement methods, including satellite and aerial methods, have
proven their ability to identify and measure large emissions events,
their detection limits may be too high to detect emissions from sources
with relatively low emission rates or that are spread across large
areas, which is common for landfills.\22\ This is likely why only seven
percent of the landfills in the Duren, et al. (2019) study had
detectable emissions. The EPA will continue to review additional
information on existing and advanced methodologies and new literature
studies, and consider ways to effectively incorporate these methods and
data in future revisions under subpart HH for estimating annual
emissions.
---------------------------------------------------------------------------
\22\ Duren, et al. 2019. ``California's methane super-
emitters.'' Nature, Vol. 575, Issue 7781, pp. 180-184, available at
https://doi.org/10.1038/s41586-019-1720-3. Available in the docket
for this rulemaking, Docket ID. No. EPA-HQ-OAR-2023-0234.
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For the oil and gas sector, the super-emitter program that allows
third-party measurement data to be submitted was proposed under 40 CFR
part 60, subpart OOOOb (87 FR 74702, December 6, 2022). The GHGRP
looked to use this information, but we did not develop or propose such
a program under the GHGRP. As such, this type of program is beyond the
scope of the proposed rule. We will consider whether developing and
implementing a similar super-emitter program within subpart HH of part
98 or the overall GHGRP is appropriate under future rulemakings.
We proposed, and are finalizing, several additional reporting
elements including, for landfills with a gas collection system,
information on the applicability of the NSPS (40 CFR part 60, subparts
WWW or XXX), state plans implementing the EG (40 CFR part 60, subparts
Cc or Cf), and Federal plans (40 CFR part 62, subparts GGG and OOO). We
note that several of the items suggested are already reporting
elements. For example, we already require reporting of a description of
the gas collection system, such as the manufacturer, capacity, and
number of wells, which provides requested information on GCCS type and
design. We also proposed and are finalizing reporting requirements for
the type of destruction device. We already require reporting of cover
type. We consider the reporting requirements to be sufficient based on
the current methodologies used to estimate CH4 emissions. We
will consider the need for additional reporting elements if we
incorporate additional measurement or monitoring methodologies in
future rulemakings.
Comment: Several commentors expressed limited support for the
proposed use of surface emission monitoring data to help account for
[[Page 31855]]
emissions from cover leaks. These commenters either recommended that
the EPA use more quantitative emission measurement methods instead of
surface-emissions monitoring or to require that the surface-emissions
monitoring be conducted at 25-foot intervals consistent with California
and other state requirements, and to use a lower leaks definition of 25
parts per million volume (ppmv), rather than using the proposed 30-
meter intervals (about 98-foot intervals) with leaks defined as
concentrations of 500 ppmv or more above background, to help ensure the
surface-emissions monitoring identifies all leaks from the landfill's
surface. Other commenters opposed the proposed use of a surface-
emissions monitoring correction term in equations HH-6, HH-7, and HH-8.
One commenter noted that the correction term that the EPA proposed
relied on one study conducted over 20 years ago at one landfill in
Canada. This commenter cited several other studies
23 24 25 26 that showed significant variability in
correlations between surface methane concentrations and methane
emissions and indicated that the EPA should not rely on the results of
this limited single study. Another commenter suggested that there is
nothing special from a technical perspective of 500 ppmv surface
concentration that should drive a step function change in correcting
for emissions and surface oxidation, as proposed by the EPA. This
commenter indicated that there is already uncertainty in the gas
collection efficiencies and that including the proposed surface methane
concentration term simply adds to the uncertainty. The commenter
recommended mandating the use of lower collection efficiencies when
there is evidence of a high number of exceedances or a high surface
methane concentration, rather than adding the surface methane
concentration term to equations HH-6, HH-7, and HH-8. This commenter
also cited the work of Dr. Tarek Abichou (Kormi, et al., 2017 and 2018)
for using surface concentration measurements to estimate
emissions.27 28
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\23\ Abichou, T., J. Clark, and J. Chanton. 2011. ``Reporting
central tendencies of chamber measured surface emission and
oxidation.'' Waste Management, 31: 1002-1008. https://doi.org/10.1016/j.wasman.2010.09.014.
\24\ Abedini, A.R. 2014. Integrated Approach for Accurate
Quantification of Methane Generation at Municipal Solid Waste
Landfills. Ph.D. thesis, Dept. of Civil Engineering, University of
British Columbia.
\25\ Lando, A.T., H. Nakayama, and T. Shimaoka. 2017.
``Application of portable gas detector in point and scanning method
to estimate spatial distribution of methane emission in landfill.''
Waste Management, 59: 255-266. https://doi.org/10.1016/j.wasman.2016.10.033.
\26\ Hettiarachchi, H., E. Irandoost, J.P. Hettiaratchi, and D.
Pokhrel. 2023. ``A field-verified model to estimate landfill methane
flux using surface methane concentration measurements.'' J. Hazard.
Toxic Radioact. Waste, 27(4): 04023019. https://doi.org/10.1061/JHTRBP.HZENG-1226.
\27\ Kormi, T., N.B.H. Ali, T. Abichou, and R. Green. 2017.
``Estimation of landfill methane emissions using stochastic search
methods.'' Atmospheric Pollution Research, 8(4): 597-605. https://dx.doi.org/10.1016/j.apr.2016.12.020.
\28\ Kormi, T., et al. 2018. ``Estimation of fugitive landfill
methane emissions using surface emission monitoring and Genetic
Algorithms optimization.'' Waste Management 2018, 72: 313-328.
https://dx.doi.org/10.1016/j.wasman.2016.11.024.
---------------------------------------------------------------------------
Response: After considering comments received and reviewing
additional studies, including those cited by the commenters, we are not
taking final action on the proposed surface-emissions monitoring
correction term at this time.\29\ Upon review of the literature studies
cited by one commenter (Abichou, et al., 2011; Abidini, 2014; Lando, et
al., 2017; Hettiarachchi, et al., 2023), we confirmed that there is
significant variability in measured surface concentrations and methane
emissions flux across different landfills. The proposed correction
factor, attributed to Heroux, et al. (2010),\30\ was the smallest of
the correlation factors found across the other cited literature studies
we reviewed. Based on a preliminary review of the additional study
data, a more central tendency estimate of the correction factor term
would be four to six times higher than the correction term proposed.
---------------------------------------------------------------------------
\29\ Irandoost, E. (2020). An Investigation on Methane Flux in
Landfills and Correlation with Surface Methane Concentration
(Master's thesis, University of Calgary, Calgary, Canada). Retrieved
from https://prism.ucalgary.ca. http://hdl.handle.net/1880/111978.
\30\ H[eacute]roux, M., C. Guy and D. Millette. 2010. ``A
statistical model for landfill surface emissions.'' J. of the Air &
Waste Management Assoc. 60:2, 219-228. https://doi.org/10.3155/1047-3289.60.2.219.
---------------------------------------------------------------------------
Due to the high uncertainty in the proposed correction factor, we
are assessing whether the correction term proposed for equations HH-6,
HH-7, and HH-8 is the most appropriate method for developing a site-
specific correction for the overall gas collection efficiency for
reporters under subpart HH. The approach presented by Kormi, et al.
(2017, 2018) uses a Gaussian plume model in conjunction with surface
methane concentration measurements to estimate emissions. This approach
appears too complex to incorporate into subpart HH. We are also
evaluating other direct measurement technologies for assessing more
accurate, landfill-specific gas collection efficiencies. Therefore, we
decided not to take final action on the proposed correction term for
equations HH-6, HH-7, and HH-8 at this time while we consider and
evaluate other options. The EPA will continue to review additional
information on existing and advanced methodologies and new literature
studies and consider ways to effectively incorporate these methods and
data in future revisions under subpart HH for estimating annual
emissions.
Comment: Numerous commenters cited studies suggesting that subpart
HH underestimates the actual methane emissions released from
landfills.31 32 These commenters noted that the
underestimation in subpart HH emissions is primarily due to high
default gas collection efficiencies in subpart HH. Two commenters
asserted that gas collection efficiencies over 90 percent should not be
used. One of these commenters noted that despite its own two-year study
indicating otherwise, the EPA uses a 95 percent collection efficiency
for landfills with final covers.\33\ Two commenters opposed the EPA's
use of the Maryland landfill data to support the proposed 10-percentage
point decrease in landfill gas collection efficiencies, noting that
these gas collection efficiencies were calculated based on modeled
methane generation rather than actual methane emissions measurements.
One commenter further suggested that the Maryland study was not
properly peer-reviewed and is not suitable for use by the EPA in
rulemaking according to the EPA's Summary of General Assessment Factors
For Evaluating the Quality of Scientific and Technical Information
(hereinafter referred to as ``General Assessment Factors'').\34\ The
commenter further stated that the Maryland study is based on a small
subset of landfills that is likely not representative of the sector and
the EPA's reliance on that study to support a change to the default
collection efficiency table (table HH-3
[[Page 31856]]
to subpart HH) is inappropriate and will lead to inaccurate reporting
of GHG emissions from the sector. This commenter stated that the EPA
should continue to rely on the gas collection efficiencies recommended
in the Solid Waste Industry for Climate Solutions (``SWICS'') white
paper entitled Current MSW Industry Position and State-of-the-Practice
on LFG Collection Efficiency, Methane Oxidation, and Carbon
Sequestration in Landfills.\35\ According to the commenter, the SWICS
white paper is more comprehensive and relevant than the Maryland study.
The commenters noted that the SWICS white paper is being revised and
encouraged the EPA to delay revisions to the gas collection efficiency
until the revised SWICS white paper is released.
---------------------------------------------------------------------------
\31\ Oonk, H., 2012. ``Efficiency of landfill gas collection for
methane emissions reduction.'' Greenhouse Gas Measurement and
Management, 2:2-3, 129-145. https://doi.org/10.1080/20430779.2012.730798.
\32\ Nesser, H., et al., 2023. ``High-resolution U.S. methane
emissions inferred from an inversion of 2019 TROPOMI satellite data:
contributions from individual states, urban areas, and landfills.''
EGUsphere [preprint], https://doi.org/10.5194/egusphere-2023-946.
\33\ ARCADIS, 2012. Quantifying Methane Abatement Efficiency at
Three Municipal Solid Waste Landfills; Final Report. Prepared for
U.S. EPA, Office of Research and Development, Research Triangle
Park, NC. EPA Report No. EPA/600/R-12/003. January. https://nepis.epa.gov/Exe/ZyPDF.cgi/P100DGTB.PDF?Dockey=P100DGTB.PDF.
\34\ Available at https://www.epa.gov/sites/default/files/2015-01/documents/assess2.pdf. Accessed January 9, 2024.
\35\ SCS Engineers. 2009. Current MSW Industry Position and
State-of-the-Practice on LFG Collection Efficiency, Methane
Oxidation, and Carbon Sequestration in Landfills. Prepared for Solid
Waste Industry for Climate Solutions (SWICS). Version 2.2. https://www.scsengineers.com/wp-content/uploads/2015/03/Sullivan_SWICS_White_Paper_Version_2.2_Final.pdf.
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Response: We reviewed the various studies cited by commenters,
including available versions of the SWICS white paper. Upon review of
these papers and comments received, we maintain our position that the
historical collection efficiencies are overstated and that it is
appropriate to apply the lower collection efficiency to all landfills.
In our review of the SWICS white paper, which was the basis for the
historical gas collection efficiencies, we noted that data were omitted
due to poor operation of gas collection system. Thus, we consider the
historical gas collection efficiencies to be representative of ideal
gas collection efficiencies. In our proposal, we required facilities
that conduct surface-emission monitoring data to apply a correction
factor that would reduce the overall collection efficiency, clearly
indicating that we thought the current collection efficiencies are
overstated, even for regulated landfills. While we expected that the
surface emission correction factor would result in lower emissions than
those calculated using the 10-percentage point decrease in collection
efficiency, based on our review of other studies correlating surface
methane concentrations with methane flux, a more central tendency
correlation factor is projected to yield emissions similar to a 10-
percentage point decrease in collection efficiency. All the measurement
study data we reviewed suggests that current GHGRP collection
efficiencies are overstated on average by 10-percentage points or more
(Duan, et al., 2022 and Nesser, et al., 2023).\36\ In reviewing the
data from Nesser, et al. (2023), including the supplemental
information,\37\ we found that all 38 landfills for which gas
collection systems were reported were subject to the NSPS or EG.
Comparing the gas collection efficiencies directly reported in the
GHGRP, 35 of the 38 landfills had lower or similar measured gas
collection efficiencies to those reported in subpart HH. With a 10-
percentage point decrease in the default gas collection efficiencies,
measured gas collection efficiencies were still at least 10-percentage
points lower for 20 of the 38 landfills, approximately equivalent for
13 landfills, and only higher than subpart HH proposed lower default
collection efficiencies for 5 of the landfills. Similar low average
collection efficiencies were noted by Duan, et al., (2022). Therefore,
based on direct measurement data for landfills, we determined it is
appropriate to finalize the lower default gas collection efficiencies
and apply the lower gas collection efficiency for all landfills.
---------------------------------------------------------------------------
\36\ Duan, Z., Kjeldsen, P., & Scheutz, C. (2022). Efficiency of
gas collection systems at Danish landfills and implications for
regulations. Waste management (New York, N.Y.), 139, 269-278.
https://doi.org/10.1016/j.wasman.2021.12.023.
\37\ See https://egusphere.copernicus.org/preprints/2023/egusphere-2023-946/egusphere-2023-946-supplement.pdf.
---------------------------------------------------------------------------
While the Maryland study data suggests that the gas collection
efficiency for voluntary systems may be lower than for regulated gas
collection systems, we agree with commenters that these gas collection
efficiencies are based on modeled generation rather than measured
emissions. The DOC values for individual landfills can vary
significantly and the differences observed could be due to differences
in the wastes managed at the different Maryland landfills. We could not
identify direct measurement study data by which to support further
reductions in gas collection efficiencies for voluntary gas collection
systems. Therefore, we are providing a single set of gas collection
efficiencies for subpart HH reporters to use.
In conclusion, we are finalizing gas collection efficiencies that
are lower than those historically provided in subpart HH by 10-
percentage points based on comments received and review of recent
landfill methane emission measurement studies for landfills with gas
collection systems. We had proposed these collection efficiencies for
facilities not conducting surface emission monitoring, but we are now
finalizing these lower gas collection efficiencies for all landfills.
Comment: Several commenters provided input on the proposed
revisions to equations HH-6 through HH-8 to subpart HH to capture
emissions from other large release events. Two commenters suggested
that the EPA should require monitoring of both the pilot light and flow
rate and that the ``fDest'' term should be excluded during
any period the combustion device is not operating properly. The
commenters specified that ``fDest'' should be excluded
during any period when the reporter has operational data indicating
that the combustion device is not operating according to manufacturer
specifications or when the reporter has received credible monitoring
data showing an unlit or malfunctioning control device.
One commenter stated that the proposed revisions would be difficult
to implement and tend to capture very limited or marginal data. The
commenter asserted that gas collection systems by nature require
constant adjustment of temperature, pressure, and other parameters or
may be subject to frequent repairs that would not be expected to affect
the overall control efficiency. The commenter asked the EPA to remove
``normally'' from the first sentence of the proposed definition of
``fRec'' and remove ``or poor operation, such as times when
pressure, temperature, or other parameters indicative of operation are
outside of normal variances,'' from the second sentence.
The commenter also expressed concerns regarding how the proposed
revisions to ``fDest'' applies to flares, stating that a
large portion of landfill controls use open flares, or are equipped
with automatic shutoffs, which have no parameters for monitoring
effective operation other than the presence of a flame. The commenter
requested the sentence addressing the pilot flame (``For flares, times
when there is no pilot flame present must be excluded from the annual
operating hours for the destruction device.'') be removed from the
proposed revision of ``fDest,'' because it is confusing,
unnecessary, and technically incorrect, as a pilot is typically only
required during startup.
One commenter also requested the EPA remove the phrase ``. . . as
measured at the nth measurement location'' from the first sentence of
``fDest'' description; the commenter stated the text adds
confusion by implying that the time gas is sent to the nth measurement
location is equal to the time gas is sent to the control device, which
may be incorrect for measurement locations with more than one control
device. The commenter also
[[Page 31857]]
proposed a definition striking out ``The annual operating hours for the
destruction device should include only those periods when flow was sent
to the destruction device and the destruction device was operating at
its intended temperature or other parameter indicative of effective
operation.'' The commenter added that because flares and other
destruction devices are designed with fail-closed valves or other
devices to prevent venting of gas when they are not operating, applying
the definition as written overestimates emissions when a measurement
location has more than one destruction device and all devices are not
operating at the same time.
Response: The EPA agrees with the commenters regarding monitoring
the flow rate of the landfill gas; however, a change to the proposed
rule is not necessary in this case as the continuous monitoring of the
gas flow is already required in 40 CFR 98.343. The EPA disagrees with
the comment that ``EPA should likewise specify that fDest
must be excluded during any period when the pilot light and flow rate
are not meeting manufacturer specifications for complete combustion.''
Adding this specification to the rule is not necessary as the revision
to the definition of fDest already accounts for this
scenario. The proposed revision to the fDest definition in
the supplemental proposal states, ``The annual operating hours for the
destruction device should include only those periods when flow was sent
to the destruction device and the destruction device was operating at
its intended temperature or other parameter indicative of effective
operation.'' Thus, if the destruction device has manufacturer
specifications for effective operation that are not met during its
operation, the revision to the fDest definition requires
those periods to be excluded in the hours for fDest. We will
further evaluate how credible monitoring data may be defined and
excluded from fDest in a future rulemaking.
The EPA disagrees with the proposed edits to the definition of
fRec, which are to remove the word ``normally'' from the
first sentence and remove the phrase ``or poor operation, such as times
when pressure, temperature, or other parameters indicative of operation
are outside of normal variances'' from the second sentence. These edits
would allow for all operating hours in the calculation regardless of
how the system operated. We asked for comment on what set of parameters
should be used to identify poorly operating periods and whether a
threshold on the proportion of wells operating outside of their normal
operating variance should be included in the definition of
fRec to define periods of poor performance.
With regards to the commenters' input on the definition of
fDest, the EPA agrees with removing ``as measured at the nth
measurement location'' from the first sentence of the definition as the
commenter notes, ``flares and other destruction devices are designed
with fail-closed valves or other devices to prevent venting of gas when
they are not operating, keeping that phrase can overestimate emissions
when a measurement location has more than one destruction device and
all devices are not operating at the same time.'' We are revising this
sentence to remove ``as measured at the nth measurement location.'' We
disagree with removing from the definition ``For flares, times when
there is no pilot flame present must be excluded from the annual
operating hours for the destruction device.'' Instead, we are revising
this sentence to read ``For flares, times when there is no flame
present must be excluded from the annual operating hours for the
destruction device.'' We believe the lack of a flame is an indication
the flare is not operating effectively. Lastly, we disagree with
removing the sentence, ``The annual operating hours for the destruction
device should include only those periods when flow was sent to the
destruction device and the destruction device was operating at its
intended temperature or other parameter indicative of effective
operation.'' We believe this sentence is necessary to ensure the
calculation of fDest represents proper operation of the
destruction device.
Comment: We received several comments regarding the revised DOC
values. Some commenters supported lowering of the default DOC for bulk
waste from 0.20 to 0.17, citing similar findings in a 2019
Environmental Research and Education Foundation (EREF) study.\38\ These
commenters generally opposed the proposed default value of 0.27 for
bulk MSW (excluding inerts and construction and demolition (C&D) waste)
and the proposed default value of 0.32 for uncharacterized wastes and
recommended the use of either the value of 0.19 from the EREF report or
the 0.17 value for bulk wastes for these other general waste
categories. According to these commenters, the EPA's method for
determining the DOC for bulk MSW (excluding inerts and C&D waste) does
not comport with how landfills characterize and manage input waste
streams, and the high default DOC value for bulk MSW makes the modified
bulk MSW option unusable. Other commenters opposed the proposed
reduction in bulk waste and bulk MSW default DOC values, indicating
that this will lead to lower emissions over the life of the landfill
when research indicates emissions inventories of landfill emissions
underestimate actual emissions. One commenter referenced a paper
(Bahor, et al., 2010) that, according to the commenter, validated the
default DOC of MSW to be 0.20.\39\ Other commenters noted that many
landfill reporters were taking advantage of the composition method by
only reporting inerts and uncharacterized wastes. These commenters
supported the proposed default value of 0.32 for uncharacterized
wastes.
---------------------------------------------------------------------------
\38\ The Environmental Research & Education Foundation (2019).
``Analysis of Waste Streams Entering MSW Landfills: Estimating DOC
Values & the Impact of Non-MSW Materials.'' Available in the docket
to this rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424.
\39\ Bahor, Brian, et al. 2010. ``Life-cycle assessment of waste
management greenhouse gas emissions using municipal waste combustor
data.'' Journal of Environmental Engineering 136.8 (2010): 749-755.
https://doi.org/10.1061/(ASCE)EE.1943-7870.0000189.
---------------------------------------------------------------------------
Response: The EPA included a DOC of 0.20 for bulk waste in subpart
HH because the data we reviewed circa 2000 to 2010 indicated that was
the best fit DOC value.\40\ As noted in the memorandum ``Modified Bulk
MSW Option Update'' included in Docket ID. No. EPA-HQ-OAR-2019-0424, we
have seen a significant decrease in the percentage of paper and
paperboard products being landfilled due to increased recycling of
these waste streams. This change in the composition of MSW landfilled
supports and confirms the drop in DOC from 0.20 to 0.17 over the time
period between 2005 and 2011. With respect to the Bahor, et al. (2010)
study, it appears that the HHV measurement data was made using data
from 1996 to 2006, with biogenic correction factors developed over 2007
and 2008. Based on the timing of the measurements made, agreement with
the DOC value of 0.20 is not surprising and consistent with the
findings by which we originally used a default DOC value of 0.20. We
specifically sought to reassess the average DOC values considering more
recent data to account for potential changes in DOC values over the
past decade. Based on our analysis, an average DOC value of 0.17
provides a better fit with current landfill practices. Therefore, we
are finalizing a revision of the default DOC value to
[[Page 31858]]
0.17 as proposed. However, we note that the proposed revision was not
clear regarding how the new DOC value should be incorporated into the
facility's emissions estimate. Some reporters may only begin applying
the new DOC value to new wastes being disposed of in 2025 and later
years. Other reporters may opt to revise the DOC value for all wastes
disposed of in the landfill for all previous disposal years. This could
lead to significant discrepancies between emissions reported by
reporters with similar landfills and also between the emissions
reported for different years by a given reporter. As noted in this
discussion, we expect that wastes disposed of prior to 2010 are best
characterized using a default DOC value of 0.20 and that wastes
disposed of in 2010 and later years are best characterized using a
default DOC of 0.17. Therefore, while we are finalizing a revision in
the default bulk waste DOC value to 0.17, we are also finalizing
clarifications to these revisions to incorporate these revisions
consistently across reporters and consistent with the timeframe where
the reduction in DOC occurred. Specifically, we are maintaining the
historic DOC value of 0.20 for historic disposal years (prior to 2010)
and, starting with RY2025, requiring the use of the revised DOC value
of 0.17 for disposal years 2010 and later (see memorandum ``Revised
Analysis and Calculation of Optimal k values for Subpart HH MSW
Landfills Using a 0.17 DOC Default and Timing Considerations''
available in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-
2019-0424).
---------------------------------------------------------------------------
\40\ RTI International (2004). Solid Waste Inventory Support--
Review Draft: Documentation of Methane Emission Estimates. Prepared
for U.S. EPA, Office of Atmospheric Programs, Washington, DC.
September 29.
---------------------------------------------------------------------------
With respect to the proposed DOC value for bulk MSW (excluding
inerts and C&D waste), the approach we used to develop the proposed DOC
value is consistent with the approach we used when we originally
developed and provided the modified bulk waste option following
consideration of comments received (75 FR 66450, October 28, 2010).
This option was specifically provided to address comments that the
waste composition option was too detailed for most landfill operators
to use and that landfill operators should have the opportunity to
characterize some of the waste received as inerts under the bulk waste
option. Because the DOC values for bulk waste option were derived based
on the full quantity of waste disposed at landfills, that DOC value for
bulk waste intrinsically includes inerts. Therefore, we sought to
develop a representative MSW DOC value that excludes inerts for use in
the modified bulk MSW option. We disagree that this makes the modified
bulk waste option inaccurate or unusable. On the contrary, we find that
using the bulk waste DOC value in the modified bulk MSW option would be
less accurate for predicting the CH4 generation for the
modified bulk MSW option because the DOC value for bulk waste was
determined by the full quantity of waste disposed at landfills
including inerts and C&D waste. We also agree with commenters that some
reporters are misusing the waste composition option in order to
separately account for inerts but then use the bulk waste DOC value for
the rest of the MSW. We conducted a multivariant analysis to project
the DOC of uncharacterized MSW in landfills for which reporters used
the waste composition method and the DOC for this uncharacterized waste
was estimated to be 0.32. This agrees well with the proposed DOC value
for bulk MSW of 0.27 and confirms that, when facilities separately
report inert waste quantities, the DOC for the remaining MSW (excluding
inerts and C&D waste) is much higher than suggested by some of the
commenters. Consequently, we concluded that our proposed values of 0.27
for bulk MSW (excluding inerts and C&D waste) and 0.32 for
uncharacterized waste should be finalized as proposed. Similar to our
clarification regarding how the revision in bulk waste DOC must be
implemented, we are finalizing requirements to use the current bulk MSW
(excluding inerts and C&D waste) DOC value of 0.31 for historic
disposal years (prior to 2010) and requiring the use of the revised
bulk MSW (excluding inerts and C&D waste) DOC value of 0.27 for
disposal years 2010 and later, consistent with the timeline for which
these values were determined. Because we have no method to indicate a
change in DOC for uncharacterized wastes, we are requiring the use of
the new DOC for uncharacterized waste using the composition option of
0.32 for all years for which the composition option was used.
We also disagree with commenters that having a high bulk MSW
default DOC value makes the modified bulk MSW method unusable. Based on
waste characterization data as reported for RY2022, approximately 23
percent use the modified bulk MSW method, which suggests a quarter of
the reports find the modified bulk MSW option useful. While this option
was specifically provided for landfills that accept large quantities of
C&D waste or inert waste streams, we disagree that its use should be
restricted to that scenario. There is significant variability in the
DOC of bulk waste from landfill to landfill. There are many cases when
the quantity of landfill gas recovered exceeds the modeled methane
generation rates. This is a clear indication that the default DOC (and/
or k value) is too low. For reporters with high actual CH4
generation rates, as noted by the quantity of CH4 recovered
at the landfill, we find that the use of the modified bulk MSW option
is appropriate for these reporters and would likely provide a more
accurate estimate of modeled CH4 generation, even if these
reporters do not have large quantities of inert or C&D wastes. We
encourage reporters that have CH4 recovery rates exceeding
their modeled CH4 generation rates to evaluate and use, as
appropriate, the modified bulk MSW or waste composition options in
order to more accurately estimate modeled methane generation.
Comment: Several comments supported revisions to decay rate
constants (k values) that more closely match the IPCC recommendations.
Other comments were critical of the revisions, suggesting the proposed
k values were too high. One commenter noted that the original k values
were developed using a separate analysis considering the use of the
CH4 generation potential (Lo, analogous to the DOC input for
the first order decay model used in subpart HH). The commenter noted
that optimizing k and DOC values simultaneously can lead to extreme and
unrealistic values because an error in one value causes an offsetting
error in the other. The commenter also stated that the EPA allowed an
extremely wide range for the ``optimized'' k values (e.g., 0.001 to
0.400 for dry climates) and should have constrained the k values to
more realistic values. The commenter also suggested that the EPA rely
on its own research as published in PLoS ONE (Jain et al., 2021).\41\
Finally, the commenter suggested that multivariant analysis was not
peer-reviewed and therefore does not appear to comply with the General
Assessment Factors.
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\41\ Jain, P., et al. 2021. ``Greenhouse gas reporting data
improves understanding of regional climate impact on landfill
methane production and collection.'' PLoS ONE, at 1-3, 10-11 (Feb.
26, 2021), available at https://journals.plos.org/plosone/article?id=10.1371/journal.pone.0246334.
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Response: The EPA reviewed the documentation supporting the
existing DOC and k value defaults used for subpart HH (RTI
International, 2004). Importantly, the memorandum documents that the
development of the DOC and k values utilized a two-step process. The
first step was a
[[Page 31859]]
multivariant analysis, similar to the analysis conducted in 2019
(McGrath et al., 2019), which was used to determine an optimal DOC
value. The second step was to determine optimal k values for each
precipitation range using the optimal DOC value from the multivariant
analysis. At proposal, we used the DOC and k values determined directly
from the multivariant analysis. After consideration of the comments
received and the approach used historically, we determined that it
would be more appropriate to determine optimal k values once the
default DOC value is established. We agree with the commenter that
using a fixed DOC value (set at the proposed bulk waste DOC value of
0.17), we expect that the optimal k values in a single-variable
analysis would have less variability and better predict methane
generation across landfills when using the revised DOC default.
Therefore, we conducted this second step of the analysis using the
original data set for facilities using the bulk waste approach to
determine the optimal k values for these landfills, given a default DOC
value of 0.17 (the bulk waste DOC value recommended in the McGrath et
al. (2019) memo based on the multivariant analysis).
We also reviewed additional literature to assess reasonable ranges
for k values. We found that the lowest allowed k value of 0.001
yr-1 was unrealistic and much lower than any k value
reported in the literature. We identified some studies suggesting a k
value of 0.4 yr-1 is possible for wet landfills (or
landfills using leachate recirculation). After our review of the
additional literature, we revised the allowable k value range from
0.001-0.4 yr-1 to 0.007-0.3 yr-1. The results of
applying this second step of the analysis, consistent with the approach
used previously to develop default k values, indicate that the optimal
k values for dry, moderate, and wet climates were 0.033, 0.067, and
0.098 yr-1, respectively (see memorandum ``Revised Analysis
and Calculation of Optimal k Values for Subpart HH MSW Landfills Using
a 0.17 DOC Default and Timing Considerations'' available in the docket
to this rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424). These values
are lower than those developed from the multivariant analysis, but
still significantly higher than the current defaults in subpart HH.
These values also align well with IPCC recommended k value ranges for
moderately decaying waste and the k values reported by Jain, et al.
(2021). Table 5 of this preamble presents a comparison of the old
subpart HH and revised k values with the values recommended by the IPCC
and Jain, et al. (2021).
Table 5--Comparison of Finalized Decay Rate Constants (k Values in yrs-\1\) by Precipitation Range
----------------------------------------------------------------------------------------------------------------
Historic IPCC default
subpart HH and Revised decay value Jain, et al. (2021),
Precipitation zone inventory subpart HH (k) ranges for recommended k value
default decay default decay moderately (and 95% confidence
value (k) value (k) decaying waste range)
----------------------------------------------------------------------------------------------------------------
Dry (<20 inches/year).................. 0.02 0.033 0.04-0.05 0.043 (0.033-0.054)
Moderate (20-40 inches/year)........... 0.038 0.067 0.04-0.1 0.074 (0.061-0.088)
Wet (>40 inches/year).................. 0.057 0.098 0.07-0.17 0.090 (0.077-0.105)
----------------------------------------------------------------------------------------------------------------
Similar to the incorporation of the new DOC values, we note that
the proposed revision was not clear regarding how the new k values for
bulk waste under the ``Bulk waste option'' and bulk MSW under the
``Modified bulk MSW option'' should be incorporated into the facility's
emissions estimate. While we are finalizing revisions for the default
bulk waste k values for dry, moderate, and wet climates as 0.033,
0.067, and 0.098 yr-1, respectively, we are also finalizing
clarifications to these revisions to incorporate these revisions
consistently across reporters and consistent with the timeframe where
the reduction in DOC occurred. Specifically, starting in RY2025, we are
maintaining the historic k values of 0.20, 0.038, and 0.057
yr-1 for historic disposal years (prior to 2010) and
requiring the use of the revised k values of 0.033, 0.067, and 0.098
yr-1 for disposal years 2010 and later. We are finalizing
requirements under the modified bulk waste MSW option to use the
current bulk MSW (excluding inerts and C&D waste) k values of 0.02 to
0.057 yr-1 for historic disposal years (prior to 2010) and
requiring the use of the revised bulk MSW (excluding inerts and C&D
waste) k values of 0.033 to 0.098 yr-1 for disposal years
2010 and later, consistent with the timeline for which these values
were determined. Because we have no method to indicate a change in k
value for uncharacterized wastes, we are requiring the use of the new k
values for uncharacterized waste using the composition option of 0.033
to 0.098 for all years for which the composition option was used.
With respect to compliance with the General Assessment Factors, we
considered a wide variety of information, including peer-reviewed
material, when developing our proposed and final k values. While our
technical support documents are not formally peer reviewed at proposal,
we consider the proposal/public review process to be an adequate forum
for public review of our analysis and conclusions. After considering
the public comments received, we revised our analysis to more closely
match the original approach used to determine default k values. We also
adjusted our allowable range for k values based on public comment and
additional literature review. All information we have reviewed indicate
that the historic subpart HH k values are too low and that the values
we determined in our re-analysis of the data will provide improved
methane generation estimates. For these reasons, we are finalizing
revised k values for subpart HH of 0.033, 0.067, and 0.098
yr-1 for dry, moderate, and wet climates, respectively.
These k values apply to bulk waste, bulk MSW, and uncharacterized MSW,
as proposed.
U. Subpart OO--Suppliers of Industrial Greenhouse Gases
We are finalizing several amendments to subpart OO of part 98
(Suppliers of Industrial Greenhouse Gases) as proposed. Section
III.U.1. of this preamble discusses the final revisions to subpart OO.
The EPA received comments on the proposed revisions to subpart OO which
are discussed in section III.U.2. of this preamble. We are also
finalizing as proposed confidentiality determinations for new data
elements resulting from the revisions to subpart OO as described in
section VI. of this preamble.
[[Page 31860]]
1. Summary of Final Amendments to Subpart OO
This section summarizes the final amendments to subpart OO. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other
changes to 40 CFR part 98, subpart OO can be found in this section and
section III.U.2. of this preamble. Additional rationale for these
amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal and 2023 Supplemental Proposal.
The EPA is finalizing several revisions to subpart OO of part 98
that will improve the quality of the data collection under the GHGRP.
First, we are adding a requirement at 40 CFR 98.417(c)(7) for bulk
importers of F-GHGs to include, as part of the information required for
each import in the annual report, the customs entry number. The customs
entry number is provided as part of the U.S. Customs and Border
Protection (CBP) Form 7501: Entry Summary and is assigned for each
filed CBP entry for each shipment. The EPA has made one minor
clarification from proposal. We initially proposed the requirement as
the ``customs entry summary number''; the final rule modifies 40 CFR
98.416(a)(7) to clarify the requirement to the ``customs entry
number,'' which is associated with the CBP Form 7501, ``Entry
Summary.''
As proposed, we are adding a reporting requirement at 40 CFR
98.416(k) that suppliers of N2O, saturated PFCs,
SF6, and fluorinated HTFs identify the end uses for which
the N2O, SF6, saturated PFC, or fluorinated HTF
is used and the aggregated annual quantities of N2O,
SF6, each saturated PFC, or each fluorinated HTF transferred
to each end use, if known. As discussed in the proposed rules, this
requirement is based on a similar requirement in subpart PP to part 98
(Suppliers of Carbon Dioxide) and is intended to provide additional
insight into the identities and magnitudes of the uses of these
compounds, which are currently less well understood than those of other
industrial GHGs such as HFCs, although the GWP-weighted totals supplied
are relatively large.
The EPA is also finalizing a clarification to the reporting
requirements for importers and exporters of F-GHGs, F-HTFs, or
N2O, to revise the required reporting of ``commodity code,''
which is required for importers at 40 CFR 98.416(c)(6) and for
exporters at 40 CFR 98.416(d)(4), to clarify that reporters should
submit the Harmonized Tariff System (HTS) code for each F-GHG, F-HTF,
or N2O shipped. Reporters will enter the full 10-digit HTS
code with decimals, to extend to the statistical suffix, as it was
entered on related customs forms. See section III.S. of the preamble to
the 2022 Data Quality Improvements Proposal for additional information
on the EPA's rationale for these changes.
As discussed in section III.A.1.b. of this preamble, we are
finalizing related revisions to the definition of ``fluorinated HTF,''
previously included in subpart I of part 98 (Electronics
Manufacturing), and to move the definition to subpart A of part 98
(General Provisions), to harmonize with the changes to subpart OO.
Finally, we are finalizing revisions to 40 CFR 98.416(c) and (d) to
clarify that certain exceptions to the reporting requirements for
importers and exporters are voluntary, consistent with our original
intent. To implement this change, we are finalizing revisions to insert
``importers may exclude'' between ``except'' and ``for shipments'' in
the first sentence of Sec. 98.416(c) and (d), deleting the ``for.'' We
are also finalizing revisions to clarify that imports and exports of
transshipments will both have to be either included or excluded for any
given importer or exporter, and we are finalizing a similar
clarification for heels. These changes ensure that importers and
exporters treat the exceptions consistently. See section III.K. of the
preamble to the 2023 Supplemental Proposal for additional information
on these revisions and their supporting basis.
In the 2023 Supplemental Proposal, the EPA proposed a requirement
at 40 CFR 98.416(c) for bulk importers of F-GHGs to provide, for GHGs
that are not regulated substances under 40 CFR part 84 (Phasedown of
Hydrofluorocarbons), copies of the corresponding U.S. CBP entry forms
(e.g., CBP Form 7501) in their annual report. Following consideration
of public comments received on a similar proposed revision to subpart
QQ of part 98 (Importers and Exporters of Fluorinated Greenhouse Gases
Contained in Pre-Charged Equipment and Closed-Cell Foams), including
concerns regarding the availability of this information and the
potential burden of submitting large volumes of entry forms, the EPA is
not taking final action on the proposed revision to subpart OO. See
section III.W. of this preamble for additional information.
2. Summary of Comments and Responses on Subpart OO
This section summarizes the major comments and responses related to
the proposed amendments to subpart OO. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart OO.
Comment: One commenter requested that we clarify that chemical
supply ``end use'' refers to industry category only, such as
electronics or semiconductor use, and does not refer to more specific
uses. The commenter recommended that specific purchases and purposes of
chemical use should be considered industry confidential business
information and therefore protected from public disclosure. The
commenter also noted that chemical suppliers or distributors do not
typically have visibility to end use, particularly specific end use
categories.
Response: As discussed in section VI. of this preamble, we are
planning to finalize our proposed determination that the two new
subpart OO data elements (the end use(s) to which the N2O,
SF6, each PFC, or each fluorinated HTF is transferred and
the aggregated annual quantity of the GHG that is transferred to that
end use application) are ``Eligible for Confidential Treatment.'' This
will protect the data from public disclosure. Regarding suppliers'
knowledge of the uses of compounds within each industry, suppliers are
required to report the end uses only ``if known.'' For N2O,
SF6, and saturated PFCs, the end uses that we identified in
the proposed rule coincided with individual industries and not specific
uses within those industries. For fluorinated HTFs, the end uses that
we identified in the proposed rule coincided with some specific uses
within industries, such as cleaning versus temperature control within
the electronics industry. This was because different end uses, even
within the same industry, have different emission patterns, which
affect the relationship between emissions and consumption of these
compounds. (For example, end uses that quickly emit the F-HTF, such as
cleaning, are expected to have emissions that are close to consumption,
whereas end uses that store the F-HTF, such as process cooling, may
have emissions that are less than half of consumption.) However, the
electronics industry, unlike other industries that
[[Page 31861]]
use F-HTFs, reports its F-HTF emissions to EPA. Thus, in the subpart OO
electronic reporting form, we are planning to list ``electronics
manufacturing'' (including manufacturing of semiconductors, MEMS,
photovoltaic cells, and displays), and not specific uses within
electronics manufacturing, among the end uses whose consumption of the
fluorinated HTF will be reported.
V. Subpart PP--Suppliers of Carbon Dioxide
We are finalizing several amendments to subpart PP of part 98
(Suppliers of Carbon Dioxide) as proposed. This section discusses the
final revisions to subpart PP. The EPA received comments on the
proposed revisions to subpart PP. See the document ``Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of
all comments and responses related to subpart PP.
The EPA is finalizing several revisions to subpart PP to improve
the quality of the data collected from this subpart. As proposed, we
are adding new 40 CFR 98.420(a)(4) and a new definition to 40 CFR 98.6
to explicitly include direct air capture (DAC) as a capture option
under subpart PP. Unlike conventional capture sources where
CO2 is separated during the manufacturing or treatment phase
of product stream, DAC captures CO2 from ambient air using
aqueous or solid sorbents, which is then processed into a concentrated
stream for utilization or injection underground. This final rule
provides that 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. DAC 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.''
The EPA is also finalizing an amendment to the definition of
``carbon dioxide stream'' in 40 CFR 98.6 to add ``captured from ambient
air (e.g., direct air capture)'' to the definition so that it reads,
``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.''
We are finalizing harmonizing changes to 40 CFR 98.422, 98.423,
98.426, and 98.427 to add references to DAC into the reporting
requirements. The final rule also amends 40 CFR 98.426 as proposed to
add additional reporting requirements in paragraph (i) to require DAC
facilities to report the annual quantities and sources (e.g., non-
hydropower renewable sources, natural gas, oil, coal) of on-site and
off-site sourced electricity, heat, and combined heat and power used to
power the DAC plant. These quantities must represent the electricity
and heat used starting from the air intake at the facility and ending
with the compressed CO2 stream (i.e., the CO2
stream ready for supply for commercial applications or, if maintaining
custody of the stream, sequestration or injection of the stream
underground). These quantities must be provided per energy source, if
known. For electricity provided to the DAC plant from the grid,
reporters must additionally provide identifying information for the
facility and electric utility company. In addition, for on-site sourced
electricity, heat, and combined heat and power, DAC facilities must
indicate whether flue gas is also captured by the DAC process unit.
These changes will aid the EPA in understanding this emerging
technology at facilities that utilize DAC and in better understanding
potential net emissions impacts associated with DAC facilities
(particularly given that interest in DAC is primarily intended to be a
carbon removal technology to achieve climate benefits). See section
III.T. of the preamble to the 2022 Data Quality Improvements Proposal
for additional information on the EPA's rationale for these changes.
The EPA is finalizing two additional revisions to improve data
quality. First, we are finalizing the addition of a data element to 40
CFR 98.426(f) that will require suppliers to report the annual quantity
of CO2 in metric tons that is transferred for use in
geologic sequestration with EOR subject to new subpart VV to part 98
(Geologic Sequestration of Carbon Dioxide With Enhanced Oil Recovery
Using ISO 27916). To inform the revision of the subpart PP electronic
reporting form, the EPA also sought comment on potential end use
applications to add to 40 CFR 98.426(f), such as algal systems,
chemical production, and mineralization processes, such as the
production of cements, aggregates, or bicarbonates. However, because 40
CFR 98.426(f) already includes a reporting category for ``other,'' the
existing rule already provides flexibility for this reporting, and we
are not taking final action on the addition of specific end-use
applications to 40 CFR 98.426 at this time. The EPA may consider the
addition of other end-use applications in a future rulemaking.
Second, the EPA is finalizing as proposed that 40 CFR 98.426(h)
will apply to any facilities that capture a CO2 stream from
a facility subject to 40 CFR part 98 and supply that CO2
stream to facilities that are subject to either subpart RR (Geologic
Sequestration of Carbon Dioxide) or new subpart VV. The revised
paragraph will no longer apply only to suppliers that capture
CO2 from EGUs subject to subpart D (Electricity Generation),
but also to suppliers that capture CO2 from any direct
emitting facility that is subject to 40 CFR part 98 and transfer to
facilities subject to subparts RR or VV. Reporters must provide the
facility identification number associated with the facility that is the
source of the captured CO2 stream, each facility
identification number associated with the annual GHG reports for each
subpart RR and subpart VV facility to which CO2 is
transferred, and the annual quantity of CO2 transferred to
each subpart RR and VV facility. See section III.L. of the preamble to
the 2023 Supplemental Proposal for additional information.
The EPA also requested comment on, but did not propose, expanding
the requirement at 40 CFR 98.426(h) such that facilities subject to
subpart PP would report transfers of CO2 to any facilities
reporting under 40 CFR part 98, not just those subject to subparts RR
and VV. This would include reporting the amount of CO2
transferred on an annual basis as well as the relevant GHGRP facility
identification numbers. The EPA further requested comment on whether
information regarding additional end uses would be available to
facilities. Following consideration of public comments, we are not
extending the reporting requirements at this time but may consider
doing so in a future rulemaking.
We are finalizing, with revisions, related confidentiality
determinations for data elements resulting from the revisions to
subpart PP as described in section VI. of this preamble.
W. Subpart QQ--Importers and Exporters of Fluorinated Greenhouse Gases
Contained in Pre-Charged Equipment and Closed-Cell Foams
We are finalizing the amendments to subpart QQ of part 98
(Importers and Exporters of Fluorinated Greenhouse Gases Contained in
Pre-Charged
[[Page 31862]]
Equipment and Closed-Cell Foams) as proposed. In some cases, we are
finalizing the proposed amendments with revisions. Section III.W.1.
discusses the final revisions to subpart QQ. The EPA received several
comments on proposed subpart QQ revisions which are discussed in
section III.W.2. We are also finalizing as proposed confidentiality
determinations for new data elements resulting from the final revisions
to subpart QQ, as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart QQ
This section summarizes the final amendments to subpart QQ. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other
changes to 40 CFR part 98, subpart QQ can be found in this section and
section III.W.2. of this preamble. Additional rationale for these
amendments are available in the preamble to the 2023 Supplemental
Proposal.
We are finalizing two revisions from the 2023 Supplemental
Proposal. We are finalizing requirements for importers and exporters of
fluorinated GHGs contained in pre-charged equipment or closed-cell
foams to include, for each import and export, the HTS code (for
importers, at 40 CFR 98.436(a)(7)) and the Schedule B code (for
exporters, at 40 CFR 98.436(b)(7)) used for shipping each equipment
type. These requirements are consistent with the final revisions to
subpart OO of part 98 (Suppliers of Industrial Greenhouse Gases), which
clarify that reporters should submit the HTS code for each shipment, as
discussed in section III.U. of this preamble. See section III.S. of the
preamble to the 2023 Supplemental Proposal for additional information
on the EPA's rationale for these changes.
The EPA also proposed to revise 40 CFR 98.436 to add a requirement
to include collecting copies of the U.S. CBP entry form (e.g., CBP form
7501) for each reported import, which are currently maintained as
records under 40 CFR 98.437(a). Following consideration of public
comments, the EPA is not taking final action on the proposed
requirement to submit copies of each U.S. CBP entry form. See section
III.W.2. of this preamble for a summary of the related comments and the
EPA's response.
2. Summary of Comments and Responses on Subpart QQ
This section summarizes the major comments and responses related to
the proposed amendments and supplemental amendments to subpart QQ. See
the document ``Summary of Public Comments and Responses for 2024 Final
Revisions and Confidentiality Determinations for Data Elements under
the Greenhouse Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-
0424 for a complete listing of all comments and responses related to
subpart QQ.
Comment: Several commenters contested the EPA's proposed
requirements to collect a copy of the corresponding U.S. CBP entry form
(e.g., Form 7501) for each reported import in 40 CFR 98.436. Some
commenters asserted that the information available in the forms is
currently provided electronically to CBP through the Automated
Commercial Environment (ACE) and should be available to the EPA within
the need for reporters to develop or submit copies. The commenters
noted that this information should be sufficient to identify which
entries are subject to data requirements under subpart QQ. Commenters
recommended that the EPA should coordinate with CBP through established
bodies (e.g., the Border Interagency Executive Council and Commercial
Targeting and Analysis Center, to which the EPA already participates)
to identify and utilize this data. One commenter specifically
recommended that the EPA review the Entry Summary Line Detail Report,
which would show the total quantity reported for entry summary lines by
tariff number for the reported unit of measure. The commenters stated
that such reports capture the actual data in CBP's system, as filed by
importers, and should be sufficient to ensure that the Agency is able
to improve the verification and accuracy of the data it collects. One
commenter expressed that if the EPA is unable to identify applicable
entries through more efficient means, importers should only be asked to
identify specific entry numbers that will allow the EPA to identify the
applicable electronic submissions within ACE.
Commenters objected to the implied submission of hard-copy entry
records as an unnecessary administrative burden. Commenters stated that
the proposed requirement runs counter to CBP's longstanding effort to
collect import data and documents electronically. One commenter stated
that submittal of the border crossing document would necessitate a
substantial amount of additional work and resources to comply,
including gathering documentation from multiple sources prior to annual
reporting. Another commenter noted that in some cases, importers could
be required to file over 70,000 entries or forms. One commenter stated
that this would require at least 1,300 manual searches for the
appropriate forms for each entry. Commenters urged that this would be
prohibitively expensive and burdensome. One commenter pointed out that
this would require substantial modifications to automakers' existing
information systems and processes for their GHG and related reporting
obligations. Other commenters noted that paper form requirements would
obfuscate industry efforts to further automate their record-keeping and
reporting systems. One commenter added that the increased volume of
documentation would likely put much more pressure on businesses than
they can manage based on the current requirement to file data by March
31st of the year following the reporting year.
One commenter stated that the CBP forms would merely confirm the
amount of foam board imported or exported and would not validate the F-
GHG quantity which is the intent of the report. The commenter continued
that, even if border documents were provided, it would be impossible
for the EPA to validate the current reports as the calculations
involved to provide the volume of F-gas per board foot would require
detailed technical knowledge, including density of the foam board.
Some commenters asserted that the entry form requirement runs
counter to Executive Order 13659 and 19 U.S.C. 1411(d), as amended by
sections 106 and 107 of the Trade Facilitation and Trade Enforcement
Act of 2015, which advance the goal of providing for electronic
transmission of import data and seek to eliminate the need for
duplicative information submissions across U.S. government agencies
with regulatory authority related to goods entered or imported into the
United States.
Other commenters questioned the EPA's requirements to require
reporting of the HTS) code for each type of pre-charged equipment or
closed-cell foam imported and/or the Schedule B code for each type of
pre-charged equipment or closed-cell foam exported. One commenter
questioned whether the inclusion of both HTS codes and Schedule B codes
is necessary for validation of the data that is currently collected, as
all polystyrene foams use the same codes. The commenter urged that
requiring more than one type of document would prove redundant in
showing product type; be burdensome for manufacturers and for the EPA;
and would not provide any additional
[[Page 31863]]
clarity or validation to the current report.
Another commenter stated that only the border crossing document
(which includes the customs tariff number, with the first six digits of
an HTS and Schedule B number) should be required as part of the annual
report. The commenter noted that these border crossing documents share
highly sensitive information such as quantity and price, so should be
handled securely. One commenter reiterated that all data proposed to be
collected is, and would be, considered highly confidential business
information. The commenter added that access to this type of
information is restricted internally, which adds complexity to who
could manage and deal with the processing of this documentation within
facilities.
Response: The EPA is revising the final rule to remove the
requirement for reporters to submit copies of their U.S. CBP form 7501.
Following consideration of comments received, it has been determined
that annually reporting these documents could pose a significant burden
for many reporters. Therefore, the EPA is not adopting the proposed
data reporting requirement in the final rule.
The EPA is finalizing the proposed requirement to report HTS codes
(for imports) and Schedule B codes (for exports) to assist the Agency
in verification of data. This requirement will allow the EPA to better
compare reported GHGRP data with data from other government sources,
specifically CBP records. As only one type of code (HTS or Schedule B)
will be required based on whether the shipment is an import or export,
this will not require the reporting of redundant information to the
EPA. Furthermore, we are making ``No Determination'' of confidentiality
for this data element. ``No Determination'' means that the EPA is not
making a confidentiality determination through rulemaking at this time.
If necessary, the EPA will evaluate and determine the confidentiality
status of this data on a per-facility basis in accordance with the
provisions of 40 CFR part 2, subpart B.
X. Subpart RR--Geologic Sequestration of Carbon Dioxide
We are finalizing amendments to subpart RR of part 98 (Geologic
Sequestration of Carbon Dioxide) as proposed. This section discusses
the substantive final revisions to subpart RR. The EPA received only
one supportive comment for subpart RR. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart RR.
Additional rationale for these amendments is available in the preamble
to the 2023 Supplemental Proposal.
We are adding a definition for ``offshore'' to 40 CFR 98.449 to
mean ``seaward of the terrestrial borders of the United States,
including waters subject to the ebb and flow of the tide, as well as
adjacent bays, lakes or other normally standing waters, and extending
to the outer boundaries of the jurisdiction and control of the United
States under the Outer Continental Shelf Lands Act.'' This definition
clarifies the applicability of subpart RR to offshore geologic
sequestration activities, including on the outer continental shelf.
Additional rationale for these amendments is available in the preamble
to the 2023 Supplemental Proposal.
Y. Subpart SS--Electrical Equipment Manufacture or Refurbishment
We are finalizing several amendments to subpart SS of part 98
(Electrical Equipment Manufacture or Refurbishment) as proposed. In
some cases, we are finalizing the proposed amendments with revisions.
Section III.Y.1. of this preamble discusses the substantive final
revisions to subpart SS. The EPA received several comments on the
proposed revisions to subpart SS which are addressed in section
III.Q.2. of this preamble. We are also finalizing as proposed
confidentiality determinations for new data elements resulting from the
revisions to subpart SS as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart SS
This section summarizes the final amendments to subpart SS. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other final
revisions to 40 CFR part 98, subpart SS can be found in this section
and section III.Y.2. of this preamble. Additional rationale for these
amendments is available in the preamble to the 2022 Data Quality
Improvements Proposal.
a. Revisions To Improve the Quality of Data Collected for Subpart SS
The EPA is finalizing several revisions to subpart SS to improve
the quality of the data collected from this subpart. We are generally
finalizing as proposed revisions to the calculation, monitoring, and
reporting requirements of subpart SS (at 40 CFR 98.452, 98.453, 98.454,
and 98.456) to require reporting of additional F-GHGs as defined under
40 CFR 98.6, except electrical equipment manufacturers and refurbishers
will not be required to report emissions of insulating gases with
weighted average GWPs of one (1) or less. However, they will be
required to report the quantities of insulating gases with weighted
average GWPs of one or less, as well as the nameplate capacities of the
associated equipment, that they transfer to their customers. To
implement these revisions, we are finalizing revisions that redefine
the source category at 40 CFR 98.450 to include equipment containing
``fluorinated GHGs (F-GHG), including but not limited to sulfur-
hexafluoride (SF6) and perfluorocarbons (PFCs).'' The
changes also apply to the threshold in 40 CFR 98.451, which we are
revising as discussed in section III.Y.1. of this preamble. Facilities
also must consider additional F-GHGs purchased by the facility in
estimating emissions for comparison to the threshold.
The revisions to subpart SS include the addition of a new equation
SS-1 in the reporting threshold at 40 CFR 98.451 (discussed in section
III.Y.b. of this preamble) and a new equation SS-2 in the GHGs to
report at 40 CFR 98.452. Equation SS-2 is also used in the definition
of ``reportable insulating gas,'' discussed in this section of the
preamble. We are also making minor revisions to equations SS-1 through
SS-6 (which we are renumbering as SS-3 through SS-8 to accommodate new
equations SS-1 and SS-2) to incorporate the estimation of emissions
from all F-GHGs within the existing calculation methodology. To account
for the possibility that the same fluorinated GHG could be a component
of multiple reportable insulating gases, we are inserting in the final
rule a summation sign at the beginning of the right side of equation
SS-3 to ensure that emissions of each fluorinated GHG i are summed
across all reportable insulating gases j. In addition, we are updating
the monitoring and quality assurance requirements to account for
emissions from additional F-GHGs, and harmonizing revisions to the
reporting requirements such that reporters account for the mass of each
F-GHG at the facility level.
We are also finalizing the proposed definition of ``insulating
gas'' and adding the term ``reportable insulating gas,'' which is
defined as ``an insulating gas whose weighted average GWP, as
calculated in equation SS-2, is greater
[[Page 31864]]
than one. A fluorinated GHG that makes up either part or all of a
reportable insulating gas is considered to be a component of the
reportable insulating gas.'' This term is intended to distinguish
between insulating gases whose emissions must be reported under subpart
SS and insulating gases whose emissions are not required to be reported
under subpart SS (although, as noted above, the quantities of all
insulating gases supplied to customers must be reported). In many
though not all cases, we are also replacing occurrences of the proposed
phrase ``fluorinated GHGs, including PFCs and SF6'' with
``fluorinated GHGs that are components of reportable insulating
gases.'' In addition, we are finalizing revisions to add reporting of
an ID number or descriptor for each insulating gas and the name and
weight percent of each insulating gas reported. The EPA has also made
one minor clarification from proposal. We initially proposed 40 CFR
98.456(u) to require reporting of an ID number or descriptor for each
unique insulating gas. To clarify the applicability of this requirement
for those gases mixed on-site, the final rule clarifies that facilities
must report an ID number or other appropriate descriptor that is unique
to the reported insulating gas, and for each ID number or descriptor
reported, the name and weight percent of each fluorinated gas in the
insulating gas. See section III.U.1. of the preamble to the 2022 Data
Quality Improvements Proposal for additional information on these
revisions and their supporting basis.
b. Revisions To Streamline and Improve Implementation for Subpart SS
To account for changes in the usage of certain GHGs and reduce the
likelihood that the reporting threshold will cover facilities with
emissions well below 25,000 mtCO2e, we are generally
finalizing revisions to the applicability threshold of subpart SS as
proposed. (The one change is the introduction of the term ``reportable
insulating gas,'' as described in this section III.Y. of the preamble.)
The revisions remove the consumption-based threshold at 40 CFR 98.451
and instead require facilities to estimate total annual GHG emissions
for comparison to the 25,000 mtCO2e threshold by introducing
a new equation, equation SS-1. The equation SS-1 continues to be based
on the total annual purchases of insulating gases, but establishes an
updated comparison to the threshold, and accounts for the additional
fluorinated gases reported by industry. Potential reporters are
required to account for the total annual purchases of all reportable
insulating gases and multiply the purchases of each reportable
insulating gas by the GWP for each F-GHG and the emission factor of
0.10 (or 10 percent). The final rule threshold methodology is more
appropriate because it represents the actual fluorinated gases used by
a reporter; these revisions also streamline the reporting requirements
to focus Agency resources on the substantial emission sources within
the sector. Additionally, the changes revise the inclusion of subpart
SS in the existing table A-3 to subpart A. Because we are providing a
method for direct comparison to the 25,000 mtCO2e threshold,
we are removing subpart SS from table A-3 and including the subpart in
table A-4 to subpart A. This will require facilities to determine
applicability according to 40 CFR 98.2(a)(2) and consider the combined
emissions from stationary fuel combustion sources (subpart C),
miscellaneous use of carbonates (subpart U), and other applicable
source categories. Including subpart SS in table A-4 to subpart A is
consistent with other GHGRP subparts that use the 25,000
mtCO2e threshold included under 40 CFR 98.2(a)(2) to
determine applicability. See section III.U.2. of the preamble to the
2022 Data Quality Improvements Proposal for additional information on
these revisions and their supporting basis.
2. Summary of Comments and Responses on Subpart SS
This section summarizes the major comments and responses related to
the proposed amendments to subpart SS. See the document ``Summary of
Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart SS.
Comment: One commenter suggested redefining the definition of
``insulating gas'' to including any gas with a GWP greater than one and
not any fluorinated GHG or fluorinated GHG mixture. The commenter urged
that the proposed definition ignores other potential gases that may
come onto the market that are not fluorinated but still have a GWP
potential. The commenter stated that defining insulating gas under
subpart SS to include any gas with a GWP greater than one used as an
insulating gas and/or arc quenching gas in electrical equipment would
mirror the threshold implemented by the California Air Resources Board
and would provide consistency for reporters across Federal and State
reporting rules.
Response: In the final rule, the EPA is not requiring electrical
equipment manufacturers and refurbishers to report emissions of
insulating gases with weighted average 100-year GWPs of one or less,
but the EPA is requiring such facilities to report the quantities of
insulating gases with GWPs of one or less, as well as the nameplate
capacity of the associated equipment, that they transfer to their
customers. Based on a review of the subpart SS data submitted to date,
the EPA has concluded that excluding emissions of insulating gases with
weighted average GWPs of one or less from reporting under subpart SS
will have little effect on the accuracy or completeness of the GWP-
weighted totals reported under subpart SS or under the GHGRP generally.
Between 2011 and 2021, total SF6 and PFC emissions across
all facilities reporting under subpart SS have ranged from 5 to 15 mt
(unweighted) or 120,000 to 350,000 mtCO2e. At GWPs of one,
these weighted totals would be equivalent to the unweighted quantities
reported, which constitute approximately 0.004% (1/23,500) of the GWP-
weighted totals. Even in a worst-case scenario where the annual
manufacturer emissions of a very low-GWP insulating gas were assumed to
equal the total quantity of that gas transferred from manufacturers to
customers (implying an emission rate of 100%, higher than any ever
reported under subpart SS), the total GWP-weighted emissions reported
under subpart SS would be considerably smaller than those reported
under any other subpart: total unweighted quantities shipped to
customers reported across all facilities to date have ranged between
196 and 372 mt. At GWPs of 1, these totals would fall well below the
15,000- and 25,000 mtCO2e quantities below which individual
facilities are eventually allowed to exit the program under the off-
ramp provisions of subpart A of part 98 (40 CFR 98.2(i)), as
applicable.
While the EPA is not requiring electrical equipment manufacturers
and refurbishers to report their emissions of insulating gases with
GWPs of one or less, the EPA is requiring such facilities to report the
quantities of insulating gases with weighted average GWPs of one or
less, as well as the nameplate capacity of the associated equipment,
that they transfer to their customers. Tracking such transfers is
important to understanding the extent to which substitutes for
SF6 are replacing SF6 as an insulating gas, which
will inform future policies and programs under provisions of the CAA.
The EPA
[[Page 31865]]
anticipates that tracking transfers to customers will involve a lower
burden than tracking emissions and other quantities in addition to
transfers.
Z. Subpart UU--Injection of Carbon Dioxide
We are finalizing the amendments to subpart UU of part 98
(Injection of Carbon Dioxide) as revised in the 2023 Supplemental
Proposal. This section discusses the final revisions to subpart UU. The
EPA received only one supportive comments on the proposed revision to
subpart UU in the 2023 Supplemental Proposal. See the document
``Summary of Public Comments and Responses for 2024 Final Revisions and
Confidentiality Determinations for Data Elements under the Greenhouse
Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a
complete listing of all comments and responses related to subpart UU.
The EPA initially proposed amendments to subpart UU in the 2022
Data Quality Improvements Proposal that were intended to harmonize with
revisions to add new subpart VV to part 98 (Geologic Sequestration of
Carbon Dioxide With Enhanced Oil Recovery Using ISO 27916). Subpart VV
is described further in section III.Z. of this preamble. However, we
received comments on the 2022 Data Quality Improvements Proposal saying
that the applicability of proposed subpart VV was unclear. The EPA
subsequently re-proposed revisions to 40 CFR 98.470 in the 2023
Supplemental Proposal. As described in sections III.O. of the preamble
of the 2023 Supplemental Proposal, the EPA proposed, and is finalizing,
revisions to Sec. 98.470 of subpart UU of part 98 to clarify the
applicability of each subpart when a facility quantifies their geologic
sequestration of CO2 in association with EOR operations
through the use of the CSA/ANSI ISO 27916:19 method. Specifically, we
are clarifying that facilities with a well or group of wells that must
report under subpart VV shall not also report data for those same wells
under subpart UU. These changes also clarify how CO2-EOR
projects that may transition to use of the CSA/ANSI ISO 27916:19 method
during a reporting year will be required to report for the portion of
the reporting year before they began using CSA/ANSI ISO 27916:19 and
for the portion after they began using CSA/ANSI ISO 27916:19.
Additional rationale for these amendments is available in the preamble
to the 2023 Supplemental Proposal.
AA. Subpart VV--Geologic Sequestration of Carbon Dioxide With Enhanced
Oil Recovery Using ISO 27916
We are finalizing several amendments to add subpart VV (Geologic
Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO
27916) to part 98 as proposed. Section III.Z.1. of this preamble
discusses the final requirements of subpart VV. The EPA received
several comments on the proposed subpart VV which are discussed in
section III.V.2. of this preamble. We are also finalizing as proposed
related confidentiality determinations for data elements resulting from
the revisions to subpart VV as described in section VI. of this
preamble.
1. Summary of Final Amendments to Subpart VV
This section summarizes the substantive final amendments to subpart
VV. Major changes to the final rule as compared to the proposed
revisions are identified in this section. The rationale for these and
any other changes to 40 CFR part 98, subpart VV can be found in this
section. Additional rationale for these amendments is available in the
preamble to the 2022 Data Quality Improvements Proposal 2023
Supplemental Proposal.
a. Source Category Definition
In the 2022 Data Quality Improvements Proposal, the EPA proposed
adding a new source category, subpart VV, to part 98 to add calculation
and reporting requirements for quantifying geologic sequestration of
CO2 in association with EOR operations, which would only
apply to facilities that quantify the geologic sequestration of
CO2 in association with EOR operations in conformance with
the ISO standard designated as CSA/ANSI ISO 27916:19, Carbon dioxide
capture, transportation and geological storage--Carbon dioxide storage
using enhanced oil recovery.\42\ In our initial proposal, the EPA
outlined the source category definition, rationale for no threshold,
calculation methodology, and monitoring, recordkeeping, and reporting
requirements. We noted at that time that under existing GHGRP
requirements, facilities that receive CO2 for injection at
EOR operations report under subpart UU (Injection of Carbon Dioxide),
and facilities that geologically sequester CO2 through EOR
operations may instead opt-in to subpart RR (Geologic Sequestration of
Carbon Dioxide). The EPA proposed to add new subpart VV to require
reporting of incidental CO2 storage associated with EOR
based on the CSA/ANSI ISO 27916:19 standard. We subsequently received
detailed comments saying that the applicability of proposed subpart VV
was unclear, specifically, proposed 40 CFR 98.480 ``Definition of the
Source Category.'' The commenters were uncertain whether the EPA had
intended to require facilities using CSA/ANSI ISO 27916:19 to report
under subpart VV or whether facilities that used CSA/ANSI ISO 27916:19
would have the option to choose under which subpart they would report
to: subpart RR, subpart UU, or subpart VV.
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\42\ Although the title of the standard references only EOR,
Clause 1.1 of CSA/ANSI ISO 27916:19 indicates that the standard can
apply to enhanced gas recovery as well. Therefore, any reference to
EOR in subpart VV also applies to enhanced gas recovery.
---------------------------------------------------------------------------
In the 2023 Supplemental Proposal, the EPA subsequently reproposed
Sec. Sec. 98.480 and 98.481 of subpart VV to clarify the applicability
to each subpart. As explained in section III.P. of the preamble the
2023 Supplemental Proposal, the EPA clarified that if a facility elects
to use the CSA/ANSI ISO 27916:19 method for quantifying geologic
sequestration of CO2 in association with EOR operations,
then the facility would be required under the GHGRP to report under new
subpart VV (unless the facility chooses to report under subpart RR and
has received an approved Monitoring, Reporting, and Verification Plan
(MRV Plan) from EPA). The EPA further clarified that subpart VV is not
intended to apply to facilities that use the content of CSA/ANSI ISO
27916:19 for a purpose other than demonstrating secure geologic
storage, such as only as a reference material or for informational
purposes. Following review of subsequent comments received on the
reproposed source category definition, we are finalizing the definition
of the source category as proposed in the 2023 Supplemental Proposal.
b. Reporting Threshold
In the 2022 Data Quality Improvements Proposal, the EPA proposed no
threshold for reporting under subpart VV (i.e., that subpart VV would
be an ``all-in'' reporting subpart). The EPA also proposed under 40 CFR
98.480(c) that facilities subject only to subpart VV would not be
required to report emissions under subpart C or any other subpart
listed in 40 CFR 98.2(a)(1) or (2), consistent with the requirements
for existing reporters under subpart UU. In the 2023 Supplemental
Proposal, the EPA maintained no threshold is required for reporting,
but amended the regulatory text to clarify that all CO2-
[[Page 31866]]
EOR projects using CSA/ANSI ISO 27916:19 as a method of quantifying
geologic sequestration that do not report under subpart RR would report
under subpart VV. We also proposed text at 40 CFR 98.481(c) to clarify
how CO2-EOR projects previously reporting under subpart UU
that begin using CSA/ANSI ISO 27916:19 part-way through a reporting
year must report. The EPA is finalizing these requirements as
reproposed in the 2023 Supplemental Proposal.
Additionally, we are finalizing revisions at 40 CFR 98.481(b) that
facilities subject to subpart VV will not be subject to the off-ramp
requirements of 40 CFR 98.2(i). Instead, once a facility opts-in to
subpart VV, the owner or operator must continue for each year
thereafter to comply with all requirements of the subpart, including
the requirement to submit annual reports, until the facility
demonstrates termination of the CO2-EOR project following
the requirements of CSA/ANSI ISO 27916:19. The operator must notify the
Administrator of its intent to cease reporting and provide a copy of
the CO2-EOR project termination documentation prepared for
CSA/ANSI ISO 27916:19.
c. Calculation Methods
In the 2022 Data Quality Improvements Proposal and 2023
Supplemental Proposal, the EPA proposed incorporating the
quantification methodology of CSA/ANSI ISO 27916:19 for calculation of
emissions. Under CSA/ANSI ISO 27916:19, the mass of CO2
stored is determined as the total mass of CO2 received minus
the total mass of CO2 lost from project operations and the
mass of CO2 lost from the EOR complex. The EOR complex is
defined as the project reservoir, trap, and such additional surrounding
volume in the subsurface as defined by the operator within which
injected CO2 will remain in safe, long-term containment.
Specific losses include those from leakage from production, handling,
and recycling facilities; from infrastructure (including wellheads);
from venting/flaring from production operations; and from entrainment
within produced gas/oil/water when this CO2 is not separated
and reinjected. We are finalizing the calculation requirements as
proposed.
d. Monitoring, QA/QC, and Verification Requirements
The EPA is finalizing as proposed the requirement for reporters to
use the applicable monitoring and quality assurance requirements set
forth in CSA/ANSI ISO 27916:19.
e. Procedures for Estimating Missing Data
The EPA is finalizing as proposed the requirement for reporters to
use the applicable missing data and quality assurance procedures set
forth in CSA/ANSI ISO 27916:19.
f. Data Reporting Requirements
The EPA is finalizing, as proposed, that facilities will report the
amount of CO2 stored, inputs included in the mass balance
equation used to determine CO2 stored using the CSA/ANSI ISO
27916:19 methodology, and documentation providing the basis for that
determination as set forth in CSA/ANSI ISO 27916:19. Documentation
includes providing the CSA/ANSI ISO 27916:19 EOR Operations Management
Plan (OMP), which is required to specify: (1) a geological description
of the site and the procedures for field management and operational
containment during the quantification period; (2) the initial
containment assurance plan to identify potential leakage pathways; (3)
the plan for monitoring of potential leakage pathways; and (4) the
monitoring methods for detecting and quantifying losses and how this
will serve to provide the inputs into site-specific mass balance
equations. Reporters must also specify any changes made to containment
assurance and monitoring approaches and procedures in the EOR OMP made
within the reporting year.
We are also finalizing the reporting of the following information
per CSA/ANSI ISO 27916:19: (1) the quantity of CO2 stored
during the year; (2) the formula and data used to quantify the storage,
including the quantity of CO2 delivered to the
CO2-EOR project and losses during the year; (3) the methods
used to estimate missing data and the amounts estimated; (4) the
approach and method for quantification utilized by the operator,
including accuracy, precision and uncertainties; (5) a statement
describing the nature of validation or verification, including the date
of review, process, findings, and responsible person or entity; and (6)
the source of each CO2 stream quantified as storage. The
final rule also requires that reporters provide a copy of the
independent engineer or geologist's certification as part of reporting
to subpart VV, if such a certification has been made.
Finally, the EPA is finalizing a notification for project
termination. The final rule specifies that the time for cessation of
reporting under subpart VV is the same as under CSA/ANSI ISO 27916:19;
the operator must notify the Administrator of its intent to cease
reporting and provide a copy of the CO2-EOR project
termination documentation.
g. Records That Must Be Retained
The EPA is finalizing as proposed the requirement that reporters
meet the record retention requirements of 40 CFR 98.3(g) and the
applicable recordkeeping retention requirements set forth in CSA/ANSI
ISO 27916:19.
2. Summary of Comments and Responses on Subpart VV
The EPA received several comments for subpart VV; the majority of
these comments were received on the 2022 Data Quality Improvements
Proposal and were previously addressed in the preamble to the 2023
Supplemental Proposal (see section III.P. of the preamble to the 2023
Supplemental Proposal). The EPA received only supportive comments on
the proposed revisions to subpart VV in the 2023 Supplemental Proposal;
see the document ``Summary of Public Comments and Responses for 2024
Final Revisions and Confidentiality Determinations for Data Elements
under the Greenhouse Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-
2019-0424 for a complete listing of all comments and responses related
to subpart VV.
BB. Subpart WW --Coke Calciners
We are finalizing the addition of subpart WW to part 98 (Coke
Calciners) with revisions in some cases. Section III.BB.1. of this
preamble discusses the final requirements of subpart WW. The EPA
received several comments on the proposed subpart WW which are
discussed in section III.BB.2. of this preamble. We are also finalizing
as proposed related confidentiality determinations for data elements
resulting from the revisions to subpart WW as described in section VI.
of this preamble.
1. Summary of Final Amendments to Subpart WW
This section summarizes the substantive final amendments to subpart
WW. Major changes in this final rule as compared to the proposed
revisions are identified in this section. The rationale for these and
any other changes to 40 CFR part 98, subpart WW can be found in this
section. Additional rationale for these amendments is available in the
preamble to the 2022 Data Quality Improvements Proposal and 2023
Supplemental Proposal.
[[Page 31867]]
a. Source Category Definition
The EPA is finalizing the source category definition as proposed,
with one minor clarification. Specifically, we proposed that the coke
calciner source category consists of process units that heat petroleum
coke to high temperatures in the absence of air or oxygen for the
purpose of removing impurities or volatile substances in the petroleum
coke feedstock. Following review of comments received, the EPA is
revising the source category definition from that proposed to remove
the language ``in the absence of air or oxygen.'' See section III.BB.2.
of this preamble for additional information on related comments and the
EPA's response. The final definition of the coke calciner source
category includes, but is not limited to, rotary kilns or rotary hearth
furnaces used to calcine petroleum coke and any afterburner or other
equipment used to treat the process gas from the calciner. The source
category includes all coke calciners, not just those co-located at
petroleum refineries, to provide consistent requirements for all coke
calciners.
b. Reporting Threshold
In the 2023 Supplemental Proposal, the EPA proposed no threshold
for reporting under subpart WW. Because coke calciners are large
emission sources, they are expected to emit over the 25,000
mtCO2e threshold generally required to report under existing
GHGRP subparts with thresholds, and nearly all of them are also
projected to exceed the 100,000 mtCO2e threshold. Therefore,
the EPA projects that there are limited differences in the number of
reporting facilities based on any of the emission thresholds
considered. For this reason, the EPA is finalizing the coke calciner
source category as an ``all-in'' subpart (i.e., regardless of their
emissions profile).
c. Calculation Methods
Coke calciners primarily emit CO2, but also have
CH4 and N2O emissions as part of the process gas
emission control combustion device operation. The EPA is finalizing, as
proposed in the 2023 Supplemental Proposal, that CO2,
CH4, and N2O emissions from each coke calcining
unit be estimated.
The EPA reviewed a number of different emissions estimation methods
for coke calciners. We subsequently proposed, and are finalizing, to
require either one of two separate calculation methods, the use of a
CEMS or the carbon mass balance method for estimating emissions. Each
of these methodologies are used to estimate CO2 emissions.
We are also finalizing, as proposed, that coke calciners also estimate
process CH4 and N2O emissions based on the total
CO2 emissions determined for the coke calciner and the ratio
of the default CO2 emission factor for petroleum coke in
table C-1 to subpart C of part 98 to the default CH4 and
N2O emission factors for petroleum products in table C-2 to
subpart C of part 98. Under the final methods, petroleum refineries
with coke calciners are able to maintain their current calculation
methods. Additional detail on the calculation methods reviewed are
available in section IV.B. of the preamble to the 2023 Supplemental
Proposal.
Direct measurement using CEMS. The CEMS approach directly measures
CO2 concentration and total exhaust gas flow rate for the
combined process and combustion source emissions. CO2 mass
emissions are calculated from these measured values using equation C-6
and, if necessary, equation C-7 in 40 CFR 98.33(a)(4).
The EPA proposed that the CEMS method under subpart WW would be
implemented consistent with subpart Y of part 98 (Petroleum
Refineries), which required reporters to determine CO2
emissions from auxiliary fuel use discharged in the coke calciner
exhaust stack using methods in subpart C of part 98, and to subtract
those emissions from the measured CEMS emissions to determine the
process CO2 emissions. We are finalizing this requirement.
Carbon balance method. For those facilities that do not have a
qualified CEMS in-place, facilities may use the carbon mass balance
method, using data that is expected to be routinely monitored by coke
calcining facilities. The carbon mass balance method uses the mass of
green coke, calcined coke and petroleum coke dust removed from the dust
collection system, along with the carbon content of the green and
calcined coke, to estimate process CO2 emissions; the
methodology is the same as current equation Y-13 of 40 CFR 98.253(g)(2)
that is used for coke calcining processes co-located at petroleum
refineries.
d. Monitoring, QA/QC, and Verification Requirements
The EPA is finalizing the monitoring methods to subpart WW as
proposed.
Direct measurement using CEMS. For direct measurement using CEMS,
the CEMS method requires both a continuous CO2 concentration
monitor and a continuous volumetric flow monitor. Reporters required to
or electing to use CEMS must install, operate, and calibrate the
monitoring system according to subpart C (General Stationary Fuel
Combustion Sources), which is consistent with the current requirements
for coke calciner CO2 CEMS monitoring requirements within
subpart Y. We are finalizing that all CO2 CEMS and flow rate
monitors used for direct measurement of GHG emissions should comply
with QA/QC procedures for daily calibration drift checks and quarterly
or annual accuracy assessments, such as those provided in Appendix F to
part 60 or similar QA/QC procedures. These requirements ensure the
quality of the reported GHG emissions and are consistent with the
current requirements for CEMS measurements within subparts A (General
Provisions) and C of the GHGRP.
Carbon balance method. The carbon mass balance method requires
monitoring of mass quantities of green coke fed to the process,
calcined coke leaving the process, and coke dust removed from the
process by dust collection systems. It also requires periodic
determination of carbon content of the green and calcined coke. For
coke mass measurements, we are finalizing that the measurement device
be calibrated according to the procedures specified by the updated NIST
HB 44-2023: Specifications, Tolerances, and Other Technical
Requirements For Weighing and Measuring Devices, 2023 edition (we have
clarified the title and publication date of this method in the final
rule) or the procedures specified by the manufacturer. We are requiring
the measurement device be recalibrated either biennially or at the
minimum frequency specified by the manufacturer. These requirements are
to ensure the quality of the reported GHG emissions and to be
consistent with the current requirements for coke calciner mass
measurements within subpart Y.
For carbon content of coke measurements, the owner or operator must
follow approved analytical procedures and maintain and calibrate
instruments used according to manufacturer's instructions and to
document the procedures used to ensure the accuracy of the measurement
devices used. These requirements are to ensure the quality of the
reported GHG emissions and to be consistent with the current
requirements for coke calciner mass measurements within subpart Y.
These determinations must be made monthly. If carbon content
measurements are made more often than monthly, all measurements made
within the calendar month must be used to determine the average for the
month.
[[Page 31868]]
e. Procedures for Estimating Missing Data
The EPA is finalizing as proposed the procedures for estimating
missing data. For the CEMS methodology, whenever a quality-assured
value of a required parameter is unavailable (e.g., if a CEMS
malfunctions during unit operation or if a required fuel sample is not
taken), a substitute data value for the missing parameter shall be used
in the calculations. For missing CEMS data, the missing data procedures
in subpart C must be used.
Under the carbon mass balance method, for each missing value of
mass or carbon content of coke, reporters must use the average of the
data measurements before and after the missing data period. If, for a
particular parameter, no quality assured data are available prior to
the missing data incident, the substitute data value must be the first
quality-assured value obtained after the missing data period.
Similarly, if no quality-assured data are available after the missing
data incident, the substitute data value must be the most recently
acquired quality-assured value obtained prior to the missing data
period.
f. Data Reporting Requirements
The EPA is finalizing the data reporting requirements of subpart WW
as proposed. For coke calcining units, the owner and operator shall
report the coke calciner unit ID number and maximum rated throughput of
the unit, the method used to calculate GHG emissions, and the
calculated CO2, CH4, and N2O annual
emissions for each unit, expressed in metric tons of each pollutant
emitted. We are also requiring the owner and operator to report the
annual mass of green coke fed to the coke calcining unit, the annual
mass of marketable petroleum coke produced by the coke calcining unit,
the annual mass of petroleum coke dust removed from the process through
the dust collection system of the coke calcining unit, the annual
average mass fraction carbon content of green coke fed to the unit, and
the annual average mass fraction carbon content of the marketable
petroleum coke produced by the coke calcining unit.
g. Records That Must Be Retained
The EPA is finalizing the record retention requirements of subpart
WW as proposed. Facilities are required to maintain records documenting
the procedures used to ensure the accuracy of the measurements of all
reported parameters, including but not limited to, calibration of
weighing equipment, flow meters, and other measurement devices. The
estimated accuracy of measurements made with these devices must also be
recorded, and the technical basis for these estimates must be provided.
For the coke calciners source category, we are finalizing that the
verification software specified in 40 CFR 98.5(b) be used to fulfill
the recordkeeping requirements for the following five data elements:
Monthly mass of green coke fed to the coke calcining unit;
Monthly mass of marketable petroleum coke produced by the
coke calcining unit;
Monthly mass of petroleum coke dust removed from the
process through the dust collection system of the coke calcining unit;
Average monthly mass fraction carbon content of green coke
fed to the coke calcining unit; and
Average monthly mass fraction carbon content of marketable
petroleum coke produced by the coke calcining unit.
2. Summary of Comments and Responses on Subpart WW
This section summarizes the major comments and responses related to
the proposed subpart WW. The EPA previously requested comment on the
addition of coke calciners production source category as a new subpart
to part 98 in the 2022 Data Quality Improvements Proposal. The EPA
received several comments for subpart WW on the 2022 Data Quality
Improvements Proposal; many of these comments were previously addressed
in the preamble to the 2023 Supplemental Proposal, wherein the EPA
proposed to add new subpart WW for coke calciners (see section IV.B. of
the preamble to the 2023 Supplemental Proposal). The EPA received
additional comments regarding the proposed subpart WW following the
2023 Supplemental Proposal. See the document ``Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of
all comments and responses related to subpart WW.
Comment: One commenter stated that the description of coke
calciners may be overly narrow. The commenter contended that the
language ``in the absence of air or oxygen'' is not necessarily
accurate. The commenter stated that air/oxygen is necessary for
combustion to occur, and that the high temperatures required for proper
calcination are from the combustion of volatiles and carbon in the
green coke.
Response: We understand that air is introduced in the coke calciner
to burn the volatiles from the coke, but the air is introduced in a
limited fashion (limited oxygen) so that the complete combustion of
coke in the calciner does not occur. However, we agree with the
commenter that the phrase ``in the absence of air or oxygen'' may be
too restrictive and we have deleted this phrase from the proposed
source category description at 40 CFR 98.490(a) in the final rule.
Comment: One commenter stated that coke calciners that use refinery
fuel gas or natural gas during startup or during hot standby should be
allowed to report emissions from these fuel gases using a methodology
from subpart C of part 98, separately from the coke calciner emissions.
The commenter stated that where coke calcining and fuel gas combustion
are occurring simultaneously, the fuel gas emissions should be
subtracted from the emissions that are calculated using CEMS and the
proposed stack flow methodology to avoid double counting. The commenter
added that the requirements for fuel gas or natural gas composition and
heat content use in coke calciners should be the same as required in
subpart C.
Response: We agree with the commenter and the issues identified by
the commenter were addressed in the 2023 Supplemental Proposal. We are
finalizing these provisions for treating GHG emissions from auxiliary
fuel use as proposed (see 40 CFR 98.493(b)(1)).
CC. Subpart XX--Calcium Carbide Production
We are finalizing the addition of subpart XX (Calcium Carbide
Production) to part 98 as proposed. Section III.CC.1. of this preamble
discusses the final requirements of subpart XX. The EPA received
comments on the proposed subpart XX which are discussed in section
III.CC.2. of this preamble. We are also finalizing as proposed related
confidentiality determinations for data elements resulting from the
addition of subpart XX as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart XX
This section summarizes the final amendments to subpart XX. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other
changes to 40 CFR part 98, subpart XX can be found in this section and
section III.CC.2. of this preamble.
[[Page 31869]]
Additional rationale for these amendments is available in the preamble
to the 2022 Data Quality Improvements Proposal and 2023 Supplemental
Proposal.
a. Source Category Definition
The EPA is finalizing the source category definition as proposed.
We are defining calcium carbide production to include any process that
produces calcium carbide. Calcium carbide is an industrial chemical
manufactured from lime (CaO) and carbon, usually petroleum coke, by
heating the mixture to 2,000 to 2,100 C (3,632 to 3,812 [deg]F) in an
electric arc furnace. During the production of calcium carbide, the use
of carbon-containing raw materials (petroleum coke) results in
emissions of CO2.
Although we considered accounting for emissions from the production
of acetylene at calcium carbide facilities in the 2022 Data Quality
Improvements Proposal, we ultimately determined that acetylene is not
produced at the one known plant that produces calcium carbide. For this
reason, in the 2023 Supplemental Proposal we did not propose, and as
such are not taking final action on, inclusion of reporting of
CO2 emissions from the production of acetylene from calcium
carbide under subpart XX.
b. Reporting Threshold
In the 2023 Supplemental Proposal, the EPA proposed no threshold
for reporting under subpart XX. The current estimate of emissions from
the single known calcium carbide production facility in the United
States exceeds 25,000 mtCO2e by a factor of about 1.9.
Therefore we are finalizing, as proposed, the calcium carbide source
category as an ``all-in'' subpart. For a full discussion of the
threshold analysis, please refer to section IV.C. of the preamble to
the 2023 Supplemental Proposal.
c. Calculation Methods
In the 2023 Supplemental Proposal, the EPA reviewed the production
processes and available emissions estimation methods for calcium
carbide production including a default emission factor methodology, a
carbon balance methodology (IPCC Tier 3), and direct measurement using
CEMS (see section IV.C.5. of the preamble to the 2023 Supplemental
Proposal). We subsequently proposed and are finalizing two different
methods for quantifying GHG emissions from calcium carbide
manufacturing, depending on current emissions monitoring at the
facility. If a qualified CEMS is in place, the CEMS must be used.
Otherwise, the facility can elect to either install a CEMS or elect to
use the carbon mass balance method.
Direct measurement using CEMS. Facilities with an existing CEMS
that meet the requirements outlined in subpart C of part 98 (General
Stationary Fuel Combustion) are required to use CEMS to estimate
combined process and combustion CO2 emissions. Facilities
are required to follow the requirements of subpart C to estimate all
CO2 emissions from the industrial source. Facilities will be
required to follow subpart C to estimate emissions of CO2,
CH4, and N2O from stationary combustion.
Carbon balance method. For facilities that do not have CEMS that
meet the requirements of 40 CFR part 98 subpart C, the alternate
monitoring method is the carbon balance method. For any stationary
combustion units included at the facility, facilities will be required
to follow the existing requirements at 40 CFR part 98, subpart C to
estimate emissions of CO2, CH4, and
N2O from stationary combustion. Use of facility specific
information is consistent with IPCC Tier 3 methods and is the preferred
method for estimating emissions for other GHGRP sectors.
d. Monitoring, QA/QC, and Verification requirements
The EPA is finalizing the monitoring, QA/QC, and verification
requirements to subpart XX as proposed. We are finalizing two separate
monitoring methods: direct measurement and a mass balance emission
calculation.
Direct measurement using CEMS. For facilities where process
emissions and/or combustion GHG emissions are contained within a stack
or vent, facilities can take direct measurement of the GHG
concentration in the stack gas and the flow rate of the stack gas using
a CEMS. Under the final rule, if facilities use an existing CEMS to
meet the monitoring requirements, they are required to use CEMS to
estimate CO2 emissions. Where the CEMS capture all
combustion- and process-related CO2 emissions, facilities
will be required to follow the requirements of subpart C to estimate
emissions.
The CEMS method requires both a continuous CO2
concentration monitor and a continuous volumetric flow monitor. To
qualify as a CEMS, the monitors are required to be installed, operated,
and calibrated according to subpart C of part 98 (40 CFR 98.33(a)(4)),
which is consistent with CEMS requirements in other GHGRP subparts.
Carbon balance method. For facilities using the carbon mass balance
method, we are requiring the facility to determine the annual mass for
each material used for the calculations of annual process
CO2 emissions by summing the monthly mass for the material
determined for each month of the calendar year. The monthly mass may be
determined using plant instruments used for accounting purposes,
including either direct measurement of the quantity of the material
placed in the unit or by calculations using process operating
information.
For the carbon content of the materials used to calculate process
CO2 emissions, we are finalizing a requirement that the
owner or operator determine the carbon content using material supplier
information or collect and analyze at least three representative
samples of the material inputs and outputs each year. The final rule
will require the carbon content be analyzed at least annually using
standard ASTM methods, including their QA/QC procedures. To reduce
burden, if a specific process input or output contributes less than one
percent of the total mass of carbon into or out of the process, the
reporter does not have to determine the monthly mass or annual carbon
content of that input or output.
e. Procedures for Estimating Missing Data
We are finalizing as proposed the use of substitute data whenever a
quality-assured value of a parameter is used to calculate emissions is
unavailable, or ``missing.'' If the carbon content analysis of carbon
inputs or outputs is missing, the substitute data value will be based
on collected and analyzed representative samples for average carbon
contents. If the monthly mass of carbon-containing inputs and outputs
is missing, the substitute data value will be based on the best
available estimate of the mass of the inputs and outputs from all
available process data or data used for accounting purposes, such as
purchase records. The likelihood for missing process input or output
data is low, as businesses closely track their purchase of production
inputs. These missing data procedures are the same as those for the
ferroalloy production source category, subpart K of part 98, under
which the existing U.S. calcium carbide production facility currently
reports.
f. Data Reporting Requirements
The EPA is finalizing, as proposed, that each carbon carbide
production facility report the annual CO2 emissions
[[Page 31870]]
from each calcium carbide production process, as well as any stationary
fuel combustion emissions. In addition, we are finalizing requirements
for facilities to provide additional information that forms the basis
of the emissions estimates, along with supplemental data, so that we
can understand and verify the reported emissions. All calcium carbide
production facilities will be required to report their annual
production and production capacity, total number of calcium carbide
production process units, annual consumption of petroleum coke, each
end use of any calcium carbide produced and sent off site, and, if the
facility produces acetylene, the annual production of acetylene, the
quantity of calcium carbide used for acetylene production at the
facility, and the end use of the acetylene produced on-site. The EPA is
also finalizing reporting the end use of calcium carbide sent off site,
as well as acetylene production information for current or future
calcium carbide production facilities, to inform future Agency policy
under the CAA.
As proposed, we are finalizing requirements that if a facility uses
CEMS to measure their CO2 emissions, they will be required
to also report the identification number of each process unit; the EPA
is clarifying in the final rule that if a facility uses CEMS, emissions
are reported from each CEMS monitoring location. If a CEMS is not used
to measure CO2 emissions, the facility will also report the
method used to determine the carbon content of each material for each
process unit, how missing data were determined, and the number of
months missing data procedures were used.
g. Records That Must Be Retained
The EPA is finalizing as proposed the requirement that facilities
maintain records of information used to determine the reported GHG
emissions, to allow us to verify that GHG emissions monitoring and
calculations were done correctly. If a facility uses a CEMS to measure
their CO2 emissions, they will be required to record the
monthly calcium carbide production from each process unit and the
number of monthly and annual operating hours for each process unit. If
a CEMS is not used, the facility will be required to retain records of
monthly production, monthly and annual operating hours, monthly
quantities of each material consumed or produced, and carbon content
determinations.
As proposed, we are finalizing requirements that the owner or
operator maintain records of how measurements are made, including
measurements of quantities of materials used or produced and the carbon
content of process input and output materials. The procedures for
ensuring accuracy of measurement methods, including calibration, must
be recorded.
The final rule also requires the retention of a record of the file
generated by the verification software specified in 40 CFR 98.5(b)
including:
Carbon content (percent by weight expressed as a decimal
fraction) of the reducing agent (petroleum coke), carbon electrode,
product produced, and nonproduct outgoing materials; and
Annual mass (tons) of the reducing agent (petroleum coke),
carbon electrode, product produced, and nonproduct outgoing materials.
2. Summary of Comments and Responses on Subpart XX
The EPA previously requested comment on the addition of a calcium
carbide source category as a new subpart to part 98 in the 2022 Data
Quality Improvements Proposal. The EPA received one comment objecting
to the addition of the proposed source category and one comment on the
potential calculation methodology. Subsequently, the EPA responded to
the comments and proposed to add new subpart XX for calcium carbide
(see section IV.C. of the preamble to the 2023 Supplemental Proposal).
The EPA received no comments regarding proposed subpart XX following
the 2023 Supplemental Proposal. See the document ``Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of
all comments and responses related to subpart XX.
DD. Subpart YY--Caprolactam, Glyoxal, and Glyoxylic Acid Production
We are finalizing the addition of subpart YY (Caprolactam, Glyoxal,
and Glyoxylic Acid Production) to part 98 with revisions in some cases.
Section III.DD.1. of this preamble discusses the final requirements of
subpart YY. Major comments, as applicable, are addressed in section
III.DD.2. of this preamble. We are also finalizing as proposed related
confidentiality determinations for data elements resulting from the
revisions to subpart YY as described in section VI. of this preamble.
1. Summary of Final Amendments to Subpart YY
This section summarizes the substantive final amendments to subpart
YY. Major changes to the final rule as compared to the proposed
revisions are identified in this section. The rationale for these and
any other changes to 40 CFR part 98, subpart YY can be found in this
section. Additional rationale for these amendments is available in the
preamble to the 2022 Data Quality Improvements Proposal and 2023
Supplemental Proposal.
a. Source Category Definition
In the 2023 Supplemental Proposal, the EPA proposed that the
caprolactam, glyoxal, or glyoxylic acid source category, as defined
under subpart YY, would include any facility that produces caprolactam,
glyoxal, or glyoxylic acid.
Caprolactam is a crystalline solid organic compound with a wide
variety of uses, including brush bristles, textile stiffeners, film
coatings, synthetic leather, plastics, plasticizers, paint vehicles,
cross-linking for polyurethanes, and in the synthesis of lysine.
Caprolactam is primarily used in the manufacture of synthetic fibers,
especially Nylon 6.
Glyoxal is a solid organic compound with a wide variety of uses,
including as a crosslinking agent in various polymers for paper
coatings, textile finishes, adhesives, leather tanning, cosmetics, and
oil-drilling fluids; as a sulfur scavenger in natural gas sweetening
processes; as a biocide in water treatment; to improve moisture
resistance in wood treatment; and as a chemical intermediate in the
production of pharmaceuticals, dyestuffs, glyoxylic acid, and other
chemicals. It is also used as a less toxic substitute for formaldehyde
in some applications (e.g., in wood adhesives and embalming fluids).
Glyoxylic acid is a solid organic compound exclusively produced by
the oxidation of glyoxal with nitric acid. It is used mainly in the
synthesis of vanillin, allantoin, and several antibiotics like
amoxicillin, ampicillin, and the fungicide azoxystrobin.
We are finalizing the source category definition to include any
facility that produces caprolactam, glyoxal, or glyoxylic acid as
proposed. The source category will exclude the production of glyoxal
through the LaPorte process (i.e., the gas-phase catalytic oxidation of
ethylene glycol with air in the presence of a silver or copper
catalyst). As explained in the 2023 Supplemental Proposal, the LaPorte
process does not
[[Page 31871]]
emit N2O and there are no methods for estimating
CO2 in available literature.
b. Reporting Threshold
In the 2023 Supplemental Proposal, the EPA proposed no threshold
for reporting under subpart YY (i.e., that subpart YY would be an
``all-in'' reporting subpart). The EPA noted that the total process
emissions from current production of caprolactam, glyoxal, and
glyoxylic acid are estimated at 1.2 million mtCO2e, largely
from two known caprolactam production facilities; although the known
universe of facilities that produce caprolactam, glyoxal, and glyoxylic
acid in the United States is four to six total facilities. We proposed
that adding caprolactam, glyoxal, and glyoxylic acid production as an
``all-in'' subpart (i.e., regardless of the facility emissions profile)
is a conservative approach to gather information from as many
facilities that produce caprolactam, glyoxal, and glyoxylic acid as
possible, especially if production of glyoxal and glyoxylic acid
increase in the near future. The EPA is finalizing these requirements
as proposed.
c. Calculation Methods
In the 2023 Supplemental Proposal, the EPA reviewed the production
processes and available emissions estimation methods for caprolactam,
glyoxal, and glyoxylic acid production and proposed that only
N2O emissions would be estimated from these processes. The
EPA also proposed to require the reporting of combustion emissions from
facilities that produce caprolactam, glyoxal, and glyoxylic acid,
including CO2, CH4, and N2O.
The EPA reviewed two methods from the 2006 IPCC Guidelines,\43\
including the Tier 2 and Tier 3 methodologies, for calculating
N2O emissions from the production of caprolactam, glyoxal,
and glyoxylic acid, and subsequently proposed the IPCC Tier 2 approach
to quantify N2O process emissions. We are finalizing the
N2O calculation requirements as proposed, with minor
revisions. Following the Tier 2 approach established by the IPCC,
reporters will apply default N2O generation factors on a
site-specific basis. This requires raw material input to be known in
addition to a standard N2O generation factor, which differs
for each of the three chemicals. In addition, Tier 2 requires site-
specific knowledge of the use of N2O control technologies.
The volume or mass of each product is measured with a flow meter or
weigh scales. The process-related N2O emissions are
estimated by multiplying the generation factor by the production and
the destruction efficiency of any N2O control technology.
The EPA is revising the final rule to adjust the N2O
generation factors (proposed in table 1 to subpart YY) for glyoxal and
glyoxylic acid production to correctly reflect the conversion of the
IPCC default emission factors, which were intended to be converted from
metric tons N2O emitted per metric ton of product produced
to kg N2O per metric ton of product produced using a
conversion factor of 1,000 kg per metric ton. The final rule corrects
the generation factor for glyoxal from 5,200 to 520 and, for glyoxylic
acid, from 1,000 to 100. The EPA is finalizing a minor clarification to
equation 1 to 40 CFR 98.513(d)(2) (proposed as equation YY-1) to re-
order the defined parameters of the equation to follow their order of
appearance in the equation. The EPA is also finalizing an additional
equation (equation 3 to 40 CFR 98.513(f)) from the proposed rule, which
sums the monthly process emissions estimated by equation 2 to 40 CFR
98.513(e) (proposed as equation YY-2) to an annual value. This
additional equation clarifies the methodology for reporting annual
emissions and does not require the collection of any additional data.
---------------------------------------------------------------------------
\43\ IPCC 2006. IPCC Guidelines for National Greenhouse Gas
Inventories, Volume 3, Industrial Processes and Product Use. Chapter
3, Chemical Industry Emissions. 2006. www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_3_Ch3_Chemical_Industry.pdf.
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For any stationary combustion units included at the facility, we
proposed that facilities would be required to follow the existing
requirements in 40 CFR part 98, subpart C to calculate emissions of
CO2, CH4 and N2O from stationary
combustion. We are finalizing the combustion calculation requirements
as proposed.
d. Monitoring, QA/QC, and Verification Requirements
Monitoring is required to comply with the N2O
calculation methodologies for reporters that produce caprolactam,
glyoxal, and glyoxylic acid. In the 2023 Supplemental Proposal, the EPA
proposed that reporters that produce caprolactam, glyoxal, and
glyoxylic acid are to determine the monthly and annual production
quantities of each chemical and to determine the N2O
destruction efficiency of any N2O abatement technologies in
use. The EPA is finalizing as proposed the requirement for reporters to
either perform direct measurement of production quantities or to use
existing plant procedures to determine production quantities. E.g., the
production rate can be determined through sales records or by direct
measurement using flow meters or weigh scales.
For determination of the N2O destruction efficiency, we
are finalizing as proposed the requirement that reporters estimate the
destruction efficiency for each N2O abatement technology.
The destruction efficiency can be determined by using the
manufacturer's specific destruction efficiency or estimating the
destruction efficiency through process knowledge. Documentation of how
process knowledge was used to estimate the destruction efficiency is
required. Examples of information that could constitute process
knowledge include calculations based on material balances, process
stoichiometry, or previous test results provided that the results are
still relevant to the current vent stream conditions.
For the caprolactam, glyoxal, and glyoxylic acid production
subpart, we are requiring reporters to perform all applicable flow
meter calibration and accuracy requirements and maintain documentation
as specified in 40 CFR 98.3(i).
e. Procedures for Estimating Missing Data
For caprolactam, glyoxal, and glyoxylic acid production, the EPA is
finalizing as proposed the requirement that substitute data for each
missing production value is the best available estimate based on all
available process data or data used for accounting purposes (such as
sales records). For the control device destruction efficiency, assuming
that the control device operation is generally consistent from year to
year, the substitute data value should be the most recent quality
assured value.
f. Data Reporting Requirements
The EPA is finalizing, as proposed, that facilities must report
annual N2O emissions (in metric tons) from each production
line. In addition, facilities must submit the following data to
facilitate understanding of the emissions data and verify the
reasonableness of the reported emissions: number of process lines;
annual production capacity; annual production; number of operating
hours in the calendar year for each process line; abatement technology
used and installation dates (if applicable); abatement utilization
factor for each process line; number of times in the reporting year
that missing data procedures were followed to measure production
quantities of caprolactam, glyoxal, or glyoxylic acid (months); and
[[Page 31872]]
overall percent N2O reduction for each chemical for all
process lines.
g. Records That Must Be Retained
The EPA is finalizing as proposed the requirement that facilities
maintain records documenting the procedures used to ensure the accuracy
of the measurements of all reported parameters, including but not
limited to, calibration of weighing equipment, flow meters, and other
measurement devices. The estimated accuracy of measurements made with
these devices must also be recorded, and the technical basis for these
estimates must be provided. We are also requiring, as proposed, that
facilities maintain records documenting the estimate of production rate
and abatement technology destruction efficiency through accounting
procedures and process knowledge, respectively.
Finally, the EPA is also requiring, as proposed, the retention of a
record of the file generated by the verification software specified in
40 CFR 98.5(b) including:
Monthly production quantities of caprolactam from all
process lines;
Monthly production quantities of glyoxal from all process
lines; and
Monthly production quantities of glyoxylic acid from all
process lines.
We are revising the final rule to clarify that these monthly
production quantities must be supplied in metric tons and for each
process line. Additionally, we are adding a requirement that facilities
maintain records of the destruction efficiency of the N2O
abatement technology from each process line, consistent with
requirements of equation 2 to 40 CFR 98.513(e). Facilities will enter
this information into EPA's electronic verification software in order
to ensure proper verification of the reported emission values.
Following electronic verification, facilities will be required to
retain a record of the file generated by the verification software
specified in 40 CFR 98.5(b), therefore, no additional burden is
anticipated.
2. Summary of Comments and Responses on Subpart YY
The EPA previously requested comment on the addition of a
caprolactam, glyoxal, and glyoxylic acid production source category as
a new subpart to part 98 in the 2022 Data Quality Improvements
Proposal. The EPA received no comments regarding the addition of the
proposed source category. Subsequently, the EPA proposed to add new
subpart YY for caprolactam, glyoxal, and glyoxylic acid production (see
section IV.D. of the preamble to the 2023 Supplemental Proposal). The
EPA received no comments regarding proposed subpart YY following the
2023 Supplemental Proposal.
EE. Subpart ZZ--Ceramics Manufacturing
We are finalizing the addition of subpart ZZ of part 98 (Ceramics
Manufacturing) with revisions in some cases. Section III.EE.1. of this
preamble discusses the final requirements of subpart ZZ. The EPA
received a number of comments on the proposed subpart ZZ which are
discussed in section III.EE.2. of this preamble. We are also finalizing
as proposed related confidentiality determinations for data elements
resulting from the addition of subpart ZZ as described in section VI.
of this preamble.
1. Summary of Final Amendments to Subpart ZZ
This section summarizes the final amendments to subpart ZZ. Major
changes to the final rule as compared to the proposed revisions are
identified in this section. The rationale for these and any other
changes to 40 CFR part 98, subpart ZZ can be found in section III.EE.2.
of this preamble. Additional rationale for these amendments is
available in the preamble to the 2022 Data Quality Improvements
Proposal and 2023 Supplemental Proposal.
a. Source Category Definition
In the 2023 Supplemental Proposal, the EPA defined the ceramics
manufacturing source category as any facility that uses nonmetallic,
inorganic materials, many of which are clay-based, to produce ceramic
products such as bricks and roof tiles, wall and floor tiles, table and
ornamental ware (household ceramics), sanitary ware, refractory
products, vitrified clay pipes, expanded clay products, inorganic
bonded abrasives, and technical ceramics (e.g., aerospace, automotive,
electronic, or biomedical applications).
The EPA also proposed that the ceramics source category would apply
to facilities that annually consume at least 2,000 tons of carbonates
or 20,000 tons of clay heated to a temperature sufficient to allow the
calcination reaction to occur, and operate a ceramics manufacturing
process unit. The proposed definition of ceramics manufacturers as
facilities that use at least the minimum quantity of carbonates or clay
(2,000 tons/20,000 tons) was considered consistent with subpart U of
part 98 (Miscellaneous Uses of Carbonate). This minimum 2,000 tons of
carbonate use was added to subpart U in the 2009 Final Rule based on
comments received on the April 10, 2009 proposed rule (74 FR 16448),
where commenters requested a carbonate use threshold of 2,000 tons in
order to exempt small operations and activities which use carbonates in
trace quantities. The proposed source category definition for ceramics
manufacturing in the 2023 Supplemental Proposal established a minimum
production level as a means to exclude and thus reduce the reporting
burden for small artisan-level ceramics manufacturing processes. We
defined a ceramics manufacturing process unit as a kiln, dryer, or oven
used to calcine clay or other carbonate-based materials for the
production of a ceramics product.
The EPA is finalizing the definition of the source category with
one change. We are revising the minimum production level in the
definition from ``at least 2,000 tons of carbonates or 20,000 tons of
clay which is heated to a temperature sufficient to allow the
calcination reaction to occur'' to ``at least 2,000 tons of carbonates,
either as raw materials or as a constituent in clay, which is heated to
a temperature sufficient to allow the calcination reaction to occur.''
These final revisions focus the production level on the carbonates
contained within the raw material rather than the total tons of clay;
the final revisions will provide a more accurate means of assessing
applicability. Facilities will be required to estimate their carbonate
usage using available records to determine applicability. For example,
facilities that use clay as a raw material input could calculate
whether they meet the carbonate use threshold by multiplying the amount
of clay they consume (and heat to calcination) annually by the weight
fraction of carbonates contained in the clay. These final revisions add
two harmonizing edits to 40 CFR 98.523(b)(1) and 98.526(c)(2) to
clarify that the carbonate-based raw materials include clay.
b. Reporting Threshold
In the 2023 Supplemental Proposal, the EPA proposed that facilities
must report under subpart ZZ if they met the definition of the source
category and if their estimated combined emissions (including from
stationary combustion and all applicable source categories) exceed a
25,000 mtCO2e threshold. We are finalizing the threshold as
proposed. The final definition of ceramics manufacturers as facilities
that use at least the minimum quantity of carbonates (2,000 tons,
either as raw materials or as a constituent in clay) and
[[Page 31873]]
the 25,000 mtCO2e threshold are both expected to ensure that
small ceramics manufacturers are excluded. It is estimated that over 25
facilities will meet the definition of a ceramics manufacturer and the
threshold of 25,000 mtCO2e for reporting. For a full
discussion of this analysis, section IV.E. of the preamble to the 2023
Supplemental Proposal.
c. Calculation Methods
In the 2023 Supplemental Proposal, the EPA reviewed the production
processes and available emissions estimation methods for ceramics
manufacturing and proposed that only CO2 emissions would be
estimated from these processes. The EPA also proposed to require the
reporting of combustion emissions, including CO2,
CH4, and N2O from the ceramics manufacturing unit
and other combustion sources on site.
In the 2023 Supplemental Proposal, the EPA reviewed the production
processes and available emissions estimation methods for ceramics
manufacturing including a basic mass balance methodology that assumed a
fixed percentage for carbonates consumed (IPCC Tier 1), a carbon
balance methodology (IPCC Tier 3) based on carbon content and the mass
of materials input, and direct measurement using CEMS (see section
IV.C.5. of the preamble to the 2023 Supplemental Proposal). We are
finalizing, as proposed, two different methods for quantifying GHG
emissions from ceramics manufacturing, depending on current emissions
monitoring at the facility. If a qualified CEMS is in place, the CEMS
must be used. Otherwise, the facility can elect to either install a
CEMS or elect to use the carbon mass balance method.
Direct measurement using CEMS. Facilities with a CEMS that meet the
requirements in subpart C of part 98 (General Stationary Fuel
Combustion) will be required to use CEMS to estimate the combined
process and combustion CO2 emissions. The CEMS measures
CO2 concentration and total exhaust gas flow rate for the
combined process and combustion source emissions. CO2 mass
emissions will be calculated from these measured values using equation
C-6 and, if necessary, equation C-7 in 40 CFR 98.33(a)(4). The combined
process and combustion CO2 emissions will be calculated
according to the Tier 4 Calculation Methodology specified in 40 CFR
98.33(a)(4). Facilities will be required to use subpart C to estimate
emissions of CO2, CH4, and N2O from
stationary combustion.
Carbon balance method. For facilities using carbon mass balance
method, the carbon content and the mass of carbonaceous materials input
to the process must be determined. The facility must measure the
consumption of specific process inputs and the amounts of these
materials consumed by end-use/product type. Carbon contents of
materials must be determined through the analysis of samples of the
material or from information provided by the material suppliers.
Additionally, the quantities of materials consumed and produced during
production must be measured and recorded. CO2 emissions are
estimated by multiplying the carbon content of each raw material by the
corresponding mass, by a carbonate emission factor, and by the decimal
fraction of calcination achieved for that raw material. We are
finalizing the carbonate emission factors provided in table 1 to
subpart ZZ of part 98 as proposed. These factors, pulled from table N-1
to subpart N of part 98, and from Table 2.1 of the 2006 IPCC
Guidelines,\44\ are based on stoichiometric ratios and represent the
weighted average of the emission factors for each particular carbonate.
Emission factors provided by the carbonate vendor for other minerals
not listed in table 1 to subpart ZZ may also be used.
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\44\ IPCC Guidelines for National Greenhouse Gas Inventories,
Volume 3, Industrial Processes and Product Use, Mineral Industry
Emissions. 2006. https://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_2_Ch2_Mineral_Industry.pdf.
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For any stationary combustion units included at the facility,
facilities will be required to follow subpart C to estimate emissions
of CO2, CH4, and N2O from stationary
combustion. Use of facility specific information under the carbon mass
balance method is consistent with IPCC Tier 3 methods and is the
preferred method for estimating emissions for other GHGRP sectors.
d. Monitoring, QA/QC, and Verification Requirements
The EPA is finalizing, as proposed, two separate monitoring
methods: direct measurement and a mass balance emission calculation.
Direct measurement using CEMS. We are finalizing the CEMS
monitoring requirements as proposed. In the case of ceramics
manufacturing, process and combustion GHG emissions from ceramics
process units are typically emitted from the same stack. If facilities
use an existing CEMS to meet the monitoring requirements, they will be
required to use CEMS to estimate CO2 emissions. Where the
CEMS capture all combustion- and process-related CO2
emissions, facilities will be required to follow the requirements of
subpart C of part 98 to estimate all CO2 emissions from the
industrial source. The CEMS method requires both a continuous
CO2 concentration monitor and a continuous volumetric flow
monitor. To qualify as a CEMS, the monitors will be required to be
installed, operated, and calibrated according to subpart C of part 98
(40 CFR 98.33(a)(4)), which is consistent with CEMS requirements in
other GHGRP subparts.
Carbon balance method. We are finalizing the carbon mass balance
method as proposed, with one change. The carbon mass balance method
requires monitoring of mass quantities of carbonate-based raw material
(e.g., clay) fed to the process, establishing the mass fraction of
carbonate-based minerals in the raw material, and an emission factor
based on the type of carbonate consumed. The mass quantities of
carbonate-based raw materials consumed by each ceramics process unit
can be determined using direct weight measurement of plant instruments
or techniques used for accounting purposes, such as calibrated scales,
weigh hoppers, or weigh belt feeders. The direct weight measurement can
then be compared to records of raw material purchases for the year.
For the carbon content of the materials used to calculate process
CO2 emissions, the final rule requires that the owner or
operator determine the carbon mass fraction either by using information
provided by the raw material supplier, by collecting and sending
representative samples of each carbonate-based material consumed to an
off-site laboratory for a chemical analysis of the carbonate content
(weight fraction), or by choosing to use the default value of 1.0. The
use of 1.0 for the mass fraction assumes that the carbonate-based raw
material comprises 100 percent of one carbonate-based mineral. We are
revising the final rule to also state that where it is determined that
the mass fraction of a carbonate-based raw material is below the
detection limit of available testing standards, the facility must
assume a default of 0.005 for that material.
We are revising the final rule to allow facilities that determine
the carbonate-based mineral mass fractions of a carbonate-based
material to use additional sampling and chemical analysis methods to
provide additional flexibility for facilities. Specifically, we are
revising 40 CFR 98.524(b) from requiring sampling and chemical analysis
using consensus standards that specify x-ray fluorescence to requiring
that facilities use an ``x-ray fluorescence test, x-ray diffraction
test, or other enhanced testing method published by an industry
consensus standards
[[Page 31874]]
organization'' (e.g., ASTM, American Society of Mechanical Engineers
(ASME), American Petroleum Institute (API)). The final rule requires
the carbon content be analyzed at least annually to verify the mass
fraction data provided by the supplier of the raw material.
For the ceramics manufacturing source category, we are finalizing
the QA/QC requirements as proposed. Reporters must calibrate all meters
or monitors and maintain documentation of this calibration as
documented in subpart A of part 98 (General Provisions). These meters
or monitors should be calibrated prior to the first reporting year,
using a suitable method published by a consensus standards
organization, and will be required to be recalibrated either annually
or at the minimum frequency specified by the manufacturer. In addition,
any flow rate monitors used for direct measurement will be required to
comply with QA/QC procedures for daily calibration drift checks and
quarterly or annual accuracy assessments, such as those provided in
Appendix F to part 60 or similar QA/QC procedures. We are finalizing
these requirements to ensure the quality of the reported GHG emissions
and to be consistent with the current requirements for CEMS
measurements within subparts A (General Provisions) and C of the GHGRP.
For measurements of carbonate content, reporters will assess
representativeness of the carbonate content received from suppliers
with laboratory analysis.
e. Procedures for Estimating Missing Data
We are finalizing the procedures for estimation of missing data as
proposed. The final rule requires the use of substitute data whenever a
quality-assured value of a parameter that is used to calculate
emissions is unavailable, or ``missing.'' For example, if the CEMS
malfunctions during unit operation, the substitute data value would be
the average of the quality-assured values of the parameter immediately
before and immediately after the missing data period. For missing data
on the amounts of carbonate-based raw materials consumed, we are
finalizing that reporters must use the best available estimate based on
all available process data or data used for accounting purposes, such
as purchase records. For missing data on the mass fractions of
carbonate-based minerals in the carbonate-based raw materials,
reporters will assume that the mass fraction of each carbonate-based
mineral is 1.0. The use of 1.0 for the mass fraction assumes that the
carbonate-based raw material comprises 100 percent of one carbonate-
based mineral. Missing data procedures will be applicable for CEMS
measurements, mass measurements of raw material, and carbon content
measurements.
f. Data Reporting Requirements
The EPA is finalizing the data reporting requirements for subpart
ZZ as proposed, with one minor revision. Each ceramics manufacturing
facility must report the annual CO2 process emissions from
each ceramics manufacturing process, as well as any stationary fuel
combustion emissions. In addition, facilities must report additional
information that forms the basis of the emissions estimates so that we
can understand and verify the reported emissions. For ceramic
manufacturers, the additional information will include: the total
number of ceramics process units at the facility and the total number
of units operating; annual production of each ceramics product for each
process unit and for all ceramics process units combined; the annual
production capacity of each ceramics process unit; and the annual
quantity of carbonate-based raw material charged to each ceramics
process unit and for all ceramics process units combined. The EPA has
revised the final rule to clarify at 40 CFR 98.526(c) that facilities
that use the carbon balance method must also report the annual quantity
of each carbonate-based raw material (including clay) charged to each
ceramics process unit. This change is consistent with the requirements
the EPA proposed for facilities conducting direct measurement using
CEMS, and is not anticipated to substantively impact the burden to
reporters as proposed. For ceramic manufacturers with non-CEMS units,
the finalized rules will also require reporting of the following
information: the method used for the determination for each carbon-
based mineral in each raw material; applicable test results used to
verify the carbonate based mineral mass fraction for each carbonate-
based raw material charged to a ceramics process unit, including the
date of test and test methods used; and the number of times in the
reporting year that missing data procedures were used.
g. Records That Must Be Retained
The EPA is finalizing the record retention requirements of subpart
ZZ as proposed. All facilities are required to maintain monthly records
of the ceramics manufacturing rate for each ceramics process unit and
the monthly amount of each carbonate-based raw material charged to each
ceramics process unit.
For facilities that use the carbon balance procedure, the final
rule requires facilities to also maintain monthly records of the
carbonate-based mineral mass fraction for each mineral in each
carbonate-based raw material. Additionally, facilities that use the
carbon balance procedure will be required to maintain (1) records of
the supplier-provided mineral mass fractions for all raw materials
consumed annually; (2) results of all analyses used to verify the
mineral mass fraction for each raw material (including the mass
fraction of each sample, the date of test, test methods and method
variations, equipment calibration data, and identifying information for
the laboratory conducting the test); and (3) annual operating hours for
each unit. If facilities use the CEMS procedure, they are required to
maintain the CEMS measurement records.
Procedures for ensuring accuracy of measurement methods, including
calibration, must be recorded. The final rule requires records of how
measurements are made, including measurements of quantities of
materials used or produced and the carbon content of minerals in raw
materials.
Finally, the final rule requires the retention of a record of the
file generated by the verification software specified in 40 CFR 98.5(b)
including:
Annual average decimal mass fraction of each carbonate-
based mineral per carbonate-based raw material for each ceramics
process unit (percent by weight expressed as a decimal fraction);
Annual mass of each carbonate-based raw material charged
to each ceramics process unit (tons); and
The decimal fraction of calcination achieved for each
carbonate-based raw material for each ceramics process unit (percent by
weight expressed as a decimal fraction).
2. Summary of Comments and Responses on Subpart ZZ
This section summarizes the major comments and responses related to
the proposed subpart ZZ. The EPA previously requested comment on the
addition of ceramics manufacturing sources category as a new subpart to
part 98 in the 2022 Data Quality Improvements Proposal. The EPA
received some comments for subpart ZZ on the 2022 Data Quality
Improvements Proposal; the majority of these comments were previously
addressed in the preamble to the 2023 Supplemental Proposal, wherein
the EPA proposed to add new subpart ZZ for ceramics manufacturing (see
section III.E. of the
[[Page 31875]]
preamble to the 2023 Supplemental Proposal). The EPA received
additional comments regarding the proposed subpart ZZ following the
2023 Supplemental Proposal. See the document ``Summary of Public
Comments and Responses for 2024 Final Revisions and Confidentiality
Determinations for Data Elements under the Greenhouse Gas Reporting
Rule'' in Docket ID. No. EPA-HQ-OAR-2019-0424 for a complete listing of
all comments and responses related to subpart ZZ.
Comments: One commenter objected to the EPA's inclusion of the
brick manufacturing industry in proposed subpart ZZ. The commenter
asserted that GHG emissions from the brick industry represent only
about 0.027 percent of U.S. anthropogenic emissions, stating that any
relative improvement in accuracy of emissions would not change the fact
that GHG emissions from brick manufacturing are a very small fraction
of the national total.
The commenter provided a number of reasons to exclude brick
manufacturing from subpart ZZ. First, the commenter contested the EPA's
assumption that all ceramics manufacturing use materials with
significant carbonate content. The commenter stated that the materials
used for the production of brick are low carbonate clay and shale
materials that should not be characterized as ``carbonate-based
materials,'' and that the various processes used to prepare raw
materials and to form and fire brick are such that higher carbonate
materials cannot be used. The commenter added that high carbonate
materials can result in durability problems of the brick, ranging from
cosmetic ``lime pops'' to scenarios where the brick can actually fail
in service. The commenter further stated that the majority production
of brick in the United States is red bodied brick, and therefore the
use of carbonates including limestone are undesirable, due to bleaching
of the red color during firing.
The commenter explained that the EPA's proposal assumes a carbonate
content of 10-15 percent, whereas tested averages for brick making
materials average 0.58 percent. The commenter provided a table of
carbonate brick values based on testing from the NBRC (National Brick
Research Center at Clemson University). The commenter stated that, as
such, the actual brick making carbonate percentages are only about 3.8-
5.8 percent (0.58 percent divided by 10 percent and 15 percent,
respectively) of the carbonate material percentages in the proposed
rule. The commenter estimated that based on this determination, the
inclusion of carbonate process emissions would only increase reported
emissions from a facility by about 2.10 percent, and few, if any,
additional sites not already reporting exceeding the 25,000
mtCO2e reporting threshold would be required to report. The
commenter added that even if facilities do not meet the threshold, the
added requirements would impose on all sites additional testing and
measurement requirements to determine if they exceed the reporting
threshold. The commenter stated that the associated costs do not
justify the requirements.
The commenter stated that a limited number of brickmaking sites add
small amounts of carbonates to some of their products for various
reasons. The commenter explained that some manufacturers add barium
carbonate to the brick body mix to prevent soluble salts from forming
on the final product. In such cases, the commenter noted that barium
carbonate is added typically in the range of 0.05 to 0.1 percent. The
commenter also stated that sodium carbonate (added in the range of 0.5
percent) is sometimes used to improve the uptake of water during the
brick forming process. The commenter asserted that in such cases, if
the additional usages of carbonates are significant, they already would
be reported under subpart U.
The commenter noted that the EPA's existing methods for estimating
GHG emissions from the brick manufacturing industry are good enough to
adequately inform the Agency's policy/regulatory decision making and to
satisfy the EPA's desire and obligation to maintain an accurate
national GHG emissions inventory. The commenter suggested that the EPA
could, in lieu of annual reporting, issue a one-time information
collection request.
Response: The EPA has considered the information provided by the
commenter and is finalizing the addition of the ceramics category to
include the brick industry. Consistent with the other source categories
of 40 CFR part 98, requiring annual reporting of data for ceramics
facilities is preferred to a one-time information collection request.
The collection of annual data will help the EPA to understand changes
in industry emissions and trends over time. The snapshot of information
provided by a one-time information collection request would not provide
the type of ongoing information which could inform potential
legislation or EPA policy. Collecting annual data also allows us to
incorporate accurate time-series emissions changes for the ceramics
industry in the GHG Inventory and other EPA analyses. Further,
including brick manufacturing in the ceramics source category is
consistent with the 2006 IPCC Guidelines for National Greenhouse Gas
Inventories.\45\ While the commenter asserts that brick manufacturing
is a small percentage of the total national GHG emissions, the ceramics
subpart would cover more industries than just brick manufacturing and
is anticipated to cover emissions comparable to other existing
subparts. We have included both an emissions threshold and a carbonate
use threshold in order to exempt small facilities or those with minor
emissions.
---------------------------------------------------------------------------
\45\ IPCC Guidelines for National Greenhouse Gas Inventories,
Volume 3, Industrial Processes and Product Use, Mineral Industry
Emissions. 2006. Prepared by the National Greenhouse Gas Inventories
Programme, Eggleston H.S., Buendia L., Miwa K., Ngara T. and Tanabe
K. (eds). Published: IGES, Japan. www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/3_Volume3/V3_2_Ch2_Mineral_Industry.pdf.
---------------------------------------------------------------------------
Rather than exempting the brick industry from the ceramics subpart
entirely, we have taken the commenter's concerns into account and are
modifying the definition of the source category such that the subpart
``would apply to facilities that annually consume at least 2,000 tons
of carbonates, either as raw materials or as a constituent in clay . .
.''. This is in contrast to the original proposed definition which
included the phrase ``or 20,000 tons of clay.'' This revised carbonate
use threshold will exclude and thus avoid the reporting burden for
facilities that use low annual quantities of carbonates, such as brick
manufacturers that use low-carbonate clay. Facilities could estimate
their carbonate usage to determine their applicability for whether they
meet this carbonate use threshold by multiplying the annual amount of
clay consumed as a raw material (and heated to calcination) by the
weight fraction of carbonates contained in the clay.
Comment: One commenter objected to the proposed measurement
protocols of subpart ZZ and indicated that the methods are infeasible
for brick manufacturing materials. The commenter stated that the
proposal cites ``suitable chemical analysis methods include using an x-
ray fluorescence standard method.'' The commenter asserted that the use
of x-ray fluorescence requires a minimum of at least 2.0 percent of any
single carbonate material to speciate and determine an amount, which is
higher than the total of all carbonates in brick making material, which
the commenter
[[Page 31876]]
provided as 0.58 percent based on testing.
The commenter stated that for brick manufacturing, an alternate
measurement of total carbonates such as ASTM E1915 Standard Test
Methods for Analysis of Metal Bearing Ores and Related Materials for
Carbon, Sulfur, and Acid-Base Characteristics (2020) \46\ and
CO2e calculation would be a necessary option. The commenter
suggested a simpler option would be to develop a default percentage of
carbonate in brickmaking raw materials, or an AP-42, Compilation of Air
Pollutant Emissions Factors type metric allowing a direct calculation
of CO2e emissions per product throughput tonnage. The
commenter contended that this would still yield sufficiently accurate
results and suggested that the historical testing data could be the
basis for this option.
---------------------------------------------------------------------------
\46\ Available at https://www.astm.org/e1915-20.html. Accessed
January 9, 2024.
---------------------------------------------------------------------------
Response: Upon careful review and consideration, the EPA has
considered the information provided by the commenter and will finalize
40 CFR 98.524(b) to allow for other industry standards (i.e., x-ray
fluorescence test, x-ray diffraction test, or other enhanced testing
method published by an industry consensus standards organization (e.g.,
ASTM, ASME, API)) as described in 40 CFR 98.524(d) to allow for the
flexibility of using the most appropriate standard test method.
Furthermore, following consideration of the commenter's recommendation
that the EPA include a default carbonate percentage, we are revising 40
CFR 98.524(b) to include a default value of 0.005 for each carbonate
material where it is determined that the mass fraction is below the
detection limit of available testing standards. The 0.005 value (0.5
percent) is consistent with the example limestone mass fraction that
was provided by the Brick Industry Association.\47\ Furthermore, the
EPA's research into carbonate testing standards revealed that 0.01 (1
percent) is an example detection limit for existing standards (e.g.,
ASTM F3419-22, Standard Test Method for Mineral Characterization of
Equine Surface Materials by X-Ray Diffraction (XRD) Techniques (2022)
\48\). In scientific settings, it is a common practice to assume that a
value of one half the detection limit when concentrations are too low
to accurately measure.
---------------------------------------------------------------------------
\47\ See Docket ID. No. EPA-HQ-OAR-2019-0424-0332 at
www.regulations.gov.
\48\ Available at https://www.astm.org/f3419-22.html. Accessed
January 9, 2024.
---------------------------------------------------------------------------
Comment: One commenter stated that the proposed rule requirements
to report on a unit-by-unit basis instead of facility wide reporting
would impose unnecessary burdens on the brick industry. The commenter
asserted that most activities (natural gas billing, clay hauling
deliveries, material preparation logs, etc.) are done on a per-site
basis. The commenter added that there is no benefit to requiring
reporting to be done on a per unit basis, and a per site basis should
be adequate for determining if emissions exceed the 25,000 metric ton
CO2e reporting threshold.
Response: The EPA routinely collects unit-level capacity data for
process equipment in 40 CFR part 98. These unit-level data are
essential for quantifying actual GHG emissions from the facility (e.g.,
the carbon balance method for estimating emissions relies on the actual
quantities of carbonate-based raw materials charged to the ceramics
process units, not just those delivered to the facility). Furthermore,
we use these data to perform statistical analyses as part of our
verification process, which allows us to develop ranges of expected
emissions by emission source type and successfully identify outliers in
the reported data. We disagree that there will be no benefit to
reporting on a unit-level basis, as this information will improve the
EPA's verification of reported emissions and will provide a more
accurate facility-level and national-level emissions profile for the
industry.
IV. Final Revisions to 40 CFR Part 9
The EPA is finalizing the proposed amendment to 40 CFR part 9 to
include the OMB control number issued under the PRA for the ICR for the
GHGRP. The EPA is amending the table in 40 CFR part 9 to list the OMB
approval number (OMB No. 2060-0629) under which the ICR for activities
in the existing part 98 regulations that were previously approved by
OMB have been consolidated. The EPA received no comments on the
proposed amendments to 40 CFR part 9 and is finalizing the change as
proposed. This codification in the CFR satisfies the display
requirements of the PRA and OMB's implementing regulations at 5 CFR
part 1320.
V. Effective Date of the Final Amendments
As proposed in the 2023 Supplemental Proposal, the final amendments
will become effective on January 1, 2025. As provided under the
existing regulations at 40 CFR 98.3(k), the GWP amendments to table A-1
to subpart A will apply to reports submitted by current reporters that
are submitted in calendar year 2025 and subsequent years (i.e.,
starting with reports submitted for RY2024 on or before March 31,
2025). The revisions to GWPs do not affect the data collection,
monitoring, or calculation methodologies used by these existing
reporters. All other final revisions, which apply to both existing and
new reporters, will be implemented for reports prepared for RY2025 and
submitted March 31, 2026. Reporters who are newly subject to the rule
(facilities that have not previously reported to the GHGRP), either due
to final revisions that change what facilities must report under the
rule (e.g., newly subject to subparts I or P or subparts WW, XX, YY, or
ZZ), or due to the revisions to GWPs in table A-1 to subpart A, will be
required to implement all requirements to collect data, including any
required monitoring and recordkeeping, on January 1, 2025.
This final rule includes new and revised requirements for numerous
provisions under various aspects of GHGRP, including revisions to
applicability and updates to reporting, recordkeeping, and monitoring
requirements. Further, as explained in section I.B. and this section of
this preamble, it amends numerous sections of part 98 for various
specific reasons. Therefore, this final rule is a multifaceted rule
that addresses many separate things for independent reasons, as
detailed in each respective section of this preamble. We intended each
portion of this rule to be severable from each other, though we took
the approach of including all the parts in one rulemaking rather than
promulgating multiple rules to amend each part of the GHGRP. For
example, the following portions of this rulemaking are mutually
severable from each other, as numbered: (1) revisions to General
Provisions, including updates to GWPs in table A-1 to subpart A of part
98 in section III.A.1. of this preamble, (2) revisions to applicability
to subparts G (Ammonia Manufacturing), P (Hydrogen Production), and Y
(Petroleum Refineries) to address non-merchant hydrogen production in
sections III.E., III.I., and III.M.; (3) revisions to applicability to
subparts Y and WW (Coke Calciners) to address stand-alone coke
calcining operations; (4) revisions to subparts PP (Carbon Dioxide
Suppliers) and new subpart VV (Geologic Sequestration of Carbon Dioxide
with Enhanced Oil Recovery Using ISO 27916) in sections III.V. and
III.Z.; (5) revisions to applicability in subparts UU (Injection of
Carbon Dioxide) and subpart VV in sections
[[Page 31877]]
III.Z. and III.AA., (6) other regulatory amendments discussed in
section III. and IV. of this preamble, and (7) confidentiality
determinations as discussed in section VI. of this preamble. Each of
the regulatory amendments in section III. is severable from all the
other regulatory amendments in that section, and each of the
confidentiality determinations in section VI. is also severable from
all the other determinations in that section. If any of the above
portions is set aside by a reviewing court, then we intend the
remainder of this action to remain effective, and the remaining
portions will be able to function absent any of the identified portions
that have been set aside. Moreover, this list is not intended to be
exhaustive, and should not be viewed as an intention by the EPA to
consider other parts of the rule not explicitly listed here as not
severable from other parts of the rule.
VI. Final Confidentiality Determinations
This section provides a summary of the EPA's final confidentiality
determinations and emission data designations for new and substantially
revised data elements included in these final amendments, certain
existing part 98 data elements for which no determination has been
previously established, certain existing part 98 data elements for
which the EPA is amending or clarifying the existing confidentiality
determination, and the EPA's final reporting determinations for inputs
to equations included in the final amendments. This section also
summarizes the major comments and responses related to the proposed
confidentiality determinations, emission data designations, and
reporting determinations for these data elements.
The EPA is not taking final action on any requirements for subpart
W (Petroleum and Natural Gas Systems) in this final rule, therefore, we
are not taking any action on confidentiality determinations or
reporting determinations proposed for data elements in subpart W of
part 98 in the 2022 Data Quality Improvements Proposal. See section
I.C. of this preamble for a discussion of the EPA's actions regarding
subpart W. Additionally, we are not taking any final action on proposed
subpart B (Energy Consumption) in this final rule; therefore we are not
taking any action on confidentiality determinations proposed in the
2023 Supplemental Proposal for subpart B. See section III.B. of this
preamble for additional information on subpart B.
For all remaining data elements included in the 2022 Data Quality
Improvements Proposal or 2023 Supplemental Proposal, this section
identifies any changes to the proposed confidentiality determinations,
emissions data designations, or reporting determinations in the final
rule.
A. EPA's Approach To Assess Data Elements
In the 2022 Data Quality Improvements Proposal and the 2023
Supplemental Proposal, the EPA proposed to assess data elements for
eligibility of confidential treatment using a revised approach, in
response to Food Marketing Institute v. Argus Leader Media, 139 S. Ct.
2356 (2019) (hereafter referred to as Argus Leader).\49\ The EPA
proposed that the Argus Leader decision did not affect our approach to
designating data elements as ``inputs to emission equations'' or our
previous approach for designating new and revised reporting
requirements as ``emission data.'' We proposed to continue identifying
new and revised reporting elements that qualify as ``emission data''
(i.e., data necessary to determine the identity, amount, frequency, or
concentration of the emission emitted by the reporting facilities) by
evaluating the data for assignment to one of the four data categories
designated by the 2011 Final CBI Rule (76 FR 30782, May 26, 2011) to
meet the CAA definition of ``emission data'' in 40 CFR 2.301(a)(2)(i)
(hereafter referred to as ``emission data categories''). Refer to
section II.B. of the July 7, 2010 proposal (75 FR 39094) for
descriptions of each of these data categories and the EPA's rationale
for designating each data category as ``emission data.'' For data
elements designated as ``inputs to emission equations,'' the EPA
maintained the two subcategories, data elements entered into e-GGRT's
Inputs Verification Tool (IVT) and those directly reported to the EPA.
Refer to section VI.C. of the preamble of the 2022 Data Quality
Improvements Proposal for further discussion of ``inputs to emission
equations.''
---------------------------------------------------------------------------
\49\ Available in the docket for this rulemaking (Docket ID. No.
EPA-HQ-OAR-2019-0424).
---------------------------------------------------------------------------
In the 2022 Data Quality Improvements Proposal, for new or revised
data elements that the EPA did not propose to designate as ``emission
data'' or ``inputs to emission equations,'' the EPA proposed a revised
approach for assessing data confidentiality. We proposed to assess each
individual reporting element according to the new Argus Leader
standard. So, we evaluated each data element individually to determine
whether the information is customarily and actually treated as private
by the reporter and proposed a confidentiality determination based on
that evaluation.
The EPA received several comments on its proposed approach in the
2022 Data Quality Improvements Proposal and the 2023 Supplemental
Proposal. The commenters' concerns and the EPA's responses thereto are
provided in the document ``Summary of Public Comments and Responses for
2024 Final Revisions and Confidentiality Determinations for Data
Elements under the Greenhouse Gas Reporting Rule'' in Docket ID. No.
EPA-HQ-OAR-2019-0424. Following consideration of the comments received,
the EPA is not revising this approach and is continuing to assess data
elements for confidentiality determinations as described in the 2022
Data Quality Improvements Proposal and the 2023 Supplemental Proposal.
We are also finalizing the specific confidentiality determinations and
reporting determinations as described in section VI.B. and VI.C. of
this preamble.
B. Final Confidentiality Determinations and Emissions Data Designations
1. Summary of Final Confidentiality Determinations
a. Final Confidentiality Determinations for New and Revised Data
Elements
The EPA is making final confidentiality determinations and emission
data designations for new and substantially revised data elements
included in these final amendments. Substantially revised data elements
include those data elements where the EPA is, in this final action,
substantially revising the data elements as compared to the existing
requirements. Please refer to the preamble to the 2022 Data Quality
Improvements Proposal or the 2023 Supplemental Proposal for additional
information regarding the proposed confidentiality determinations for
these data elements.
For subparts A (General Provisions), C (General Stationary Fuel
Combustion), F (Aluminum Production), G (Ammonia Manufacturing), H
(Cement Production), P (Hydrogen Production), S (Lime Manufacturing),
HH (Municipal Solid Waste Landfills), OO (Suppliers of Industrial
Greenhouse Gases), and QQ (Importers and Exporters of Fluorinated
Greenhouse Gases Contained in Pre-Charged Equipment or Closed-Cell
Foams), the EPA is not finalizing the proposed confidentiality
determinations for certain data elements because the
[[Page 31878]]
EPA is not taking final action on the requirements to report these data
elements at this time (see section III. of this preamble for additional
information). These data elements are listed in table 5 of the
memorandum ``Confidentiality Determinations and Emission Data
Designations for Data Elements in the 2024 Final Revisions to the
Greenhouse Gas Reporting Rule,'' available in the docket to this
rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424.
For subparts C (General Stationary Fuel Combustion) and PP
(Suppliers of Carbon Dioxide), the EPA has revised its final
confidentiality determinations or emissions data designations for
certain data elements from proposal. For subpart PP, following
consideration of public comments, the EPA has revised its final
confidentiality determination for eight data elements that were
proposed as ``Not Eligible'' to ``Eligible for Confidential
Treatment.'' See section VI.B.2. of this preamble for a summary of the
related comments and the EPA's response. For subpart C, we identified
two revised data elements where the EPA had inadvertently proposed to
place the revised version of the data elements into a different
emissions data category than the existing version of the data elements
(i.e., proposed moving the data elements from one category of emissions
data into a different category of emissions data). The EPA has
corrected the placement of these data elements from ``Facility and Unit
Identifier Information'' to ``Emissions.'' Table 6 of this preamble
lists the data elements where the EPA has revised its final
confidentiality determinations or emissions data designations as
compared to the 2022 Data Quality Improvements Proposal.
Table 6--Data Elements for Which the EPA Is Revising the Final Confidentiality Determinations or Emission Data
Designations
----------------------------------------------------------------------------------------------------------------
Subpart Citation in 40 CFR part 98 Data element description
----------------------------------------------------------------------------------------------------------------
C \1\............................ 98.36(c)(1)(vi)............................ When reporting using aggregation
of units, if any of the
stationary fuel combustion
units burn biomass, the annual
CO2 emissions from combustion
of all biomass fuels combined
(metric tons).
C \1\............................ 98.36(c)(3)(vi)............................ When reporting using the common
pipe configuration, if any of
the stationary fuel combustion
units burn biomass, the annual
CO2 emissions from combustion
of all biomass fuels combined
(metric tons).
PP \2\........................... 98.426(i)(1)............................... If you capture a CO2 stream at a
facility with a direct air
capture (DAC) process unit and
electricity (excluding combined
heat and power (CHP)) is
provided to a dedicated meter
for the DAC process unit:
annual quantity of electricity
(generated on-site or off-site)
consumed for the DAC process
unit (MWh).
PP \2\........................... 98.426(i)(1)(i)(C)......................... If you capture a CO2 stream at a
facility with a DAC process
unit and electricity (excluding
CHP) is provided to a dedicated
meter for the DAC process unit:
if the electricity is sourced
from a grid connection, the
name of the electric utility
company that supplied the
electricity as shown on the
last monthly bill issued by the
utility company during the
reporting period.
PP \2\........................... 98.426(i)(1)(i)(D)......................... If you capture a CO2 stream at a
facility with a DAC process
unit and electricity (excluding
CHP) is provided to a dedicated
meter for the DAC process unit:
if the electricity is sourced
from a grid connection, the
name of the electric utility
company that delivered the
electricity.
PP \2\........................... 98.426(i)(1)(i)(E)......................... If you capture a CO2 stream at a
facility with a DAC process
unit and electricity (excluding
CHP) is provided to a dedicated
meter for the DAC process unit:
if the electricity is sourced
from a grid connection, the
annual quantity of electricity
consumed for the DAC process
unit (MWh).
PP \2\........................... 98.426(i)(1)(ii)........................... If you capture a CO2 stream at a
facility with a DAC process
unit and electricity (excluding
CHP) is provided to a dedicated
meter for the DAC process unit:
if electricity is sourced from
on-site or through a
contractual mechanism for
dedicated off-site generation,
the annual quantity of
electricity consumed per
applicable source (MWh), if
known.
PP \2\........................... 98.426(i)(2)............................... If you capture a CO2 stream at a
facility with a DAC process
unit and you use heat, steam,
or other forms of thermal
energy (excluding CHP) for the
DAC process unit: the annual
quantity of heat, steam, or
other forms of thermal energy
sourced from on-site or through
a contractual mechanism for
dedicated off-site generation
per applicable energy source
(MJ), if known.
PP \2\........................... 98.426(i)(3)(i)............................ If you capture a CO2 stream at a
facility with a DAC process
unit and electricity from CHP
is sourced from on-site or
through a contractual mechanism
for dedicated off-site
generation: the annual quantity
of electricity consumed for the
DAC process unit per applicable
energy source (MWh), if known.
PP \2\........................... 98.426(i)(3)(ii)........................... If you capture a CO2 stream at a
facility with a DAC process
unit and you use heat from CHP
for the DAC process unit: the
annual quantity of heat, steam,
or other forms of thermal
energy from CHP sourced from on-
site or through a contractual
mechanism for dedicated off-
site generation per applicable
energy source (MJ), if known.
----------------------------------------------------------------------------------------------------------------
\1\ In the May 26, 2011, final rule (76 FR 30782), this data element was assigned to the ``Emissions Data'' data
category and determined to be ``Emissions Data.'' In the 2022 Data Quality Improvements Proposal, the data
element was significantly revised, and the EPA proposed that the revised data element would be assigned to the
data category ``Facility and Unit Identifier'' and would have a determination of ``Emissions Data.'' We have
subsequently determined that the revisions to the data element (revising the language ``if any units burn both
fossil fuels and biomass'' with ``if any of the units burn biomass'') is a clarifying change and that the data
element was incorrectly assigned to a new data category. Therefore we are finalizing the revised data element
in the ``Emissions Data'' data category and determining that it is ``Emissions Data.''
\2\ Revised from ``Not Eligible'' to ``Eligible for Confidential Treatment''; see section VI.B.2. of this
preamble.
For subparts I (Electronics Manufacturing), P (Hydrogen
Production), and ZZ (Ceramics Manufacturing), the EPA is finalizing
revisions that include new data elements for which the EPA did not
propose a determination. These data elements are listed in table 7 of
this preamble and table 6 of the memorandum, ``Confidentiality
Determinations and Emission Data Designations for Data Elements in the
2024 Final Revisions to the Greenhouse Gas Reporting Rule,'' available
in the docket to this rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424.
Because the EPA has not proposed or solicited public comment on a
determination for
[[Page 31879]]
these data elements, we are not finalizing confidentiality
determinations for these data elements at this time.
Table 7--New Data Elements From Proposal to Final for Which the EPA Is Not Finalizing Confidentiality
Determinations or Emission Data Designations
----------------------------------------------------------------------------------------------------------------
Subpart Citation in 40 CFR part 98 Data element description
----------------------------------------------------------------------------------------------------------------
I................................ 98.96(y)(2)(iv)............................ For electronics manufacturing
facilities, for the technology
assessment report required
under 40 CFR 98.96(y), for any
destruction or removal
efficiency data submitted, if
you choose to use an additional
alternative calculation
methodology to calculate and
report the input gas emission
factors and by-product
formation rates: a complete,
mathematical description of the
alternative method used
(including the equation used to
calculate each reported
utilization and by-product
formation rate).
P................................ 98.166(d)(10).............................. For each hydrogen production
process unit, an indication
(yes or no) if best available
monitoring methods used in
accordance with 40 CFR
98.164(c) to determine fuel
flow for each stationary
combustion unit directly
associated with hydrogen
production (e.g., reforming
furnace and hydrogen production
process unit heater).
P................................ 98.166(d)(10)(i)........................... For each hydrogen production
process unit, if best available
monitoring methods were used in
accordance with 40 CFR
98.164(c) to determine fuel
flow for each stationary
combustion unit directly
associated with hydrogen
production, the beginning date
of using best available
monitoring methods.
P................................ 98.166(d)(10)(ii).......................... For each hydrogen production
process unit, if best available
monitoring methods were used in
accordance with 40 CFR
98.164(c) to determine fuel
flow for each stationary
combustion unit directly
associated with hydrogen
production, the anticipated or
actual end date of using best
available monitoring methods.
ZZ............................... 98.526(c)(2)............................... For a facility containing a
ceramics manufacturing process,
for each ceramics manufacturing
process unit, if process CO2
emissions are calculated
according to the procedures
specified in 40 CFR 98.523(b),
annual quantity of each
carbonate-based raw material
(including clay) charged (tons)
(no CEMS).
----------------------------------------------------------------------------------------------------------------
In a handful of cases, the EPA has made minor revisions to data
elements in this final action as compared to the proposed data element
included in either the 2022 Data Quality Improvements Proposal or the
2023 Supplemental Proposal. For certain proposed data elements, we have
revised the citations from proposal to final. In other cases, the minor
revisions include clarifications to the text. The EPA evaluated these
data elements and how they have been clarified in the final rule to
verify that the information collected has not substantially changed
since proposal. These data elements are listed in table 7 of the
memorandum ``Confidentiality Determinations and Emission Data
Designations for Data Elements in the 2024 Final Revisions to the
Greenhouse Gas Reporting Rule,'' available in the docket to this
rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424. Because the
information to be collected has not substantially changed since
proposal, we are finalizing the confidentiality determinations or
emission data designations for these data elements as proposed. For
additional information on the rationales for the confidentiality
determinations for these data elements, see the preamble to the 2022
Data Quality Improvements Proposal or the 2023 Supplemental Proposal
and the memoranda ``Proposed Confidentiality Determinations and
Emission Data Designations for Data Elements in Proposed Revisions to
the Greenhouse Gas Reporting Rule'' and ``Proposed Confidentiality
Determinations and Emission Data Designations for Data Elements in
Proposed Supplemental Revisions to the Greenhouse Gas Reporting Rule,''
available in the docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-
2019-0424).
For all other confidentiality determinations for the new or
substantially revised data reporting elements for these subparts, the
EPA is finalizing the confidentiality determinations as they were
proposed. Please refer to the preamble to the 2022 Data Quality
Improvements Proposal or the 2023 Supplemental Proposal for additional
information regarding these confidentiality determinations.
b. Final Confidentiality Determinations and Emission Data Designations
for Existing Data Elements for Which EPA Did Not Previously Finalize a
Confidentiality Determination or Emission Data Designation
The EPA is finalizing all confidentiality determinations as they
were proposed for other part 98 data reporting elements for which no
determination has been previously established. The EPA received no
comments on the proposed determinations. Please refer to the preamble
to the 2022 Data Quality Improvements Proposal or the 2023 Supplemental
Proposal for additional information regarding the proposed
confidentiality determinations.
c. Final Confidentiality Determinations for Existing Data Elements for
Which the EPA is Amending or Clarifying the Existing Confidentiality
Determination
The EPA is finalizing as proposed all confidentiality
determinations for other part 98 data reporting elements for which the
EPA proposed to amend or clarify the existing confidentiality
determinations. The EPA received no comments on the proposed
determinations. Please refer to the preamble to the 2022 Data Quality
Improvements Proposal for additional information regarding the proposed
confidentiality determinations.
2. Summary and Response to Public Comments on Proposed Confidentiality
Determinations
The EPA received several comments related to the proposed
confidentiality determinations. The EPA received minimal comments on
the proposed confidentiality determinations for all new or
substantially revised data elements, except certain data elements in
subparts PP (Suppliers of Carbon Dioxide) and VV (Geologic
Sequestration of Carbon Dioxide With Enhanced Oil Recovery Using ISO
27916) as described in this section. Additional comments may be found
in the EPA's comment response document in Docket ID. No. EPA-HQ-OAR-
2019-
[[Page 31880]]
0424. For subparts PP and VV, we received comments questioning the
proposed confidentiality determination of certain new and substantially
revised data elements in each subpart, including requests that the data
elements be treated as confidential. Summaries of the major comments
and the EPA's responses thereto are provided below. Additional comments
and the EPA's responses may be found in the comment response document
noted above.
Comment: One commenter contended that public disclosure of the
annual quantity of electricity consumed to power the DAC process unit
and natural gas used for thermal energy could undermine the commercial
deployment of DAC. The commenter stated that this information should be
kept as confidential. The commenter explained that power in a DAC
facility is one of the main operating expenses and power consumption is
directly related to power cost. The commenter stated that a
comprehensive understanding of a DAC unit's power demand, coupled with
a basic understanding of the clean power markets in the region where
the DAC facility is located, could be used to estimate the DAC power
cost. The commenter contended that this knowledge, if available to a
competitor or provider of clean power, would affect business-to-
business contract negotiations, allow for speculation on potential
profit margins on captured CO2 volumes, and negatively
impact the ability of a DAC operator to procure clean power at
competitive rates.
The commenter added that many carbon capture technologies will
utilize natural gas to provide the thermal energy needed to drive the
CO2 capture process, including DAC facilities. The commenter
explained contract negotiations for the supply of natural gas for DAC
facilities are competitive and a major operating cost for a DAC
facility and information on the annual amount of natural gas consumed
by a DAC facility, if available to a competitor or natural gas
supplier, will affect the ability of a DAC operator to contract for
responsibly sourced natural gas supply at a competitive cost. The
commenter requested that natural gas consumption be declared CBI. The
commenter added that they still supported the requirement to report on
whether flue gas is also captured by the DAC process unit as this
requirement allows for a clear distinction of CO2 captured
from the process versus CO2 captured from the air,
increasing public trust in reported CO2 volumes.
Response: The EPA proposed that 12 new subpart PP data elements in
40 CFR 98.426(i) specific to DAC facilities would not be eligible for
confidential treatment. These data elements included: the annual
quantities of on-site and off-site electricity consumed for the DAC
process unit; the annual quantities of heat, steam, other forms of
thermal energy, and combined heat and power (CHP) consumed by the DAC
process unit; the state and county where the facility with the DAC
process unit is located; the name of the electric utility company that
supplied and delivered the electricity if electricity is sourced from a
grid connection; the annual quantity of electricity consumed by the DAC
process unit supported by billing statements; the annual quantity of
electricity, heat, and CHP consumed for the DAC process unit by each
applicable source; and whether flue gas is also captured by the DAC
process unit when electricity or CHP is generated on-site from natural
gas, coal, or oil.
The EPA's proposed determinations were based on research that
indicated the proposed data elements are not customarily and actually
treated as private by the reporter. We note that this, rather than
competitive harm, is now the standard for treating reported data
elements as ``Eligible for Confidential Treatment'' or ``Not Eligible''
based on the decision in Food Marketing Institute v. Argus Leader
Media, 139 S. Ct. 2356 (2019). While the commenter explains that there
may be competitive harm from releasing electricity and natural gas
consumption data in 40 CFR 98.426, they do not clearly demonstrate
whether such data are customarily and actually treated as confidential.
Following receipt of public comment, the EPA conducted additional
research on the public availability of energy use data for DAC and
other facilities, and determined that, with the exception of the state
and county where the DAC facility is located, the other proposed data
elements are not consistently available to the public at this time. As
DAC is a nascent field, there are not yet many examples of such
facilities to support a determination as to whether the other proposed
data elements are typically and actually held confidential. The EPA,
therefore, partially agrees with the commenter that certain data
elements for DAC process unit energy requirements in 40 CFR 98.426(i)
may be treated as confidential by certain facilities. The EPA is,
therefore, making a determination of ``Eligible for Confidential
Treatment'' for certain data elements. Specifically, the EPA is
finalizing the rule with all new data elements in 40 CFR 98.426(i)
having the categorical determination of ``Eligible for Confidential
Treatment'' except for proposed 40 CFR 98.426(i)(1)(i)(A) and (B), the
state and county where the DAC process unit is located, and certain
information reported under 40 CFR 98.426(i)(1) through (3), which
requires the reporter to indicate each applicable energy source type
(e.g., natural gas, oil, coal, nuclear) and provide an indication of
whether flue gas is captured (proposed 40 CFR 98.426(i)(1)),
respectively. The rule is being finalized with the determination that
these four data elements are not eligible for confidential treatment.
The requirements to report the state and county are similar to data
required to be reported under 40 CFR 98.3(c)(1) that was designated as
``emission data,'' which under CAA section 114 is not entitled to
confidential treatment (76 FR 30782, May 26, 2011; CBI Memo, April 29,
2011). Furthermore, the EPA has previously determined that indication
of source is not confidential (77 FR 48072, August 13, 2012). Regarding
reporting whether flue gas is captured, the EPA has previously
determined that an indication of flue gas is ``Not Eligible'' (76 FR
30782, May 26, 2011). While the source of energy would be ``Not
Eligible'' for confidential treatment, the actual quantities of energy
reported under 40 CFR 98.426(i)(1) through (3) would be ``Eligible for
Confidential Treatment.'' The EPA will consider revising the
confidentiality status of the energy consumption data elements in the
future, as more DAC facilities begin operating and we have a better
understanding of how these data are customarily treated. For example,
if DAC facilities begin customarily sharing their energy consumption
information to advertise their energy efficiency, we may consider
revising the confidentiality status to ``No Determination'' or ``Not
Eligible for Confidential treatment.''
Comment: The EPA received several comments regarding the
confidential treatment of the proposed EOR OMP at 40 CFR 98.488.
Several commenters strongly supported the publishing of non-
confidential data related to anthropogenic CO2 volumes
permanently stored in in CO2-EOR operations, including the
EOR OMP. Commenters compared the EOR OMP to the MRV plan issued or
required under subpart RR, noting that the plans serve very similar
purposes and include a geologic characterization of the storage
location, information about wells within the storage site area,
operations history, monitoring programs, and calculation and
quantification methods used to determine the total amount of
CO2
[[Page 31881]]
stored in the storage site. One commenter strongly objected to the
public disclosure of the OMP. The commenter stated that, unlike an MRV
which must receive approval by the EPA under subpart RR, there is no
such approval required for an OMP under subpart VV, which is
appropriate given the differences in the subpart methodologies. The
commenter added that reporting entities are currently free to exercise
discretion to publicly disclose their OMPs.
Response: The EPA disagrees with the commenter. The EPA's review
and approval of a document does not determine whether the document is
eligible for confidential treatment. The EPA proposed that the OMP is
not eligible for confidential treatment because it does not consider
the data elements in the OMP to be customarily and actually treated as
confidential. We note that this, rather than whether the EPA reviews
and approves a submission, is the standard for confidentiality of
reported data elements based on the Argus Leader decision. For example,
the OMP shall include geologic characterization of the EOR complex, a
description of the facilities within the CO2-EOR project, a
description of all wells and other engineered features in the
CO2-EOR project, the operations history of the project
reservoir, descriptions of containment assurance and the monitoring
plan, mass of CO2 previously injected and other information
required in the CSA/ANSI ISO 27916:19 standard. This information is
normally available to the public through geologic records, construction
and operating permitting files, well permits, tax records, and other
public records. Furthermore, such information is available in EPA-
approved subpart RR MRV plans which have been determined to be not-
confidential and are consistently made publicly available on the EPA's
website. That the EPA does not have a role in approving the OMP does
not mean that the content itself is typically and actually held
confidential.
C. Final Reporting Determinations for Inputs to Emission Equations
In the 2022 Data Quality Improvements Proposal and the 2023
Supplemental Proposal, the EPA proposed to assign several data elements
to the ``Inputs to Emission Equation'' data category. As discussed in
section VI.B.1. of the preamble to the 2022 Data Quality Improvements
Proposal, the EPA determined that the Argus Leader decision does not
affect our approach for handling of data elements assigned to the
``Inputs to Emission Equations'' data category. Data assigned to the
``Inputs to Emission Equations'' data category are assigned to one of
two subcategories, including ``inputs to emission equations'' that must
be directly reported to the EPA, and ``inputs to emission equations''
that are not reported but are entered into the EPA's Inputs
Verification Tool (IVT). The EPA received no comments specific to the
proposed reporting determinations for inputs to emission equations in
the proposed rules. Additional information regarding these reporting
determinations may be found in section VI.C. of the preamble to the
2022 Data Quality Improvements Proposal and the 2023 Supplemental
Proposal.
The EPA is finalizing the reporting determinations for data
elements that the EPA proposed to assign to the ``Inputs to the
Emission Equation'' data category as they were proposed for all
subparts with the exception of certain records proposed for subparts G
(Ammonia Production), P (Hydrogen Production), S (Lime Production), and
HH (Municipal Solid Waste Landfills). For subparts G, P, and S, the new
and substantially revised data elements were not proposed to be
included in the reporting section of those subparts but were instead to
be retained as records to be input into the EPA's IVT, and the EPA did
not evaluate these data elements further. The EPA is not taking final
action on these inputs into IVT because the EPA is not taking final
action on the requirement to retain these data elements as records (see
section III. of this preamble for additional information.) For subpart
HH, the EPA is not finalizing the proposed reporting determinations for
certain data elements because the EPA is not taking final action on the
requirements to report these data elements at this time (see section
III. of this preamble for additional information). These data elements
are listed in table 3 of the memorandum ``Reporting Determinations for
Data Elements Assigned to the Inputs to Emission Equations Data
Category in the 2024 Final Revisions to the Greenhouse Gas Reporting
Rule,'' available in the docket to this rulemaking, Docket ID. No. EPA-
HQ-OAR-2019-0424.
In a handful of cases, the EPA has made minor revisions to data
elements assigned to the ``Inputs to Emissions Equations'' data
category in this final action as compared to the proposed data element
included in the 2022 Data Quality Improvements Proposal or the 2023
Supplemental Proposal. For certain proposed data elements, we have
revised the citations from proposal to final. In other cases, the minor
revisions include clarifications to the text. The EPA evaluated these
inputs to emissions equations and how they have been clarified in the
final rule to verify that the data element has not substantially
changed since proposal. These data elements and how they have been
clarified in the final rule are listed in table 4 of the memorandum
``Reporting Determinations for Data Elements Assigned to the Inputs to
Emission Equations Data Category in the 2024 Final Revisions to the
Greenhouse Gas Reporting Rule,'' available in the docket to this
rulemaking, Docket ID. No. EPA-HQ-OAR-2019-0424. Because the input has
not substantially changed since proposal, we are finalizing the
proposed reporting determinations for these data elements as proposed.
For additional information on the rationale for the reporting
determinations for the data elements, see the preamble to the 2022 Data
Quality Improvements Proposal or the 2023 Supplemental Proposal and the
memorandums ``Proposed Reporting Determinations for Data Elements
Assigned to the Inputs to Emission Equations Data Category in Proposed
Revisions to the Greenhouse Gas Reporting Rule'' and ``Proposed
Reporting Determinations for Data Elements Assigned to the Inputs to
Emission Equations Data Category in Proposed Supplemental Revisions to
the Greenhouse Gas Reporting Rule,'' available in the docket for this
rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424).
For all other reporting determinations for the data elements
assigned to the ``Inputs to Emission Equations'' data category, the EPA
is finalizing the reporting determinations as they were proposed.
Please refer to the preamble to the 2022 Data Quality Improvements
Proposal or the 2023 Supplemental Proposal for additional information.
VII. Impacts and Benefits of the Final Amendments
This section of the preamble examines the costs and economic
impacts of the final rule and the estimated impacts of the rule on
affected entities, in addition to the benefits of the final rule. The
revisions in this final rule are anticipated to increase burden in
cases where the amendments expand the applicability, monitoring, or
reporting requirements of part 98. In some cases, the final amendments
are anticipated to decrease burden where we streamlined the rule to
remove notification or reporting requirements or simplify monitoring
and reporting requirements. The final rule consolidates amendments
[[Page 31882]]
from the 2022 Data Quality Improvements Proposal and the 2023
Supplemental Proposal that revise 32 subparts that directly affect 30
industries--including revisions to update the GWPs in table A-1 to
subpart A of part 98 that affect the number of facilities required to
report under part 98; revisions to implement five new source categories
or to expand existing source categories that may require facilities to
newly report or to report under new provisions; and revisions to add
new reporting requirements to a number of subparts that will improve
the quality of the data collected under part 98. The bulk of costs
associated with the final rule includes those costs to facilities that
would be required to newly report under part 98 (subparts I, P, W, DD,
HH, II, OO, TT, WW, XX, YY, and ZZ). However, the majority of subparts
affected will reflect a modest increase in burden to individual
reporters. As discussed in the preamble to the 2022 Data Quality
Improvements Proposal and the 2023 Supplemental Proposal, in several
cases the final rule amendments are anticipated to result in a decrease
in burden. In some cases we have quantified where the final rule would
result in a decrease in burden for certain reporters, but in other
cases we were unable to quantify this decrease. The final revisions
also include minor amendments, corrections, and clarifications,
including simple revisions of requirements such as clarifying changes
to definitions, calculation methodologies, monitoring and quality
assurance requirements, and reporting requirements. These revisions
clarify part 98 to better reflect the EPA's intent, and do not present
any additional burden on reporters. The impacts of the final rule
generally reflect an increase in burden for most subparts.
The EPA received a number of comments on the proposed revisions and
the impacts of the proposed revisions in both the 2022 Data Quality
Improvements Proposal and the 2023 Supplemental Proposal. See the
document ``Summary of Public Comments and Responses for 2024 Final
Revisions and Confidentiality Determinations for Data Elements under
the Greenhouse Gas Reporting Rule'' in Docket ID. No. EPA-HQ-OAR-2019-
0424 for a complete listing of all comments and responses related to
the impacts of the proposed rules. Following consideration of these
comments, the EPA has, in some cases, revised the final rule
requirements and updated the impacts analysis to reflect these changes.
As noted in section I.C. of this preamble, although the EPA
proposed amendments to subpart W (Petroleum and Natural Gas Systems) in
the 2022 Data Quality Improvements Proposal, this final rule does not
address implementation of these revisions to subpart W, which the EPA
is reviewing in concurrent rulemakings. Additionally, as stated in
section III.B. of this preamble, the EPA is not taking final action on
its proposed amendments to add a source category for collection of data
on energy consumption (subpart B) at this time. Accordingly, the
impacts of the final rule do not reflect the costs for these proposed
revisions.
For some subparts, we are not taking final action on revisions to
calculation, monitoring, or reporting requirements that would have
required reporters to collect or submit additional data. For example,
for subpart C (General Stationary Fuel Combustion), we are not taking
final action on proposed revisions to (1) add new reporting for the
unit type, maximum rated heat input capacity, and an estimate of the
fraction of the total annual heat input from each unit in either an
aggregation of units or common pipe configuration (excluding units less
than 10 mmBtu/hour); and (2) add new reporting to identify whether any
unit in the configuration (individual units, aggregation of units,
common stack, or common pipe) is an EGU, and, for multi-unit
configurations, an estimated decimal fraction of total emissions from
the group that are attributable to EGU(s) included in the group. For
subparts G (Ammonia Production), P (Hydrogen Production), S (Lime
Production), and HH (Municipal Solid Waste Landfills) we are not taking
final action on certain revisions to the calculation methodologies that
would have revised how data is collected and reported in e-GGRT.
Similarly, we are not taking final action on certain data elements that
were proposed to be added to subparts A (General Provisions), F
(Aluminum Production), G (Ammonia Production), H (Cement Production),
P, S (Lime Production), HH, OO (Suppliers of Industrial Greenhouse
Gases), and QQ (Importers and Exporters of Fluorinated Greenhouse Gases
Contained in Pre-Charged Equipment and Closed-Cell Foams). Therefore,
the final burden for these subparts has been revised to reflect only
those requirements that are being finalized, and is lower than
proposed.
In a few cases, the EPA has adjusted the burden of the final rule
to account for additional costs associated with the final rule. In
these cases, we have made minor adjustments to the reporting and
recordkeeping requirements in the final rule. Specifically, we are
finalizing changes from the proposed rule that would add 8 new data
elements to subparts I, P, DD, and ZZ (see section III. of this
preamble for additional information). The final rule burden estimate
has been adjusted to include additional time and labor for these
activities, which the EPA estimates is minimal for the reasons
described in section III. of this preamble. Finally, the burden for the
activities in the final rule has been adjusted to reflect updates to
the estimated number of affected reporters based on a review of data
from RY2022 reporting.
As discussed in section V. of this preamble, the final rule will be
implemented on January 1, 2025, and will apply to RY2025 reports. Costs
have been estimated over the three years following the year of
implementation. One-time implementation costs are incorporated into
first year costs, while subsequent year costs represent the annual
burden that will be incurred in total by all affected reporters. The
incremental implementation labor costs for all subparts include
$2,684,681 in RY2025, and $2,671,831 in each subsequent year (RY2026
and RY2027). The incremental implementation labor costs over the next
three years (RY2025 through RY2027) total $8,028,343. There is an
additional incremental burden of $2,733,937 for capital and O&M costs
in RY2025 and in each subsequent year (RY2026 and RY2027), which
reflects changes to applicability and monitoring for subparts I, P, W,
V, Y, DD, HH, II, OO, TT, UU and new subparts VV, WW, XX, YY, and ZZ.
The incremental non-labor costs for RY2025 through RY2027 total
$8,201,812 over the next three years. The incremental burden is
summarized by subpart for the rule changes that are finalized for
initial and subsequent years in table 8 of this preamble. Note that
subparts A, U, FF, and RR only include revisions that are
clarifications or harmonizing changes that would not result in any
changes to burden, and are not included in table 8 of this preamble.
[[Page 31883]]
Table 8--Annual Incremental Burden of the Final Rule, by Subpart
----------------------------------------------------------------------------------------------------------------
Labor costs
Number of -------------------------------- Capital and
Subpart affected Subsequent O&M
facilities Initial year years
----------------------------------------------------------------------------------------------------------------
C--General Stationary Fuel Combustion Sources .............. .............. .............. ..............
\a\............................................
Facilities Reporting only to Subpart C.......... 133 ($1,446) ($1,446) ..............
Facilities Reporting to Subpart C plus another 177 (979) (979) ..............
subpart........................................
G--Ammonia Manufacturing........................ 29 119 119 ..............
H--Cement Production............................ 94 1,999 1,999 ..............
I--Electronics Manufacturing \b\ \c\............ 48 19,651 18,023 $62
N--Glass Production............................. 101 2,074 2,074 ..............
P--Hydrogen Production \b\...................... 114 7,497 7,497 2,561
Q--Iron and Steel Production.................... 121 1,485 1,485 ..............
S--Lime Manufacturing........................... 71 1,186 1,186 ..............
V--Nitric Acid Production \d\ \e\............... 1 (2,680) (2,680) (11,085)
W--Petroleum and Natural Gas Systems \d\........ 188 2,433,058 2,433,058 2,717,864
X--Petrochemical Production..................... 31 618 618 ..............
Y--Petroleum Refineries \f\..................... 57 (6,133) (6,133) (3,930)
AA--Pulp and Paper Manufacturing................ 1 104 104 ..............
BB--Silicon Carbide Production.................. 1 20 20 ..............
DD--Electrical Transmission \b\................. 95 15,278 15,278 3,119
GG--Zinc Production............................. 5 20 20 ..............
HH--Municipal Solid Waste Landfills \b\......... 1,129 84,651 81,793 374
II--Industrial Wastewater Treatment \d\......... 2 5,288 4,713 3,077
OO--Suppliers of Industrial Greenhouse Gases \a\ 121 6,884 6,884 62
PP--Suppliers of Carbon Dioxide................. 22 872 872 ..............
QQ--Importers and Exporters of Fluorinated 33 249 249 ..............
Greenhouse Gases Contained in Pre-Charged
Equipment or Closed-Cell Foams.................
SS--Electrical Equipment Manufacture or 5 358 358 ..............
Refurbishment..................................
TT--Industrial Waste Landfills \b\ \d\.......... 1 4,853 3,934 62
UU--Injection of Carbon Dioxide \g\............. 2 (1,886) (1,886) (125)
VV--Geologic Sequestration of Carbon Dioxide 2 1,882 3,443 250
with Enhanced Oil Recovery Using ISO 27916 \g\.
WW--Coke Calciners.............................. 15 37,847 34,525 19,649
XX--Calcium Carbide Production.................. 1 2,849 2,627 62
YY--Caprolactam, Glyoxal, and Glyoxylic Acid 6 12,285 11,089 374
Production.....................................
ZZ--Ceramics Manufacturing...................... 25 56,678 52,987 1,559
---------------------------------------------------------------
Total....................................... .............. 2,684,681 2,671,831 2,733,937
----------------------------------------------------------------------------------------------------------------
\a\ Reflects reduced burden due to revisions to simplify calculation methods and remove reporting requirements.
\b\ Applies to reporters that may currently report under existing subparts of part 98 and that are newly subject
to reporting under part 98.
\c\ Average subsequent year costs for subpart I. Subpart I subsequent year costs include $17,794 in Year 2 and
$18,252 in Year 3.
\d\ Reflects burden to reporters estimated to be affected due to revisions to table A-1 to subpart A only.
\e\ Reflects changes to the number of reporters able to off-ramp from reporting under the part 98 source
category.
\f\ Reflects changes to the number of reporters with coke calciners reporting under subpart Y that would be
required to report under proposed subpart WW.
\g\ Reflects changes to the number of reporters reporting under subpart UU who will begin submitting reports
under new subpart VV in each year.
Additional details on the EPA's review of the impacts may be found
in the memorandum, ``Assessment of Burden Impacts for Final Revisions
to the Greenhouse Gas Reporting Rule,'' available in Docket ID. No.
EPA-HQ-OAR-2019-0424.
The implementation of the final rule will provide numerous benefits
for stakeholders, the Agency, industry, and the general public. The
final revisions include improvements to the calculation, monitoring,
and reporting requirements, incorporate new data and reflect updated
scientific knowledge; provide coverage of new emissions sources and
additional sectors; improve analysis and verification of collected
data; provide additional data to complement or inform other EPA
programs; and streamline calculation, monitoring, or reporting to
provide flexibility or increase the efficiency of data collection. The
revisions will maintain the quality of the data collected under part 98
where continued collection of information assists in evaluation and
support of EPA programs and policies under provisions of the CAA. In
some cases, the amendments improve the EPA's ability to assess
compliance by revising or adding recordkeeping or reporting elements
that will allow the EPA to more thoroughly verify GHG data and advance
the ability of the GHGRP to provide access to quality data on
greenhouse gas emissions by adding or updating emission factors,
revising or adding calculation methodologies, or adding key data
elements to improve the usefulness of the data.
Because part 98 is a reporting rule, the EPA did not quantify
estimated emission reductions or monetize the benefits from such
reductions that could be associated with the final rule. The benefits
of the final rule are based on its relevance to policy making,
transparency, and market efficiency. The improvements to the GHGRP will
benefit the EPA, other policymakers, and the public by increasing the
completeness and accuracy of facility emissions data. Public data on
emissions allows for accountability of emitters to the public. Improved
facility-specific emissions data will aid local, state, and national
policymakers as they evaluate and consider future climate change policy
decisions and other policy decisions for criteria pollutants, ambient
air quality standards, and toxic
[[Page 31884]]
air emissions. For example, GHGRP data on petroleum and natural gas
systems (subpart W of part 98) were previously analyzed to inform
targeted improvements to the 2016 NSPS for the oil and gas industry and
to update emission factor and activity data used for that proposal and
the final NSPS, as updated in the Inventory (83 FR 52056; October 15,
2018). Similarly, GHGRP data on municipal solid waste landfills
(subpart HH of part 98) were previously used to inform the development
of the 2016 NSPS and EG for landfills; the EPA was able to update its
internal landfills data set and consider the technical attributes of
over 1,200 landfills based on data reported under subpart HH. The
benefits of improved reporting also include enhancing existing
voluntary programs, such as the Landfill Methane Outreach Program
(LMOP), which uses GHGRP data to supplement the LMOP Landfill and
Landfill Gas Energy Project Database and includes data collected from
LMOP Partners about landfill gas energy projects or potential for
project development.
The final rule would additionally benefit states by providing
improved facility-specific emissions data. Several states use GHGRP
data to inform their own policymaking. For example, the state of Hawaii
uses GHGRP data to establish an emissions baseline for each facility
subject to their GHG Reduction Plan and to assess whether facilities
meet their targets in future years.
GHGRP data are also used to improve estimates of GHG emissions
internationally. Data collected through the GHGRP complements the
Inventory and are used to significantly improve our understanding of
key emissions sources by allowing the EPA to better reflect changing
technologies and emissions from a wide range of industrial facilities.
Specifically, GHGRP data have been used to inform several of the
updates to emission estimation methods included in the 2019 Refinement.
Benefits to industry of improved GHG emissions monitoring and
reporting from the amendments include the value of having standardized
emissions data to present to the public to demonstrate appropriate
environmental stewardship, and a better understanding of their emission
levels and sources to identify opportunities to reduce emissions. For
example, the final rule updates the global warming potential values
used under the GHGRP to reflect values from the IPCC AR5 and AR6, which
are consistent with the values used under several voluntary standards
and frameworks such as the GHG Protocol and Sustainability Accounting
Standards Board (SASB), and will provide consistency for company
reporting. Businesses and other innovators can use the data to
determine and track their GHG footprints, find cost-saving efficiencies
that reduce GHG emissions and save product, foster technologies to
protect public health and the environment, and to reduce costs
associated with fugitive emissions. The final rule will continue to
allow for facilities to benchmark themselves against similar facilities
to understand better their relative standing within their industry and
achieve and disseminate information about their environmental
performance.
In addition, transparent, standardized public data on emissions
allows for accountability of polluters to the public who bear the cost
of the pollution. The GHGRP serves as a powerful data resource and
provides a critical tool for communities to identify nearby sources of
GHGs and provide information to state and local governments. As
discussed in section II. of this preamble, GHGRP data are easily
accessible to the public via the EPA's FLIGHT, which allows users to
view and sort GHG data by location, industrial sector, and type of GHG
emitted, and includes demographic data. Although the emissions reported
to the EPA by reporting facilities are global pollutants, many of these
facilities also release pollutants that have a more direct and local
impact in the surrounding communities. Citizens, community groups, and
labor unions have made use of public pollutant release data to
negotiate directly with emitters to lower emissions, avoiding the need
for additional regulatory action. The final rule would improve the
quality and transparency of this reported data to affected communities.
VIII. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review and 14094:
Modernizing Regulatory Review
This action is not a significant regulatory action as defined in
Executive Order 12866, as amended by Executive Order 14094, and was
therefore not subject to a requirement for Executive Order 12866
review.
B. Paperwork Reduction Act
The information collection activities in this rule have been
submitted for approval to the OMB under the PRA. The Information
Collection Request (ICR) document that the EPA prepared has been
assigned OMB number 2060-0748, EPA ICR number 2773.02. You can find a
copy of the ICR in the docket for this rule, and it is briefly
summarized here. The information collection requirements are not
enforceable until OMB approves them.
The EPA has estimated that the final rule will result in an
increase in burden, specifically in cases where the amendments expand
the applicability, monitoring, or reporting requirements of part 98. In
some cases, the final amendments are anticipated to decrease burden
where we streamlined the rule to remove notification or reporting
requirements or simplify monitoring and reporting requirements. The
final rule consolidates amendments from the 2022 Data Quality
Improvements Proposal and the 2023 Supplemental Proposal that revise 31
subparts that directly affect 30 industries--including revisions to
update the GWPs in table A-1 to subpart A of part 98 that affect the
number of facilities required to report under part 98; revisions to
implement five new source categories or to expand existing source
categories that may require facilities to newly report; and revisions
to add new reporting requirements that will improve the quality of the
data collected under part 98. The costs associated with the final rule
largely reflect the costs to facilities that would be required to newly
report under part 98. However, the majority of subparts affected will
reflect a modest increase in burden to existing individual reporters.
Further information on the EPA's assessment on the impact on burden
can be found in the memorandum ``Assessment of Burden Impacts for Final
Revisions for the Greenhouse Gas Reporting Rule,'' available in the
docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424).
Respondents/affected entities: Owners and operators of facilities
that must report their GHG emissions and other data to the EPA to
comply with 40 CFR part 98.
Respondent's obligation to respond: The respondent's obligation to
respond is mandatory and the requirements in this rule are under the
authority provided in CAA section 114.
Estimated number of respondents: 2,701.
Frequency of response: Initially, annually.
Total estimated burden: 25,647 hours (annual average per year).
Burden is defined at 5 CFR 1320.3(b).
Total estimated cost: $5,410,000 (annual average per year),
includes $2,734,000 annualized capital or operation and maintenance
costs.
An agency may not conduct or sponsor, and a person is not required
to
[[Page 31885]]
respond to, a collection of information unless it displays a currently
valid OMB control number. The OMB control numbers for the EPA's
regulations in 40 CFR are listed in 40 CFR part 9. When OMB approves
this ICR, the Agency will announce that approval in the Federal
Register and publish a technical amendment to 40 CFR part 9 to display
the OMB control number for the approved information collection
activities contained in this final rule.
C. Regulatory Flexibility Act (RFA)
I certify that this final action will not have a significant
economic impact on a substantial number of small entities under the
RFA. The small entities subject to the requirements of this action are
small businesses across all sectors encompassed by the rule, small
governmental jurisdictions, and small non-profits. In the development
of 40 CFR part 98, the EPA determined that some small entities are
affected because their production processes emit GHGs that must be
reported, because they have stationary combustion units on site that
emit GHGs that must be reported, or because they have fuel supplier
operations for which supply quantities and GHG data must be reported.
Small governments and small non-profits are generally affected because
they have regulated landfills or stationary combustion units on site,
or because they own a local distribution company (LDC).
The EPA previously conducted screening analyses to identify impacts
to small entities during the development of the 2022 Data Quality
Improvements Proposal and the 2023 Supplemental Proposal. The EPA
conducted small entity analyses that assessed the costs and impacts to
small entities in three areas, including: (1) amendments that revise
the number or types of facilities required to report (i.e., updates of
the GHGRP's applicability to certain sources), (2) changes to refine
existing monitoring or calculation methodologies that require
collection of additional data, and (3) revisions to reporting and
recordkeeping requirements for data provided to the program. The
analyses provided the subparts affected, the number of small entities
affected, and the estimated impact to these entities based on the total
annualized reporting costs of the proposed rules. Details of these
analyses are presented in the memoranda, Assessment of Burden Impacts
for Proposed Revisions for the Greenhouse Gas Reporting Rule (May 2022)
and Assessment of Burden Impacts for Proposed Supplemental Revisions
for the Greenhouse Gas Reporting Rule (April 2023), available in the
docket for this rulemaking (Docket ID. No. EPA-HQ-OAR-2019-0424). Based
on the results of these analyses, we concluded that the 2022 Data
Quality Improvements Proposal and 2023 Supplemental Proposal will have
no significant regulatory burden for any directly regulated small
entities and thus would not have a significant economic impact on a
substantial number of small entities.
As discussed in sections III. and VII. of this preamble, this
action finalizes revisions to part 98 as proposed in the 2022 Data
Quality Improvements Proposal and the 2023 Supplemental Proposal, or
with minor revisions, and we have revised the cost impacts to reflect
the final rule requirements and more recent data. For example, we have
updated the impacts to better reflect the number of affected reporters
that would be subject to the final requirements, based on a review of
RY2022 data. These updates also predominantly include removing or
adjusting costs where the EPA is not taking final action on specific
proposed revisions, including costs associated with the addition of
proposed subpart B (Energy Consumption), certain costs associated with
proposed revisions to subpart W (Petroleum and Natural Gas Systems)
included in the 2022 Data Quality Improvements Proposal,\50\ and costs
associated with certain revisions to calculations, monitoring, or
reporting requirements for subparts A (General Provisions), C (General
Stationary Fuel Combustion), F (Aluminum Production), G (Ammonia
Production), H (Cement Production), S (Lime Production), HH (Municipal
Waste Landfills), OO (Suppliers of Industrial Greenhouse Gases), and QQ
(Importers and Exporters of Fluorinated Greenhouse Gases Contained in
Pre-Charged Equipment and Closed-Cell Foams). Accordingly, the burden
of the final rule is reduced, as compared to the proposals, for
facilities that may report for these source categories, including all
direct emitting facilities previously proposed to report under subpart
B.
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\50\ The EPA is not taking final action on any revisions to
requirements for subpart W (Petroleum and Natural Gas Systems) in
this final rule. See sections I.C. and VII. of this preamble for
additional information regarding the EPA's actions regarding subpart
W and the impacts included in this final rule.
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The EPA has also adjusted the burden to account for additional
costs from changes adopted in the final rule. Specifically, we have
adjusted the reporting and recordkeeping requirements for subparts I
(Electronics Manufacturing), P (Hydrogen Production), DD (Electrical
Transmission and Distribution Equipment Use), HH (Municipal Solid Waste
Landfills), and ZZ (Ceramics Manufacturing) to add new data elements
for annual reporting across these subparts. The estimated costs
associated with the revisions to these subparts for regulated entities
are minimal (less than $100 annually), and would not result in costs
exceeding more than one percent of sales in any firm size category.
Details of this analysis are presented in the memorandum ``Assessment
of Burden Impacts for Final Revisions for the Greenhouse Gas Reporting
Rule,'' available in Docket ID. No. EPA-HQ-OAR-2019-0424.
The remaining revisions to the final rule include minor
clarifications or adjustments to the proposed requirements that are not
anticipated to increase the burdens estimated for the 2022 Data Quality
Improvements Proposal and 2023 Supplemental Proposal which we
previously determined would not have a significant impact on a
significant number of small businesses. For these reasons, we have
determined that these final revisions are consistent with our prior
small entity analyses, and would impose no significant regulatory
burden on any directly regulated small entities, and thus would not
have a significant economic impact on a substantial number of small
entities.
Refer to the memorandum ``Assessment of Burden Impacts for Final
Revisions for the Greenhouse Gas Reporting Rule,'' available in Docket
ID. No. EPA-HQ-OAR-2019-0424 for further discussion. 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.
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.
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.
[[Page 31886]]
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 facilities emitting and supplying GHGs 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 10) tribal facilities will be affected. This regulation
is not anticipated to impact facilities or suppliers of additional
sectors owned by tribal governments.
In evaluating the potential implications for tribal entities, we
first assessed whether tribes would be affected by any final revisions
that expanded the universe of facilities that would report GHG data to
the EPA. The final rule amendments will implement requirements to
collect additional data to understand new source categories, new
sources of GHG emissions or supply for specific sectors; improve the
existing emissions estimation methodologies; and improve the EPA's
understanding of the sector-specific processes or other factors that
influence GHG emission rates and improve verification of collected
data. Of the 254 facilities that we anticipate will be newly required
to report under the final revisions, we do not anticipate that there
are any tribally owned facilities. As discussed in section VII. of this
preamble, we expect the final revisions to table A-1 to part 98 to
result in a change to the number of facilities required to report under
subparts W (Petroleum and Natural Gas Systems), V (Nitric Acid
Production), DD (Electrical Transmission and Distribution Equipment
Use), HH (MSW Landfills), II (Industrial Wastewater Treatment), OO
(Suppliers of Industrial GHGs), and TT (Industrial Waste Landfills).
However, we did not identify any potential sources in these source
categories that are owned by tribal entities not already reporting to
the GHGRP. Similarly, although we are finalizing amendments that will
require some facilities in select source categories not currently
subject to the GHGRP to begin implementing requirements under the
program, we have not identified, and do not anticipate that any of
these affected facilities are owned by tribal governments.
As a second step to evaluate potential tribal implications, we
evaluated whether there were any tribally owned facilities that are
currently reporting under the GHGRP that will be affected by the final
revisions. Tribally owned facilities currently subject to part 98 will
only be subject to changes that are improvements or clarifications of
requirements and that, for the most part, do not significantly change
the existing requirements or result in substantial new activities
because they do not require new equipment, sampling, or monitoring.
Rather, tribally owned facilities would only be subject to new
requirements where reporters would provide data that is readily
available from company records. As such, the final revisions will not
substantially increase reporter burden, impose significant direct
compliance costs for tribal facilities, or preempt tribal law.
Specifically, we identified ten facilities currently reporting to
part 98 that are owned by six tribal parent companies. For these six
parent companies, we identified facilities in the stationary fuel
combustion (subpart C), cement production (subpart H), petroleum and
natural gas (subpart W), electrical transmission and distribution
equipment use (subpart DD), and MSW landfill (subpart HH) source
categories that may be affected by the final revisions.
For stationary fuel combustion, the EPA is not taking final action
on proposed revisions to add reporting requirements to subpart C, but
is retaining revisions that would remove certain reporting
requirements. Therefore, the costs for any tribally-owned facilities
currently reporting to subpart C are anticipated to decrease and no
facilities are anticipated to be negatively impacted. For petroleum and
natural gas facilities, the EPA is not including any revisions to
subpart W in this final rule (see section I.C. of this document);
therefore, any tribally-owned facilities currently reporting to subpart
W are not anticipated to be impacted. Three parent companies include
existing facilities that report only under subparts C or W, which are
not anticipated to have significant impacts under this rule for the
reasons discussed in this section. Therefore, the remaining facilities
that could be affected by the final revisions are those that report to
subparts H, DD, and HH. For the remaining three parent companies, we
reviewed publicly available sales and revenue data to assess whether
the costs of the final rule would be significant. Under the final rule,
the costs for facilities currently reporting under subparts H, DD, or
HH are anticipated to increase by less than $100 per year per subpart.
Therefore, we were able to confirm that the costs of the final
revisions would not have a significant impact for these sources.
Further, based on our review of our small entity analyses (discussed in
VIII.C. of this preamble), we do not anticipate the final revisions to
subparts H, DD, or HH will impose substantial direct compliance costs
on the remaining tribally owned entities.
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,\51\ 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), and 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 final rule does not significantly revise
the established regulatory requirements and will not substantially
change the equipment, monitoring, or reporting activities conducted by
these facilities, or result in other substantial impacts for tribal
facilities.
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\51\ EPA Policy on Consultation and Coordination with Indian
Tribes, May 4, 2011. Available at: www.epa.gov/sites/default/files/2013-08/documents/cons-and-coord-with-indian-tribes-policy.pdf.
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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
[[Page 31887]]
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 subject to Executive Order 13211, because it is
not a significant regulatory action under Executive Order 12866.
I. National Technology Transfer and Advancement Act and 1 CFR Part 51
This action involves technical standards. The EPA has decided to
incorporate by reference several standards in establishing monitoring
requirements in these final amendments.
The EPA currently allows for the use of the Protocol for Measuring
Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas
Abatement Equipment in Electronics Manufacturing, Version 1, EPA-430-R-
10-003, March 2010 (EPA 430-R-10-003) in other sections of part 98,
including subpart I (Electronics Manufacturing). The EPA is adding the
use of EPA 430-R-10-003 to subpart I for use for measurement of DREs
from abatement systems, including HC fuel CECS, purchased and installed
on or after January 1, 2025. EPA 430-R-10-003 provides methods for
measuring abatement system inlet and outlet mass or volume flows for
single or multi-chamber process tools, accounting for dilution. Anyone
may access EPA 430-R-10-003 at https://www.epa.gov/sites/default/files/2016-02/documents/dre_protocol.pdf. This standard is available to
everyone at no cost; therefore, the method is reasonably available for
reporters.
The EPA is allowing 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 ASTM E415-17 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. (See the end of
section VIII.I. of this preamble for availability information.)
The EPA is adding new subpart VV to part 98 for certain EOR
operations that choose to use the co-published ISO/CSA standard
designated as CSA/ANSI ISO 27916:19, Carbon dioxide capture,
transportation and geological storage--Carbon dioxide storage using
enhanced oil recovery (CO2-EOR), as a means of quantifying
geologic sequestration. The EPA is also clarifying in subpart UU at 40
CFR 98.470(c) and subpart VV at 40 CFR 98.481 that CO2-EOR
projects previously reporting under subpart UU that begin using CSA/
ANSI ISO 27916:19 part-way through a reporting year must report under
subpart UU for the portion of the year before CSA/ANSI ISO 27916:19 was
used and report under subpart VV for the portion of the year once CSA/
ANSI ISO 27916:19 began to be used and thereafter. CSA/ANSI ISO
27916:19 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 CSA
group website (www.csagroup.org/store) for additional information. The
standard is available to everyone at a cost determined by CSA Group
($225). CSA Group also offers memberships or subscriptions for reduced
costs. Because the use of the standard is optional, the cost of
obtaining this standard is not a significant financial burden.
The EPA is adding new subpart WW to part 98 (Coke Calciners) and is
allowing the use of any one of the following standards for coke
calcining facilities: (1) ASTM D3176-15 Standard Practice for Ultimate
Analysis of Coal and Coke, (2) ASTM D5291-16 Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants, and (3) ASTM D5373-21 Standard Test
Methods for Determination of Carbon, Hydrogen, and Nitrogen in Analysis
Samples of Coal and Carbon in Analysis Samples of Coal and Coke. These
methods are used to determine the carbon content of petroleum coke. The
EPA currently allows for the use of an earlier version of these
standard methods for the instrumental determination of carbon content
in laboratory samples of petroleum coke in other sections of part 98,
including the use of ASTM D3176-89, ASTM D5291-02, and ASTM D5373-08 in
40 CFR 98.244(b) (subpart X--Petrochemical Production) and 40 CFR
98.254(i) (subpart Y--Petroleum Refineries). The EPA is allowing the
use of the updated versions of these standards (ASTM D3176-15, ASTM
D5291-16, and ASTM D5373-21) to determine the carbon content of
petroleum coke for subpart WW (Coke Calciners). ASTM D3176-15 provides
direction for a convenient and uniform system of analysis of the ash
content and the content of organic constituents in coal and coke; this
method references the appropriate ASTM methods for sample collection,
preparation, content determination, and provides consistency measures
for calculation and reporting of results. ASTM D5291-16 provides a
series of test methods for the simultaneous instrumental determination
of carbon, hydrogen, and nitrogen in petroleum products and lubricants
such as crude oils, fuel oils, additives, and residues; the method
allows for a variety of instrumental components and configurations for
measurement and calculation of concentrations of carbon, hydrogen, and
nitrogen. ASTM D5373-21 provides a methodology for the determination of
carbon, hydrogen, and nitrogen content in coal or carbon in coke using
furnace combustion and instrument detection systems; the method
addresses the determination of carbon in the range of 54.9 percent m/m
to 84.7 percent m/m, hydrogen in the range of 3.26 percent m/m to 5.08
percent m/m, and nitrogen in the range of 0.57 percent m/m to 1.76
percent m/m in the analysis sample of coal. (See the end of section
VIII.I. of this preamble for availability information.)
We are allowing the use of the following standard for coke
calciners subject to subpart WW: NIST HB 44-2023, NIST Handbook 44:
Specifications, Tolerances, and Other Technical Requirements For
Weighing and Measuring Devices, 2023 edition. The EPA currently allows
for the use of an earlier version of the proposed standard method,
Specifications, Tolerances, and Other Technical Requirements For
Weighing and Measuring Devices, NIST Handbook 44 (2009), for the
calibration and maintenance of instruments used for weighing of mass of
samples of petroleum coke in other sections of part 98, including 40
CFR 98.244(b) (subpart X). The EPA is allowing the use of the updated
version of this standard, NIST HB 44-2023: Specifications, Tolerances,
and Other Technical Requirements For Weighing and Measuring Devices,
2023 edition, for performing mass measurements of petroleum coke for
subpart WW (Coke Calciners). This
[[Page 31888]]
standard includes specifications on design of equipment, tolerances to
limit the allowable error, sensitivity requirements, and other
technical requirements for weighing and measuring devices. Anyone may
access the standards on the NIST website (www.nist.gov/index.html) for
additional information. These standards are available to everyone at no
cost; therefore the methods are reasonably available for reporters.
The EPA is adding new subpart XX to part 98 (Calcium Carbide
Production) and is allowing the use of one of the following standards
for calcium carbide production facilities: (1) ASTM D5373-08 Standard
Test Methods for Instrumental Determination of Carbon, Hydrogen, and
Nitrogen in Laboratory Samples of Coal, or (2) ASTM C25-06, Standard
Test Methods for Chemical Analysis of Limestone, Quicklime, and
Hydrated Lime. ASTM D5373-08 addresses the determination of carbon in
the range of 54.9 percent m/m to 84.7 percent m/m, hydrogen in the
range of 3.25 percent m/m to 5.10 percent m/m, and nitrogen in the
range of 0.57 percent m/m to 1.80 percent m/m in the analysis sample of
coal. The EPA currently allows for the use of ASTM D5373-08 in other
sections of part 98, including in 40 CFR 98.244(b) (subpart X--
Petrochemical Production), 40 CFR 98.284(c) (subpart BB--Silicon
Carbide Production), and 40 CFR 98.314(c) (subpart EE--Titanium
Production) for the instrumental determination of carbon content in
laboratory samples. Therefore, we are allowing the use of ASTM D5373-08
for determination of carbon content of materials consumed, used, or
produced at calcium carbide facilities.
The EPA currently allows for the use of ASTM C25-06 in other
sections of part 98, including in 40 CFR 98.194(c) (subpart S--Lime
Production) for chemical composition analysis of lime products and
calcined byproducts and in 40 CFR 98.184(b) (subpart R--Lead
Production) for analysis of flux materials such as limestone or
dolomite. ASTM C25-06 addresses the chemical analysis of high-calcium
and dolomitic limestone, quicklime, and hydrated lime. We are allowing
the use of ASTM C25-06 for determination of carbon content of materials
consumed, used, or produced at calcium carbide facilities, including
analysis of materials such as limestone or dolomite.
Anyone may access the standards on the ASTM website (www.astm.org/)
for additional information. These standards are available to everyone
at a cost determined by the ASTM (between $48 and $92 per standard).
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 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. The EPA is not requiring the use of specific consensus
standards for new subparts YY (Caprolactam, Glyoxal, and Glyoxylic Acid
Production) or ZZ (Ceramics Manufacturing), or for other amendments to
part 98.
The following standards appear in the amendatory text of this
document and were previously approved for the locations in which they
appear:
ASTM D3176-89 (Reapproved 2002) Standard Practice for
Ultimate Analysis of Coal and Coke;
ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants;
ASTM E1019-08 Standard Test Methods for Determination of
Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt
Alloys by Various Combustion and Fusion Techniques;
Specifications, Tolerances, and Other Technical
Requirements For Weighing and Measuring Devices, NIST Handbook 44
(2009);
ASTM D6866-16 Standard Test Methods for Determining the
Biobased Content of Solid, Liquid, and Gaseous Samples Using
Radiocarbon Analysis).
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.
ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity
Ethylene by Gas Chromatography.
T650 om-05 Solids Content of Black Liquor, TAPPI.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
The EPA believes that this type of action does not directly concern
human health or environmental conditions and therefore cannot be
evaluated with respect to potentially disproportionate and adverse
effects on communities with environmental justice concerns. This action
does not affect the level of protection provided to human health or the
environment, but instead, addresses information collection and
reporting procedures. Although this action does not concern human
health or environmental conditions, the EPA identified and addressed
environmental justice concerns by promoting meaningful engagement from
communities in developing the action, and in developing requirements
that improve the quality of data available to communities. The EPA
provided multiple public comment periods on the proposed 2022 Data
Quality Improvements Proposal (from June 21, 2022 to October 6, 2022)
and the 2023 Supplemental Proposal (May 22, 2023 to July 21, 2023), and
provided opportunities for virtual public hearing(s) for members of the
public to share information or concerns and participate in the
decision-making process. Further, the EPA has developed improvements to
the GHGRP that benefit the public by increasing the completeness and
accuracy of facility emissions data. The data collected through this
action will provide an important data resource for communities and the
public to understand GHG emissions, including requiring reporting of
GHG data from additional emission sources and providing more
comprehensive coverage of U.S. GHG emissions. Transparent, standardized
public data on emissions allows for accountability of polluters to the
public who bear the cost of the pollution. Although the emissions
reported to the EPA by reporting facilities are global pollutants, many
of these facilities also release pollutants that have a more direct and
local impact in the surrounding communities. GHGRP data are easily
accessible to the public via the EPA's online data publication tool
(FLIGHT), which allows users to view and sort GHG data from over 8,000
entities in a variety of ways including by location, industrial sector,
type of GHG emitted, and provides supplementary demographic data that
may be useful to communities with environmental justice concerns. As
described further in sections II. and III. of this preamble, the final
rule improves the quality and transparency of this reported data to
affected communities and enables members of the public to have access
to and improve their understanding of GHG emissions and pollutants that
may impact them.
K. Congressional Review Act (CRA)
This action is subject to the CRA, and the EPA will submit a rule
report to each House of the Congress and to the
[[Page 31889]]
Comptroller General of the United States. This action is not a ``major
rule'' as defined by 5 U.S.C. 804(2).
L. Judicial Review
Under CAA section 307(b)(1), any petition for review of this final
rule must be filed in the U.S. Court of Appeals for the District of
Columbia Circuit by June 24, 2024. This final rule establishes
requirements applicable to owners and operators of facilities and
suppliers in many industry source categories located across the United
States that are subject to 40 CFR part 98 and therefore is ``nationally
applicable'' within the meaning of CAA section 307(b)(1).
Further, pursuant to CAA section 307(d)(1)(V), the Administrator
has determined that this rule is subject to the provisions of CAA
section 307(d). See CAA section 307(d)(1)(V) (the provisions of section
307(d) apply to ``such other actions as the Administrator may
determine''). Under CAA section 307(d)(7)(B), only an objection to this
final rule that was raised with reasonable specificity during the
period for public comment can be raised during judicial review. CAA
section 307(d)(7)(B) also provides a mechanism for the EPA to convene a
proceeding for reconsideration, ``[i]f the person raising an objection
can demonstrate to EPA that it was impracticable to raise such
objection within [the period for public comment] or if the grounds for
such objection arose after the period for public comment (but within
the time specified for judicial review) and if such objection is of
central relevance to the outcome of the rule.'' Any person seeking to
make such a demonstration should submit a Petition for Reconsideration
to the Office of the Administrator, Environmental Protection Agency,
Room 3000, William Jefferson Clinton Building, 1200 Pennsylvania Ave.
NW, Washington, DC 20460, with an electronic copy to the person listed
in FOR FURTHER INFORMATION CONTACT, and the Associate General Counsel
for the Air and Radiation Law Office, Office of General Counsel (Mail
Code 2344A), Environmental Protection Agency, 1200 Pennsylvania Ave.
NW, Washington, DC 20004. Note that under CAA section 307(b)(2), the
requirements established by this final rule may not be challenged
separately in any civil or criminal proceedings brought by the EPA to
enforce these requirements.
List of Subjects
40 CFR Part 9
Environmental protection, Administrative practice and procedure,
Reporting and recordkeeping requirements.
40 CFR Part 98
Environmental protection, 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 amends 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 ``98.1-98.528'' 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
------------------------------------------------------------------------
98.1-98.528............................................. 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. 98.2 by:
0
a. Revising paragraphs (f)(1) and (i)(1) and (2); and
0
b. Adding paragraph (k).
The revisions and addition 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
[[Page 31890]]
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.
* * * * *
(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 (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 to 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
5. Amend Sec. 98.3 by:
0
a. Revising paragraphs (b)(2), (h)(4), and (k)(1) through (3); and
0
b. Revising and republishing paragraph (l).
The revisions and republication 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) of this
section. 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) of this section 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) of this
section 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.
* * * * *
(k) * * *
(1) A facility or supplier that first becomes subject to part 98
due to a change in the GWP for one or more compounds in table A-1 to
this subpart, Global Warming Potentials, is not required to submit an
annual GHG report for the reporting year during which the change in
GWPs is published in the Federal Register as a final rulemaking.
(2) A facility or supplier that was already subject to one or more
subparts of this part but becomes subject to one or more additional
subparts due to a change in the GWP for one or more compounds in table
A-1 to this subpart, is not required to include those subparts to which
the facility is subject only due to the change in the GWP in the annual
GHG report submitted for the reporting year during which the change in
GWPs is published in the Federal Register as a final rulemaking.
(3) Starting on January 1 of the year after the year during which
the change in GWPs is published in the Federal Register as a final
rulemaking, facilities or suppliers identified in paragraph (k)(1) or
(2) of this section must start monitoring and collecting GHG data in
compliance with the applicable subparts of part 98 to which the
facility is subject due to the change in the GWP for the annual
greenhouse gas report for that reporting year, which is due by March 31
of the following calendar year.
* * * * *
(l) Special provision for best available monitoring methods in 2014
and subsequent years. This paragraph (l) applies to owners or operators
of facilities or suppliers that first become subject to any subpart of
this part due to an amendment to table A-1 to this subpart, Global
Warming Potentials.
(1) Best available monitoring methods. From January 1 to March 31
of the year after the year during which the change in GWPs is published
in the Federal Register as a final rulemaking, owners or operators
subject to this paragraph (l) may use best available monitoring methods
for any parameter (e.g., fuel use, feedstock rates) that cannot
reasonably be measured according to the monitoring and QA/QC
requirements of a relevant subpart. The owner or operator must use the
calculation methodologies and equations in the ``Calculating GHG
Emissions'' sections of each relevant subpart, but may use the best
available monitoring method for any parameter for which it is not
reasonably feasible to acquire, install, and operate a required piece
of monitoring equipment by January 1 of the year after the year during
which the change in GWPs is published in the Federal Register as a
final rulemaking. Starting no later than April 1 of the year after the
year during which the change in GWPs is published, the owner or
operator must discontinue using best available methods and begin
following all applicable monitoring and QA/QC requirements of this
part, except as provided in paragraph (l)(2) of this section. Best
available monitoring methods means any of the following methods:
(i) Monitoring methods currently used by the facility that do not
meet the specifications of a relevant subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2) Requests for extension of the use of best available monitoring
methods. The owner or operator may submit a request to the
Administrator to use one or more best available monitoring methods
beyond March 31 of the year after the year during which the change in
GWPs is published in the Federal Register as a final rulemaking.
(i) Timing of request. The extension request must be submitted to
EPA no later than January 31 of the year after the year during which
the change in GWPs is published in the Federal Register as a final
rulemaking.
(ii) Content of request. Requests must contain the following
information:
(A) A list of specific items of monitoring instrumentation for
which the request is being made and the locations where each piece of
[[Page 31891]]
monitoring instrumentation will be installed.
(B) Identification of the specific rule requirements (by rule
subpart, section, and paragraph numbers) for which the instrumentation
is needed.
(C) A description of the reasons that the needed equipment could
not be obtained and installed before April 1 of the year after the year
during which the change in GWPs is published in the Federal Register as
a final rulemaking.
(D) If the reason for the extension is that the equipment cannot be
purchased and delivered by April 1 of the year after the year during
which the change in GWPs is published in the Federal Register as a
final rulemaking, include supporting documentation such as the date the
monitoring equipment was ordered, investigation of alternative
suppliers and the dates by which alternative vendors promised delivery,
backorder notices or unexpected delays, descriptions of actions taken
to expedite delivery, and the current expected date of delivery.
(E) If the reason for the extension is that the equipment cannot be
installed without a process unit shutdown, include supporting
documentation demonstrating that it is not practicable to isolate the
equipment and install the monitoring instrument without a full process
unit shutdown. Include the date of the most recent process unit
shutdown, the frequency of shutdowns for this process unit, and the
date of the next planned shutdown during which the monitoring equipment
can be installed. If there has been a shutdown or if there is a planned
process unit shutdown between November 29 of the year during which the
change in GWPs is published in the Federal Register as a final
rulemaking and April 1 of the year after the year during which the
change in GWPs is published, include a justification of why the
equipment could not be obtained and installed during that shutdown.
(F) A description of the specific actions the facility will take to
obtain and install the equipment as soon as reasonably feasible and the
expected date by which the equipment will be installed and operating.
(iii) Approval criteria. To obtain approval, the owner or operator
must demonstrate to the Administrator's satisfaction that it is not
reasonably feasible to acquire, install, and operate a required piece
of monitoring equipment by April 1 of the year after the year during
which the change in GWPs is published in the Federal Register as a
final rulemaking. The use of best available methods under this
paragraph (l) will not be approved beyond December 31 of the year after
the year during which the change in GWPs is published.
0
6. Amend Sec. 98.5 by revising paragraph (b) to read as follows:
Sec. 98.5 How is the report submitted?
* * * * *
(b) For reporting year 2014 and thereafter, unless a later year is
specified in the applicable recordkeeping section, you must enter into
verification software specified by the Administrator the data specified
as verification software records in each applicable recordkeeping
section. For each data element entered into the verification software,
if the software produces a warning message for the data value and you
elect not to revise the data value, you may provide an explanation in
the verification software of why the data value is not being revised.
0
7. Amend Sec. 98.6 by:
0
a. Revising the definitions ``ASTM'', ``Bulk'', and ``Carbon dioxide
stream'';
0
b. Adding the definitions ``Cyclic'' and ``Direct air capture (DAC)''
in alphabetical order;
0
c. Removing the definition ``Fluorinated greenhouse gas'';
0
d. Adding the definition ``Fluorinated greenhouse gas (GHG)'' in
alphabetical order;
0
e. Revising the definition ``Fluorinated greenhouse gas (GHG) group'';
0
f. Adding the definition ``Fluorinated heat transfer fluids'' in
alphabetic order;
0
g. Revising the definition ``Greenhouse gas or GHG'';
0
h. Removing the definition ``Other fluorinated GHGs'';
0
i. Revising the definition ``Process vent''; and
0
j. Adding definitions ``Remaining fluorinated GHGs'', ``Saturated
chlorofluorocarbons (CFCs)'', ``Unsaturated bromochlorofluorocarbons
(BCFCs)'', ``Unsaturated bromofluorocarbons (BFCs)'', ``Unsaturated
chlorofluorocarbons (CFCs)'', ``Unsaturated
hydrobromochlorofluorocarbons (HBCFCs)'', and ``Unsaturated
hydrobromofluorocarbons (HBFCs)'' in alphabetic order.
The revisions and additions read as follows:
Sec. 98.6 Definitions.
* * * * *
ASTM means ASTM, International.
* * * * *
Bulk, with respect to industrial GHG suppliers and CO2
suppliers, means a transfer of gas in any amount that is in a container
for the transportation or storage of that substance such as cylinders,
drums, ISO tanks, and small cans. An industrial gas or CO2
that must first be transferred from a container to another container,
vessel, or piece of equipment in order to realize its intended use is a
bulk substance. An industrial GHG or CO2 that is contained
in a manufactured product such as electrical equipment, appliances,
aerosol cans, or foams is not a bulk substance.
* * * * *
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.
* * * * *
Cyclic, in the context of fluorinated GHGs, means a fluorinated GHG
in which three or more carbon atoms are connected to form a ring.
* * * * *
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.
* * * * *
Fluorinated greenhouse gas (GHG) means sulfur hexafluoride
(SF6), nitrogen trifluoride (NF3), and any fluorocarbon
except for controlled substances as defined at part 82, subpart A of
this subchapter and substances with vapor pressures of less than 1 mm
of Hg absolute at 25 degrees C. With these exceptions, ``fluorinated
GHG'' includes but is not limited to any hydrofluorocarbon, any
perfluorocarbon, any fully fluorinated linear, branched or cyclic
alkane, ether, tertiary amine or aminoether, any perfluoropolyether,
and any hydrofluoropolyether.
Fluorinated greenhouse gas (GHG) group means one of the following
sets of fluorinated GHGs:
(1) Fully fluorinated GHGs;
(2) Saturated hydrofluorocarbons with two or fewer carbon-hydrogen
bonds;
(3) Saturated hydrofluorocarbons with three or more carbon-hydrogen
bonds;
[[Page 31892]]
(4) Saturated hydrofluoroethers and hydrochlorofluoroethers with
one carbon-hydrogen bond;
(5) Saturated hydrofluoroethers and hydrochlorofluoroethers with
two carbon-hydrogen bonds;
(6) Saturated hydrofluoroethers and hydrochlorofluoroethers with
three or more carbon-hydrogen bonds;
(7) Saturated chlorofluorocarbons (CFCs);
(8) Fluorinated formates;
(9) Cyclic forms of the following: unsaturated perfluorocarbons
(PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated
hydrochlorofluorocarbons (HCFCs), unsaturated bromofluorocarbons
(BFCs), unsaturated bromochlorofluorocarbons (BCFCs), unsaturated
hydrobromofluorocarbons (HBFCs), unsaturated
hydrobromochlorofluorocarbons (HBCFCs), unsaturated halogenated ethers,
and unsaturated halogenated esters;
(10) Fluorinated acetates, carbonofluoridates, and fluorinated
alcohols other than fluorotelomer alcohols;
(11) Fluorinated aldehydes, fluorinated ketones and non-cyclic
forms of the following: unsaturated PFCs, unsaturated HFCs, unsaturated
CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated BCFCs,
unsaturated HBFCs, unsaturated HBCFCs, unsaturated halogenated ethers,
and unsaturated halogenated esters;
(12) Fluorotelomer alcohols;
(13) Fluorinated GHGs with carbon-iodine bonds; or
(14) Remaining fluorinated GHGs.
Fluorinated heat transfer fluids means fluorinated GHGs used for
temperature control, device testing, cleaning substrate surfaces and
other parts, other solvent applications, and soldering in certain types
of electronics manufacturing production processes and in other
industries. Fluorinated heat transfer fluids do not include fluorinated
GHGs used as lubricants or surfactants in electronics manufacturing.
For fluorinated heat transfer fluids, the lower vapor pressure limit of
1 mm Hg in absolute at 25 [deg]C in the definition of ``fluorinated
greenhouse gas'' in this section shall not apply. Fluorinated heat
transfer fluids include, but are not limited to, perfluoropolyethers
(including PFPMIE), perfluoroalkylamines, perfluoroalkylmorpholines,
perfluoroalkanes, perfluoroethers, perfluorocyclic ethers, and
hydrofluoroethers. Fluorinated heat transfer fluids include HFC-43-
10meee but do not include other hydrofluorocarbons.
* * * * *
Greenhouse gas or GHG means carbon dioxide (CO2),
methane (CH4), nitrous oxide (N2O), and
fluorinated greenhouse gases (GHGs) as defined in this section.
* * * * *
Process vent means a gas stream that: Is discharged through a
conveyance to the atmosphere either directly or after passing through a
control device; originates from a unit operation, including but not
limited to reactors (including reformers, crackers, and furnaces, and
separation equipment for products and recovered byproducts); and
contains or has the potential to contain GHG that is generated in the
process. Process vent does not include safety device discharges,
equipment leaks, gas streams routed to a fuel gas system or to a flare,
discharges from storage tanks.
* * * * *
Remaining fluorinated GHGs means fluorinated GHGs that are none of
the following:
(1) Fully fluorinated GHGs;
(2) Saturated hydrofluorocarbons with two or fewer carbon-hydrogen
bonds;
(3) Saturated hydrofluorocarbons with three or more carbon-hydrogen
bonds;
(4) Saturated hydrofluoroethers and hydrochlorofluoroethers with
one carbon-hydrogen bond;
(5) Saturated hydrofluoroethers and hydrochlorofluoroethers with
two carbon-hydrogen bonds;
(6) Saturated hydrofluoroethers and hydrochlorofluoroethers with
three or more carbon-hydrogen bonds;
(7) Saturated chlorofluorocarbons (CFCs);
(8) Fluorinated formates;
(9) Cyclic forms of the following: unsaturated perfluorocarbons
(PFCs), unsaturated HFCs, unsaturated CFCs, unsaturated
hydrochlorofluorocarbons (HCFCs), unsaturated bromofluorocarbons
(BFCs), unsaturated bromochlorofluorocarbons (BCFCs), unsaturated
hydrobromofluorocarbons (HBFCs), unsaturated
hydrobromochlorofluorocarbons (HBCFCs), unsaturated halogenated ethers,
and unsaturated halogenated esters;
(10) Fluorinated acetates, carbonofluoridates, and fluorinated
alcohols other than fluorotelomer alcohols;
(11) Fluorinated aldehydes, fluorinated ketones and non-cyclic
forms of the following: unsaturated PFCs, unsaturated HFCs, unsaturated
CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated BCFCs,
unsaturated HBFCs, unsaturated HBCFCs, unsaturated halogenated ethers,
and unsaturated halogenated esters;
(12) Fluorotelomer alcohols; or
(13) fluorinated GHGs with carbon-iodine bonds.
* * * * *
Saturated chlorofluorocarbons (CFCs) means fluorinated GHGs that
contain only chlorine, fluorine, and carbon and that contain only
single bonds.
* * * * *
Unsaturated bromochlorofluoro-carbons (BCFCs) means fluorinated
GHGs that contain only bromine, chlorine, fluorine, and carbon and that
contain one or more bonds that are not single bonds.
Unsaturated bromofluorocarbons (BFCs) means fluorinated GHGs that
contain only bromine, fluorine, and carbon and that contain one or more
bonds that are not single bonds.
Unsaturated chlorofluorocarbons (CFCs) means fluorinated GHGs that
contain only chlorine, fluorine, and carbon and that contain one or
more bonds that are not single bonds.
* * * * *
Unsaturated hydrobromochloro-fluorocarbons (HBCFCs) means
fluorinated GHGs that contain only hydrogen, bromine, chlorine,
fluorine, and carbon and that contain one or more bonds that are not
single bonds.
Unsaturated hydrobromofluoro-carbons (HBFCs) means fluorinated GHGs
that contain only hydrogen, bromine, fluorine, and carbon and that
contain one or more bonds that are not single bonds.
* * * * *
0
8. Amend Sec. 98.7 by:
0
a. Revising the introductory text;
0
b. Redesignating paragraphs (c) through (e) as paragraphs (b) through
(d);
0
c. Revising newly redesignated paragraph (d);
0
d. Adding new paragraph (e); and
0
e. Revising paragraphs (i) and (m)(3).
The revisions and addition 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
[[Page 31893]]
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: 202-566-1744; email: [email protected]; website: www.epa.gov/dockets/epa-docket-center-reading-room. For information on the availability of this
material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email [email protected]. The material may be obtained
from the following sources:
* * * * *
(d) ASTM International (ASTM), 100 Barr Harbor Drive, P.O. Box
CB700, West Conshohocken, Pennsylvania 19428-B2959; (800) 262-1373;
www.astm.org.
(1) ASTM C25-06, Standard Test Method for Chemical Analysis of
Limestone, Quicklime, and Hydrated Lime, approved February 15, 2006;
IBR approved for Sec. Sec. 98.114(b); 98.174(b); 98.184(b); 98.194(c);
98.334(b); and 98.504(b).
(2) ASTM C114-09, Standard Test Methods for Chemical Analysis of
Hydraulic Cement; IBR approved for Sec. 98.84(a) through (c).
(3) ASTM D235-02 (Reapproved 2007), Standard Specification for
Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent);
IBR approved for Sec. 98.6.
(4) ASTM D240-02 (Reapproved 2007), Standard Test Method for Heat
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter; IBR
approved for Sec. 98.254(e).
(5) ASTM D388-05, Standard Classification of Coals by Rank; IBR
approved for Sec. 98.6.
(6) ASTM D910-07a, Standard Specification for Aviation Gasolines;
IBR approved for Sec. 98.6.
(7) ASTM D1826-94 (Reapproved 2003), Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter; IBR approved for Sec. 98.254(e).
(8) ASTM D1836-07, Standard Specification for Commercial Hexanes;
IBR approved for Sec. 98.6.
(9) ASTM D1941-91 (Reapproved 2007), Standard Test Method for Open
Channel Flow Measurement of Water with the Parshall Flume, approved
June 15, 2007; IBR approved for Sec. 98.354(d).
(10) ASTM D1945-03, Standard Test Method for Analysis of Natural
Gas by Gas Chromatography; IBR approved for Sec. Sec. 98.74(c);
98.164(b); 98.244(b); 98.254(d); 98.324(d); 98.344(b); 98.354(g).
(11) ASTM D1946-90 (Reapproved 2006), Standard Practice for
Analysis of Reformed Gas by Gas Chromatography; IBR approved for
Sec. Sec. 98.74(c); 98.164(b); 98.254(d); 98.324(d); 98.344(b);
98.354(g); 98.364(c).
(12) ASTM D2013-07, Standard Practice for Preparing Coal Samples
for Analysis; IBR approved for Sec. 98.164(b).
(13) ASTM D2234/D2234M-07, Standard Practice for Collection of a
Gross Sample of Coal; IBR approved for Sec. 98.164(b).
(14) ASTM D2502-04, Standard Test Method for Estimation of Mean
Relative Molecular Mass of Petroleum Oils From Viscosity Measurements;
IBR approved for Sec. 98.74(c).
(15) ASTM D2503-92 (Reapproved 2007), Standard Test Method for
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor Pressure; IBR approved for
Sec. Sec. 98.74(c); 98.254(d)(6).
(16) ASTM D2505-88 (Reapproved 2004)e1, Standard Test Method for
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity
Ethylene by Gas Chromatography; IBR approved for Sec. 98.244(b).
(17) ASTM D2593-93 (Reapproved 2009), Standard Test Method for
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography,
approved July 1, 2009; IBR approved for Sec. 98.244(b).
(18) ASTM D2597-94 (Reapproved 2004), Standard Test Method for
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing
Nitrogen and Carbon Dioxide by Gas Chromatography; IBR approved for
Sec. 98.164(b).
(19) ASTM D2879-97 (Reapproved 2007), Standard Test Method for
Vapor Pressure-Temperature Relationship and Initial Decomposition
Temperature of Liquids by Isoteniscope (ASTM D2879), approved May 1,
2007; IBR approved for Sec. 98.128.
(20) ASTM D3176-15, Standard Practice for Ultimate Analysis of Coal
and Coke, approved January 1, 2015; IBR approved for Sec. 98.494(c).
(21) ASTM D3176-89 (Reapproved 2002), Standard Practice for
Ultimate Analysis of Coal and Coke; IBR approved for Sec. Sec.
98.74(c); 98.164(b); 98.244(b); 98.284(c) and (d); 98.314(c), (d), and
(f).
(22) ASTM D3238-95 (Reapproved 2005), Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method; IBR approved for Sec. Sec.
98.74(c); 98.164(b).
(23) ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels; IBR approved for Sec. 98.254(e).
(24) ASTM D3682-01 (Reapproved 2006), Standard Test Method for
Major and Minor Elements in Combustion Residues from Coal Utilization
Processes; IBR approved for Sec. 98.144(b).
(25) ASTM D4057-06, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products; IBR approved for Sec. 98.164(b).
(26) ASTM D4177-95 (Reapproved 2005), Standard Practice for
Automatic Sampling of Petroleum and Petroleum Products; IBR approved
for Sec. 98.164(b).
(27) ASTM D4809-06, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method); IBR
approved for Sec. 98.254(e).
(28) ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion; IBR approved for Sec. Sec. 98.254(e); 98.324(d).
(29) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants; IBR approved for Sec. Sec.
98.74(c); 98.164(b); 98.244(b).
(30) ASTM D5291-16, Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products
and Lubricants, approved October 1, 2016; IBR approved for Sec.
98.494(c).
(31) ASTM D5373-08, Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal, approved February 1, 2008; IBR approved for Sec. Sec.
98.74(c); 98.114(b); 98.164(b); 98.174(b); 98.184(b); 98.244(b);
98.274(b); 98.284(c) and (d); 98.314(c), (d), and (f); 98.334(b);
98.504(b).
(32) ASTM D5373-21, Standard Test Methods for Determination of
Carbon, Hydrogen, and Nitrogen in Analysis Samples of Coal and Carbon
in Analysis Samples of Coal and Coke, approved April 1, 2021; IBR
approved for Sec. 98.494(c).
(33) ASTM D5614-94 (Reapproved 2008), Standard Test Method for Open
Channel Flow Measurement of Water with Broad-Crested Weirs, approved
October 1, 2008; IBR approved for Sec. 98.354(d).
(34) ASTM D6060-96 (Reapproved 2001), Standard Practice for
Sampling of Process Vents With a Portable Gas Chromatograph; IBR
approved for Sec. 98.244(b).
(35) ASTM D6348-03, Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared
[[Page 31894]]
(FTIR) Spectroscopy; IBR approved for Sec. 98.54(b); table I-9 to
subpart I of this part; Sec. Sec. 98.224(b); 98.414(n).
(36) ASTM D6349-09, Standard Test Method for Determination of Major
and Minor Elements in Coal, Coke, and Solid Residues from Combustion of
Coal and Coke by Inductively Coupled Plasma--Atomic Emission
Spectrometry; IBR approved for Sec. 98.144(b).
(37) ASTM D6609-08, Standard Guide for Part-Stream Sampling of
Coal; IBR approved for Sec. 98.164(b).
(38) ASTM D6751-08, Standard Specification for Biodiesel Fuel Blend
Stock (B100) for Middle Distillate Fuels; IBR approved for Sec. 98.6.
(39) ASTM D6866-16, Standard Test Methods for Determining the
Biobased Content of Solid, Liquid, and Gaseous Samples Using
Radiocarbon Analysis, approved June 1, 2016; IBR approved for
Sec. Sec. 98.34(d) and (e); 98.36(e).
(40) ASTM D6883-04, Standard Practice for Manual Sampling of
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles; IBR
approved for Sec. 98.164(b).
(41) ASTM D7359-08, Standard Test Method for Total Fluorine,
Chlorine and Sulfur in Aromatic Hydrocarbons and Their Mixtures by
Oxidative Pyrohydrolytic Combustion followed by Ion Chromatography
Detection (Combustion Ion Chromatography-CIC) (ASTM D7359), approved
October 15, 2008; IBR approved for Sec. 98.124(e)(2).
(42) ASTM D7430-08ae1, Standard Practice for Mechanical Sampling of
Coal; IBR approved for Sec. 98.164(b).
(43) 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; IBR approved
for Sec. Sec. 98.34(d) and (e); 98.36(e).
(44) ASTM D7633-10, Standard Test Method for Carbon Black--Carbon
Content, approved May 15, 2010; IBR approved for Sec. 98.244(b).
(45) ASTM E359-00 (Reapproved 2005)e1, Standard Test Methods for
Analysis of Soda Ash (Sodium Carbonate); IBR approved for Sec.
98.294(a) and (b).
(46) ASTM E415-17, Standard Test Method for Analysis of Carbon and
Low-Alloy Steel by Spark Atomic Emission Spectrometry, approved May 15,
2017; IBR approved for Sec. 98.174(b).
(47) ASTM E1019-08, Standard Test Methods for Determination of
Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt
Alloys by Various Combustion and Fusion Techniques; IBR approved for
Sec. 98.174(b).
(48) ASTM E1915-07a, Standard Test Methods for Analysis of Metal
Bearing Ores and Related Materials by Combustion Infrared-Absorption
Spectrometry; IBR approved for Sec. 98.174(b).
(49) ASTM E1941-04, Standard Test Method for Determination of
Carbon in Refractory and Reactive Metals and Their Alloys; IBR approved
for Sec. Sec. 98.114(b); 98.184(b); 98.334(b).
(50) ASTM UOP539-97, Refinery Gas Analysis by Gas Chromatography;
IBR approved for Sec. Sec. 98.164(b); 98.244(b); 98.254(d); 98.324(d);
98.344(b); 98.354(g).
(e) CSA Group (CSA), 178 Rexdale Boulevard, Toronto, Ontario Canada
M9W 183; (800) 463-6727; https://shop.csa.ca.
(1) CSA/ANSI ISO 27916:19, Carbon dioxide capture, transportation
and geological storage--Carbon dioxide storage using enhanced oil
recovery (CO2-EOR), approved August 30, 2019; IBR approved
for Sec. Sec. 98.470(c); 98.480(a); 98.481(a) through (c); 98.482;
98.483; 98.484; 98.485; 98.486(g); 98.487; 98.488(a)(5); 98.489.
Note 1 to paragraph (e)(1): This standard is also available
from ISO as ISO 27916:2019(E).
(2) [Reserved]
* * * * *
(i) National Institute of Standards and Technology (NIST), 100
Bureau Drive, Stop 1070, Gaithersburg, MD 20899-1070, (800) 877-8339,
www.nist.gov/.
(1) NIST HB 44-2023: Specifications, Tolerances, and Other
Technical Requirements For Weighing and Measuring Devices, 2023
edition, approved November 18, 2022; IBR approved for Sec. 98.494(b).
(2) Specifications, Tolerances, and Other Technical Requirements
For Weighing and Measuring Devices, NIST Handbook 44 (2009); IBR
approved for Sec. Sec. 98.244(b); 98.344(a).
* * * * *
(m) * * *
(3) Protocol for Measuring Destruction or Removal Efficiency (DRE)
of Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing, Version 1, EPA-430-R-10-003, March 2010 (EPA 430-R-10-
003), approved March 2010; IBR approved for Sec. Sec. 98.94(e);
98.94(f) and (g); 98.97(b) and (d); 98.98; appendix A to subpart I of
this part; Sec. Sec. 98.124(e); 98.414(n). (Also available from:
www.epa.gov/sites/default/files/2016-02/documents/dre_protocol.pdf.)
* * * * *
0
9. Revise table A-1 to subpart A to read as follows:
Table A-1 to Subpart A of Part 98--Global Warming Potentials, 100-Year Time Horizon
----------------------------------------------------------------------------------------------------------------
Global
warming
Name CAS No. Chemical formula potential
(100 yr.)
----------------------------------------------------------------------------------------------------------------
Chemical-Specific GWPs
----------------------------------------------------------------------------------------------------------------
Carbon dioxide.............................. 124-38-9 CO2............................ 1
Methane..................................... 74-82-8 CH4............................ \a\ \d\ 28
Nitrous oxide............................... 10024-97-2 N2O............................ \a\ \d\ 265
----------------------------------------------------------------------------------------------------------------
Fully Fluorinated GHGs
----------------------------------------------------------------------------------------------------------------
Sulfur hexafluoride......................... 2551-62-4 SF6............................ \a\ \d\ 23,500
Trifluoromethyl sulphur pentafluoride....... 373-80-8 SF5CF3......................... \d\ 17,400
Nitrogen trifluoride........................ 7783-54-2 NF3............................ \d\ 16,100
PFC-14 (Perfluoromethane)................... 75-73-0 CF4............................ \a\ \d\ 6,630
PFC-116 (Perfluoroethane)................... 76-16-4 C2F6........................... \a\ \d\ 11,100
PFC-218 (Perfluoropropane).................. 76-19-7 C3F8........................... \a\ \d\ 8,900
Perfluorocyclopropane....................... 931-91-9 c-C3F6......................... \d\ 9,200
PFC-3-1-10 (Perfluorobutane)................ 355-25-9 C4F10.......................... \a\ \d\ 9,200
PFC-318 (Perfluorocyclobutane).............. 115-25-3 c-C4F8......................... \a\ \d\ 9,540
[[Page 31895]]
Perfluorotetrahydrofuran.................... 773-14-8 c-C4F8O........................ \e\ 13,900
PFC-4-1-12 (Perfluoropentane)............... 678-26-2 C5F12.......................... \a\ \d\ 8,550
PFC-5-1-14 (Perfluorohexane, FC-72)......... 355-42-0 C6F14.......................... \a\ \d\ 7,910
PFC-6-1-12.................................. 335-57-9 C7F16; CF3(CF2)5CF3............ \b\ 7,820
PFC-7-1-18.................................. 307-34-6 C8F18; CF3(CF2)6CF3............ \b\ 7,620
PFC-9-1-18.................................. 306-94-5 C10F18......................... \d\ 7,190
PFPMIE (HT-70).............................. NA CF3OCF(CF3)CF2OCF2OCF3......... \d\ 9,710
Perfluorodecalin (cis)...................... 60433-11-6 Z-C10F18....................... \b\ \d\ 7,240
Perfluorodecalin (trans).................... 60433-12-7 E-C10F18....................... \b\ \d\ 6,290
Perfluorotriethylamine...................... 359-70-6 N(C2F5)3....................... \e\ 10,300
Perfluorotripropylamine..................... 338-83-0 N(CF2CF2CF3)3.................. \e\ 9,030
Perfluorotributylamine...................... 311-89-7 N(CF2CF2CF2CF3)3............... \e\ 8,490
Perfluorotripentylamine..................... 338-84-1 N(CF2CF2CF2CF2CF3)3............ \e\ 7,260
----------------------------------------------------------------------------------------------------------------
Saturated Hydrofluorocarbons (HFCs) With Two or Fewer Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
(4s,5s)-1,1,2,2,3,3,4,5- 158389-18-5 trans-cyc (-CF2CF2CF2CHFCHF-).. \e\ 258
octafluorocyclopentane.
HFC-23...................................... 75-46-7 CHF3........................... \a\ \d\ 12,400
HFC-32...................................... 75-10-5 CH2F2.......................... \a\ \d\ 677
HFC-125..................................... 354-33-6 C2HF5.......................... \a\ \d\ 3,170
HFC-134..................................... 359-35-3 C2H2F4......................... \a\ \d\ 1,120
HFC-134a.................................... 811-97-2 CH2FCF3........................ \a\ \d\ 1,300
HFC-227ca................................... 2252-84-8 CF3CF2CHF2..................... \b\ 2,640
HFC-227ea................................... 431-89-0 C3HF7.......................... \a\ \d\ 3,350
HFC-236cb................................... 677-56-5 CH2FCF2CF3..................... \d\ 1,210
HFC-236ea................................... 431-63-0 CHF2CHFCF3..................... \d\ 1,330
HFC-236fa................................... 690-39-1 C3H2F6......................... \a\ \d\ 8,060
HFC-329p.................................... 375-17-7 CHF2CF2CF2CF3.................. \b\ 2360
HFC-43-10mee................................ 138495-42-8 CF3CFHCFHCF2CF3................ \a\ \d\ 1,650
----------------------------------------------------------------------------------------------------------------
Saturated Hydrofluorocarbons (HFCs) With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
1,1,2,2,3,3-hexafluorocyclopentane.......... 123768-18-3 cyc (-CF2CF2CF2CH2CH2-)........ \e\ 120
1,1,2,2,3,3,4-heptafluorocyclopentane....... 15290-77-4 cyc (-CF2CF2CF2CHFCH2-)........ \e\ 231
HFC-41...................................... 593-53-3 CH3F........................... \a\ \d\ 116
HFC-143..................................... 430-66-0 C2H3F3......................... \a\ \d\ 328
HFC-143a.................................... 420-46-2 C2H3F3......................... \a\ \d\ 4,800
HFC-152..................................... 624-72-6 CH2FCH2F....................... \d\ 16
HFC-152a.................................... 75-37-6 CH3CHF2........................ \a\ \d\ 138
HFC-161..................................... 353-36-6 CH3CH2F........................ \d\ 4
HFC-245ca................................... 679-86-7 C3H3F5......................... \a\ \d\ 716
HFC-245cb................................... 1814-88-6 CF3CF2CH3...................... \b\ 4,620
HFC-245ea................................... 24270-66-4 CHF2CHFCHF2.................... \b\ 235
HFC-245eb................................... 431-31-2 CH2FCHFCF3..................... \b\ 290
HFC-245fa................................... 460-73-1 CHF2CH2CF3..................... \d\ 858
HFC-263fb................................... 421-07-8 CH3CH2CF3...................... \b\ 76
HFC-272ca................................... 420-45-1 CH3CF2CH3...................... \b\ 144
HFC-365mfc.................................. 406-58-6 CH3CF2CH2CF3................... \d\ 804
----------------------------------------------------------------------------------------------------------------
Saturated Hydrofluoroethers (HFEs) and Hydrochlorofluoroethers (HCFEs) With One Carbon-Hydrogen Bond
----------------------------------------------------------------------------------------------------------------
HFE-125..................................... 3822-68-2 CHF2OCF3....................... \d\ 12,400
HFE-227ea................................... 2356-62-9 CF3CHFOCF3..................... \d\ 6,450
HFE-329mcc2................................. 134769-21-4 CF3CF2OCF2CHF2................. \d\ 3,070
HFE-329me3.................................. 428454-68-6 CF3CFHCF2OCF3.................. \b\ 4,550
1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2- 3330-15-2 CF3CF2CF2OCHFCF3............... \b\ 6,490
tetrafluoroethoxy)-propane.
----------------------------------------------------------------------------------------------------------------
Saturated HFEs and HCFEs With Two Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-134 (HG-00)............................. 1691-17-4 CHF2OCHF2...................... \d\ 5,560
HFE-236ca................................... 32778-11-3 CHF2OCF2CHF2................... \b\ 4,240
HFE-236ca12 (HG-10)......................... 78522-47-1 CHF2OCF2OCHF2.................. \d\ 5,350
HFE-236ea2 (Desflurane)..................... 57041-67-5 CHF2OCHFCF3.................... \d\ 1,790
HFE-236fa................................... 20193-67-3 CF3CH2OCF3..................... \d\ 979
HFE-338mcf2................................. 156053-88-2 CF3CF2OCH2CF3.................. \d\ 929
HFE-338mmz1................................. 26103-08-2 CHF2OCH(CF3)2.................. \d\ 2,620
HFE-338pcc13 (HG-01)........................ 188690-78-0 CHF2OCF2CF2OCHF2............... \d\ 2,910
HFE-43-10pccc (H-Galden 1040x, HG-11)....... E1730133 CHF2OCF2OC2F4OCHF2............. \d\ 2,820
HCFE-235ca2 (Enflurane)..................... 13838-16-9 CHF2OCF2CHFCl.................. \b\ 583
[[Page 31896]]
HCFE-235da2 (Isoflurane).................... 26675-46-7 CHF2OCHClCF3................... \d\ 491
HG-02....................................... 205367-61-9 HF2C-(OCF2CF2)2-OCF2H.......... \b\ \d\ 2,730
HG-03....................................... 173350-37-3 HF2C-(OCF2CF2)3-OCF2H.......... \b\ \d\ 2,850
HG-20....................................... 249932-25-0 HF2C-(OCF2)2-OCF2H............. \b\ 5,300
HG-21....................................... 249932-26-1 HF2C-OCF2CF2OCF2OCF2O-CF2H..... \b\ 3,890
HG-30....................................... 188690-77-9 HF2C-(OCF2)3-OCF2H............. \b\ 7,330
1,1,3,3,4,4,6,6,7,7,9,9,10,10,12,12,13,13,15 173350-38-4 HCF2O(CF2CF2O)4CF2H............ \b\ 3,630
,15-eicosafluoro-2,5,8,11,14-
Pentaoxapentadecane.
1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane. 84011-06-3 CHF2CHFOCF3.................... \b\ 1,240
Trifluoro(fluoromethoxy)methane............. 2261-01-0 CH2FOCF3....................... \b\ 751
----------------------------------------------------------------------------------------------------------------
Saturated HFEs and HCFEs With Three or More Carbon-Hydrogen Bonds
----------------------------------------------------------------------------------------------------------------
HFE-143a.................................... 421-14-7 CH3OCF3........................ \d\ 523
HFE-245cb2.................................. 22410-44-2 CH3OCF2CF3..................... \d\ 654
HFE-245fa1.................................. 84011-15-4 CHF2CH2OCF3.................... \d\ 828
HFE-245fa2.................................. 1885-48-9 CHF2OCH2CF3.................... \d\ 812
HFE-254cb1.................................. 425-88-7 CH3OCF2CHF2.................... \d\ 301
HFE-263fb2.................................. 460-43-5 CF3CH2OCH3..................... \d\ 1
HFE-263m1; R-E-143a......................... 690-22-2 CF3OCH2CH3..................... \b\ 29
HFE-347mcc3 (HFE-7000)...................... 375-03-1 CH3OCF2CF2CF3.................. \d\ 530
HFE-347mcf2................................. 171182-95-9 CF3CF2OCH2CHF2................. \d\ 854
HFE-347mmy1................................. 22052-84-2 CH3OCF(CF3)2................... \d\ 363
HFE-347mmz1 (Sevoflurane)................... 28523-86-6 (CF3)2CHOCH2F.................. \c\ 216
HFE-347pcf2................................. 406-78-0 CHF2CF2OCH2CF3................. \d\ 889
HFE-356mec3................................. 382-34-3 CH3OCF2CHFCF3.................. \d\ 387
HFE-356mff2................................. 333-36-8 CF3CH2OCH2CF3.................. \b\ 17
HFE-356mmz1................................. 13171-18-1 (CF3)2CHOCH3................... \d\ 14
HFE-356pcc3................................. 160620-20-2 CH3OCF2CF2CHF2................. \d\ 413
HFE-356pcf2................................. 50807-77-7 CHF2CH2OCF2CHF2................ \d\ 719
HFE-356pcf3................................. 35042-99-0 CHF2OCH2CF2CHF2................ \d\ 446
HFE-365mcf2................................. 22052-81-9 CF3CF2OCH2CH3.................. \b\ 58
HFE-365mcf3................................. 378-16-5 CF3CF2CH2OCH3.................. \d\ 0.99
HFE-374pc2.................................. 512-51-6 CH3CH2OCF2CHF2................. \d\ 627
HFE-449s1 (HFE-7100) Chemical blend......... 163702-07-6 C4F9OCH3....................... \d\ 421
163702-08-7 (CF3)2CFCF2OCH3................ ..............
HFE-569sf2 (HFE-7200) Chemical blend........ 163702-05-4 C4F9OC2H5...................... \d\ 57
163702-06-5 (CF3)2CFCF2OC2H5............... ..............
HFE-7300.................................... 132182-92-4 (CF3)2CFCFOC2H5CF2CF2CF3....... \e\ 405
HFE-7500.................................... 297730-93-9 n-C3F7CFOC2H5CF(CF3)2.......... \e\ 13
HG'-01...................................... 73287-23-7 CH3OCF2CF2OCH3................. \b\ 222
HG'-02...................................... 485399-46-0 CH3O(CF2CF2O)2CH3.............. \b\ 236
HG'-03...................................... 485399-48-2 CH3O(CF2CF2O)3CH3.............. \b\ 221
Difluoro(methoxy)methane.................... 359-15-9 CH3OCHF2....................... \b\ 144
2-Chloro-1,1,2-trifluoro-1-methoxyethane.... 425-87-6 CH3OCF2CHFCl................... \b\ 122
1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane... 22052-86-4 CF3CF2CF2OCH2CH3............... \b\ 61
2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5- 920979-28-8 C12H5F19O2..................... \b\ 56
bis[1,2,2,2-tetrafluoro-1-
(trifluoromethyl)ethyl]-furan.
1-Ethoxy-1,1,2,3,3,3-hexafluoropropane...... 380-34-7 CF3CHFCF2OCH2CH3............... \b\ 23
Fluoro(methoxy)methane...................... 460-22-0 CH3OCH2F....................... \b\ 13
1,1,2,2-Tetrafluoro-3-methoxy-propane; 60598-17-6 CHF2CF2CH2OCH3................. \b\ \d\ 0.49
Methyl 2,2,3,3-tetrafluoropropyl ether.
1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane. 37031-31-5 CH2FOCF2CF2H................... \b\ 871
Difluoro(fluoromethoxy)methane.............. 461-63-2 CH2FOCHF2...................... \b\ 617
Fluoro(fluoromethoxy)methane................ 462-51-1 CH2FOCH2F...................... \b\ 130
----------------------------------------------------------------------------------------------------------------
Saturated Chlorofluorocarbons (CFCs)
----------------------------------------------------------------------------------------------------------------
E-R316c..................................... 3832-15-3 trans-cyc (-CClFCF2CF2CClF-)... \e\ 4,230
Z-R316c..................................... 3934-26-7 cis-cyc (-CClFCF2CF2CClF-)..... \e\ 5,660
----------------------------------------------------------------------------------------------------------------
Fluorinated Formates
----------------------------------------------------------------------------------------------------------------
Trifluoromethyl formate..................... 85358-65-2 HCOOCF3........................ \b\ 588
Perfluoroethyl formate...................... 313064-40-3 HCOOCF2CF3..................... \b\ 580
1,2,2,2-Tetrafluoroethyl formate............ 481631-19-0 HCOOCHFCF3..................... \b\ 470
Perfluorobutyl formate...................... 197218-56-7 HCOOCF2CF2CF2CF3............... \b\ 392
Perfluoropropyl formate..................... 271257-42-2 HCOOCF2CF2CF3.................. \b\ 376
1,1,1,3,3,3-Hexafluoropropan-2-yl formate... 856766-70-6 HCOOCH(CF3)2................... \b\ 333
2,2,2-Trifluoroethyl formate................ 32042-38-9 HCOOCH2CF3..................... \b\ 33
[[Page 31897]]
3,3,3-Trifluoropropyl formate............... 1344118-09-7 HCOOCH2CH2CF3.................. \b\ 17
----------------------------------------------------------------------------------------------------------------
Fluorinated Acetates
----------------------------------------------------------------------------------------------------------------
Methyl 2,2,2-trifluoroacetate............... 431-47-0 CF3COOCH3...................... \b\ 52
1,1-Difluoroethyl 2,2,2-trifluoroacetate.... 1344118-13-3 CF3COOCF2CH3................... \b\ 31
Difluoromethyl 2,2,2-trifluoroacetate....... 2024-86-4 CF3COOCHF2..................... \b\ 27
2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate. 407-38-5 CF3COOCH2CF3................... \b\ 7
Methyl 2,2-difluoroacetate.................. 433-53-4 HCF2COOCH3..................... \b\ 3
Perfluoroethyl acetate...................... 343269-97-6 CH3COOCF2CF3................... \b\ \d\ 2
Trifluoromethyl acetate..................... 74123-20-9 CH3COOCF3...................... \b\ \d\ 2
Perfluoropropyl acetate..................... 1344118-10-0 CH3COOCF2CF2CF3................ \b\ \d\ 2
Perfluorobutyl acetate...................... 209597-28-4 CH3COOCF2CF2CF2CF3............. \b\ \d\ 2
Ethyl 2,2,2-trifluoroacetate................ 383-63-1 CF3COOCH2CH3................... \b\ \d\ 1
----------------------------------------------------------------------------------------------------------------
Carbonofluoridates
----------------------------------------------------------------------------------------------------------------
Methyl carbonofluoridate.................... 1538-06-3 FCOOCH3........................ \b\ 95
1,1-Difluoroethyl carbonofluoridate......... 1344118-11-1 FCOOCF2CH3..................... \b\ 27
----------------------------------------------------------------------------------------------------------------
Fluorinated Alcohols Other Than Fluorotelomer Alcohols
----------------------------------------------------------------------------------------------------------------
Bis(trifluoromethyl)-methanol............... 920-66-1 (CF3)2CHOH..................... \d\ 182
2,2,3,3,4,4,5,5-Octafluorocyclopentanol..... 16621-87-7 cyc (-(CF2)4CH(OH)-)........... \d\ 13
2,2,3,3,3-Pentafluoropropanol............... 422-05-9 CF3CF2CH2OH.................... \d\ 19
2,2,3,3,4,4,4-Heptafluorobutan-1-ol......... 375-01-9 C3F7CH2OH...................... \b\ \d\ 34
2,2,2-Trifluoroethanol...................... 75-89-8 CF3CH2OH....................... \b\ 20
2,2,3,4,4,4-Hexafluoro-1-butanol............ 382-31-0 CF3CHFCF2CH2OH................. \b\ 17
2,2,3,3-Tetrafluoro-1-propanol.............. 76-37-9 CHF2CF2CH2OH................... \b\ 13
2,2-Difluoroethanol......................... 359-13-7 CHF2CH2OH...................... \b\ 3
2-Fluoroethanol............................. 371-62-0 CH2FCH2OH...................... \b\ 1.1
4,4,4-Trifluorobutan-1-ol................... 461-18-7 CF3(CH2)2CH2OH................. \b\ 0.05
----------------------------------------------------------------------------------------------------------------
Non-Cyclic, Unsaturated Perfluorocarbons (PFCs)
----------------------------------------------------------------------------------------------------------------
PFC-1114; TFE............................... 116-14-3 CF2 = CF2; C2F4................ \b\ 0.004
PFC-1216; Dyneon HFP........................ 116-15-4 C3F6; CF3CF = CF2.............. \b\ 0.05
Perfluorobut-2-ene.......................... 360-89-4 CF3CF = CFCF3.................. \b\ 1.82
Perfluorobut-1-ene.......................... 357-26-6 CF3CF2CF = CF2................. \b\ 0.10
Perfluorobuta-1,3-diene..................... 685-63-2 CF2 = CFCF = CF2............... \b\ 0.003
----------------------------------------------------------------------------------------------------------------
Non-Cyclic, Unsaturated Hydrofluorocarbons (HFCs) and Hydrochlorofluorocarbons (HCFCs)
----------------------------------------------------------------------------------------------------------------
HFC-1132a; VF2.............................. 75-38-7 C2H2F2, CF2 = CH2.............. \b\ 0.04
HFC-1141; VF................................ 75-02-5 C2H3F, CH2 = CHF............... \b\ 0.02
(E)-HFC-1225ye.............................. 5595-10-8 CF3CF = CHF(E)................. \b\ 0.06
(Z)-HFC-1225ye.............................. 5528-43-8 CF3CF = CHF(Z)................. \b\ 0.22
Solstice 1233zd(E).......................... 102687-65-0 C3H2ClF3; CHCl = CHCF3......... \b\ 1.34
HCFO-1233zd(Z).............................. 99728-16-2 (Z)-CF3CH = CHCl............... \e\ 0.45
HFC-1234yf; HFO-1234yf...................... 754-12-1 C3H2F4; CF3CF = CH2............ \b\ 0.31
HFC-1234ze(E)............................... 1645-83-6 C3H2F4; trans-CF3CH = CHF...... \b\ 0.97
HFC-1234ze(Z)............................... 29118-25-0 C3H2F4; cis-CF3CH = CHF; CF3CH \b\ 0.29
= CHF.
HFC-1243zf; TFP............................. 677-21-4 C3H3F3, CF3CH = CH2............ \b\ 0.12
(Z)-HFC-1336................................ 692-49-9 CF3CH = CHCF3(Z)............... \b\ 1.58
HFO-1336mzz(E).............................. 66711-86-2 (E)-CF3CH = CHCF3.............. \e\ 18
HFC-1345zfc................................. 374-27-6 C2F5CH = CH2................... \b\ 0.09
HFO-1123.................................... 359-11-5 CHF=CF2........................ \e\ 0.005
HFO-1438ezy(E).............................. 14149-41-8 (E)-(CF3)2CFCH = CHF........... \e\ 8.2
HFO-1447fz.................................. 355-08-8 CF3(CF2)2CH = CH2.............. \e\ 0.24
Capstone 42-U............................... 19430-93-4 C6H3F9, CF3(CF2)3CH = CH2...... \b\ 0.16
Capstone 62-U............................... 25291-17-2 C8H3F13, CF3(CF2)5CH = CH2..... \b\ 0.11
Capstone 82-U............................... 21652-58-4 C10H3F17, CF3(CF2)7CH = CH2.... \b\ 0.09
(e)-1-chloro-2-fluoroethene................. 460-16-2 (E)-CHCl = CHF................. \e\ 0.004
3,3,3-trifluoro-2-(trifluoromethyl)prop-1- 382-10-5 (CF3)2C = CH2.................. \e\ 0.38
ene.
----------------------------------------------------------------------------------------------------------------
Non-Cyclic, Unsaturated CFCs
----------------------------------------------------------------------------------------------------------------
CFC-1112.................................... 598-88-9 CClF=CClF...................... \e\ 0.13
CFC-1112a................................... 79-35-6 CCl2=CF2....................... \e\ 0.021
----------------------------------------------------------------------------------------------------------------
[[Page 31898]]
Non-Cyclic, Unsaturated Halogenated Ethers
----------------------------------------------------------------------------------------------------------------
PMVE; HFE-216............................... 1187-93-5 CF3OCF = CF2................... \b\ 0.17
Fluoroxene.................................. 406-90-6 CF3CH2OCH = CH2................ \b\ 0.05
Methyl-perfluoroheptene-ethers.............. N/A CH3OC7F13...................... \e\ 15
----------------------------------------------------------------------------------------------------------------
Non-Cyclic, Unsaturated Halogenated Esters
----------------------------------------------------------------------------------------------------------------
Ethenyl 2,2,2-trifluoroacetate.............. 433-28-3 CF3COOCH=CH2................... \e\ 0.008
Prop-2-enyl 2,2,2-trifluoroacetate.......... 383-67-5 CF3COOCH2CH=CH2................ \e\ 0.007
----------------------------------------------------------------------------------------------------------------
Cyclic, Unsaturated HFCs and PFCs
----------------------------------------------------------------------------------------------------------------
PFC C-1418.................................. 559-40-0 c-C5F8......................... \d\ 2
Hexafluorocyclobutene....................... 697-11-0 cyc (-CF=CFCF2CF2-)............ \e\ 126
1,3,3,4,4,5,5-heptafluorocyclopentene....... 1892-03-1 cyc (-CF2CF2CF2CF=CH-)......... \e\ 45
1,3,3,4,4-pentafluorocyclobutene............ 374-31-2 cyc (-CH=CFCF2CF2-)............ \e\ 92
3,3,4,4-tetrafluorocyclobutene.............. 2714-38-7 cyc (-CH=CHCF2CF2-)............ \e\ 26
----------------------------------------------------------------------------------------------------------------
Fluorinated Aldehydes
----------------------------------------------------------------------------------------------------------------
3,3,3-Trifluoro-propanal.................... 460-40-2 CF3CH2CHO...................... \b\ 0.01
----------------------------------------------------------------------------------------------------------------
Fluorinated Ketones
----------------------------------------------------------------------------------------------------------------
Novec 1230 (perfluoro (2-methyl-3- 756-13-8 CF3CF2C(O)CF (CF3)2............ \b\ 0.1
pentanone)).
1,1,1-trifluoropropan-2-one................. 421-50-1 CF3COCH3....................... \e\ 0.09
1,1,1-trifluorobutan-2-one.................. 381-88-4 CF3COCH2CH3.................... \e\ 0.095
----------------------------------------------------------------------------------------------------------------
Fluorotelomer Alcohols
----------------------------------------------------------------------------------------------------------------
3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1- 185689-57-0 CF3(CF2)4CH2CH2OH.............. \b\ 0.43
ol.
3,3,3-Trifluoropropan-1-ol.................. 2240-88-2 CF3CH2CH2OH.................... \b\ 0.35
3,3,4,4,5,5,6,6,7,7,8,8,9,9,9- 755-02-2 CF3(CF2)6CH2CH2OH.............. \b\ 0.33
Pentadecafluorononan-1-ol.
3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11- 87017-97-8 CF3(CF2)8CH2CH2OH.............. \b\ 0.19
Nonadecafluoroundecan-1-ol.
----------------------------------------------------------------------------------------------------------------
Fluorinated GHGs With Carbon-Iodine Bond(s)
----------------------------------------------------------------------------------------------------------------
Trifluoroiodomethane........................ 2314-97-8 CF3I........................... \b\ 0.4
----------------------------------------------------------------------------------------------------------------
Remaining Fluorinated GHGs with Chemical-Specific GWPs
----------------------------------------------------------------------------------------------------------------
Dibromodifluoromethane (Halon 1202)......... 75-61-6 CBr2F2......................... \b\ 231
2-Bromo-2-chloro-1,1,1-trifluoroethane 151-67-7 CHBrClCF3...................... \b\ 41
(Halon-2311/Halothane).
Heptafluoroisobutyronitrile................. 42532-60-5 (CF3)2CFCN..................... \e\ 2,750
Carbonyl fluoride........................... 353-50-4 COF2........................... \e\ 0.14
----------------------------------------------------------------------------------------------------------------
------------------------------------------------------------------------
Global warming
Fluorinated GHG group \f\ potential (100
yr.)
------------------------------------------------------------------------
Default GWPs for Compounds for Which Chemical-Specific GWPs Are Not
Listed Above
------------------------------------------------------------------------
Fully fluorinated GHGs \g\............................. 9,200
Saturated hydrofluorocarbons (HFCs) with 2 or fewer 3,000
carbon-hydrogen bonds \g\.............................
Saturated HFCs with 3 or more carbon-hydrogen bonds \g\ 840
Saturated hydrofluoroethers (HFEs) and 6,600
hydrochlorofluoroethers (HCFEs) with 1 carbon-hydrogen
bond \g\..............................................
Saturated HFEs and HCFEs with 2 carbon-hydrogen bonds 2,900
\g\...................................................
Saturated HFEs and HCFEs with 3 or more carbon-hydrogen 320
bonds \g\.............................................
Saturated chlorofluorocarbons (CFCs) \g\............... 4,900
Fluorinated formates................................... 350
Cyclic forms of the following: unsaturated 58
perfluorocarbons (PFCs), unsaturated HFCs, unsaturated
CFCs, unsaturated hydrochlorofluorocarbons (HCFCs),
unsaturated bromofluorocarbons (BFCs), unsaturated
bromochlorofluorocarbons (BCFCs), unsaturated
hydrobromofluorocarbons (HBFCs), unsaturated
hydrobromochlorofluorocarbons (HBCFCs), unsaturated
halogenated ethers, and unsaturated halogenated esters
\g\...................................................
Fluorinated acetates, carbonofluoridates, and 25
fluorinated alcohols other than fluorotelomer alcohols
\g\...................................................
[[Page 31899]]
Fluorinated aldehydes, fluorinated ketones, and non- 1
cyclic forms of the following: unsaturated
perfluorocarbons (PFCs), unsaturated HFCs, unsaturated
CFCs, unsaturated HCFCs, unsaturated BFCs, unsaturated
BCFCs, unsaturated HBFCs, unsaturated HBCFCs,
unsaturated halogenated ethers and unsaturated
halogenated esters \g\................................
Fluorotelomer alcohols \g\............................. 1
Fluorinated GHGs with carbon-iodine bond(s) \g\........ 1
Other fluorinated GHGs \g\............................. 1,800
------------------------------------------------------------------------
\a\ The GWP for this compound was updated in the final rule published on
November 29, 2013 [78 FR 71904] and effective on January 1, 2014.
\b\ This compound was added to table A-1 in the final rule published on
December 11, 2014, and effective on January 1, 2015.
\c\ The GWP for this compound was updated in the final rule published on
December 11, 2014, and effective on January 1, 2015.
\d\ The GWP for this compound was updated in the final rule published on
April 25, 2024 and effective on January 1, 2025.
\e\ The GWP for this compound was added to table A-1 in the final rule
published on April 25, 2024 and effective on January 1, 2025.
\f\ 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. 98.6), whether or not they are also fluorinated
GHGs.
\g\ The GWP for this fluorinated GHG group was updated in the final rule
published on April 25, 2024 and effective on January 1, 2025.
0
10. Revise and republish table A-3 to subpart A to read as follows:
Table A-3 to Subpart A of Part 98--Source Category List for Sec.
98.2(a)(1)
------------------------------------------------------------------------
-------------------------------------------------------------------------
Source Categories \a\ Applicable in Reporting Year 2010 and Future
Years:
Electricity generation units that report CO2 mass emissions year
round through 40 CFR part 75 (subpart D).
Adipic acid production (subpart E of this part).
Aluminum production (subpart F of this part).
Ammonia manufacturing (subpart G of this part).
Cement production (subpart H of this part).
HCFC-22 production (subpart O of this part).
HFC-23 destruction processes that are not collocated with a HCFC-22
production facility and that destroy more than 2.14 metric tons of
HFC-23 per year (subpart O of this part).
Lime manufacturing (subpart S of this part).
Nitric acid production (subpart V of this part).
Petrochemical production (subpart X of this part).
Petroleum refineries (subpart Y of this part).
Phosphoric acid production (subpart Z of this part).
Silicon carbide production (subpart BB of this part).
Soda ash production (subpart CC of this part).
Titanium dioxide production (subpart EE of this part).
Municipal solid waste landfills that generate CH4 in amounts
equivalent to 25,000 metric tons CO2e or more per year, as
determined according to subpart HH of this part.
Manure management systems with combined CH4 and N2O emissions in
amounts equivalent to 25,000 metric tons CO2e or more per year, as
determined according to subpart JJ of this part.
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 of this part), are
equivalent to 25,000 metric tons CO2e or more per year.
Underground coal mines liberating 36,500,000 actual cubic feet of
CH4 or more per year (subpart FF of this part).
Geologic sequestration of carbon dioxide (subpart RR of this part).
Injection of carbon dioxide (subpart UU of this part).
Additional Source Categories \a\ Applicable in Reporting Year 2025 and
Future Years:
Geologic sequestration of carbon dioxide with enhanced oil recovery
using ISO 27916 (subpart VV of this part).
Coke calciners (subpart WW of this part).
Calcium carbide production (subpart XX of this part).
Caprolactam, glyoxal, and glyoxylic acid production (subpart YY of
this part).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart of this
part.
0
11. Revise and republish table A-4 to subpart A to read as follows:
Table A-4 to Subpart A of Part 98--Source Category List for Sec.
98.2(a)(2)
------------------------------------------------------------------------
-------------------------------------------------------------------------
Source Categories \a\ Applicable in Reporting Year 2010 and Future
Years:
Ferroalloy production (subpart K of this part).
Glass production (subpart N of this part).
Hydrogen production (subpart P of this part).
Iron and steel production (subpart Q of this part).
Lead production (subpart R of this part).
Pulp and paper manufacturing (subpart AA of this part).
Zinc production (subpart GG of this part).
Additional Source Categories \a\ Applicable in Reporting Year 2011 and
Future Years:
[[Page 31900]]
Electronics manufacturing (subpart I of this part).
Fluorinated gas production (subpart L of this part).
Magnesium production (subpart T of this part).
Petroleum and Natural Gas Systems (subpart W of this part).
Industrial wastewater treatment (subpart II of this part).
Electrical transmission and distribution equipment manufacture or
refurbishment, as determined under Sec. 98.451 (subpart SS of
this part).
Industrial waste landfills (subpart TT of this part).
Additional Source Categories \a\ Applicable in Reporting Year 2025 and
Future Years:
Ceramics manufacturing facilities, as determined under Sec. 98.520
(subpart ZZ of this part).
------------------------------------------------------------------------
\a\ Source categories are defined in each applicable subpart.
Subpart C--General Stationary Fuel Combustion Sources
0
12. Amend Sec. 98.33 by:
0
a. Revising and republishing paragraph (a)(3)(iii);
0
b. Revising paragraph (b)(1)(vii);
0
c. Revising parameter ``EF'' of equation C-10 in paragraph (c)(4)
introductory text;
0
d. Revising and republishing paragraph (c)(6);
0
e. Revising parameter ``R'' of equation C-11 in paragraph (d)(1); and
0
f. Revising the introductory text of paragraphs (e), (e)(1) and (3),
and paragraph (e)(3)(iv).
The revisions read as follows:
Sec. 98.33 Calculating GHG emissions.
* * * * *
(a) * * *
(3) * * *
(iii) For a gaseous fuel, use equation C-5 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.000
Where:
CO2 = Annual CO2 mass emissions from
combustion of the specific gaseous fuel (metric tons).
Fuel = Annual volume of the gaseous fuel combusted (scf). The volume
of fuel combusted must be measured directly, using fuel flow meters
calibrated according to Sec. 98.3(i). Fuel billing meters may be
used for this purpose.
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
(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)(B)(1) and (2) of
this section.
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.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
(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 to this section 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 to
this section. If multiple carbon content determinations are made in any
month, average the values for the month arithmetically.
[GRAPHIC] [TIFF OMITTED] TR25AP24.001
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
[[Page 31901]]
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 (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 to this
section. If multiple molecular weight determinations are made in any
month, average the values for the month arithmetically.
[GRAPHIC] [TIFF OMITTED] TR25AP24.002
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)(B)(1) 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) * * *
(4) * * *
EF = Fuel-specific emission factor for CH4 or
N2O, from table C-2 to this subpart (kg CH4 or
N2O per mmBtu).
* * * * *
(6) Calculate the annual CH4 and N2O mass
emissions from the combustion of blended fuels as follows:
(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
to this subpart:
(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'';
(B) [Reserved]
(C) Calculate the annual CH4 and N2O
emissions from component ``i'', using equation C-8 (fuel mass or
volume) to this section, C-8a (fuel heat input) to this section, C-8b
(fuel heat input) to this section, C-9a (fuel mass or volume) to this
section, or C-10 (fuel heat input) to this section, as applicable;
(D) Sum the annual CH4 emissions across all component
fuels to obtain the annual CH4 emissions for the blend.
Similarly sum the annual N2O emissions across all component
fuels to obtain the annual N2O emissions for the blend.
Report these annual emissions totals.
(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 to this subpart, MSW, and tires. In
addition, when a biomass fuel that is not listed in table C-1 to this
subpart 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
paragraph (b)(3)(iii) of this section, 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
[[Page 31902]]
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 to this section to calculate the
annual CO2 mass emissions from the combustion of the biomass
fuels listed in table C-1 to 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):
* * * * *
(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
(e)(3)(iv) 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 (e)(3)(iv) 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
13. Amend Sec. 98.34 by revising paragraphs (c)(6), (d) and (e) 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 and ASTM D7459-08 (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.
(e) For other units that combust combinations of biomass fuel(s)
(or heterogeneous fuels that have a biomass component, e.g., tires) and
fossil (or other non-biogenic) fuel(s), in any proportions, ASTM D6866-
16 and ASTM D7459-08 (both incorporated by reference, see Sec. 98.7)
may be used to determine the biogenic portion of the CO2
emissions in every calendar quarter in which biomass and non-biogenic
fuels are co-fired in the unit. Follow the procedures in paragraph (d)
of this section. If multiple units at the facility are fed from a
common fuel source, testing at only one of the units is sufficient.
* * * * *
0
14. Amend Sec. 98.36 by revising paragraphs (c)(1)(vi), (c)(3)(vi),
(e)(2)(ii)(C) and (e)(2)(xi) to read as follows:
Sec. 98.36 Data reporting requirements.
* * * * *
(c) * * *
(1) * * *
(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) * * *
(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.
* * * * *
(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
[[Page 31903]]
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
15. Amend Sec. 98.37 by revising and republishing paragraph (b) to
read as follows:
Sec. 98.37 Records that must be retained.
* * * * *
(b) The applicable verification software records as identified in
this paragraph (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), (C), and (D), (e)(2)(iv)(A), (C),
and (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.
(1) Mass of each solid fuel combusted (tons/year) (equation C-1 to
Sec. 98.33).
(2) Volume of each liquid fuel combusted (gallons/year) (equation
C-1 to Sec. 98.33).
(3) Volume of each gaseous fuel combusted (scf/year) (equation C-1
to Sec. 98.33).
(4) Annual natural gas usage (therms/year) (equation C-1a to Sec.
98.33).
(5) Annual natural gas usage (mmBtu/year) (equation C-1b to Sec.
98.33).
(6) Mass of each solid fuel combusted (tons/year) (equation C-2a to
Sec. 98.33).
(7) Volume of each liquid fuel combusted (gallons/year) (equation
C-2a to Sec. 98.33).
(8) Volume of each gaseous fuel combusted (scf/year) (equation C-2a
to Sec. 98.33).
(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 to Sec. 98.33). Annual average HHV of each solid fuel
(mmBtu per ton) (equation C-2a to 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 to Sec. 98.33). Annual average HHV of each liquid fuel
(mmBtu per gallons) (equation C-2a to 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 to Sec. 98.33). Annual average HHV of each gaseous fuel
(mmBtu per scf) (equation C-2a to Sec. 98.33).
(12) Mass of each solid fuel combusted during month (tons)
(equation C-2b to Sec. 98.33).
(13) Volume of each liquid fuel combusted during month (gallons)
(equation C-2b to Sec. 98.33).
(14) Volume of each gaseous fuel combusted during month (scf)
(equation C-2b, equation C-5A, equation C-5B to Sec. 98.33).
(15) Total mass of steam generated by municipal solid waste or each
solid fuel combustion during the reporting year (pounds steam)
(equation C-2c to Sec. 98.33).
(16) Ratio of the boiler's maximum rated heat input capacity to its
design rated steam output capacity (MMBtu/pounds steam) (equation C-2c
to Sec. 98.33).
(17) Annual mass of each solid fuel combusted (short tons/year)
(equation C-3 to Sec. 98.33).
(18) Annual average carbon content of each solid fuel (percent by
weight, expressed as a decimal fraction) (equation C-3 to Sec. 98.33).
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 to Sec. 98.33--see the
definition of ``CC'' in equation C-3 to Sec. 98.33).
(19) Annual volume of each liquid fuel combusted (gallons/year)
(equation C-4 to Sec. 98.33).
(20) Annual average carbon content of each liquid fuel (kg C per
gallon of fuel) (equation C-4 to Sec. 98.33). 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 to Sec.
98.33--see the definition of ``CC'' in equation C-3 to Sec. 98.33).
(21) Annual volume of each gaseous fuel combusted (scf/year)
(equation C-5 to Sec. 98.33).
(22) Annual average carbon content of each gaseous fuel (kg C per
kg of fuel) (equation C-5 to Sec. 98.33). 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 to Sec. 98.33).
(23) Annual average molecular weight of each gaseous fuel (kg/kg-
mole) (equation C-5 to Sec. 98.33). 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 to Sec. 98.33).
(24) Molar volume conversion factor at standard conditions, as
defined in Sec. 98.6 (scf per kg-mole) (equation C-5 to Sec. 98.33).
(25) Identify for each fuel if you will use the default high heat
value from table C-1 to this subpart, or actual high heat value data
(equation C-8 to Sec. 98.33).
(26) High heat value of each solid fuel (mmBtu/tons) (equation C-8
to Sec. 98.33).
(27) High heat value of each liquid fuel (mmBtu/gallon) (equation
C-8 to Sec. 98.33).
(28) High heat value of each gaseous fuel (mmBtu/scf) (equation C-8
to Sec. 98.33).
(29) Cumulative annual heat input from combustion of each fuel
(mmBtu) (equation C-10 to Sec. 98.33).
(30) Total quantity of each solid fossil fuel combusted in the
reporting year, as defined in Sec. 98.6 (pounds) (equation C-13 to
Sec. 98.33).
(31) Total quantity of each liquid fossil fuel combusted in the
reporting year, as defined in Sec. 98.6 (gallons) (equation C-13 to
Sec. 98.33).
(32) Total quantity of each gaseous fossil fuel combusted in the
reporting year, as defined in Sec. 98.6 (scf) (equation C-13 to Sec.
98.33).
(33) High heat value of the each solid fossil fuel (Btu/lb)
(equation C-13 to Sec. 98.33).
(34) High heat value of the each liquid fossil fuel (Btu/gallons)
(equation C-13 to Sec. 98.33).
(35) High heat value of the each gaseous fossil fuel (Btu/scf)
(equation C-13 to Sec. 98.33).
[[Page 31904]]
(36) Fuel-specific carbon based F-factor per fuel (scf
CO2/mmBtu) (equation C-13 to Sec. 98.33).
(37) Moisture content used to calculate the wood and wood residuals
wet basis HHV (percent), if applicable (equations C-1 and C-8 to Sec.
98.33).
Subpart G--Ammonia Manufacturing
0
16. 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
17. 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 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 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.003
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 Sec.
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 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.004
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 Sec.
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 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.005
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 Sec. 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) CO2 process emissions. You must calculate the annual
CO2 process emissions at each ammonia manufacturing unit
according to equation G-4 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.006
Where:
CO2 = Annual 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.
* * * * *
0
18. Amend Sec. 98.76 by revising the introductory text and paragraphs
(b)(1) and (13) and adding paragraph (b)(16) to read as follows:
[[Page 31905]]
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 CO2 process emissions (metric tons) for each
ammonia manufacturing unit.
* * * * *
(13) Annual amount of CO2 (metric tons) collected from
ammonia production and consumed on site for urea production and the
method used to determine the CO2 consumed in urea
production.
* * * * *
(16) Annual quantity of excess hydrogen produced that is not
consumed through the production of ammonia (metric tons).
Subpart H--Cement Production
0
19. Amend Sec. 98.83 by:
0
a. Revising paragraph (d)(1);
0
b. Revising parameters ``CKDCaO'' 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 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.007
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) * * *
CKDncCaO = Quarterly non-calcined CaO 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 to this
section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.008
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
20. Amend Sec. 98.86 by adding paragraphs (a)(4) through (8) 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 facility CKD not recycled to the kiln(s), tons.
(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
21. Revise and republish Sec. 98.91 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 (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
[[Page 31906]]
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
to this section, or the consumption of each input gas, the default
emission factors shown in table I-2 to this subpart, and equation I-1B
to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.009
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 to this section (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] TR25AP24.010
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 semiconductor or MEMS
manufacturing processes listed at Sec. 98.90(a)(1) through (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-2A to this
section or the consumption of each input gas, the default emission
factors shown in table I-2 to this subpart, and equation I-2B to this
section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.011
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 to this section (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] TR25AP24.012
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 (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 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.013
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 (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) You must calculate total annual production process emissions
for threshold applicability purposes using equation I-4 to this
section.
[[Page 31907]]
[GRAPHIC] [TIFF OMITTED] TR25AP24.014
Where:
ET = Annual production process emissions of all
fluorinated GHGs for threshold applicability purposes (metric tons
CO2e).
[delta] = Factor accounting for fluorinated heat transfer fluid
emissions, estimated as 10 percent of total annual production
process emissions at a semiconductor facility. Set equal to 1.1 when
equation I-4 to this section is used to calculate total annual
production process emissions from semiconductor manufacturing. Set
equal to 1 when equation I-4 to this section is used to calculate
total annual production process emissions from MEMS, LCD, or PV
manufacturing.
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 to this
section.
i = Emitted gas.
(b) You must calculate annual manufacturing capacity of a facility
using equation I-5 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.015
Where:
S = 100 percent of annual manufacturing capacity of a facility
(m\2\).
Wx = Maximum substrate starts of fab f in month x (m\2\
per month).
x = Month.
0
22. Amend Sec. 98.92 by revising paragraph (a) introductory text 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. 98.6). 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
23. Amend Sec. 98.93 by:
0
a. Revising paragraph (a);
0
b. Revising the introductory text of paragraph (e);
0
c. Revising parameters ``UTij'' and ``Tdijp'' of
equation I-15 in paragraph (g); and
0
d. Revising paragraphs (h)(1) and (i).
The revisions read as follows:
Sec. 98.93 Calculating GHG emissions.
(a) You must calculate total annual emissions of each fluorinated
GHG emitted by electronics manufacturing production processes from each
fab (as defined in Sec. 98.98) at your facility, including each input
gas and each by-product gas. You must use either default gas
utilization rates and by-product formations rates according to the
procedures in paragraph (a)(1), (2), (6), or (7) of this section, as
appropriate, or the stack test method according to paragraph (i) of
this section, to calculate emissions of each input gas and each by-
product gas.
(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 to 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 to this section,
plus any by-product emissions of that gas calculated under paragraph
(a) of this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.016
Where:
ProcesstypeEi = Annual emissions of input gas i from the
process type on a fab basis (metric tons).
Eij = Annual emissions of input gas i from process sub-
type or process type j as calculated in equation I-8A to this
section (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 to this section, N = 1.
i = Input gas.
j = Process sub-type or process type.
[GRAPHIC] [TIFF OMITTED] TR25AP24.017
Where:
ProcesstypeBEk = Annual emissions of by-product gas k
from the processes type on a fab basis (metric tons).
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 to this section (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 to this section, N = 1.
i = Input gas.
j = Process sub-type, or process type.
k = By-product gas.
(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 to this subpart, and by using equations I-8A and I-8B
to this section.
[[Page 31908]]
[GRAPHIC] [TIFF OMITTED] TR25AP24.018
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 to this section,
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 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 to this
section, 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] TR25AP24.019
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).
Bkij = 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). If all input gases consumed by a
chamber cleaning process sub-type are non-carbon containing input
gases, this is zero when the combination of the non-carbon
containing 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). If all input
gases consumed by an etching and wafer cleaning process sub-type are
non-carbon containing input gases, this is zero when the combination
of the non-carbon containing input gas and etching and wafer
cleaning process sub-type is never used to etch or wafer clean
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 to this
section, 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 to this section.
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 to this subpart, and by using equations I-8A and I-8B
to this section.
(iii) If default values are not available for a particular input
gas and process type or sub-type combination in tables I-3 or I-4, you
must follow the procedures in paragraph (a)(6) of this section.
(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 to this subpart, as
appropriate, and by using equations I-8A and I-8B to this section. 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 to this
subpart, 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
to this section, plus any by-product emissions of that gas calculated
under this paragraph (a).
(3)-(5) [Reserved]
(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 (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 to this subpart, 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 to this
section.
(7) If your fab employs hydrocarbon-fuel-based combustion emissions
control systems (HC fuel CECS), including, but not limited to,
abatement systems as defined at Sec. 98.98, that were purchased and
installed on or after January 1, 2025, 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 to this section using default
utilization and by-product formation rates as shown in table I-3 or I-4
to this subpart. A HC fuel CECS 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 HC fuel CECS.
[[Page 31909]]
[GRAPHIC] [TIFF OMITTED] TR25AP24.020
Where:
EABCF4 = Emissions of CF4 from HC fuel CECS
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 to this section, 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 HC fuel CECS
that are not certified not to form CF4, on a fab basis,
where the numerator is the number of tools that are equipped with HC
fuel CECS 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 HC fuel CECS
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 HC fuel CECS. 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 to this
section, 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 HC fuel CECS
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 HC fuel CECS 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 HC fuel
CECS 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 to
this section.
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
to this section. Where a gas supply system serves more than one fab,
equation I-13 to this section 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 (e) 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 to this section.
* * * * *
(g) * * *
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 (expressed as a decimal fraction). The
average uptime factor may be set to one (1) if all the abatement
systems for the relevant input gas i and process sub-type or type j
are interlocked with all the tools using input gas i in process sub-
type or type j and feeding the abatement systems such that no gas
can flow to the tools if the abatement systems are not in
operational mode.
Tdijp = The total time, in minutes, that abatement system
p, connected to process tool(s) in the fab using input gas i in
process sub-type or process type j, is not in operational mode, as
defined in Sec. 98.98, when at least one of the tools connected to
abatement system p is in operation. If your fab uses redundant
abatement systems, you may account for Tdijp as specified
in Sec. 98.94(f)(4)(vi).
* * * * *
(h) * * *
(1) If you use a fluorinated chemical both as a fluorinated heat
transfer fluid and in other applications, you may calculate and report
either emissions from all applications or from only those specified in
the definition of fluorinated heat transfer fluids in Sec. 98.6.
* * * * *
(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 paragraphs (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.
(ii) You must calculate the emissions of each fluorinated GHG
consumed as an input gas using equation I-17 to this section and each
fluorinated GHG formed as a by-product gas using equation I-18 to this
section and the procedures specified in paragraphs (i)(3)(ii)(A)
through (E) of this section. If a stack system is comprised of multiple
stacks, you must sum the emissions from each stack in the stack system
when using equation I-17 or equation I-18 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.021
[[Page 31910]]
Where:
Eis = Total fluorinated GHG input gas i, emitted from
stack system s, during the sampling period (kg).
Xism = Average concentration of fluorinated GHG input gas
i in stack system s, during the time interval m (ppbv).
MWi = Molecular weight of fluorinated GHG input gas i (g/
g-mole).
Qs = Flow rate of the stack system s, during the sampling
period (m\3\/min).
SV = Standard molar volume of gas (0.0240 m\3\/g-mole at 68 [deg]F
and 1 atm).
[Delta]tm = Length of time interval m (minutes). Each
time interval in the FTIR sampling period must be less than or equal
to 60 minutes (for example an 8 hour sampling period would consist
of at least 8 time intervals).
1/10\3\ = Conversion factor (1 kilogram/1,000 grams).
i = Fluorinated GHG input gas.
s = Stack system.
N = Total number of time intervals m in sampling period.
m = Time interval.
[GRAPHIC] [TIFF OMITTED] TR25AP24.022
Where:
Eks = Total fluorinated GHG by-product gas k, emitted
from stack system s, during the sampling period (kg).
Xks = Average concentration of fluorinated GHG by-product
gas k in stack system s, during the time interval m (ppbv).
MWk = Molecular weight of the fluorinated GHG by-product
gas k (g/g-mole).
Qs = Flow rate of the stack system s, during the sampling
period (m\3\/min).
SV = Standard molar volume of gas (0.0240 m\3\/g-mole at 68 [deg]F
and 1 atm).
[Delta]tm = Length of time interval m (minutes). Each
time interval in the FTIR sampling period must be less than or equal
to 60 minutes (for example an 8 hour sampling period would consist
of at least 8 time intervals).
1/10\3\ = Conversion factor (1 kilogram/1,000 grams).
k = Fluorinated GHG by-product gas.
s = Stack system.
N = Total number of time intervals m in sampling period.
m = Time interval.
(A) If a fluorinated GHG is consumed during the sampling period,
but emissions are not detected, use one-half of the field detection
limit you determined for that fluorinated GHG according to Sec.
98.94(j)(2) for the value of ``Xism'' in equation I-17 to
this section.
(B) If a fluorinated GHG is consumed during the sampling period and
detected intermittently during the sampling period, use the detected
concentration for the value of ``Xism'' in equation I-17 to
this section when available and use one-half of the field detection
limit you determined for that fluorinated GHG according to Sec.
98.94(j)(2) for the value of ``Xism'' when the fluorinated
GHG is not detected.
(C) If an expected or possible by-product, as listed in table I-17
to this subpart, is detected intermittently during the sampling period,
use the measured concentration for ``Xksm'' in equation I-18
to this section when available and use one-half of the field detection
limit you determined for that fluorinated GHG according to Sec.
98.94(j)(2) for the value of ``Xksm'' when the fluorinated
GHG is not detected.
(D) If a fluorinated GHG is not consumed during the sampling period
and is an expected by-product gas as listed in table I-17 to this
subpart and is not detected during the sampling period, use one-half of
the field detection limit you determined for that fluorinated GHG
according to Sec. 98.94(j)(2) for the value of ``Xksm'' in
equation I-18 to this section.
(E) If a fluorinated GHG is not consumed during the sampling period
and is a possible by-product gas as listed in table I-17 to this
subpart, and is not detected during the sampling period, then assume
zero emissions for that fluorinated GHG for the tested stack system.
(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 to this section
or equations I-19A and I-19C to this section. Use equation I-19A to
this section to calculate the controlled emissions for each carbon-
containing 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 SsEi,s (the total
measured emissions of the fluorinated GHG across all stack systems,
calculated based on the results of equation I-17 to this section) is
less than or equal to Eimax,f calculated in equation I-19A
to this section, use equation I-19B to this section to calculate the
emission factor for that fluorinated GHG. If
SsEi,s is larger than the Eimax,f
calculated in equation I-19A to this section, use equation I-19C to
this section to calculate the emission factor and treat the difference
between the total measured emissions SsEi,s and
the maximum expected controlled emissions Eimax,f as a by-
product of the other input gases, using equation I-20 to this section.
For all fluorinated GHGs that do not contain carbon, use equation I-19B
to this section to calculate the emission factor for that fluorinated
GHG.
[GRAPHIC] [TIFF OMITTED] TR25AP24.023
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 to
this section (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 to this section.
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 to this section (expressed as
decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
[[Page 31911]]
[GRAPHIC] [TIFF OMITTED] TR25AP24.024
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 to
this section (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 to this section.
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 to this section (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] TR25AP24.025
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 to this section.
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 to this section (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 to this section. When
calculating the by-product emission factor for an input gas for which
SsEi,s equals or exceeds Eimax,f,
exclude the consumption of that input gas from the term
``S(Activityif).''
[GRAPHIC] [TIFF OMITTED] TR25AP24.026
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 to
this section (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 to this section.
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 to this section (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 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.027
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 to this section
(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 to this section (kg/year).
UTf = The total uptime of all abatement systems for fab
f, during the reporting year, as calculated using equation I-23 to
this section (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 to this
section.
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 to this section (expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
(vi) You must calculate annual fab-level emissions of each
fluorinated GHG
[[Page 31912]]
by-product formed using equation I-22 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.028
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 to this
section (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 to this section.
UTf = The total uptime of all abatement systems for fab
f, during the reporting year as calculated using equation I-23 to
this section (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 to this section.
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 to this section
(expressed as decimal fraction).
f = Fab.
i = Fluorinated GHG input gas.
k = Fluorinated GHG by-product.
(vii) When using the stack testing method described in this
paragraph (i), you must calculate abatement system uptime on a fab
basis using equation I-23 to this section. When calculating abatement
system uptime for use in equation I-19 and I-20 to this section, you
must evaluate the variables ``Tdpf'' and ``UTpf'' for the sampling
period instead of the reporting year.
[GRAPHIC] [TIFF OMITTED] TR25AP24.029
Where:
UTf = The average uptime factor for all abatement systems
in fab f (expressed as a decimal fraction). The average uptime
factor may be set to one (1) if all the abatement systems in fab f
are interlocked with all the tools feeding the abatement systems
such that no gas can flow to the tools if the abatement systems are
not in operational mode.
Tdpf = The total time, in minutes, that abatement system
p, connected to process tool(s) in fab f, is not in operational mode
as defined in Sec. 98.98. If your fab uses redundant abatement
systems, you may account for Tdpf as specified in Sec.
98.94(f)(4)(vi).
UTpf = Total time, in minutes per year, in which the
tool(s) connected at any point during the year to abatement system
p, in fab f could be in operation. For determining the amount of
tool operating time, you may assume that tools that were installed
for the whole of the year were operated for 525,600 minutes per
year. For tools that were installed or uninstalled during the year,
you must prorate the operating time to account for the days in which
the tool was not installed; treat any partial day that a tool was
installed as a full day (1,440 minutes) of tool operation. For an
abatement system that has more than one connected tool, the tool
operating time is 525,600 minutes per year if there was at least one
tool installed at all times throughout the year. If you have tools
that are idle with no gas flow through the tool, you may calculate
total tool time using the actual time that gas is flowing through
the tool.
f = Fab.
p = Abatement system.
(viii) When using the stack testing option described in this
paragraph (i) 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 to this section (for input gases) and equation I-24B to this
section (for by-product gases) and table I-18 to 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] TR25AP24.030
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.
[[Page 31913]]
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.
gi,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.
gk,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 to this section (for input gases) and
equation I-24D to this section (for by-product gases) and table I-18 to
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] TR25AP24.031
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.
gi,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] TR25AP24.032
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.
gk,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 to this subpart, as applicable,
and by using equations I-8A, I-8B, I-9, and I-13 to this section. 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.
(5) [Reserved]
0
24. Amend Sec. 98.94 by:
0
a. Revising paragraph (c) introductory text;
0
b. Adding paragraph (e);
0
c. Revising paragraphs (f)(3), (f)(4) introductory text, (f)(4)(iii),
(j)(1) introductory text, (j)(1)(i), (j)(3) introductory text, and
(j)(5); and
0
d. Removing and reserving paragraphs (j)(6) and (j)(8)(v).
The revisions and addition read as follows:
[[Page 31914]]
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 to Sec. 98.93), 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 HC fuel CECS purchased and installed on or after
January 1, 2025 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 to Sec. 98.93, 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 HC fuel CECS manufacturer.
Hydrocarbon-fuel-based combustion 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 (incorporated by reference, see Sec.
98.7), adjusted to calculate the rate of conversion from F2
to CF4 rather than the DRE. Either the HC fuel CECS
manufacturer or the electronics manufacturer may perform the
measurement. The flow rate of F2 into the tested HC fuel
CECS 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 provide the abatement system manufacturer-verified
DRE value that meets (or exceeds) the default destruction or removal
efficiency in table I-16 to this subpart for the fluorinated GHG or
N2O. For abatement systems purchased and installed on or
after January 1, 2025, you must also certify and document 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 to this subpart 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 provide the abatement system
manufacturer-verified DRE value that is lower than the default
destruction or removal efficiency in table I-16 for the fluorinated GHG
or N2O. For abatement systems purchased and installed on or
after January 1, 2025, you must also certify and document 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 for abatement systems purchased and installed
on or after January 1, 2025, 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 in operational mode.
(4) If you calculate and report controlled emissions using neither
the default destruction or removal efficiency values in table I-16 to
this subpart nor an abatement system manufacturer-verified lower
destruction or removal efficiency value 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 or for which
your fab operates abatement systems outside the range of parameters
specified in the documentation supporting the certified DRE and you
elect to reflect emission reductions due to these systems. You must not
use a default value from table I-16 to 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 to 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-
[[Page 31915]]
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 combustion emissions
control systems that were purchased and installed on or after January
1, 2025, that are used 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, and 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) Emissions testing frequency. You must conduct emissions testing
to develop fab-specific emission factors on a frequency according to
the procedures in paragraph (j)(5)(i) or (ii) of this section.
(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
and the next 4 years with no further testing unless your fab operations
are changed in a way that triggers the re-test criteria in paragraph
(j)(8) of this section. In the fifth year following the last stack test
included in the previous average, you must test each of the stack
systems and repeat the relative standard deviation analysis using the
results of the most recent three tests (i.e. , the new test and the two
previous tests conducted prior to the 4-year period). If the criteria
specified in paragraphs (j)(5)(ii)(A) and (B) of this section are not
met, you must use the emission factors developed from the most recent
testing and continue annual testing. You may conduct more than one test
in the same year, but each set of emissions testing for a stack system
must be separated by a period of at least 2 months. You may repeat the
relative standard deviation analysis using the most recent three tests,
including those tests conducted prior to the 4-year period, to
determine if you are exempt from testing for the next 4 years.
(A) The relative standard deviation of the total CO2e
emission factors calculated from each of the three tests (expressed as
the total CO2e fluorinated GHG emissions of the fab divided
by the total CO2e fluorinated GHG use of the fab) is less
than or equal to 15 percent.
(B) The relative standard deviation for all single fluorinated GHGs
that individually accounted for 5 percent or more of CO2e
emissions were less than 20 percent.
* * * * *
0
25. Amend Sec. 98.96 by:
0
a. Revising paragraphs (c)(1) and (2);
0
b. Adding paragraph (o); and
0
c. Revising paragraphs (p)(2), (q)(2) and (3), (r)(2), (w)(2), (y)
introductory text, (y)(1), (y)(2)(i) and (iv), and (y)(4).
The revisions and addition read as follows:
Sec. 98.96 Data reporting requirements.
* * * * *
(c) * * *
(1) When you use the procedures specified in Sec. 98.93(a), each
fluorinated GHG emitted from each process type for which your fab is
required to calculate emissions as calculated in equations I-6, I-7,
and I-9 to Sec. 98.93.
(2) When you use the procedures specified in Sec. 98.93(a), each
fluorinated GHG emitted from each process type or process sub-type as
calculated in equations I-8A and I-8B to Sec. 98.93, as applicable.
* * * * *
(o) For all HC fuel CECS that were purchased and installed on or
after January 1, 2025, that are used to control emissions from tools
that use either NF3 as an input gas in remote plasma clean
processes or F2 as an input gas in any process type or sub-
type and for which you are not calculating emissions under equation I-9
to Sec. 98.93, certification that the rate of conversion from
F2 to CF4 is <0.1% and that the systems are
installed, operated, and maintained in accordance with the directions
of the HC fuel CECS manufacturer. Hydrocarbon-fuel-based combustion
emissions control systems include but are not limited to abatement
systems as defined in Sec. 98.98 that are hydrocarbon-fuel-based. If
you make the certification based on your own testing, you must certify
that you tested the model of the system according to the requirements
specified in Sec. 98.94(e). If you make the certification based on
testing by the HC fuel CECS manufacturer, you must provide
documentation from the HC fuel CECS manufacturer that the rate of
conversion from F2 to CF4 is <0.1% when tested
according to the requirements specified in Sec. 98.94(e).
(p) * * *
(2) The basis of the destruction or removal efficiency being used
(default, manufacturer-verified, or site-specific measurement according
to
[[Page 31916]]
Sec. 98.94(f)(4)(i)) for each process sub-type or process type and for
each gas.
(q) * * *
(2) If you use default destruction or removal efficiency values in
your emissions calculations under Sec. 98.93(a), (b), or (i),
certification that the site maintenance plan for abatement systems for
which emissions are being reported contains the manufacturer's
recommendations and specifications for installation, operation, and
maintenance for each abatement system. To use the default or lower
manufacturer-verified destruction or removal efficiency values,
operation of the abatement system must be within manufacturer's
specifications, which may include, for example, specifications on
vacuum pumps' purges, fuel and oxidizer settings, supply and exhaust
flows and pressures, and utilities to the emissions control equipment
including fuel gas flow and pressure, calorific value, and water
quality, flow and pressure.
(3) If you use default destruction or removal efficiency values in
your emissions calculations under Sec. 98.93(a), (b), and/or (i),
certification that the abatement systems for which emissions are being
reported were specifically designed for fluorinated GHG or
N2O abatement, as applicable. You must support this
certification by providing abatement system supplier documentation
stating that the system was designed for fluorinated GHG or
N2O abatement, as applicable, and supply the destruction or
removal efficiency value at which each abatement system is certified
for the fluorinated GHG or N2O abated, as applicable. You
may only use the default destruction or removal efficiency value if the
abatement system is verified to meet or exceed the destruction or
removal efficiency default value in table I-16 to this subpart. If the
system is verified at a destruction or removal efficiency value lower
than the default value, you may use the verified value.
* * * * *
(r) * * *
(2) Use equation I-28 to this section to calculate total unabated
emissions, in metric ton CO2e, of all fluorinated GHG
emitted from electronics manufacturing processes whose emissions of
fluorinated GHG you calculated according to the stack testing
procedures in Sec. 98.93(i)(3). For each set of processes, use the
same input gas consumption (Cif), input gas emission factors
(EFif), by-product gas emission factors (EFkf),
fractions of tools abated (aif and akif), and
destruction efficiencies (dif and dik) to
calculate unabated emissions as you used to calculate emissions.
[GRAPHIC] [TIFF OMITTED] TR25AP24.033
Where:
SFGHG = Total unabated emissions of fluorinated GHG emitted from
electronics manufacturing processes in the fab, expressed in metric
ton CO2e for which you calculated total emission
according to the procedures in Sec. 98.93(i)(3).
EFif = Emission factor for fluorinated GHG input gas i,
emitted from fab f, as calculated in equation I-19 to Sec. 98.93
(kg emitted/kg input gas consumed).
aif = Fraction of fluorinated GHG input gas i used in fab
f in tools with abatement systems (expressed as a decimal fraction).
dif = Fraction of fluorinated GHG i destroyed or removed
in abatement systems connected to process tools in fab f, as
calculated from equation I-24A to Sec. 98.93, which you used to
calculate total emissions according to the procedures in Sec.
98.93(i)(3) (expressed as a decimal fraction).
Cif = Total consumption of fluorinated GHG input gas i,
of tools vented to stack systems, for fab f, for the reporting year,
expressed in metric ton CO2e, which you used to calculate
total emissions according to the procedures in Sec. 98.93(i)(3)
(expressed as a decimal fraction).
EFkf = Emission factor for fluorinated GHG by-product gas
k, emitted from fab f, as calculated in equation I-20 to Sec. 98.93
(kg emitted/kg of all input gases consumed in tools vented to stack
systems).
akif = 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 to Sec. 98.93.
dik = Fraction of fluorinated GHG byproduct k destroyed
or removed in abatement systems connected to process tools in fab f,
as calculated from equation I-24B to Sec. 98.93, which you used to
calculate total emissions according to the procedures in Sec.
98.93(i)(3) (expressed as a decimal fraction).
GWPi = GWP of emitted fluorinated GHG i from table A-1 to
subpart A of this part.
GWPk = GWP of emitted fluorinated GHG by-product k from
table A-1 to subpart A of this part.
i = Fluorinated GHG.
k = Fluorinated GHG by-product.
* * * * *
(w) * * *
(2) An inventory of all stack systems from which process
fluorinated GHG are emitted.
* * * * *
(y) If your semiconductor manufacturing facility manufactures
wafers greater than 150 mm and emits more than 40,000 metric ton
CO2e of GHG emissions, based on your most recently submitted
annual report as required in paragraph (c) of this section, from the
electronics manufacturing processes subject to reporting under this
subpart, you must prepare and submit a technology assessment report
every five years to the Administrator (or an authorized representative)
that meets the requirements specified in paragraphs (y)(1) through (6)
of this section. Any other semiconductor manufacturing facility may
voluntarily submit this report to the Administrator. If your
semiconductor manufacturing facility manufactures only 150 mm or
smaller wafers, you are not required to prepare and submit a technology
assessment report, but you are required to prepare and submit a report
if your facility begins manufacturing wafers 200 mm or larger during or
before the calendar year preceding the year the technology assessment
report is due. If your semiconductor manufacturing facility is no
longer required to report to the GHGRP under subpart I due to the
cessation of semiconductor manufacturing as described in Sec.
98.2(i)(3), you are not required to submit a technology assessment
report.
(1) The first technology assessment report due after January 1,
2025, is due on March 31, 2028, and subsequent reports must be
delivered every 5 years no later than March 31 of the year in which it
is due.
(2) * * *
(i) It must describe how the gases and technologies used in
semiconductor manufacturing using 200 mm and 300 mm wafers in the
United States have changed in the past 5 years and whether any of the
identified changes are likely to have affected the emissions
characteristics of semiconductor manufacturing processes in such a way
that the default utilization and by-product formation rates or default
destruction or removal efficiency factors of this subpart may need to
be updated.
* * * * *
[[Page 31917]]
(iv) It must provide any utilization and byproduct formation rates
and/or destruction or removal efficiency data that have been collected
in the previous 5 years that support the changes in semiconductor
manufacturing processes described in the report. Any utilization or
byproduct formation rate data submitted must be reported using both of
the methods specified in paragraphs (y)(2)(iv)(A) and (B) of this
section if multiple fluorinated input gases are used, unless one of the
input gases does not have a reference process utilization rate in table
I-19 or I-20 to this subpart for the process type and wafer size whose
emission factors are being measured, in which case the data must be
submitted using the method specified in paragraph (y)(2)(iv)(A) of this
section. If only one fluorinated input gas is fed into the process, you
must use equations I-29A and I-29B to this section. In addition to
using the methods specified in paragraphs (y)(2)(iv)(A) and (B) of this
section, you have the option to calculate and report the utilization or
byproduct formation rate data using any alternative calculation
methodology. The report must include the input gases used and measured,
the utilization rates measured, the byproduct formation rates measured,
the process type, the process subtype for chamber clean processes, the
wafer size, and the methods used for the measurements. The report must
also specify the method used to calculate each reported utilization and
by-product formation rate, and provide a unique record number for each
data set. For any destruction or removal efficiency data submitted, the
report must include the input gases used and measured, the destruction
and removal efficiency measured, the process type, the methods used for
the measurements, and whether the abatement system is specifically
designed to abate the gas measured under the operating conditions used
for the measurement. If you choose to use an additional alternative
calculation methodology to calculate and report the input gas emission
factors and by-product formation rates, you must provide a complete,
mathematical description of the alternative method used (including the
equation used to calculate each reported utilization and by-product
formation rate) and include the information in this paragraph
(y)(2)(iv).
(A) All-input gas method. Use equation I-29A to this section to
calculate the input gas emission factor (1 - Uij) for each
input gas in a single test. If the result of equation I-29A exceeds 0.8
for an F-GHG that contains carbon, you must use equation I-29C to this
section to calculate the input gas emission factor for that F-GHG and
equation I-29D to this section to calculate the by-product formation
rate for that F-GHG from the other input gases. Use equation I-29B to
this section to calculate the by-product formation rates from each
input gas for F-GHGs that are not input gases. If a test uses a
cleaning or etching gas that does not contain carbon in combination
with a cleaning or etching gas that does contain carbon and the process
chamber is not used to etch or deposit carbon-containing films, you may
elect to assign carbon containing by-products only to the carbon-
containing input gases. If you choose to assign carbon containing by-
products only to carbon-containing input gases, remove the input mass
of the non-carbon containing gases from the sum of Massi and
the sum of Massg in equations I-29B and I-29D to this
section, respectively.
[GRAPHIC] [TIFF OMITTED] TR25AP24.034
Where:
Uij = Process utilization rate for fluorinated GHG i,
process type j.
Ei = The mass emissions of input gas i.
Massi = The mass of input gas i fed into the process.
i = Fluorinated GHG.
j = Process type.
[GRAPHIC] [TIFF OMITTED] TR25AP24.035
Where:
BEFkji = By-product formation rate for gas k from input
gas i, for process type j, where gas k is not an input gas.
Ek = The mass emissions of by-product gas k.
Massi = The mass of input gas i fed into the process.
i = Fluorinated GHG.
j = Process type.
k = Fluorinated GHG by-product.
[GRAPHIC] [TIFF OMITTED] TR25AP24.036
Where:
Uij = Process utilization rate for fluorinated GHG i,
process type j.
[GRAPHIC] [TIFF OMITTED] TR25AP24.037
Where:
BEFijg = By-product formation rate for gas i from input
gas g for process type j.
Ei = The mass emissions of input gas i.
Massi = The mass of input gas i fed into the process.
Massg = The mass of input gas g fed into the process,
where g does not equal input gas i.
i = Fluorinated GHG.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
j = Process type.
(B) Reference emission factor method. Calculate the input gas
emission factors and by-product formation rates from a test using
equations I-30A, I-30B, and I-29B to this section, and table I-19 or I-
20 to this subpart. In this case, use
[[Page 31918]]
equation I-30A to this section to calculate the input gas emission
factors and use equation I-30B and I-29B to this section to calculate
the by-product formation rates.
[GRAPHIC] [TIFF OMITTED] TR25AP24.038
Where:
Uij = Process utilization rate for fluorinated GHG i,
process type j.
Uijr = Reference process utilization rate for fluorinated
GHG i, process type j, for input gas i, using table I-19 or I-20 to
this subpart as appropriate.
Ei = The mass emissions of input gas i.
Massi = The mass of gas i fed into the process.
Massg = The mass of input gas g fed into the process,
where g does not equal input gas i.
BEFijgr = Reference by-product formation rate for gas i
from input gas g for process type j, using table I-19 or I-20 to
this subpart as appropriate.
i = Fluorinated GHG.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
r = Reference data.
[GRAPHIC] [TIFF OMITTED] TR25AP24.039
Where:
BEFijg = By-product formation rate for gas i from input
gas g for process type j, where gas i is also an input gas.
BEFijgr = Reference by-product formation rate for gas i
from input gas g for process type j from table I-19 or I-20 to this
subpart, as appropriate.
Uijr = Reference process utilization rate for fluorinated
GHG i, process type j, for input gas i, using table I-19 or I-20 to
this subpart, as appropriate.
Ei = The mass emissions of input gas i.
Massi = The mass of gas i fed into the process.
Massg = The mass of input gas g fed into the process,
where g does not equal input gas i.
i = Fluorinated GHG.
j = Process type.
g = Fluorinated GHG input gas, where gas g is not equal to gas i.
r = Reference data.
* * * * *
(4) Multiple semiconductor manufacturing facilities may submit a
single consolidated technology assessment report as long as the
facility identifying information in Sec. 98.3(c)(1) and the
certification statement in Sec. 98.3(c)(9) is provided for each
facility for which the consolidated report is submitted.
* * * * *
0
26. Amend Sec. 98.97 by:
0
a. Adding paragraph (b);
0
b. Revising paragraphs (d)(1)(iii), (d)(3), (d)(5)(i), (d)(6) and (7),
and (d)(9)(i);
0
c. Removing and reserving paragraph (i)(1); and
0
d. Revising paragraphs (i)(5) and (9) and (k).
The addition and revisions read as follows:
Sec. 98.97 Records that must be retained.
* * * * *
(b) If you use HC fuel CECS purchased and installed on or after
January 1, 2025, 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 to Sec. 98.93, certification and documentation that the
model for each of the systems that you claim does not form
CF4 from F2 has been tested and verified to
produce less than 0.1% CF4 from F2, and
certification that the site maintenance plan includes the HC fuel CECS
manufacturer's recommendations and specifications for installation,
operation, and maintenance of those systems. If you are relying on your
own testing to make the certification that the model produces less than
0.1% CF4 from F2, the documentation must include
the model tested, the method used to perform the testing (e.g., EPA
430-R-10-003, modified to calculate the formation rate of
CF4 from F2 rather than the DRE), complete
documentation of the results of any initial and subsequent tests, and a
final report similar to that specified in EPA 430-R-10-003
(incorporated by reference, see Sec. 98.7), with appropriate
adjustments to reflect the measurement of the formation rate of
CF4 from F2 rather than the DRE. If you are
relying on testing by the HC fuel CECS manufacturer to make the
certification that the system produces less than 0.1% CF4
from F2, the documentation must include the model tested,
the method used to perform the testing, and the results of the test.
* * * * *
(d) * * *
(1) * * *
(iii) If you use either default destruction or removal efficiency
values or certified destruction or removal efficiency values that are
lower than the default values in your emissions calculations under
Sec. 98.93(a), (b), and/or (i), certification that the abatement
systems for which emissions are being reported were specifically
designed for fluorinated GHG and N2O abatement, as required
under Sec. 98.94(f)(3), certification that the site maintenance plan
includes the abatement system manufacturer's recommendations and
specifications for installation, operation, and maintenance, and the
certified destruction and removal efficiency values for all applicable
abatement systems. For abatement systems purchased and installed on or
after January 1, 2025, also include records of the method used to
measure the destruction and removal efficiency values.
* * * * *
(3) Where either the default destruction or removal efficiency
value or a certified destruction or removal efficiency value that is
lower than the default is used, documentation from the abatement system
supplier describing the equipment's designed purpose and emission
control capabilities for fluorinated GHG and N2O.
* * * * *
(5) * * *
(i) The number of abatement systems of each manufacturer, and model
numbers, and the manufacturer's certified fluorinated GHG and
N2O destruction or removal efficiency, if any.
* * * * *
(6) Records of all inputs and results of calculations made
accounting for the uptime of abatement systems used during the
reporting year, in accordance with equations I-15 or I-23 to Sec.
98.93, as applicable. The inputs should
[[Page 31919]]
include an indication of whether each value for destruction or removal
efficiency is a default value, lower manufacturer-verified value, or a
measured site-specific value.
(7) Records of all inputs and results of calculations made to
determine the average weighted fraction of each gas destroyed or
removed in the abatement systems for each stack system using equations
I-24A and I-24B to Sec. 98.93, if applicable. The inputs should
include an indication of whether each value for destruction or removal
efficiency is a default value, lower manufacturer-verified value, or a
measured site-specific value.
* * * * *
(9) * * *
(i) The site maintenance plan for abatement systems must be based
on the abatement system manufacturer's recommendations and
specifications for installation, operation, and maintenance if you use
default or lower manufacturer-verified destruction and removal
efficiency values in your emissions calculations under Sec. 98.93(a),
(b), and/or (i). If the manufacturer's recommendations and
specifications for installation, operation, and maintenance are not
available, you cannot use default destruction and removal efficiency
values or lower manufacturer-verified value in your emissions
calculations under Sec. 98.93(a), (b), and/or (i). If you use an
average of properly measured destruction or removal efficiencies
determined in accordance with the procedures in Sec. 98.94(f)(4)(i)
through (vi), the site maintenance plan for abatement systems must be
based on the abatement system manufacturer's recommendations and
specifications for installation, operation, and maintenance, where
available. If you deviate from the manufacturer's recommendations and
specifications, you must include documentation that demonstrates how
the deviations do not negatively affect the performance or destruction
or removal efficiency of the abatement systems.
* * * * *
(i) * * *
(5) The fab-specific emission factor and the calculations and data
used to determine the fab-specific emission factor for each fluorinated
GHG and by-product, as calculated using equations I-19A, I-19B, I-19C
and I-20 to Sec. 98.93(i)(3).
* * * * *
(9) The number of tools vented to each stack system in the fab and
all inputs and results for the calculations accounting for the fraction
of gas exhausted through abatement systems using equations I-24C and I-
24D to Sec. 98.93.
* * * * *
(k) Annual gas consumption for each fluorinated GHG and
N2O as calculated in equation I-11 to Sec. 98.93, including
where your fab used less than 50 kg of a particular fluorinated GHG or
N2O used at your facility for which you have not calculated
emissions using equations I-6, I-7, I-8A, I-8B, I-9, I-10, I-21, or I-
22 to Sec. 98.93, the chemical name of the GHG used, the annual
consumption of the gas, and a brief description of its use.
* * * * *
0
27. Amend Sec. 98.98 by:
0
a. Removing the definition ``Fluorinated heat transfer fluids'';
0
b. Adding the definition ``Hydrocarbon-fuel based combustion emission
control systems (HC fuel CECs)'' in alphabetical order; and
0
c. Revising the definition ``Operational mode''.
The revisions and addition read as follows:
Sec. 98.98 Definitions.
* * * * *
Hydrocarbon-fuel based combustion emission control system (HC fuel
CECS) means a hydrocarbon fuel-based combustion device or equipment
that is designed to destroy or remove gas emissions in exhaust streams
via combustion from one or more electronics manufacturing production
processes, and that is connected to manufacturing tools that have the
potential to emit F2 or fluorinated greenhouse gases. HC
fuel CECs include both emission control systems that are and are not
designed to destroy or remove fluorinated GHGs or N2O.
* * * * *
Operational mode means the time in which an abatement system is
properly installed, maintained, and operated according to the site
maintenance plan for abatement systems as required in Sec. 98.94(f)(1)
and defined in Sec. 98.97(d)(9). This includes being properly operated
within the range of parameters as specified in the site maintenance
plan for abatement systems. For abatement systems purchased and
installed on or after January 1, 2025, this includes being properly
operated within the range of parameters specified in the DRE
certification documentation. An abatement system is considered to not
be in operational mode when it is not operated and maintained according
to the site maintenance plan for abatement systems or, for abatement
systems purchased and installed on or after January 1, 2025, not
operated within the range of parameters as specified in the DRE
certification documentation.
* * * * *
0
28. Revise table I-1 to subpart I to read as follows:
Table I-1 to Subpart I of Part 98--Default Emission Factors for Manufacturing Capacity-Based Threshold Applicability Determination
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission factors EFi
------------------------------------------------------------------------------------------------
Product type c-C4F8
CF4 C2F6 CHF3 C3F8 NF3 SF6 N2O
--------------------------------------------------------------------------------------------------------------------------------------------------------
Semiconductors (kg/m\2\)............................... 0.9 1.0 0.04 NA 0.05 0.04 0.20 NA
LCD (g/m\2\)........................................... 0.65 NA 0.0024 0.00 NA 1.29 4.14 17.06
MEMS (kg/m\2\)......................................... 0.015 NA NA 0.076 NA NA 1.86 NA
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.
0
29. Revise table I-2 to subpart I to read as follows:
[[Page 31920]]
Table I-2 to Subpart I of Part 98--Default Emission Factors for Gas Consumption-Based Threshold Applicability
Determination
----------------------------------------------------------------------------------------------------------------
Process gas i
---------------------------------------
Fluorinated GHGs N2O
----------------------------------------------------------------------------------------------------------------
1-Ui.................................................................... 0.8 1
BCF4.................................................................... 0.15 0
BC2F6................................................................... 0.05 0
----------------------------------------------------------------------------------------------------------------
0
30. Revise table I-3 to subpart I to read as follows:
Table I-3 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 150 mm and 200 mm
Wafer Sizes
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
Process type/sub-type -----------------------------------------------------------------------------------------------------------------------------------------------------------------
CF4 C2F6 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Etching/Wafer Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... 0.73 0.72 0.51 0.13 0.064 0.70 NA 0.14 0.19 0.55 0.083 0.072 NA
BCF4.......................... NA 0.10 0.085 0.079 0.077 NA NA 0.11 0.0040 0.13 0.095 NA NA
BC2F6......................... 0.041 NA 0.035 0.025 0.024 0.0034 NA 0.037 0.025 0.11 0.073 0.014 NA
BC4F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BCHF3......................... 0.091 0.047 NA 0.049 NA NA NA 0.040 NA 0.0012 0.066 0.0039 NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Chamber Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
In situ plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... 0.92 0.55 NA NA NA NA 0.40 0.10 0.18 NA NA NA 0.14
BCF4.......................... NA 0.19 NA NA NA NA 0.20 0.11 0.14 NA NA NA 0.13
BC2F6......................... NA NA NA NA NA NA NA NA NA NA NA NA 0.045
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Remote plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... NA NA NA NA NA NA NA NA 0.028 NA NA NA NA
BCF4.......................... NA NA NA NA NA NA NA NA 0.015 NA NA NA NA
BC2F6......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BF2........................... NA NA NA NA NA NA NA NA 0.5 NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
In situ thermal cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BCF4.......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC2F6......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted
from a particular process sub-type or process type.
31. Revise table I-4 to subpart I to read as follows:
Table I-4 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 300 mm and 450 mm
Wafer Size
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
Process type/sub-type ------------------------------------------------------------------------------------------------------------------------------------------------------
CF4 C2F6 CHF3 CH2F2 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Etching/Wafer Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..................................... 0.65 0.80 0.37 0.20 0.30 0.30 0.18 0.16 0.30 0.15 0.10 NA
BCF4..................................... NA 0.21 0.076 0.060 0.0291 0.21 0.045 0.044 0.033 0.059 0.11 NA
BC2F6.................................... 0.058 NA 0.058 0.043 0.009 0.018 0.027 0.045 0.041 0.062 0.083 NA
BC4F8.................................... 0.0046 NA 0.0027 0.054 0.0070 NA NA NA NA 0.0051 NA NA
BC3F8.................................... NA NA NA NA NA NA NA NA NA NA 0.00012 NA
BCHF3.................................... 0.012 NA NA 0.057 0.016 0.012 0.028 0.023 0.0039 0.017 0.0069 NA
BCH2F2................................... 0.005 NA 0.0024 NA 0.0033 NA 0.0021 0.00074 0.000020 0.000030 NA NA
BCH3F.................................... 0.0061 NA 0.027 0.0036 NA 0.00073 0.0063 0.0080 0.0082 0.00065 NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 31921]]
Chamber Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
In situ plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..................................... NA NA NA NA NA NA NA 0.20 NA NA NA NA
BCF4..................................... NA NA NA NA NA NA NA 0.037 NA NA NA NA
BC2F6.................................... NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8.................................... NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Remote plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..................................... NA NA NA NA NA 0.063 NA 0.018 NA NA NA NA
BCF4..................................... NA NA NA NA NA NA NA 0.037 NA NA NA NA
BC2F6.................................... NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8.................................... NA NA NA NA NA NA NA NA NA NA NA NA
BCHF3.................................... NA NA NA NA NA NA NA 0.000059 NA NA NA NA
BCH2F2................................... NA NA NA NA NA NA NA 0.00088 NA NA NA NA
BCH3F.................................... NA NA NA NA NA NA NA 0.0028 NA NA NA NA
BF2...................................... NA NA NA NA NA NA NA 0.5 NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
In situ thermal cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..................................... NA NA NA NA NA NA NA 0.28 NA NA NA NA
BCF4..................................... NA NA NA NA NA NA NA 0.010 NA NA NA NA
BC2F6.................................... NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8.................................... NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable default emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted
from a particular process sub-type or process type.
0
32. Revise table I-8 to subpart I to read as follows:
Table I-8 to Subpart I of Part 98--Default Emission Factors (1-UN2O,j)
for N2O Utilization (UN2O,j)
------------------------------------------------------------------------
Manufacturing type/process type/wafer size N2O
------------------------------------------------------------------------
Semiconductor Manufacturing:
200 mm or Less:
CVD 1-Ui........................................ 1.0
Other Manufacturing Process 1-Ui................ 1.0
300 mm or greater:
CVD 1-Ui........................................ 0.5
Other Manufacturing Process 1-Ui................ 1.0
LCD Manufacturing:
CVD Thin Film Manufacturing 1-Ui.................... 0.63
All other N2O Processes................................. 1.0
------------------------------------------------------------------------
0
33. Revise table I-11 to subpart I to read as follows:
Table I-11 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for Use With the Stack Test Method
[150 mm and 200 mm Wafers]
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
-------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
All processes NF3
CF4 C2F6 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3 Remote SF6 C4F6 C5F8 C4F8O
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.................................................... 0.79 0.55 0.51 0.13 0.064 0.70 0.40 0.12 0.18 0.028 0.58 0.083 0.072 0.14
BCF4.................................................... NA 0.19 0.085 0.079 0.077 NA 0.20 0.11 0.11 0.015 0.13 0.095 NA 0.13
BC2F6................................................... 0.027 NA 0.035 0.025 0.024 0.0034 NA 0.019 0.0059 NA 0.10 0.073 0.014 0.045
BC4F8................................................... NA NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8................................................... NA NA NA NA NA NA NA NA NA NA NA NA NA NA
BC5F8................................................... 0.00077 NA 0.0012 NA NA NA NA 0.0043 NA NA NA NA NA NA
BCHF3................................................... 0.060 0.0020 NA 0.049 NA NA NA 0.020 NA NA 0.0011 0.066 0.0039 NA
BF2..................................................... NA NA NA NA NA NA NA NA NA 0.50 NA NA NA NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA = Not applicable; i.e., there are no applicable emission factor measurements for this gas. This does not necessarily imply that a particular gas is not used in or emitted from a particular process sub-type or process type.
[[Page 31922]]
0
34. Revise table I-12 to subpart I to read as follows:
Table I-12 to Subpart I of Part 98--Default Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for Use With the Stack Test Method
[300 mm and 450 mm Wafers]
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
All processes C3F8 Remote NF3
CF4 C2F6 CHF3 CH2F2 CH3F C3F8 C4F8 NF3 Remote SF6 C4F6 C5F8 C4F8O
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui..................................................... 0.65 0.80 0.37 0.20 0.30 0.30 0.063 0.183 0.19 0.018 0.30 0.15 0.100 NA
BCF4..................................................... NA 0.21 0.076 0.060 0.029 0.21 NA 0.045 0.040 0.037 0.033 0.059 0.109 NA
BC2F6.................................................... 0.058 NA 0.058 0.043 0.0093 0.18 NA 0.027 0.0204 NA 0.041 0.062 0.083 NA
BC4F6.................................................... 0.0083 NA 0.01219 NA 0.001 NA NA 0.008 NA NA NA NA NA NA
BC4F8.................................................... 0.0046 NA 0.00272 0.054 0.007 NA NA NA NA NA NA 0.0051 NA NA
BC3F8.................................................... NA NA NA NA NA NA NA NA NA NA NA NA 0.00012 NA
BCH2F2................................................... 0.005 NA 0.0024 NA 0.0033 NA NA 0.0021 0.00034 0.00088 0.000020 0.000030 NA NA
BCH3F.................................................... 0.0061 NA 0.027 0.0036 NA 0.0007 NA 0.0063 0.0036 0.0028 0.0082 0.00065 NA NA
BCHF3.................................................... 0.012 NA NA 0.057 0.016 0.012 NA 0.028 0.0106 0.000059 0.0039 0.017 0.0069 NA
BF2...................................................... NA NA NA NA NA NA NA NA NA 0.50 NA NA NA NA
----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
0
35. Revise table I-16 to subpart I to read as follows:
Table I-16 to Subpart I of Part 98--Default Emission Destruction or
Removal Efficiency (DRE) Factors for Electronics Manufacturing
------------------------------------------------------------------------
Default DRE
Manufacturing type/process type/gas (%)
------------------------------------------------------------------------
MEMS, LCDs, and PV Manufacturing........................ 60
Semiconductor Manufacturing:
CF4................................................. 87
CH3F................................................ 98
CHF3................................................ 97
CH2F2............................................... 98
C4F8................................................ 93
C4F8O............................................... 93
C5F8................................................ 97
C4F6................................................ 95
C3F8................................................ 98
C2HF5............................................... 97
C2F6................................................ 98
SF6................................................. 95
NF3................................................. 96
All other carbon-based fluorinated GHGs used in 60
Semiconductor Manufacturing............................
N2O Processes...........................................
CVD and all other N2O-using processes................... 60
------------------------------------------------------------------------
0
36. Add table I-18 to subpart I to read as follows:
Table I-18 to Subpart I of Part 98--Default Factors for Gamma (gi,p and gk,i,p) for Semiconductor Manufacturing and for MEMS and PV Manufacturing Under
Certain Conditions * for Use With the Stack Testing Method
--------------------------------------------------------------------------------------------------------------------------------------------------------
Process type In-situ thermal or in-situ plasma cleaning Remote plasma cleaning
--------------------------------------------------------------------------------------------------------------------------------------------------------
c-C4F8
Gas CF4 C2F6 NF3 SF6 C3F8 CF4 NF3
--------------------------------------------------------------------------------------------------------------------------------------------------------
If manufacturing wafer sizes <=200 mm AND manufacturing 300 mm (or greater) wafer sizes
--------------------------------------------------------------------------------------------------------------------------------------------------------
gi..................................................... 13 9.3 4.7 14 11 NA NA 5.7
gCF4,i................................................. NA 23 6.7 63 8.7 NA NA 58
gC2F6,i................................................ NA NA NA NA 3.4 NA NA NA
gCHF3,i................................................ NA NA NA NA NA NA NA 0.24
gCH2F2,i............................................... NA NA NA NA NA NA NA 111
gCH3F,i................................................ NA NA NA NA NA NA NA 33
--------------------------------------------------------------------------------------------------------------------------------------------------------
If manufacturing <=200 mm OR manufacturing 300 mm (or greater) wafer sizes
--------------------------------------------------------------------------------------------------------------------------------------------------------
gi (<= 200 mm wafer size).............................. 13 9.3 4.7 2.9 11 NA NA 1.4
[[Page 31923]]
gCF4,i (<=200 mm wafer size)........................... NA 23 6.7 110 8.7 NA NA 36
gC2F6,i (<=200 mm wafer size).......................... NA NA NA NA 3.4 NA NA NA
gi (300 mm wafer size)................................. NA NA NA 26 NA NA NA 10
gCF4,i (300 mm wafer size)............................. NA NA NA 17 NA NA NA 80
gC2F6,i (300 mm wafer size)............................ NA NA NA NA NA NA NA NA
gCHF3,i (300 mm wafer size)............................ NA NA NA NA NA NA NA 0.24
gCH2F2,i (300 mm wafer size)........................... NA NA NA NA NA NA NA 111
gCH3F,i (300 mm wafer size)............................ NA NA NA NA NA NA NA 33
--------------------------------------------------------------------------------------------------------------------------------------------------------
* If you manufacture MEMS or PVs and use semiconductor tools and processes, you may use the corresponding g in this table. For all other tools and
processes, a default g of 10 must be used.
0
37. Add table I-19 to subpart I to read as follows:
Table I-19 to Subpart I of Part 98--Reference Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 150 mm and 200
mm Wafer Sizes
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
Process type/sub-type -----------------------------------------------------------------------------------------------------------------------------------------------------------------
CF4 C2F6 CHF3 CH2F2 C2HF5 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Etching/Wafer Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... 0.73 0.46 0.31 0.37 0.064 0.66 NA 0.21 0.20 0.55 0.086 0.072 NA
BCF4.......................... NA 0.20 0.10 0.031 0.077 NA NA 0.17 0.0040 0.023 0.0089 NA NA
BC2F6......................... 0.029 NA NA NA NA NA NA 0.065 NA NA 0.045 0.014 NA
BC4F6......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC4F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC5F8......................... NA NA NA NA NA NA NA 0.016 NA NA NA NA NA
BCHF3......................... 0.13 NA NA NA NA NA NA NA NA NA NA 0.0039 NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Chamber Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
In situ plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... 0.92 0.55 NA NA NA NA 0.40 0.10 0.18 NA NA NA 0.14
BCF4.......................... NA 0.19 NA NA NA NA 0.20 0.11 0.14 NA NA NA 0.13
BC2F6......................... NA NA NA NA NA NA NA NA NA NA NA NA 0.045
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Remote plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... NA NA NA NA NA NA NA NA 0.028 NA NA NA NA
BCF4.......................... NA NA NA NA NA NA NA NA 0.015 NA NA NA NA
BC2F6......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
In situ thermal cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui.......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BCF4.......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC2F6......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8......................... NA NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
0
38. Add table I-20 to subpart I to read as follows:
[[Page 31924]]
Table I-20 to Subpart I of Part 98--Reference Emission Factors (1-Uij) for Gas Utilization Rates (Uij) and By-Product Formation Rates (Bijk) for Semiconductor Manufacturing for 300 mm Wafer
Sizes
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Process gas i
Process type/sub-type --------------------------------------------------------------------------------------------------------------------------------------------------------------
CF4 C2F6 CHF3 CH2F2 CH3F C3F8 C4F8 NF3 SF6 C4F6 C5F8 C4F8O
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Etching/Wafer Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui............................. 0.68 0.80 0.35 0.15 0.34 0.30 0.16 0.17 0.28 0.17 0.10 NA
BCF4............................. NA 0.21 0.073 0.020 0.038 0.21 0.045 0.035 0.0072 0.034 0.11 NA
BC2F6............................ 0.041 NA 0.040 0.0065 0.0064 0.18 0.030 0.038 0.0017 0.025 0.083 NA
BC4F6............................ 0.0015 NA 0.00010 NA 0.0010 NA 0.00083 NA NA NA NA NA
BC4F8............................ 0.0051 NA 0.00061 NA 0.0070 NA NA NA NA NA NA NA
BC3F8............................ NA NA NA NA NA NA NA NA NA NA 0.00012 NA
BC5F8............................ NA NA NA NA NA NA NA NA NA NA NA NA
BCHF3............................ 0.0056 NA NA 0.033 0.0049 0.012 0.029 0.0065 0.0012 0.019 0.0069 NA
BCH2F2........................... 0.014 NA 0.0026 NA 0.0023 NA 0.0014 0.00086 0.000020 0.000030 NA NA
BCH3F............................ 0.00057 NA 0.12 NA NA 0.00073 NA NA 0.0082 NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Chamber Cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
In situ plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui............................. NA NA NA NA NA NA NA 0.20 NA NA NA NA
BCF4............................. NA NA NA NA NA NA NA 0.037 NA NA NA NA
BC2F6............................ NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8............................ NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Remote plasma cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui............................. NA NA NA NA NA 0.063 NA 0.018 NA NA NA NA
BCF4............................. NA NA NA NA NA NA NA 0.038 NA NA NA NA
BC2F6............................ NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8............................ NA NA NA NA NA NA NA NA NA NA NA NA
BCHF3............................ NA NA NA NA NA NA NA 0.000059 NA NA NA NA
BCH2F2........................... NA NA NA NA NA NA NA 0.0016 NA NA NA NA
BCH3F............................ NA NA NA NA NA NA NA 0.0028 NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
In situ thermal cleaning
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
1-Ui............................. NA NA NA NA NA NA NA 0.28 NA NA NA NA
BCF4............................. NA NA NA NA NA NA NA 0.010 NA NA NA NA
BC2F6............................ NA NA NA NA NA NA NA NA NA NA NA NA
BC3F8............................ NA NA NA NA NA NA NA NA NA NA NA NA
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 31925]]
0
39. Add table I-21 to subpart I to read as follows:
Table I-21 to Subpart I of Part 98--Examples of Fluorinated GHGs Used by
the Electronics Industry
------------------------------------------------------------------------
Fluorinated GHGs used during
Product type manufacture
------------------------------------------------------------------------
Electronics....................... CF4, C2F6, C3F8, c-C4F8, c-C4F8O,
C4F6, C5F8, CHF3, CH2F2, NF3, SF6,
and fluorinated HTFs (CF3-(O-
CF(CF3)-CF2)n-(O-CF2)m-O-CF3,
CnF2n+2, CnF2n+1(O)CmF2m+1, CnF2nO,
(CnF2n+1)3N).
------------------------------------------------------------------------
Subpart N--Glass Production
0
40. Revise and republish Sec. 98.146 to read as follows:
Sec. 98.146 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.
(a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required under
Sec. 98.36 for the Tier 4 Calculation Methodology and the following
information specified in paragraphs (a)(1) through (3) of this section:
(1) Annual quantity of each carbonate-based raw material (tons)
charged to each continuous glass melting furnace and for all furnaces
combined.
(2) Annual quantity of glass produced (tons), by glass type, from
each continuous glass melting furnace and from all furnaces combined.
(3) Annual quantity (tons), by glass type, of recycled scrap glass
(cullet) charged to each continuous glass melting furnace and for all
furnaces combined.
(b) If a CEMS is not used to determine CO2 emissions
from continuous glass melting furnaces, and process CO2
emissions are calculated according to the procedures specified in Sec.
98.143(b), then you must report the following information as specified
in paragraphs (b)(1) through (9) of this section:
(1) Annual process emissions of CO2 (metric tons) for
each continuous glass melting furnace and for all furnaces combined.
(2) Annual quantity of each carbonate-based raw material charged
(tons) to all furnaces combined.
(3) Annual quantity of glass produced (tons), by glass type, from
each continuous glass melting furnace and from all furnaces combined.
(4) Annual quantity (tons), by glass type, of recycled scrap glass
(cullet) charged to each continuous glass melting furnace and for all
furnaces combined.
(5) Results of all tests, if applicable, used to verify the
carbonate-based mineral mass fraction for each carbonate-based raw
material charged to a continuous glass melting furnace, as specified in
paragraphs (b)(5)(i) through (iii) of this section.
(i) Date of test.
(ii) Method(s) and any variations used in the analyses.
(iii) Mass fraction of each sample analyzed.
(6) [Reserved]
(7) Method used to determine decimal fraction of calcination,
unless you used the default value of 1.0.
(8) Total number of continuous glass melting furnaces.
(9) The number of times in the reporting year that missing data
procedures were followed to measure monthly quantities of carbonate-
based raw materials, recycled scrap glass (cullet), or mass fraction of
the carbonate-based minerals for any continuous glass melting furnace
(months).
0
41. Amend Sec. 98.147 by revising and republishing paragraphs (a) and
(b) to read as follows:
Sec. 98.147 Records that must be retained.
* * * * *
(a) If a CEMS is used to measure emissions, then you must retain
the records required under Sec. 98.37 for the Tier 4 Calculation
Methodology and the following information specified in paragraphs
(a)(1) through (3) of this section:
(1) Monthly glass production rate for each continuous glass melting
furnace, by glass type (tons).
(2) Monthly amount of each carbonate-based raw material charged to
each continuous glass melting furnace (tons).
(3) Monthly amount (tons) of recycled scrap glass (cullet) charged
to each continuous glass melting furnace, by glass type.
(b) If process CO2 emissions are calculated according to
the procedures specified in Sec. 98.143(b), you must retain the
records in paragraphs (b)(1) through (6) of this section.
(1) Monthly glass production rate for each continuous glass melting
furnace, by glass type (tons).
(2) Monthly amount of each carbonate-based raw material charged to
each continuous glass melting furnace (tons).
(3) Monthly amount (tons) of recycled scrap glass (cullet) charged
to each continuous glass melting furnace, by glass type.
(4) Data on carbonate-based mineral mass fractions provided by the
raw material supplier for all raw materials consumed annually and
included in calculating process emissions in equation N-1 to Sec.
98.143, if applicable.
(5) Results of all tests, if applicable, used to verify the
carbonate-based mineral mass fraction for each carbonate-based raw
material charged to a continuous glass melting furnace, including the
data specified in paragraphs (b)(5)(i) through (v) of this section.
(i) Date of test.
(ii) Method(s), and any variations of the methods, used in the
analyses.
(iii) Mass fraction of each sample analyzed.
(iv) Relevant calibration data for the instrument(s) used in the
analyses.
(v) Name and address of laboratory that conducted the tests.
(6) The decimal fraction of calcination achieved for each
carbonate-based raw material, if a value other than 1.0 is used to
calculate process mass emissions of CO2.
* * * * *
Subpart P--Hydrogen Production
0
42. Revise Sec. 98.160 to read as follows:
Sec. 98.160 Definition of the source category.
(a) A hydrogen production source category consists of facilities
that produce hydrogen gas as a product.
(b) This source category comprises process units that produce
hydrogen by reforming, gasification, oxidation, reaction, or other
transformations of feedstocks except the processes listed in paragraph
(b)(1) or (2) of this section.
(1) Any process unit for which emissions are reported under another
subpart of this part. This includes, but is not necessarily limited to:
(i) Ammonia production units for which emissions are reported under
subpart G.
(ii) Catalytic reforming units at petroleum refineries that
transform
[[Page 31926]]
naphtha into higher octane aromatics for which emissions are reported
under subpart Y.
(iii) Petrochemical process units for which emissions are reported
under subpart X.
(2) Any process unit that only separates out diatomic hydrogen from
a gaseous mixture and is not associated with a unit that produces
hydrogen created by transformation of one or more feedstocks, other
than those listed in paragraph (b)(1) of this section.
(c) This source category includes the process units that produce
hydrogen and stationary combustion units directly associated with
hydrogen production (e.g. , reforming furnace and hydrogen production
process unit heater).
0
43. Amend Sec. 98.162 by revising paragraph (a) to read as follows:
Sec. 98.162 GHGs to report.
* * * * *
(a) CO2 emissions from each hydrogen production process
unit, including fuel combustion emissions accounted for in the
calculation methodologies in Sec. 98.163.
* * * * *
0
44. Amend Sec. 98.163 by revising the introductory text, paragraph (b)
introductory text, and paragraph (c) to read as follows:
Sec. 98.163 Calculating GHG emissions.
You must calculate and report the annual CO2 emissions
from each hydrogen production process unit using the procedures
specified in paragraphs (a) through (c) of this section, as applicable.
* * * * *
(b) Fuel and feedstock material balance approach. Calculate and
report CO2 emissions as the sum of the annual emissions
associated with each fuel and feedstock used for each hydrogen
production process unit by following paragraphs (b)(1) through (3) of
this section. The carbon content and molecular weight shall be obtained
from the analyses conducted in accordance with Sec. 98.164(b)(2), (3),
or (4), as applicable, or from the missing data procedures in Sec.
98.165. If the analyses are performed annually, then the annual value
shall be used as the monthly average. If the analyses are performed
more frequently than monthly, use the arithmetic average of values
obtained during the month as the monthly average.
* * * * *
(c) If GHG emissions from a hydrogen production process unit are
vented through the same stack as any combustion unit or process
equipment that reports CO2 emissions using a CEMS that
complies with the Tier 4 Calculation Methodology in subpart C of this
part, then the owner or operator shall report under this subpart the
combined stack emissions according to the Tier 4 Calculation
Methodology in Sec. 98.33(a)(4) and all associated requirements for
Tier 4 in subpart C of this part. If GHG emissions from a hydrogen
production process unit using a CEMS that complies with the Tier 4
Calculation Methodology in subpart C of this part does not include
combustion emissions from the hydrogen production unit (i.e. , the
hydrogen production unit has separate stacks for process and combustion
emissions), then the calculation methodology in paragraph (b) of this
section shall be used considering only fuel inputs to calculate and
report CO2 emissions from fuel combustion related to the
hydrogen production unit.
0
45. Amend Sec. 98.164 by:
0
a. Revising the introductory text, paragraphs (b)(2) through (4), and
(b)(5) introductory text; and
0
b. Adding paragraphs (b)(5)(xix) and (c).
The revisions and additions read as follows:
Sec. 98.164 Monitoring and QA/QC requirements.
The GHG emissions data for hydrogen production process units must
be quality-assured as specified in paragraph (a) or (b) of this
section, as appropriate for each process unit, except as provided in
paragraph (c) of this section:
* * * * *
(b) * * *
(2) Determine the carbon content and the molecular weight annually
of standard gaseous hydrocarbon fuels and feedstocks having consistent
composition (e.g., natural gas) according to paragraph (b)(5) of this
section. For gaseous fuels and feedstocks that have a maximum product
specification for carbon content less than or equal to 0.00002 kg
carbon per kg of gaseous fuel or feedstock, you may instead determine
the carbon content and the molecular weight annually using the product
specification's maximum carbon content and molecular weight. For other
gaseous fuels and feedstocks (e.g., biogas, refinery gas, or process
gas), sample and analyze no less frequently than weekly to determine
the carbon content and molecular weight of the fuel and feedstock
according to paragraph (b)(5) of this section.
(3) Determine the carbon content of fuel oil, naphtha, and other
liquid fuels and feedstocks at least monthly, except annually for
standard liquid hydrocarbon fuels and feedstocks having consistent
composition, or upon delivery for liquid fuels and feedstocks delivered
by bulk transport (e.g., by truck or rail) according to paragraph
(b)(5) of this section. For liquid fuels and feedstocks that have a
maximum product specification for carbon content less than or equal to
0.00006 kg carbon per gallon of liquid fuel or feedstock, you may
instead determine the carbon content annually using the product
specification's maximum carbon content.
(4) Determine the carbon content of coal, coke, and other solid
fuels and feedstocks at least monthly, except annually for standard
solid hydrocarbon fuels and feedstocks having consistent composition,
or upon delivery for solid fuels and feedstocks delivered by bulk
transport (e.g., by truck or rail) according to paragraph (b)(5) of
this section.
(5) Except as provided in paragraphs (b)(2) and (3) of this section
for fuels and feedstocks with a carbon content below the specified
levels, you must use the following applicable methods to determine the
carbon content for all fuels and feedstocks, and molecular weight of
gaseous fuels and feedstocks. Alternatively, you may use the results of
chromatographic analysis of the fuel and feedstock, provided that the
chromatograph is operated, maintained, and calibrated according to the
manufacturer's instructions; and the methods used for operation,
maintenance, and calibration of the chromatograph are documented in the
written monitoring plan for the unit under Sec. 98.3(g)(5).
* * * * *
(xix) For fuels and feedstocks with a carbon content below the
specified levels in paragraphs (b)(2) and (3) of this section, if the
methods listed in paragraphs (b)(5)(i) through (xviii) of this section
are not appropriate because the relevant compounds cannot be detected,
the quality control requirements are not technically feasible, or use
of the method would be unsafe, you may use modifications of the methods
listed in paragraphs (b)(5)(i) through (xviii) or use other methods
that are applicable to your fuel or feedstock.
(c) You may use best available monitoring methods as specified in
paragraph (c)(2) of this section for measuring the fuel used by each
stationary combustion unit directly associated with hydrogen production
(e.g., reforming furnace and hydrogen production process unit heater)
that
[[Page 31927]]
meets the criteria specified in paragraph (c)(1) of this section.
Eligibility to use best available monitoring methods ends upon the
completion of any planned process unit or equipment shutdown after
January 1, 2025.
(1) To be eligible to use best available monitoring methods, you
must meet all criteria in paragraphs (c)(1)(i) through (iv) of this
section.
(i) The stationary combustion unit must be directly associated with
hydrogen production (e.g., reforming furnace and hydrogen production
process unit heater).
(ii) A measurement device meeting the requirements in paragraph
(b)(1) of this section is not installed to measure the fuel used by
each stationary combustion unit as of January 1, 2025.
(iii) The hydrogen production unit and associated stationary
combustion unit are operated continuously.
(iv) Installation of a measurement device to measure the fuel used
by each stationary combustion unit that meets the requirements in
paragraph (b)(1) of this section must require a planned process
equipment or unit shutdown or can only be done through a hot tap.
(2) Best available monitoring methods means any of the following
methods:
(i) Monitoring methods currently used by the facility that do not
meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
0
46. Revise Sec. 98.166 to read as follows:
Sec. 98.166 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information for each hydrogen
production process unit:
(a) The unit identification number.
(b) If a CEMS is used to measure CO2 emissions, then you
must report the relevant information required under Sec. 98.36 for the
Tier 4 Calculation Methodology. If the CEMS measures emissions from
either a common stack for multiple hydrogen production units or a
common stack for hydrogen production unit(s) and other source(s), you
must also report the estimated decimal fraction of the total annual
CO2 emissions attributable to this hydrogen production
process unit (estimated using engineering estimates or best available
data).
(c) If a material balance is used to calculate emissions using
equations P-1 through P-3 to Sec. 98.163, as applicable, report the
total annual CO2 emissions (metric tons) and the name and
annual quantity (metric tons) of each carbon-containing fuel and
feedstock.
(d) The information specified in paragraphs (d)(1) through (10):
(1) The type of hydrogen production unit (steam methane reformer
(SMR) only, SMR followed by water gas shift reaction (WGS), partial
oxidation (POX) only, POX followed by WGS, autothermal reforming only,
autothermal reforming followed by WGS, water electrolysis, brine
electrolysis, other (specify)).
(2) The type of hydrogen purification method (pressure swing
adsorption, amine adsorption, membrane separation, other (specify),
none).
(3) Annual quantity of hydrogen produced by reforming,
gasification, oxidation, reaction, or other transformation of
feedstocks (metric tons).
(4) Annual quantity of hydrogen that is purified only (metric
tons). This quantity may be assumed to be equal to the annual quantity
of hydrogen in the feedstocks to the hydrogen production unit.
(5) Annual quantity of ammonia intentionally produced as a desired
product, if applicable (metric tons).
(6) Quantity of CO2 collected and transferred off site
in either gas, liquid, or solid forms, following the requirements of
subpart PP of this part.
(7) Annual quantity of carbon other than CO2 or methanol
collected and transferred off site or transferred to a separate process
unit within the facility for which GHG emissions associated with this
carbon is being reported under other provisions of this part, in either
gas, liquid, or solid forms (metric tons carbon).
(8) Annual quantity of methanol intentionally produced as a desired
product, if applicable, (metric tons) for each process unit.
(9) Annual net quantity of steam consumed by the unit, (metric
tons). Include steam purchased or produced outside of the hydrogen
production unit. If the hydrogen production unit is a net producer of
steam, enter the annual net quantity of steam consumed by the unit as a
negative value.
(10) An indication (yes or no) if best available monitoring methods
were used, in accordance with Sec. 98.164(c), to determine fuel flow
for each stationary combustion unit directly associated with hydrogen
production (e.g., reforming furnace and hydrogen production process
unit heater). If yes, report:
(i) The beginning date of using best available monitoring methods,
in accordance with Sec. 98.164(c), to determine fuel flow for each
stationary combustion unit directly associated with hydrogen production
(e.g., reforming furnace and hydrogen production process unit heater).
(ii) The anticipated or actual end date of using best available
monitoring methods, as applicable, in accordance with Sec. 98.164(c),
to determine fuel flow for each stationary combustion unit directly
associated with hydrogen production (e.g., reforming furnace and
hydrogen production process unit heater).
0
47. Amend Sec. 98.167 by:
0
a. Revising paragraphs (a) and (b);
0
b. Removing and reserving paragraph (c); and
0
c. Revising paragraphs (d) and (e) introductory text.
The revisions read as follows:
Sec. 98.167 Records that must be retained.
* * * * *
(a) If a CEMS is used to measure CO2 emissions, then you
must retain under this subpart the records required for the Tier 4
Calculation Methodology in Sec. 98.37, and, if the CEMS measures
emissions from a common stack for multiple hydrogen production units or
emissions from a common stack for hydrogen production unit(s) and other
source(s), records used to estimate the decimal fraction of the total
annual CO2 emissions from the CEMS monitoring location
attributable to each hydrogen production unit.
(b) You must retain records of all analyses and calculations
conducted to determine the values reported in Sec. 98.166(b).
* * * * *
(d) The owner or operator must document the procedures used to
ensure the accuracy of the estimates of fuel and feedstock usage in
Sec. 98.163(b), including, but not limited to, calibration of weighing
equipment, fuel and feedstock flow meters, and other measurement
devices. The estimated accuracy of measurements made with these devices
must also be recorded, and the technical basis for these estimates must
be provided.
(e) The applicable verification software records as identified in
this paragraph (e). 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 (e)(1) through (12) of this section.
Retention of this file satisfies the recordkeeping requirement for the
data in paragraphs (e)(1) through (12) of this section for each
hydrogen production unit.
* * * * *
[[Page 31928]]
Subpart Q--Iron and Steel Production
0
48. Amend Sec. 98.173 by revising equation Q-5 in paragraph (b)(1)(v)
to read as follows:
Sec. 98.173 Calculating GHG emissions.
* * * * *
(b) * * *
(1) * * *
(v) * * *
[GRAPHIC] [TIFF OMITTED] TR25AP24.040
* * * * *
0
49. Amend Sec. 98.174 by:
0
a. Revising paragraph (b)(2) introductory text;
0
b. Redesignating paragraph (b)(2)(vi) as paragraph (b)(2)(vii); and
0
c. Adding new paragraph (b)(2)(vi).
The revision and addition read as follows:
Sec. 98.174 Monitoring and QA/QC requirements.
* * * * *
(b) * * *
(2) Except as provided in paragraph (b)(4) of this section,
determine the carbon content of each process input and output annually
for use in the applicable equations in Sec. 98.173(b)(1) based on
analyses provided by the supplier, analyses provided by material
recyclers who manage process outputs for sale or use by other
industries, or by the average carbon content determined by collecting
and analyzing at least three samples each year using the standard
methods specified in paragraphs (b)(2)(i) through (vii) of this section
as applicable.
* * * * *
(vi) ASTM E415-17, Standard Test Method for Analysis of Carbon and
Low-Alloy Steel by Spark Atomic Emission Spectrometry (incorporated by
reference, see Sec. 98.7) as applicable for steel.
* * * * *
0
50. Amend Sec. 98.176 by revising paragraphs (e)(2) and adding
paragraph (g) to read as follows:
Sec. 98.176 Data reporting requirements.
* * * * *
(e) * * *
(2) Whether the carbon content was determined from information from
the supplier, material recycler, or by laboratory analysis, and if by
laboratory analysis, the method used in Sec. 98.174(b)(2).
* * * * *
(g) For each unit, the type of unit, the annual production
capacity, and annual operating hours.
* * * * *
Subpart S--Lime Manufacturing
0
51. Amend Sec. 98.193 by revising equation S-4 in paragraph (b)(2)(iv)
to read as follows:
Sec. 98.193 Calculating GHG emissions.
* * * * *
(b) * * *
(2) * * *
(iv) * * *
[GRAPHIC] [TIFF OMITTED] TR25AP24.041
* * * * *
0
52. Amend Sec. 98.196 by:
0
a. Revising paragraph (a) introductory text;
0
b. Adding paragraphs (a)(9) through (14);
0
c. Revising paragraphs (b) introductory text and (b)(17); and
0
d. Adding paragraphs (b)(22) and (23).
The revisions and additions read as follows:
Sec. 98.196 Data reporting requirements.
* * * * *
(a) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required by
Sec. 98.36 and the information listed in paragraphs (a)(1) through
(14) of this section.
* * * * *
(9) Annual arithmetic average of calcium oxide content for each
type of lime product produced (metric tons CaO/metric ton lime).
(10) Annual arithmetic average of magnesium oxide content for each
type of lime product produced (metric tons MgO/metric ton lime).
(11) Annual arithmetic average of calcium oxide content for each
type of calcined lime byproduct/waste sold (metric tons CaO/metric ton
lime).
(12) Annual arithmetic average of magnesium oxide content for each
type of calcined lime byproduct/waste sold (metric tons MgO/metric ton
lime).
(13) Annual arithmetic average of calcium oxide content for each
type of calcined lime byproduct/waste not sold (metric tons CaO/metric
ton lime).
(14) Annual arithmetic average of magnesium oxide content for each
type of calcined lime byproduct/waste not sold (metric tons MgO/metric
ton lime)
(b) If a CEMS is not used to measure CO2 emissions, then
you must report the information listed in paragraphs (b)(1) through
(23) of this section.
* * * * *
(17) Indicate whether CO2 was captured and used on-site
(e.g., for use in a purification process, the manufacture of another
product). If CO2 was captured and used on-site, provide the
information in paragraphs (b)(17)(i) and (ii) of this section.
(i) The annual amount of CO2 captured for use in all on-
site processes.
(ii) The method used to determine the amount of CO2
captured.
* * * * *
(22) Annual average results of chemical composition analysis of all
lime byproducts or wastes not sold.
[[Page 31929]]
(23) Annual quantity (tons) of all lime byproducts or wastes not
sold.
Subpart U--Miscellaneous Uses of Carbonate
0
53. Amend Sec. 98.210 by revising paragraph (b) to read as follows:
Sec. 98.210 Definition of the source category.
* * * * *
(b) This source category does not include equipment that uses
carbonates or carbonate containing minerals that are consumed in the
production of cement, glass, ferroalloys, iron and steel, lead, lime,
phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium
hydroxide, zinc, or ceramics.
* * * * *
Subpart X-Petrochemical Production
0
54. Amend Sec. 98.243 by revising paragraphs (b)(3) and (d)(5) to read
as follows:
Sec. 98.243 Calculating GHG emissions.
* * * * *
(b) * * *
(3) For each flare, calculate CO2, CH4, and
N2O emissions using the methodology specified in Sec.
98.253(b).
* * * * *
(d) * * *
(5) For each flare, calculate CO2, CH4, and
N2O emissions using the methodology specified in Sec.
98.253(b).
0
55. Amend Sec. 98.244 by revising paragraph (b)(4)(iii) to read as
follows:
Sec. 98.244 Monitoring and QA/QC requirements.
* * * * *
(b) * * *
(4) * * *
(iii) ASTM D2505-88 (Reapproved 2004)e1 (incorporated by reference,
see Sec. 98.7).
* * * * *
0
56. Amend Sec. 98.246 by revising paragraphs (a) introductory text,
(a)(2), (5), (13) and (15), (b)(7) and (8), and (c) to read as follows:
Sec. 98.246 Data reporting requirements.
* * * * *
(a) If you use the mass balance methodology in Sec. 98.243(c), you
must report the information specified in paragraphs (a)(1) through (15)
of this section for each type of petrochemical produced, reported by
process unit.
* * * * *
(2) The type of petrochemical produced.
* * * * *
(5) Annual quantity of each type of petrochemical produced from
each process unit (metric tons). If you are electing to consider the
petrochemical process unit to be the entire integrated ethylene
dichloride/vinyl chloride monomer process, the portion of the total
amount of ethylene dichloride (EDC) produced that is used in vinyl
chloride monomer (VCM) production may be a measured quantity or an
estimate that is based on process knowledge and best available data.
The portion of the total amount of EDC produced that is not utilized in
VCM production must be measured in accordance with Sec. 98.244(b)(2)
or (3). Sum the amount of EDC used in the production of VCM plus the
amount of separate EDC product to report as the total quantity of EDC
petrochemical from an integrated EDC/VCM petrochemical process unit.
* * * * *
(13) Name and annual quantity (in metric tons) of each product
included in equations X-1, X-2, and X-3 to Sec. 98.243. If you are
electing to consider the petrochemical process unit to be the entire
integrated ethylene dichloride/vinyl chloride monomer process, the
reported quantity of EDC product should include only that which was not
used in the VCM process.
* * * * *
(15) For each gaseous feedstock or product for which the volume was
used in equation X-1 to Sec. 98.243, report the annual average
molecular weight of the measurements or determinations, conducted
according to Sec. 98.243(c)(3) or (4). Report the annual average
molecular weight in units of kg per kg mole.
(b) * * *
(7) Information listed in Sec. 98.256(e) for each flare that burns
process off-gas. Additionally, provide estimates based on engineering
judgment of the fractions of the total CO2, CH4
and N2O emissions that are attributable to combustion of
off-gas from the petrochemical process unit(s) served by the flare.
(8) Annual quantity of each type of petrochemical produced from
each process unit (metric tons).
* * * * *
(c) If you comply with the combustion methodology specified in
Sec. 98.243(d), you must report under this subpart the information
listed in paragraphs (c)(1) through (6) of this section.
(1) The ethylene process unit ID or other appropriate descriptor.
(2) For each stationary combustion unit that burns ethylene process
off-gas (or group of stationary sources with a common pipe), except
flares, the relevant information listed in Sec. 98.36 for the
applicable Tier methodology. For each stationary combustion unit or
group of units (as applicable) that burns ethylene process off-gas,
provide an estimate based on engineering judgment of the fraction of
the total emissions that is attributable to combustion of off-gas from
the ethylene process unit.
(3) Information listed in Sec. 98.256(e) for each flare that burns
ethylene process off-gas. Additionally, provide estimates based on
engineering judgment of the fractions of the total CO2,
CH4 and N2O emissions that are attributable to
combustion of off-gas from the ethylene process unit(s) served by the
flare.
(4) Name and annual quantity of each carbon-containing feedstock
(metric tons).
(5) Annual quantity of ethylene produced from each process unit
(metric tons).
(6) Name and annual quantity (in metric tons) of each product
produced in each process unit.
Subpart Y--Petroleum Refineries
0
57. Amend Sec. 98.250 by revising paragraph (c) to read as follows:
Sec. 98.250 Definition of source category.
* * * * *
(c) This source category consists of the following sources at
petroleum refineries: Catalytic cracking units; fluid coking units;
delayed coking units; catalytic reforming units; asphalt blowing
operations; blowdown systems; storage tanks; process equipment
components (compressors, pumps, valves, pressure relief devices,
flanges, and connectors) in gas service; marine vessel, barge, tanker
truck, and similar loading operations; flares; and sulfur recovery
plants.
Sec. 98.252 [Amended]
0
58. Amend Sec. 98.252 by removing and reserving paragraphs (e) and
(i).
0
59. Amend Sec. 98.253 by:
0
a. Revising the introductory text of paragraphs (b) and (c);
0
b. Revising and republishing paragraphs (c)(4) and (5);
0
c. Revising paragraph (e) introductory text;
0
d. Removing and reserving paragraph (g); and
0
e. Revising and republishing paragraphs (i)(2) and (5).
The revisions read as follows:
Sec. 98.253 Calculating GHG emissions.
* * * * *
(b) For flares, calculate GHG emissions according to the
requirements in paragraphs (b)(1) through (3) of this section. All gas
discharged through the flare stack must be included in the flare
[[Page 31930]]
GHG emissions calculations with the exception of the following, which
may be excluded as applicable: gas used for the flare pilots, and if
using the calculation method in paragraph (b)(1)(iii) of this section,
the gas released during start-up, shutdown, or malfunction events of
500,000 scf/day or less.
* * * * *
(c) For catalytic cracking units and traditional fluid coking
units, calculate the GHG emissions from coke burn-off using the
applicable methods described in paragraphs (c)(1) through (5) of this
section.
* * * * *
(4) Calculate CH4 emissions using either unit specific
measurement data, a unit-specific emission factor based on a source
test of the unit, or equation Y-9 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.042
Where:
CH4 = Annual methane emissions from coke burn-off (metric
tons CH4/year).
CO2 = Emission rate of CO2 from coke burn-off
calculated in paragraphs (c)(1), (c)(2), (e)(1), or (e)(2) of this
section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for
petroleum coke from table C-1 to subpart C of this part (kg
CO2/MMBtu).
EmF2 = Default CH4 emission factor for
``PetroleumProducts'' from table C-2 to subpart C of this part (kg
CH4/MMBtu).
(5) Calculate N2O emissions using either unit specific
measurement data, a unit-specific emission factor based on a source
test of the unit, or equation Y-10 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.043
Where:
N2O = Annual nitrous oxide emissions from coke burn-off
(mt N2O/year).
CO2 = Emission rate of CO2 from coke burn-off
calculated in paragraphs (c)(1), (c)(2), (e)(1), or (e)(2) of this
section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for
petroleum coke from table C-1 to subpart C of this part (kg
CO2/MMBtu).
EmF3 = Default N2O emission factor for
``PetroleumProducts'' from table C-2 to subpart C of this part (kg
N2O/MMBtu).
* * * * *
(e) For catalytic reforming units, calculate the CO2
emissions from coke burn-off using the applicable methods described in
paragraphs (e)(1) through (3) of this section and calculate the
CH4 and N2O emissions using the methods described
in paragraphs (c)(4) and (5) of this section, respectively.
* * * * *
(i) * * *
(2) Determine the typical mass of water in the delayed coking unit
vessel at the end of the cooling cycle prior to venting to the
atmosphere using equation Y-18b to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.044
Where:
Mwater = Mass of water in the delayed coking unit vessel
at the end of the cooling cycle just prior to atmospheric venting or
draining (metric tons/cycle).
rwater = Density of water at average temperature of the
delayed coking unit vessel at the end of the cooling cycle just
prior to atmospheric venting (metric tons per cubic feet; mt/ft\3\).
Use the default value of 0.0270 mt/ft\3\.
Hwater = Typical distance from the bottom of the coking
unit vessel to the top of the water level at the end of the cooling
cycle just prior to atmospheric venting or draining (feet) from
company records or engineering estimates.
fcoke = Fraction of the coke-filled bed that is covered
by water at the end of the cooling cycle just prior to atmospheric
venting or draining. Use 1 if the water fully covers coke-filled
portion of the coke drum.
Mcoke = Typical dry mass of coke in the delayed coking
unit vessel at the end of the coking cycle (metric tons/cycle) as
determined in paragraph (i)(1) of this section.
rparticle = Particle density of coke (metric tons per
cubic feet; mt/ft\3\). Use the default value of 0.0382 mt/ft\3\.
D = Diameter of delayed coking unit vessel (feet).
* * * * *
(5) Calculate the CH4 emissions from decoking operations
at each delayed coking unit using equation Y-18f to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.045
Where:
CH4 = Annual methane emissions from the delayed coking
unit decoking operations (metric ton/year).
Msteam = Mass of steam generated and released per
decoking cycle (metric tons/cycle) as determined in paragraph (i)(4)
of this section.
EmFDCU = Methane emission factor for delayed coking unit
(kilograms CH4 per metric ton of steam; kg
CH4/mt steam) from unit-specific measurement data. If you
do not have unit-specific measurement data, use the default value of
7.9 kg CH4/metric ton steam.
N = Cumulative number of decoking cycles (or coke-cutting cycles)
for all delayed coking unit vessels associated with the delayed
coking unit during the year.
0.001 = Conversion factor (metric ton/kg).
* * * * *
0
60. Amend Sec. 98.254 by:
0
a. Revising the introductory text of paragraphs (d) and (e); and
[[Page 31931]]
0
b. Removing and reserving paragraphs (h) and (i).
The revisions read as follows:
Sec. 98.254 Monitoring and QA/QC requirements.
* * * * *
(d) Except as provided in paragraph (g) of this section, determine
gas composition and, if required, average molecular weight of the gas
using any of the following methods. Alternatively, the results of
chromatographic or direct mass spectrometer analysis of the gas may be
used, provided that the gas chromatograph or mass spectrometer is
operated, maintained, and calibrated according to the manufacturer's
instructions; and the methods used for operation, maintenance, and
calibration of the gas chromatograph or mass spectrometer are
documented in the written Monitoring Plan for the unit under Sec.
98.3(g)(5).
* * * * *
(e) Determine flare gas higher heating value using any of the
following methods. Alternatively, the results of chromatographic
analysis of the gas may be used, provided that the gas chromatograph is
operated, maintained, and calibrated according to the manufacturer's
instructions; and the methods used for operation, maintenance, and
calibration of the gas chromatograph are documented in the written
Monitoring Plan for the unit under Sec. 98.3(g)(5).
* * * * *
Sec. 98.255 [Amended]
0
61. Amend Sec. 98.255 by removing and reserving paragraph (d).
0
62. Amend Sec. 98.256 by:
0
a. Removing and reserving paragraphs (b) and (i);
0
b. Adding paragraph (j)(2); and
0
c. Revising paragraph (k)(6).
The addition and revision read as follows:
Sec. 98.256 Data reporting requirements.
* * * * *
(j) * * *
(2) Maximum rated throughput of the unit, in metric tons asphalt/
stream day.
* * * * *
(k) * * *
(6) The basis for the typical dry mass of coke in the delayed
coking unit vessel at the end of the coking cycle (mass measurements
from company records or calculated using equation Y-18a to Sec.
98.253). If you use mass measurements from company records to determine
the typical dry mass of coke in the delayed coking unit vessel at the
end of the coking cycle, you must also report:
(i) Internal height of delayed coking unit vessel (feet) for each
delayed coking unit.
(ii) Typical distance from the top of the delayed coking unit
vessel to the top of the coke bed (i.e. , coke drum outage) at the end
of the coking cycle (feet) from company records or engineering
estimates for each delayed coking unit.
* * * * *
0
63. Amend Sec. 98.257 by:
0
a. Revising paragraphs (b)(16) through (19);
0
b. Removing and reserving paragraphs (b)(27) through (31);
0
c. Revising paragraphs (b)(45), (46), and (53); and
0
d. Removing and reserving paragraphs (b)(54) through (56).
The revisions read as follows:
Sec. 98.257 Records that must be retained.
* * * * *
(b) * * *
(16) Value of unit-specific CH4 emission factor,
including the units of measure, for each catalytic cracking unit,
traditional fluid coking unit, and catalytic reforming unit
(calculation method in Sec. 98.253(c)(4)).
(17) Annual activity data (e.g. , input or product rate), including
the units of measure, in units of measure consistent with the emission
factor, for each catalytic cracking unit, traditional fluid coking
unit, and catalytic reforming unit (calculation method in Sec.
98.253(c)(4)).
(18) Value of unit-specific N2O emission factor,
including the units of measure, for each catalytic cracking unit,
traditional fluid coking unit, and catalytic reforming unit
(calculation method in Sec. 98.253(c)(5)).
(19) Annual activity data (e.g. , input or product rate), including
the units of measure, in units of measure consistent with the emission
factor, for each catalytic cracking unit, traditional fluid coking
unit, and catalytic reforming unit (calculation method in Sec.
98.253(c)(5)).
* * * * *
(45) Mass of water in the delayed coking unit vessel at the end of
the cooling cycle prior to atmospheric venting or draining (metric ton/
cycle) (equations Y-18b and Y-18e to Sec. 98.253) for each delayed
coking unit.
(46) Typical distance from the bottom of the coking unit vessel to
the top of the water level at the end of the cooling cycle just prior
to atmospheric venting or draining (feet) from company records or
engineering estimates (equation Y-18b to Sec. 98.253) for each delayed
coking unit.
* * * * *
(53) Fraction of the coke-filled bed that is covered by water at
the end of the cooling cycle just prior to atmospheric venting or
draining (equation Y-18b to Sec. 98.253) for each delayed coking unit.
* * * * *
Subpart AA--Pulp and Paper Manufacturing
0
64. Revise and republish Sec. 98.273 to read as follows:
Sec. 98.273 Calculating GHG emissions.
(a) For each chemical recovery furnace located at a kraft or soda
facility, you must determine CO2, biogenic CO2,
CH4, and N2O emissions using the procedures in
paragraphs (a)(1) through (4) of this section. CH4 and N2O emissions
must be calculated as the sum of emissions from combustion of fuels and
combustion of biomass in spent liquor solids.
(1) Calculate CO2 emissions from fuel combustion using
direct measurement of fuels consumed and default emissions factors
according to the Tier 1 methodology for stationary combustion sources
in Sec. 98.33(a)(1). Tiers 2 or 3 from Sec. 98.33(a)(2) or (3) may be
used to calculate CO2 emissions if the respective monitoring
and QA/QC requirements described in Sec. 98.34 are met.
(2) Calculate CH4 and N2O emissions from fuel
combustion using direct measurement of fuels consumed, default or site-
specific HHV, and default emissions factors and convert to metric tons
of CO2 equivalent according to the methodology for
stationary combustion sources in Sec. 98.33(c).
(3) Calculate biogenic CO2 emissions and emissions of
CH4 and N2O from biomass using measured
quantities of spent liquor solids fired, site-specific HHV, and default
emissions factors, according to equation AA-1 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.046
Where:
CO2, CH4, or N2O, from Biomass =
Biogenic CO2 emissions or emissions of CH4 or
N2O from spent liquor solids combustion (metric tons per
year).
[[Page 31932]]
Solids = Mass of spent liquor solids combusted (short tons per year)
determined according to Sec. 98.274(b).
HHV = Annual high heat value of the spent liquor solids (mmBtu per
kilogram) determined according to Sec. 98.274(b).
EF = Default emission factor for CO2, CH4, or
N2O, from table AA-1 to this subpart (kg CO2,
CH4, or N2O per mmBtu).
0.90718 = Conversion factor from short tons to metric tons.
(4) Calculate biogenic CO2 emissions from combustion of
biomass (other than spent liquor solids) with other fuels according to
the applicable methodology for stationary combustion sources in Sec.
98.33(e).
(b) For each chemical recovery combustion unit located at a sulfite
or stand-alone semichemical facility, you must determine
CO2, CH4, and N2O emissions using the
procedures in paragraphs (b)(1) through (5) of this section:
(1) Calculate CO2 emissions from fuel combustion using
direct measurement of fuels consumed and default emissions factors
according to the Tier 1 Calculation Methodology for stationary
combustion sources in Sec. 98.33(a)(1). Tiers 2 or 3 from Sec.
98.33(a)(2) or (3) may be used to calculate CO2 emissions if
the respective monitoring and QA/QC requirements described in Sec.
98.34 are met.
(2) Calculate CH4 and N2O emissions from fuel
combustion using direct measurement of fuels consumed, default or site-
specific HHV, and default emissions factors and convert to metric tons
of CO2 equivalent according to the methodology for
stationary combustion sources in Sec. 98.33(c).
(3) Calculate biogenic CO2 emissions using measured
quantities of spent liquor solids fired and the carbon content of the
spent liquor solids, according to equation AA-2 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.047
Where:
Biogenic CO2 = Annual CO2 mass emissions for
spent liquor solids combustion (metric tons per year).
Solids = Mass of the spent liquor solids combusted (short tons per
year) determined according to Sec. 98.274(b).
CC = Annual carbon content of the spent liquor solids, determined
according to Sec. 98.274(b) (percent by weight, expressed as a
decimal fraction, e.g. , 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.90718 = Conversion from short tons to metric tons.
(4) Calculate biogenic CO2 emissions from combustion of
biomass (other than spent liquor solids) with other fuels according to
the applicable methodology for stationary combustion sources in Sec.
98.33(e).
(c) For each pulp mill lime kiln located at a kraft or soda
facility, you must determine CO2, CH4, and
N2O emissions using the procedures in paragraphs (c)(1)
through (4) of this section:
(1) Calculate CO2 emissions from fuel combustion using
direct measurement of fuels consumed and default HHV and default
emissions factors, according to the Tier 1 Calculation Methodology for
stationary combustion sources in Sec. 98.33(a)(1). Tiers 2 or 3 from
Sec. 98.33(a)(2) or (3) may be used to calculate CO2
emissions if the respective monitoring and QA/QC requirements described
in Sec. 98.34 are met.
(2) Calculate CH4 and N2O emissions from fuel
combustion using direct measurement of fuels consumed, default or site-
specific HHV, and default emissions factors and convert to metric tons
of CO2 equivalent according to the methodology for
stationary combustion sources in Sec. 98.33(c); use the default HHV
listed in table C-1 to subpart C of this part and the default
CH4 and N2O emissions factors listed in table AA-
2 to this subpart.
(3) Biogenic CO2 emissions from conversion of
CaCO3 to CaO are included in the biogenic CO2
estimates calculated for the chemical recovery furnace in paragraph
(a)(3) of this section.
(4) Calculate biogenic CO2 emissions from combustion of
biomass with other fuels according to the applicable methodology for
stationary combustion sources in Sec. 98.33(e).
(d) For makeup chemical use, you must calculate CO2
emissions by using direct or indirect measurement of the quantity of
chemicals added and ratios of the molecular weights of CO2
and the makeup chemicals, according to equation AA-3 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.048
Where:
CO2 = CO2 mass emissions from makeup chemicals
(kilograms/yr).
M (CaCO3) = Make-up quantity of CaCO3 used for
the reporting year (metric tons per year).
M (NaCO3) = Make-up quantity of
Na2CO3 used for the reporting year (metric
tons per year).
44 = Molecular weight of CO2.
100 = Molecular weight of CaCO3.
105.99 = Molecular weight of Na2CO3.
0
65. Amend Sec. 98.276 by revising paragraph (a) to read as follows:
Sec. 98.276 Data reporting requirements.
* * * * *
(a) Annual emissions of CO2, biogenic CO2,
CH4, and N2O (metric tons per year).
* * * * *
0
66. Amend Sec. 98.277 by revising paragraph (d) to read as follows:
Sec. 98.277 Records that must be retained.
* * * * *
(d) Annual quantity of spent liquor solids combusted in each
chemical recovery furnace and chemical recovery combustion unit, and
the basis for determining the annual quantity of the spent liquor
solids combusted (whether based on T650 om-05 Solids Content of Black
Liquor, TAPPI (incorporated by reference, see Sec. 98.7) or an online
measurement system). If an online measurement system is used, you must
retain records of the calculations used to determine the annual
quantity of spent liquor solids combusted from the continuous
measurements.
* * * * *
Subpart BB--Silicon Carbide Production
0
67. Amend Sec. 98.286 by revising the introductory text and adding
paragraph (c) to read as follows:
Sec. 98.286 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified
[[Page 31933]]
in paragraph (a) or (b) of this section, and paragraph (c) of this
section, as applicable for each silicon carbide production facility.
* * * * *
(c) If methane abatement technology is used at the silicon carbide
production facility, you must report the information in paragraphs
(c)(1) through (3) of this section. Upon reporting this information
once in an annual report, you are not required to report this
information again unless the information changes during a reporting
year, in which case, the reporter must include any updates in the
annual report for the reporting year in which the change occurred.
(1) Type of methane abatement technology used on each silicon
carbide process unit or production furnace, and date of installation
for each.
(2) Methane destruction efficiency for each methane abatement
technology (percent destruction). You must either use the
manufacturer's specified destruction efficiency or the destruction
efficiency determined via a performance test. If you report the
destruction efficiency determined via a performance test, you must also
report the test method that was used during the performance test.
(3) Percentage of annual operating hours that methane abatement
technology was in use for all silicon carbide process units or
production furnaces combined.
0
68. Amend Sec. 98.287 by revising the introductory text and adding
paragraph (d) to read as follows:
Sec. 98.287 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (d) of this
section for each silicon carbide production facility.
* * * * *
(d) Records of all information reported as required under Sec.
98.286(c).
0
69. Revise and republish subpart DD consisting of Sec. Sec. 98.300
through 98.308 to read as follows:
Subpart DD--Electrical Transmission and Distribution Equipment Use
Sec.
98.300 Definition of the source category.
98.301 Reporting threshold.
98.302 GHGs to report.
98.303 Calculating GHG emissions.
98.304 Monitoring and QA/QC requirements.
98.305 Procedures for estimating missing data.
98.306 Data reporting requirements.
98.307 Records that must be retained.
98.308 Definitions.
Sec. 98.300 Definition of the source category.
(a) The electrical transmission and distribution equipment use
source category consists of all electric transmission and distribution
equipment and servicing inventory insulated with or containing
fluorinated GHGs, including but not limited to sulfur hexafluoride
(SF6) and perfluorocarbons (PFCs), used within an electric
power system. Electric transmission and distribution equipment and
servicing inventory includes, but is not limited to:
(1) Gas-insulated substations.
(2) Circuit breakers.
(3) Switchgear, including closed-pressure and hermetically sealed-
pressure switchgear and gas-insulated lines containing fluorinated
GHGs, including but not limited to SF6 and PFCs.
(4) Gas containers such as pressurized cylinders.
(5) Gas carts.
(6) Electric power transformers.
(7) Other containers of fluorinated GHG, including but not limited
to SF6 and PFCs.
(b) [Reserved]
Sec. 98.301 Reporting threshold.
(a) You must report GHG emissions under this subpart if you are an
electric power system as defined in Sec. 98.308 and your facility
meets the requirements of Sec. 98.2(a)(1). To calculate total annual
GHG emissions for comparison to the 25,000 metric ton CO2e
per year emission threshold in table A-3 to subpart A to this part, you
must calculate emissions of each fluorinated GHG that is a component of
a reportable insulating gas and then sum the emissions of each
fluorinated GHG resulting from the use of electrical transmission and
distribution equipment for threshold applicability purposes using
equation DD-1 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.049
Where:
E = Annual emissions for threshold applicability purposes (metric
tons CO2e).
NCEPS,j = the total nameplate capacity of equipment
containing reportable insulating gas j (excluding hermetically
sealed-pressure equipment) located within the facility plus the
total nameplate capacity of equipment containing reportable
insulting gas j (excluding hermetically sealed-pressure equipment)
that is not located within the facility but is under common
ownership or control (lbs).
GHGi,w = The weight fraction of fluorinated GHG i in
reportable insulating gas j in the gas insulated equipment included
in the total nameplate capacity NCEPS,j, expressed as a
decimal fraction. If fluorinated GHG i is not part of a gas mixture,
use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in table A-1 to
subpart A of this part.
EF = Emission factor for electrical transmission and distribution
equipment (lbs emitted/lbs nameplate capacity). For all gases, use
an emission factor or 0.1.
i = Fluorinated GHG contained in the electrical transmission and
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.
(b) A facility other than an electric power system that is subject
to this part because of emissions from any other source category listed
in table A-3 or A-4 to subpart A of this part is not required to report
emissions under subpart DD of this part unless the total estimated
emissions of fluorinated GHGs that are components of reportable
insulating gases, as calculated in equation DD-2 to this section,
equals or exceeds 25,000 tons CO2e.
[GRAPHIC] [TIFF OMITTED] TR25AP24.050
Where:
E = Annual emissions for threshold applicability purposes (metric
tons CO2e).
NCother,j = For a facility other than an electric power
system, the total nameplate capacity of equipment containing
reportable insulating gas j (excluding hermetically sealed-pressure
equipment) located within the facility (lbs).
GHGi,w = The weight fraction of fluorinated GHG i in
reportable insulating gas j in the gas insulated equipment included
in
[[Page 31934]]
the total nameplate capacity NCother,j, expressed as a
decimal fraction. If fluorinated GHG i is not part of a gas mixture,
use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in table A-1 to
subpart A of this part.
EF = Emission factor for electrical transmission and distribution
equipment (lbs emitted/lbs nameplate capacity). For all gases, use
an emission factor or 0.1.
i = Fluorinated GHG contained in the electrical transmission and
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.
Sec. 98.302 GHGs to report.
You must report emissions of each fluorinated GHG, including but
not limited to SF6 and PFCs, from your facility (including
emissions from fugitive equipment leaks, installation, servicing,
equipment decommissioning and disposal, and from storage cylinders)
resulting from the transmission and distribution servicing inventory
and equipment listed in Sec. 98.300(a), except you are not required to
report emissions of fluorinated GHGs that are components of insulating
gases whose weighted average GWPs, as calculated in equation DD-3 to
this section, are less than or equal to one. For acquisitions of
equipment containing or insulated with fluorinated GHGs, you must
report emissions from the equipment after the title to the equipment is
transferred to the electric power transmission or distribution entity.
[GRAPHIC] [TIFF OMITTED] TR25AP24.051
Where:
GWPj = Weighted average GWP of insulating gas j.
GHGi,w = The weight fraction of GHG i in insulating gas
j, expressed as a decimal. fraction. If GHG i is not part of a gas
mixture, use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in table A-1 to
subpart A of this part.
i = GHG contained in the electrical transmission and distribution
equipment.
Sec. 98.303 Calculating GHG emissions.
(a) Calculating GHG emissions. Calculate the annual emissions of
each fluorinated GHG that is a component of any reportable insulating
gas using the mass-balance approach in equation DD-4 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.052
Where:
User Emissionsi = Emissions of fluorinated GHG i from the
facility (pounds).
GHGi,w = The weight fraction of fluorinated GHG i in
reportable insulating gas j if reportable insulating gas j is a gas
mixture, expressed as a decimal fraction. If fluorinated GHG i is
not part of a gas mixture, use a value of 1.0.
Decrease in Inventory of Reportable Insulating Gas j = (Pounds of
reportable insulating gas j stored in containers, but not in
energized equipment, at the beginning of the year)-(Pounds of
reportable insulating gas j stored in containers, but not in
energized equipment, at the end of the year). Reportable insulating
gas inside equipment that is not energized is considered to be
``stored in containers.''
Acquisitions of Reportable Insulating gas j = (Pounds of reportable
insulating gas j purchased or otherwise acquired from chemical
producers, chemical distributors, or other entities in bulk) +
(Pounds of reportable insulating gas j purchased or otherwise
acquired from equipment manufacturers, equipment distributors, or
other entities with or inside equipment, including hermetically
sealed-pressure switchgear, while the equipment was not in use) +
(Pounds of each SF6 insulating gas j returned to facility
after off-site recycling) + (Pounds of reportable insulating gas j
acquired inside equipment, except hermetically sealed-pressure
switchgear, that was transferred while the equipment was in use,
e.g., through acquisition of all or part of another electric power
system).
Disbursements of Reportable Insulating gas j = (Pounds of reportable
insulating gas j returned to suppliers) + (Pounds of reportable
insulating gas j sent off site for recycling) + (Pounds of
reportable insulating gas j sent off-site for destruction) + (Pounds
of reportable insulating gas j that was sold or transferred to other
entities in bulk) + (Pounds of reportable insulating gas j contained
in equipment, including hermetically sealed-pressure switchgear,
that was sold or transferred to other entities while the equipment
was not in use) + (Pounds of reportable insulating gas j inside
equipment, except hermetically sealed-pressure switchgear, that was
transferred while the equipment was in use, e.g., through sale of
all or part of the electric power system to another electric power
system).
Net Increase in Total Nameplate Capacity of Equipment Operated
containing reportable insulating gas j = (The Nameplate Capacity of
new equipment, as defined at Sec. 98.308, containing reportable
insulating gas j in pounds)-(Nameplate Capacity of retiring
equipment, as defined at Sec. 98.308, containing reportable
insulating gas j in pounds). (Note that Nameplate Capacity refers to
the full and proper charge of equipment rather than to the actual
charge, which may reflect leakage).
(b) Nameplate capacity adjustments. Users of closed-pressure
electrical equipment with a voltage capacity greater than 38 kV may
measure and adjust the nameplate capacity value specified by the
equipment manufacturer on the nameplate attached to that equipment, or
within the equipment manufacturer's official product specifications, by
following the requirements in paragraphs (b)(1) through (10) of this
section. Users of other electrical equipment are not permitted to
adjust the nameplate capacity value of the other equipment.
(1) If you elect to measure the nameplate capacity value(s) of one
or more pieces of electrical equipment with a voltage capacity greater
than 38 kV, you must measure the nameplate capacity values of all the
electrical
[[Page 31935]]
equipment in your facility that has a voltage capacity greater than 38
kV and that is installed or retired in that reporting year and in
subsequent reporting years.
(2) You must adopt the measured nameplate capacity value for any
piece of equipment for which the absolute value of the difference
between the measured nameplate capacity value and the nameplate
capacity value most recently specified by the manufacturer equals or
exceeds two percent of the nameplate capacity value most recently
specified by the manufacturer.
(3) You may adopt the measured nameplate capacity value for
equipment for which the absolute value of the difference between the
measured nameplate capacity value and the nameplate capacity value most
recently specified by the manufacturer is less than two percent of the
nameplate capacity value most recently specified by the manufacturer,
but if you elect to adopt the measured nameplate capacity for that
equipment, then you must adopt the measured nameplate capacity value
for all of the equipment for which the difference between the measured
nameplate capacity value and the nameplate capacity value most recently
specified by the manufacturer is less than two percent of the nameplate
capacity value most recently specified by the manufacturer. This
applies in the reporting year in which you first adopt the measured
nameplate capacity for the equipment and in subsequent reporting years.
(4) Users of electrical equipment measuring the nameplate capacity
of any new electrical equipment must:
(i) Record the amount of insulating gas in the equipment at the
time the equipment was acquired (pounds), either per information
provided by the manufacturer, or by transferring insulating gas from
the equipment to a gas container and measuring the amount of insulating
gas transferred. The equipment user is responsible for ensuring the gas
is accounted for consistent with the methodologies specified in
paragraphs (b)(4)(ii) through (iii) and (b)(5) of this section. If no
insulating gas was in the device when it was acquired, record this
value as zero.
(ii) If insulating gas is added to the equipment subsequent to the
acquisition of the equipment to energize it the first time, transfer
the insulating gas to the equipment to reach the temperature-
compensated design operating pressure per manufacturer specifications.
Follow the manufacturer-specified procedure to ensure that the measured
temperature accurately reflects the temperature of the insulating gas,
e.g., by measuring the insulating gas pressure and vessel temperature
after allowing appropriate time for the temperature of the transferred
gas to equilibrate with the vessel temperature. Measure and calculate
the total amount of reportable insulating gas added to the device using
one of the methods specified in paragraphs (b)(4)(ii)(A) and (B) of
this section.
(A) To determine the amount of reportable insulating gas
transferred to the electrical equipment, weigh the gas container being
used to fill the device prior to, and after, the addition of the
reportable insulating gas to the electrical equipment, and subtract the
second value (after-transfer gas container weight) from the first value
(prior-to-transfer gas container weight). Account for any gas contained
in hoses before and after the transfer.
(B) Connect a mass flow meter between the electrical equipment and
a gas cart. Transfer gas to the equipment to reach the temperature-
compensated design operating pressure per manufacturer specifications.
During gas transfer, you must keep the mass flow rate within the range
specified by the mass flow meter manufacturer to assure an accurate and
precise mass flow meter reading. Close the connection to the GIE from
the mass flow meter hose and ensure that the gas trapped in the filling
hose returns through the mass flow meter. Calculate the amount of gas
transferred from the mass reading on the mass flow meter.
(iii) Sum the results of paragraphs (b)(4)(i) and (ii) to obtain
the measured nameplate capacity for the new equipment.
(5) Electrical equipment users measuring the nameplate capacity of
any retiring electrical equipment must:
(i) Measure and record the initial system pressure and vessel
temperature prior to removing any insulating gas.
(ii) Compare the initial system pressure and temperature to the
equipment manufacturer's temperature/pressure curve for that equipment
and insulating gas.
(iii) If the temperature-compensated initial system pressure of the
electrical equipment does not match the temperature-compensated design
operating pressure specified by the equipment manufacturer, you may
either:
(A) Add or remove insulating gas to/from the electrical equipment
until the manufacturer-specified value is reached, or
(B) If the temperature-compensated initial system pressure of the
electrical equipment is no higher than the temperature-compensated
design operating pressure specified by the manufacturer and no lower
than five pounds per square inch (5 psi) less than the temperature-
compensated design operating pressure specified by the manufacturer,
use equation DD-5 to this section to calculate the nameplate capacity
based on the mass recorded under paragraph (b)(5)(vi) of this section.
(iv) Weigh the gas container being used to receive the gas and
record this value.
(v) Recover insulating gas from the electrical equipment until five
minutes after the pressure in the electrical equipment reaches a
pressure of at most five pounds per square inch absolute (5 psia).
(vi) Record the amount of insulating gas recovered (pounds) by
weighing the gas container that received the gas and subtracting the
weight recorded pursuant to paragraph (b)(5)(iv)(B) of this section
from this value. Account for any gas contained in hoses before and
after the transfer. The amount of gas recovered shall be the measured
nameplate capacity for the electrical equipment unless the final
temperature-compensated pressure of the electrical equipment exceeds
0.068 psia (3.5 Torr) or the electrical equipment user is calculating
the nameplate capacity pursuant to paragraph (b)(5)(iii)(B) of this
section, in which cases the measured nameplate capacity shall be the
result of equation DD-5 to this section.
(vii) If you are calculating the nameplate capacity pursuant to
paragraph (b)(5)(iii)(B) of this section, use equation DD-5 to this
section to do so.
[GRAPHIC] [TIFF OMITTED] TR25AP24.053
[[Page 31936]]
Where:
NCC = Nameplate capacity of the equipment measured and
calculated by the equipment user (pounds).
Pi = Initial temperature-compensated pressure of the
equipment, based on the temperature-pressure curve for the
insulating gas (psia).
Pf = Final temperature-compensated pressure of the
equipment, based on the temperature-pressure curve for the
insulating gas (psia). This may be equated to zero if the final
temperature-compensated pressure of the equipment is equal to or
lower than 0.068 psia (3.5 Torr).
PNC = Temperature-compensated pressure of the equipment
at the manufacturer-specified filling density of the equipment
(i.e., at the full and proper charge, psia).
MR = Mass of insulating gas recovered from the equipment,
measured in paragraph (b)(5)(vi) of this section (pounds).
(viii) Record the final system pressure and vessel temperature.
(6) Instead of measuring the nameplate capacity of electrical
equipment when it is retired, users may measure the nameplate capacity
of electrical equipment during maintenance activities that require
opening the gas compartment, but they must follow the procedures set
forth in paragraph (b)(5) of this section.
(7) If the electrical equipment will remain energized, and the
electrical equipment user is adopting the user-measured nameplate
capacity, the electrical equipment user must affix a revised nameplate
capacity label, showing the revised nameplate value and the year the
nameplate capacity adjustment process was performed, to the device by
the end of the calendar year in which the process was completed. The
manufacturer's previous nameplate capacity label must remain visible
after the revised nameplate capacity label is affixed to the device.
(8) For each piece of electrical equipment whose nameplate capacity
was adjusted during the reporting year, the revised nameplate capacity
value must be used in all provisions wherein the nameplate capacity is
required to be recorded, reported, or used in a calculation in this
subpart unless otherwise specified herein.
(9) The nameplate capacity of a piece of electrical equipment may
only be adjusted more than once if the physical capacity of the device
has changed (e.g., replacement of bushings) after the initial
adjustment was performed, in which case the equipment user must adjust
the nameplate capacity pursuant to the provisions of this paragraph
(b).
(10) Measuring devices used to measure the nameplate capacity of
electrical equipment under this paragraph (b) must meet the following
accuracy and precision requirements:
(i) Flow meters must be certified by the manufacturer to be
accurate and precise to within one percent of the largest value that
the flow meter can, according to the manufacturer's specifications,
accurately record.
(ii) Pressure gauges must be certified by the manufacturer to be
accurate and precise to within 0.5% of the largest value that the gauge
can, according to the manufacturer's specifications, accurately record.
(iii) Temperature gauges must be certified by the manufacturer to
be accurate and precise to within +/-1.0 [deg]F.
(iv) Scales must be certified by the manufacturer to be accurate
and precise to within one percent of the true weight.
Sec. 98.304 Monitoring and QA/QC requirements.
(a) [Reserved]
(b) You must adhere to the following QA/QC methods for reviewing
the completeness and accuracy of reporting:
(1) Review inputs to equation DD-4 to Sec. 98.303 to ensure inputs
and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative
emissions are not calculated. However, the Decrease in fluorinated GHG
Inventory and the Net Increase in Total Nameplate Capacity may be
calculated as negative numbers.
(3) Ensure that beginning-of-year inventory matches end-of-year
inventory from the previous year.
(4) Ensure that in addition to fluorinated GHG purchased from bulk
gas distributors, fluorinated GHG purchased from Original Equipment
Manufacturers (OEM) and fluorinated GHG returned to the facility from
off-site recycling are also accounted for among the total additions.
(c) Ensure the following QA/QC methods are employed throughout the
year:
(1) Ensure that cylinders returned to the gas supplier are
consistently weighed on a scale that is certified to be accurate and
precise to within 2 pounds of true weight and is periodically
recalibrated per the manufacturer's specifications. Either measure
residual gas (the amount of gas remaining in returned cylinders) or
have the gas supplier measure it. If the gas supplier weighs the
residual gas, obtain from the gas supplier a detailed monthly
accounting, within 2 pounds, of residual gas amounts in the
cylinders returned to the gas supplier.
(2) Ensure that cylinders weighed for the beginning and end of year
inventory measurements are weighed on a scale that is certified to be
accurate and precise to within 2 pounds of true weight and is
periodically recalibrated per the manufacturer's specifications. All
scales used to measure quantities that are to be reported under Sec.
98.306 must be calibrated using calibration procedures specified by the
scale manufacturer. Calibration must be performed prior to the first
reporting year. After the initial calibration, recalibration must be
performed at the minimum frequency specified by the manufacturer.
(3) Ensure all substations have provided information to the manager
compiling the emissions report (if it is not already handled through an
electronic inventory system).
(d) GHG Monitoring Plans, as described in Sec. 98.3(g)(5), must be
completed by April 1, 2011.
Sec. 98.305 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Replace missing data, if needed,
based on data from equipment with a similar nameplate capacity for
fluorinated GHGs, and from similar equipment repair, replacement, and
maintenance operations.
Sec. 98.306 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information for each electric
power system, by chemical:
(a) Nameplate capacity of equipment (pounds) containing each
insulating gas:
(1) Existing at the beginning of the year (excluding hermetically
sealed-pressure switchgear).
(2) New hermetically sealed-pressure switchgear during the year.
(3) New equipment other than hermetically sealed-pressure
switchgear during the year.
(4) Retired hermetically sealed-pressure switchgear during the
year.
(5) Retired equipment other than hermetically sealed-pressure
switchgear during the year.
(b) Transmission miles (length of lines carrying voltages above 35
kilovolts).
(c) Distribution miles (length of lines carrying voltages at or
below 35 kilovolts).
(d) Pounds of each reportable insulating gas stored in containers,
but not in energized equipment, at the beginning of the year.
(e) Pounds of each reportable insulating gas stored in containers,
but not in energized equipment, at the end of the year.
[[Page 31937]]
(f) Pounds of each reportable insulating gas purchased or otherwise
acquired in bulk from chemical producers, chemical distributors, or
other entities.
(g) Pounds of each reportable insulating gas purchased or otherwise
acquired from equipment manufacturers, equipment distributors, or other
entities with or inside equipment, including hermetically sealed-
pressure switchgear, while the equipment was not in use.
(h) Pounds of each reportable insulating gas returned to facility
after off-site recycling.
(i) Pounds of each reportable insulating gas acquired inside
equipment, except hermetically sealed-pressure switchgear, that was
transferred while the equipment was in use, e.g., through acquisition
of all or part of another electric power system.
(j) Pounds of each reportable insulating gas returned to suppliers.
(k) Pounds of each reportable insulating gas that was sold or
transferred to other entities in bulk.
(l) Pounds of each reportable insulating gas sent off-site for
recycling.
(m) Pounds of each reportable insulating gas sent off-site for
destruction.
(n) Pounds of each reportable insulating gas contained in
equipment, including hermetically sealed-pressure switchgear, that was
sold or transferred to other entities while the equipment was not in
use.
(o) Pounds of each reportable insulating gas disbursed inside
equipment, except hermetically sealed-pressure switchgear, that was
transferred while the equipment was in use, e.g., through sale of all
or part of the electric power system to another electric power system.
(p) State(s) or territory in which the facility lies.
(q) The number of reportable-insulating-gas-containing pieces of
equipment in each of the following equipment categories:
(1) New hermetically sealed-pressure switchgear during the year.
(2) New equipment other than hermetically sealed-pressure
switchgear during the year.
(3) Retired hermetically sealed-pressure switchgear during the
year.
(4) Retired equipment other than hermetically sealed-pressure
switchgear during the year.
(r) The total of the nameplate capacity values most recently
assigned by the electrical equipment manufacturer(s) to each of the
following groups of equipment:
(1) All new equipment whose nameplate capacity values were measured
by the user under this subpart and for which the user adopted the user-
measured nameplate capacity value during the year.
(2) All retiring equipment whose nameplate capacity values were
measured by the user under this subpart and for which the user adopted
the user-measured nameplate capacity value during the year.
(s) The total of the nameplate capacity values measured by the
electrical equipment user for each of the following groups of
equipment:
(1) All new equipment whose nameplate capacity values were measured
by the user under this subpart and for which the user adopted the user-
measured nameplate capacity value during the year.
(2) All retiring equipment whose nameplate capacity values were
measured by the user under this subpart and for which the user adopted
the user-measured nameplate capacity value during the year.
(t) For each reportable insulating gas reported in paragraphs (a),
(d) through (o), and (q) of this section, an ID number or other
appropriate descriptor that is unique to that reportable insulating
gas.
(u) For each ID number or descriptor reported in paragraph (t) of
this section for each unique insulating gas, the name (as required in
Sec. 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas
in the insulating gas.
Sec. 98.307 Records that must be retained.
(a) In addition to the information required by Sec. 98.3(g), you
must retain records of the information reported and listed in Sec.
98.306.
(b) For each piece of electrical equipment whose nameplate capacity
is measured by the equipment user, retain records of the following:
(1) Equipment manufacturer name.
(2) Year equipment was manufactured. If the date year the equipment
was manufactured cannot be determined, report a best estimate of the
year of manufacture and record how the estimated year was determined.
(3) Manufacturer serial number. For any piece of equipment whose
serial number is unknown (e.g., the serial number does not exist or is
not visible), another unique identifier must be recorded as the
manufacturer serial number. The electrical equipment user must retain
documentation that allows for each electrical equipment to be readily
identifiable.
(4) Equipment type (i.e., closed-pressure vs. hermetically sealed-
pressure).
(5) Equipment voltage capacity (in kilovolts).
(6) The name and GWP of each insulating gas used.
(7) Nameplate capacity value (pounds), as specified by the
equipment manufacturer. The value must reflect the latest value
specified by the manufacturer during the reporting year.
(8) Nameplate capacity value (pounds) measured by the equipment
user.
(9) The date the nameplate capacity measurement process was
completed.
(10) The measurements and calculations used to calculate the value
in paragraph (b)(8) of this section.
(11) The temperature-pressure curve and/or other information used
to derive the initial and final temperature-adjusted pressures of the
equipment.
(12) Whether or not the nameplate capacity value in paragraph
(b)(8) of this section has been adopted for the piece of electrical
equipment.
Sec. 98.308 Definitions.
Except as specified in this section, all terms used in this subpart
have the same meaning given in the Clean Air Act and subpart A of this
part.
Facility, with respect to an electric power system, means the
electric power system as set out in this definition. An electric power
system is comprised of all electric transmission and distribution
equipment insulated with or containing fluorinated GHGs that is linked
through electric power transmission or distribution lines and functions
as an integrated unit, that is owned, serviced, or maintained by a
single electric power transmission or distribution entity (or multiple
entities with a common owner), and that is located between:
(1) The point(s) at which electric energy is obtained from an
electricity generating unit or a different electric power transmission
or distribution entity that does not have a common owner; and
(2) The point(s) at which any customer or another electric power
transmission or distribution entity that does not have a common owner
receives the electric energy. The facility also includes servicing
inventory for such equipment that contains fluorinated GHGs.
Electric power transmission or distribution entity means any entity
that transmits, distributes, or supplies electricity to a consumer or
other user, including any company, electric cooperative, public
electric supply corporation, a similar Federal department (including
the Bureau of Reclamation or the Corps of Engineers), a municipally
owned electric department offering service to the
[[Page 31938]]
public, an electric public utility district, or a jointly owned
electric supply project.
Energized, for the purposes of this subpart, means connected
through busbars or cables to an electrical power system or fully-
charged, ready for service, and being prepared for connection to the
electrical power system. Energized equipment does not include spare gas
insulated equipment (including hermetically-sealed pressure switchgear)
in storage that has been acquired by the facility, and is intended for
use by the facility, but that is not being used or prepared for
connection to the electrical power system.
Insulating gas, for the purposes of this subpart, means any
fluorinated GHG or fluorinated GHG mixture, including but not limited
to SF6 and PFCs, that is used as an insulating and/or arc-
quenching gas in electrical equipment.
New equipment, for the purposes of this subpart, means either any
gas insulated equipment, including hermetically-sealed pressure
switchgear, that is not energized at the beginning of the reporting
year but is energized at the end of the reporting year, or any gas
insulated equipment other than hermetically-sealed pressure switchgear
that has been transferred while in use, meaning it has been added to
the facility's inventory without being taken out of active service
(e.g., when the equipment is sold to or acquired by the facility while
remaining in place and continuing operation).
Operator, for the purposes of this subpart, means any person who
operates or supervises a facility, excluding a person whose sole
responsibility is to ensure reliability, balance load or otherwise
address electricity flow.
Reportable insulating gas, for purposes of this subpart, means an
insulating gas whose weighted average GWP, as calculated in equation
DD-3 to Sec. 98.302, is greater than one. A fluorinated GHG that makes
up either part or all of a reportable insulating gas is considered to
be a component of the reportable insulating gas.
Retired equipment, for the purposes of this subpart, means either
any gas insulated equipment including hermetically-sealed pressure
switchgear, that is energized at the beginning of the reporting year
but is not energized at the end of the reporting year, or any gas
insulated equipment other than hermetically-sealed pressure switchgear
that has been transferred while in use, meaning it has been removed
from the facility's inventory without being taken out of active service
(e.g., when the equipment is acquired by a new facility while remaining
in place and continuing operation).
Subpart FF--Underground Coal Mines
0
70. Amend Sec. 98.323 by revising parameter ``MCFi'' of equation FF-3
in paragraph (b) introductory text to read as follows:
Sec. 98.323 Calculating GHG emissions.
* * * * *
(b) * * *
MCFi = Moisture correction factor for the measurement
period, volumetric basis.
= 1 when Vi and Ci are measured on a dry
basis or if both are measured on a wet basis.
= 1-(fH2O)i when Vi is measured on a wet
basis and Ci is measured on a dry basis.
= 1/[1-(fH2O)i] when Vi is measured on a
dry basis and Ci is measured on a wet basis.
* * * * *
0
71. Amend Sec. 98.326 by revising paragraph (t) to read as follows:
Sec. 98.326 Data reporting requirements.
* * * * *
(t) Mine Safety and Health Administration (MSHA) identification
number for this coal mine.
Subpart GG--Zinc Production
0
72. Amend Sec. 98.333 by revising paragraph (b)(1) introductory text
to read as follows:
Sec. 98.333 Calculating GHG emissions.
* * * * *
(b) * * *
(1) For each Waelz kiln or electrothermic furnace at your facility
used for zinc production, you must determine the mass of carbon in each
carbon-containing material, other than fuel, that is fed, charged, or
otherwise introduced into each Waelz kiln and electrothermic furnace at
your facility for each year and calculate annual CO2 process
emissions from each affected unit at your facility using equation GG-1
to this section. For electrothermic furnaces, carbon containing input
materials include carbon electrodes and carbonaceous reducing agents.
For Waelz kilns, carbon containing input materials include carbonaceous
reducing agents. If you document that a specific material contributes
less than 1 percent of the total carbon into the process, you do not
have to include the material in your calculation using equation R-1 to
Sec. 98.183.
* * * * *
0
73. Amend Sec. 98.336 by adding paragraphs (a)(6) and (b)(6) to read
as follows:
Sec. 98.336 Data reporting requirements.
* * * * *
(a) * * *
(6) Total amount of electric arc furnace dust annually consumed by
all Waelz kilns at the facility (tons).
(b) * * *
(6) Total amount of electric arc furnace dust annually consumed by
all Waelz kilns at the facility (tons).
* * * * *
Subpart HH--Municipal Solid Waste Landfills
0
74. Amend Sec. 98.343 by revising paragraphs (a)(2) and (c)(3) to read
as follows:
Sec. 98.343 Calculating GHG emissions.
(a) * * *
(2) For years when material-specific waste quantity data are
available, apply equation HH-1 to this section for each waste quantity
type and sum the CH4 generation rates for all waste types to
calculate the total modeled CH4 generation rate for the
landfill. Use the appropriate parameter values for k, DOC, MCF,
DOCF, and F shown in table HH-1 to this subpart. The annual
quantity of each type of waste disposed must be calculated as the sum
of the daily quantities of waste (of that type) disposed. You may use
the uncharacterized MSW parameters for a portion of your waste
materials when using the material-specific modeling approach for mixed
waste streams that cannot be designated to a specific material type.
For years when waste composition data are not available, use the bulk
waste parameter values for k and DOC in table HH-1 to this subpart for
the total quantity of waste disposed in those years.
* * * * *
(c) * * *
(3) For landfills with landfill gas collection systems, calculate
CH4 emissions using the methodologies specified in
paragraphs (c)(3)(i) and (ii) of this section.
(i) Calculate CH4 emissions from the modeled
CH4 generation and measured CH4 recovery using
equation HH-6 to this section.
[[Page 31939]]
[GRAPHIC] [TIFF OMITTED] TR25AP24.054
Where:
Emissions = Methane emissions from the landfill in the reporting
year (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year
from equation HH-1 to this section or the quantity of recovered
CH4 from equation HH-4 to this section, whichever is
greater (metric tons CH4).
N = Number of landfill gas measurement locations (associated with a
destruction device or gas sent off-site). If a single monitoring
location is used to monitor volumetric flow and CH4
concentration of the recovered gas sent to one or multiple
destruction devices, then N = 1.
Rn = Quantity of recovered CH4 from equation
HH-4 to this section for the nth measurement location (metric tons
CH4).
OX = Oxidation fraction. Use the appropriate oxidation fraction
default value from table HH-4 to this subpart.
DEn = Destruction efficiency (lesser of manufacturer's
specified destruction efficiency and 0.99) for the nth measurement
location. If the gas is transported off-site for destruction, use DE
= 1. If the volumetric flow and CH4 concentration of the
recovered gas is measured at a single location providing landfill
gas to multiple destruction devices (including some gas destroyed
on-site and some gas sent off-site for destruction), calculate
DEn as the arithmetic average of the DE values determined
for each destruction device associated with that measurement
location.
fDest,n = Fraction of hours the destruction device
associated with the nth measurement location was operating during
active gas flow calculated as the annual operating hours for the
destruction device divided by the annual hours flow was sent to the
destruction device. The annual operating hours for the destruction
device should include only those periods when flow was sent to the
destruction device and the destruction device was operating at its
intended temperature or other parameter indicative of effective
operation. For flares, times when there is no flame present must be
excluded from the annual operating hours for the destruction device.
If the gas is transported off-site for destruction, use
fDest,n = 1. If the volumetric flow and CH4
concentration of the recovered gas is measured at a single location
providing landfill gas to multiple destruction devices (including
some gas destroyed on-site and some gas sent off-site for
destruction), calculate fDest,n as the arithmetic average
of the fDest values determined for each destruction
device associated with that measurement location.
(ii) Calculate CH4 generation and CH4
emissions using measured CH4 recovery and estimated gas
collection efficiency and equations HH-7 and HH-8 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.055
Where:
MG = Methane generation, adjusted for oxidation, from the landfill
in the reporting year (metric tons CH4).
Emissions = Methane emissions from the landfill in the reporting
year (metric tons CH4).
C = Number of landfill gas collection systems operated at the
landfill.
X = Number of landfill gas measurement locations associated with
landfill gas collection system ``c''.
N = Number of landfill gas measurement locations (associated with a
destruction device or gas sent off-site). If a single monitoring
location is used to monitor volumetric flow and CH4
concentration of the recovered gas sent to one or multiple
destruction devices, then N = 1. Note that N =
S(c=1)C[S(x=1)X[1]].
Rx,c = Quantity of recovered CH4 from equation
HH-4 to this section for the xth measurement location for landfill
gas collection system ``c'' (metric tons CH4).
Rn = Quantity of recovered CH4 from equation
HH-4 to this section for the nth measurement location (metric tons
CH4).
CE = Collection efficiency estimated at landfill, taking into
account system coverage, operation, measurement practices, and cover
system materials from table HH-3 to this subpart. If area by soil
cover type information is not available, use applicable default
value for CE4 in table HH-3 to this subpart for all areas under
active influence of the collection system.
fRec,c = Fraction of hours the landfill gas collection
system ``c'' was operating normally (annual operating hours/8760
hours per year or annual operating hours/8784 hours per year for a
leap year). Do not include periods of shutdown or poor operation,
such as times when pressure, temperature, or other parameters
indicative of operation are outside of normal variances, in the
annual operating hours.
OX = Oxidation fraction. Use appropriate oxidation fraction default
value from table HH-4 to this subpart.
DEn = Destruction efficiency, (lesser of manufacturer's
specified destruction efficiency and 0.99) for the nth measurement
location. If the gas is transported off-site for destruction, use DE
= 1. If the volumetric flow and CH4 concentration of the
recovered gas is measured at a single location providing landfill
gas to multiple destruction devices (including some gas destroyed
on-site and some gas sent off-site for destruction), calculate
DEn as the arithmetic average of the DE values determined
for each destruction device associated with that measurement
location.
fDest,n = Fraction of hours the destruction device
associated with the nth measurement location was operating during
active gas flow calculated as the annual operating hours for the
destruction device divided by the annual hours flow was sent to the
destruction device. The annual operating hours for the destruction
device should include only those periods when flow was sent to the
destruction device and the destruction device was operating at its
intended temperature or other parameter indicative of effective
operation. For flares, times when there is no flame present must be
excluded from the annual operating hours for the destruction device.
If the gas is transported off-site for destruction, use
fDest,n = 1. If the volumetric flow and CH4
concentration of the recovered gas is measured at a single location
providing landfill gas to multiple destruction devices (including
some gas destroyed on-site and some gas sent off-site for
destruction), calculate fDest,n as the arithmetic average
of the fDest values determined for each destruction
device
[[Page 31940]]
associated with that measurement location.
0
75. Amend Sec. 98.346 by:
0
a. Redesignating paragraphs (h) and (i) as paragraphs (i) and (j),
respectively.
0
b. Adding new paragraph (h); and
0
c. Revising newly redesignated paragraphs (j)(5) through (7).
The addition and revisions read as follows:
Sec. 98.346 Data reporting requirements.
* * * * *
(h) An indication of the applicability of part 60 or part 62 of
this chapter requirements to the landfill (part 60, subparts WWW and
XXX of this chapter, approved state plan implementing part 60, subparts
Cc or Cf of this chapter, Federal plan as implemented at part 62,
subparts GGG or OOO of this chapter, or not subject to part 60 or part
62 of this chapter municipal solid waste landfill rules), and if the
landfill is subject to a part 60 or part 62 of this chapter municipal
solid waste landfill rule, an indication of whether the landfill gas
collection system is required under part 60 or part 62 of this chapter.
* * * * *
(j) * * *
(5) The number of gas collection systems at the landfill facility.
(6) For each gas collection system at the facility report:
(i) A unique name or ID number for the gas collection system.
(ii) A description of the gas collection system (manufacturer,
capacity, and number of wells).
(iii) The annual hours the gas collection system was operating
normally. Do not include periods of shut down or poor operation, such
as times when pressure, temperature, or other parameters indicative of
operation are outside of normal variances, in the annual operating
hours.
(iv) The number of measurement locations associated with the gas
collection system.
(v) For each measurement location associated with the gas
collection system, report:
(A) A unique name or ID number for the measurement location.
(B) Annual quantity of recovered CH4 (metric tons
CH4) calculated using equation HH-4 to Sec. 98.343.
(C) An indication of whether destruction occurs at the landfill
facility, off-site, or both for the measurement location.
(D) If destruction occurs at the landfill facility for the
measurement location (in full or in part), also report the number of
destruction devices associated with the measurement location that are
located at the landfill facility and the information in paragraphs
(j)(6)(v)(D)(1) through (6) of this section for each destruction device
located at the landfill facility.
(1) A unique name or ID number for the destruction device.
(2) The type of destruction device (flare, a landfill gas to energy
project (i.e., engine or turbine), off-site, or other (specify)).
(3) The destruction efficiency (decimal).
(4) The total annual hours where active gas flow was sent to the
destruction device.
(5) The annual operating hours where active gas flow was sent to
the destruction device and the destruction device was operating at its
intended temperature or other parameter indicative of effective
operation. For flares, times when there is no flame present must be
excluded from the annual operating hours for the destruction device.
(6) The estimated fraction of the recovered CH4 reported for the
measurement location directed to the destruction device based on best
available data or engineering judgement (decimal, must total to 1 for
each measurement location).
(7) The following information about the landfill.
(i) The surface area (square meters) and estimated waste depth
(meters) for each area specified in table HH-3 to this subpart.
(ii) The estimated gas collection system efficiency for the
landfill.
(iii) An indication of whether passive vents and/or passive flares
(vents or flares that are not considered part of the gas collection
system as defined in Sec. 98.6) are present at the landfill.
* * * * *
0
76. Revise table HH-1 to subpart HH to read as follows:
Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation Factors and Methods
----------------------------------------------------------------------------------------------------------------
Factor Default value Units
----------------------------------------------------------------------------------------------------------------
DOC and k values--Bulk waste option:
DOC (bulk waste) for disposal 0.20................... Weight fraction, wet basis.
years prior to 2010.
DOC (bulk waste) for disposal 0.17................... Weight fraction, wet basis.
years 2010 and later.
k (precipitation plus 0.02................... yr-\1\.
recirculated leachate \a\ <20
inches/year) for disposal years
prior to 2010.
k (precipitation plus 0.033.................. yr-\1\.
recirculated leachate \a\ <20
inches/year) for disposal years
2010 and later.
k (precipitation plus 0.038.................. yr-\1\.
recirculated leachate \a\ 20-40
inches/year) for disposal years
prior to 2010.
k (precipitation plus 0.067.................. yr-\1\.
recirculated leachate \a\ 20-40
inches/year) for disposal years
2010 and later.
k (precipitation plus 0.057.................. yr-\1\.
recirculated leachate \a\ >40
inches/year) for disposal years
prior to 2010.
k (precipitation plus 0.098.................. yr-\1\.
recirculated leachate \a\ >40
inches/year) for disposal years
2010 and later.
DOC and k values--Modified bulk MSW
option:
DOC (bulk MSW, excluding inerts 0.31................... Weight fraction, wet basis.
and C&D waste) for disposal
years prior to 2010.
DOC (bulk MSW, excluding inerts 0.27................... Weight fraction, wet basis.
and C&D waste) for disposal
years 2010 and later.
DOC (inerts, e.g., glass, 0.00................... Weight fraction, wet basis.
plastics, metal, concrete).
DOC (C&D waste).................. 0.08................... Weight fraction, wet basis.
k (bulk MSW, excluding inerts and 0.02 to 0.057 \b\...... yr-\1\.
C&D waste) for disposal years
prior to 2010.
k (bulk MSW, excluding inerts and 0.033 to 0.098 \b\..... yr-\1\.
C&D waste) for disposal years
2010 and later.
[[Page 31941]]
k (inerts, e.g., glass, plastics, 0.00................... yr-\1\.
metal, concrete).
k (C&D waste).................... 0.02 to 0.04 \b\....... yr-\1\.
DOC and k values--Waste composition
option:
DOC (food waste)................. 0.15................... Weight fraction, wet basis.
DOC (garden)..................... 0.2.................... Weight fraction, wet basis.
DOC (paper)...................... 0.4.................... Weight fraction, wet basis.
DOC (wood and straw)............. 0.43................... Weight fraction, wet basis.
DOC (textiles)................... 0.24................... Weight fraction, wet basis.
DOC (diapers).................... 0.24................... Weight fraction, wet basis.
DOC (sewage sludge).............. 0.05................... Weight fraction, wet basis.
DOC (inerts, e.g., glass, 0.00................... Weight fraction, wet basis.
plastics, metal, cement).
DOC (Uncharacterized MSW......... 0.32................... Weight fraction, wet basis.
k (food waste)................... 0.06 to 0.185 \c\...... yr-\1\.
k (garden)....................... 0.05 to 0.10 \c\....... yr-\1\.
k (paper)........................ 0.04 to 0.06 \c\....... yr-\1\.
k (wood and straw)............... 0.02 to 0.03 \c\....... yr-\1\.
k (textiles)..................... 0.04 to 0.06 \c\....... yr-\1\.
k (diapers)...................... 0.05 to 0.10 \c\....... yr-\1\.
k (sewage sludge)................ 0.06 to 0.185 \c\...... yr-\1\.
k (inerts, e.g., glass, plastics, 0.00................... yr-\1\.
metal, concrete).
k (uncharacterized MSW).......... 0.033 to 0.098 \b\..... yr-\1\.
Other parameters--All MSW landfills:
MCF.............................. 1......................
DOCF............................. 0.5....................
F................................ 0.5....................
OX............................... See table HH-4 to this
subpart.
DE............................... 0.99...................
----------------------------------------------------------------------------------------------------------------
\a\ Recirculated leachate (in inches/year) is the total volume of leachate recirculated from company records or
engineering estimates divided by the area of the portion of the landfill containing waste with appropriate
unit conversions. Alternatively, landfills that use leachate recirculation can elect to use the k value of
0.098 rather than calculating the recirculated leachate rate.
\b\ Use the lesser value when precipitation plus recirculated leachate is less than 20 inches/year. Use the
greater value when precipitation plus recirculated leachate is greater than 40 inches/year. Use the average of
the range of values when precipitation plus recirculated leachate is 20 to 40 inches/year (inclusive).
Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than
calculating the recirculated leachate rate.
\c\ Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate
plus recirculated leachate. Use the greater value when the potential evapotranspiration rate does not exceed
the mean annual precipitation rate plus recirculated leachate. Alternatively, landfills that use leachate
recirculation can elect to use the greater value rather than assessing the potential evapotranspiration rate
or recirculated leachate rate.
0
77. Revise table HH-3 to subpart HH to read as follows:
Table HH-3 to Subpart HH of Part 98--Landfill Gas Collection
Efficiencies
------------------------------------------------------------------------
Landfill gas
Description Term ID collection
efficiency
------------------------------------------------------------------------
A1: Area with no waste in-place Not applicable; do not use this area in
the calculation.
----------------------------------------
A2: Area without active gas CE2................ 0%.
collection, regardless of
cover type.
A3: Area with daily soil cover CE3................ 50%.
and active gas collection.
A4: Area with an intermediate CE4................ 65%.
soil cover, or a final soil
cover not meeting the criteria
for A5 below, and active gas
collection.
A5: Area with a final soil CE5................ 85%.
cover of 3 feet or thicker of
clay or final cover (as
approved by the relevant
agency) and/or geomembrane
cover system and active gas
collection.
----------------------------------------
Area weighted average CEave1 = (A2*CE2 + A3*CE3 + A4*CE4 +
collection efficiency for A5*CE5)/(A2 + A3 + A4 + A5).
landfills.
------------------------------------------------------------------------
0
78. Revise footnote ``b'' to table HH--4 to subpart HH to read as
follows:
[[Page 31942]]
Table HH-4 to Subpart HH of Part 98--Landfill Methane Oxidation
Fractions
------------------------------------------------------------------------
Use this landfill
methane oxidation
Under these conditions: fraction:
------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
* * * * * * *
\b\ Methane flux rate (in grams per square meter per day; g/m\2\/d) is
the mass flow rate of methane per unit area at the bottom of the
surface soil prior to any oxidation and is calculated as follows:
For equation HH-5 to Sec. 98.343, or for equation TT-6 to Sec.
98.463,
MF = K x GCH4/SArea
For equation HH-6 to Sec. 98.343,
[GRAPHIC] [TIFF OMITTED] TR25AP24.056
For equation HH-7 to Sec. 98.343,
[GRAPHIC] [TIFF OMITTED] TR25AP24.057
For equation HH-8 to Sec. 98.343,
[GRAPHIC] [TIFF OMITTED] TR25AP24.058
Where:
MF = Methane flux rate from the landfill in the reporting year
(grams per square meter per day, g/m\2\/d).
K = unit conversion factor = 106/365 (g/metric ton per
days/year) or 106/366 for a leap year.
SArea = The surface area of the landfill containing waste at the
beginning of the reporting year (square meters, m\2\).
GCH4 = Modeled methane generation rate in reporting year
from equation HH-1 to Sec. 98.343 or equation TT-1 to Sec. 98.463,
as applicable, except for application with equation HH-6 to Sec.
98.343 (metric tons CH4). For application with equation
HH-6 to Sec. 98.343, the greater of the modeled methane generation
rate in reporting year from equation HH-1 to Sec. 98.343 or
equation TT-1 to Sec. 98.463, as applicable, and the quantity of
recovered CH4 from equation HH-4 to Sec. 98.343 (metric
tons CH4).
CE = Collection efficiency estimated at landfill, taking into
account system coverage, operation, measurement practices, and cover
system materials from table HH-3 to this subpart. If area by soil
cover type information is not available, use applicable default
value for CE4 in table HH-3 to this subpart for all areas under
active influence of the collection system.
C = Number of landfill gas collection systems operated at the
landfill.
X = Number of landfill gas measurement locations associated with
landfill gas collection system ``c''.
N = Number of landfill gas measurement locations (associated with a
destruction device or gas sent off-site). If a single monitoring
location is used to monitor volumetric flow and CH4
concentration of the recovered gas sent to one or multiple
destruction devices, then N = 1. Note that N =
[Sigma]c=1C[[Sigma]x=1X[1]].
Rx,c = Quantity of recovered CH4 from equation
HH-4 to Sec. 98.343 for the x\th\ measurement location for landfill
gas collection system ``c'' (metric tons CH4).
Rn = Quantity of recovered CH4 from equation
HH-4 to Sec. 98.343 for the n\th\ measurement location (metric tons
CH4).
fRec,c = Fraction of hours the landfill gas collection
system ``c'' was operating normally (annual operating hours/8,760
hours per year or annual operating hours/8,784 hours per year for a
leap year). Do not include periods of shutdown or poor operation,
such as times when pressure, temperature, or other parameters
indicative of operation are outside of normal variances, in the
annual operating hours.
Subpart OO--Suppliers of Industrial Greenhouse Gases
0
79. Amend Sec. 98.416 by revising paragraphs (c) introductory text,
(c)(6) and (7), (d) introductory text, and (d)(4), and adding paragraph
(k) to read as follows:
Sec. 98.416 Data reporting requirements.
* * * * *
(c) Each bulk importer of fluorinated GHGs, fluorinated heat
transfer fluids (HTFs), or nitrous oxide shall submit an annual report
that summarizes its imports at the corporate level, except importers
may exclude shipments including less than twenty-five kilograms of
fluorinated GHGs, fluorinated HTFs, or nitrous oxide; transshipments if
the importer also excludes transshipments from reporting of exports
under paragraph (d) of this section; and heels that meet the conditions
set forth at Sec. 98.417(e) if the importer also excludes heels from
any reporting of exports under paragraph (d) of this section. The
report shall contain
[[Page 31943]]
the following information for each import:
* * * * *
(6) Harmonized tariff system (HTS) code of the fluorinated GHGs,
fluorinated HTFs, or nitrous oxide shipped.
(7) Customs entry number and importer number for each shipment.
* * * * *
(d) Each bulk exporter of fluorinated GHGs, fluorinated HTFs, or
nitrous oxide shall submit an annual report that summarizes its exports
at the corporate level, except reporters may exclude shipments
including less than twenty-five kilograms of fluorinated GHGs,
fluorinated HTFs, or nitrous oxide; transshipments if the exporter also
excludes transshipments from reporting of imports under paragraph (c)
of this section; and heels if the exporter also excludes heels from any
reporting of imports under paragraph (c) of this section. The report
shall contain the following information for each export:
* * * * *
(4) Harmonized tariff system (HTS) code of the fluorinated GHGs,
fluorinated HTFs, or nitrous oxide shipped.
* * * * *
(k) For nitrous oxide, saturated perfluorocarbons, sulfur
hexafluoride, and fluorinated heat transfer fluids as defined at Sec.
98.6, report the end use(s) for which each GHG or fluorinated HTF is
transferred and the aggregated annual quantity of that GHG or
fluorinated HTF in metric tons that is transferred to that end use
application, if known.
Subpart PP--Suppliers of Carbon Dioxide
0
80. Amend Sec. 98.420 by adding paragraph (a)(4) to read as follows:
Sec. 98.420 Definition of the source category.
(a) * * *
(4) Facilities with process units, including but not limited to
direct air capture (DAC), that capture a CO2 stream from
ambient air for purposes of supplying CO2 for commercial
applications or that capture and maintain custody of a CO2
stream in order to sequester or otherwise inject it underground.
* * * * *
0
81. Amend Sec. 98.422 by adding paragraph (e) to read as follows:
Sec. 98.422 GHGs to report.
* * * * *
(e) Mass of CO2 captured from DAC process units.
(1) Mass of CO2 captured from ambient air.
(2) Mass of CO2 captured from any on-site heat and/or
electricity generation, where applicable.
0
82. Amend Sec. 98.423 by revising paragraphs (a)(3)(i) introductory
text and (a)(3)(ii) introductory text to read as follows:
Sec. 98.423 Calculating CO2 supply.
(a) * * *
(3) * * *
(i) For facilities with production process units, DAC process
units, or production wells that capture or extract a CO2
stream and either measure it after segregation or do not segregate the
flow, calculate the total CO2 supplied in accordance with
equation PP-3a to paragraph (a)(3)(i) of this section.
* * * * *
(ii) For facilities with production process units or DAC process
units that capture a CO2 stream and measure it ahead of
segregation, calculate the total CO2 supplied in accordance
with equation PP-3b to paragraph (a)(3)(ii) of this section.
* * * * *
0
83. Amend Sec. 98.426 by:
0
a. Redesignating paragraphs (f)(12) and (13) as paragraphs (f)(13) and
(14), respectively;
0
b. Adding new paragraph (f)(12);
0
c. Revising paragraph (h); and
0
d. Adding paragraph (i).
The additions and revision read as follows:
Sec. 98.426 Data reporting requirements.
* * * * *
(f) * * *
(12) Geologic sequestration of carbon dioxide with enhanced oil
recovery that is covered by subpart VV of this part.
* * * * *
(h) If you capture a CO2 stream from a facility that is
subject to this part and transfer CO2 to any facilities that
are subject to subpart RR or VV of this part, you must:
(1) Report the facility identification number associated with the
annual GHG report for the facility that is the source of the captured
CO2 stream;
(2) Report each facility identification number associated with the
annual GHG reports for each subpart RR and subpart VV facility to which
CO2 is transferred; and
(3) Report the annual quantity of CO2 in metric tons
that is transferred to each subpart RR and subpart VV facility.
(i) If you capture a CO2 stream at a facility with a DAC
process unit, report the annual quantity of on-site and off-site
electricity and heat generated for each DAC process unit as specified
in paragraphs (i)(1) through (3) of this section. The quantities
specified in paragraphs (i)(1) through (3) of this section must be
provided per energy source if known and must represent the electricity
and heat used for the DAC process unit starting with air intake and
ending with the compressed CO2 stream (i.e., the
CO2 stream ready for supply for commercial applications or,
if maintaining custody of the stream, sequestration or injection of the
stream underground).
(1) Electricity excluding combined heat and power (CHP). If
electricity is provided to a dedicated meter for the DAC process unit,
report the annual quantity of electricity consumed, in megawatt hours
(MWh), and the information in paragraph (i)(1)(i) or (ii) of this
section.
(i) If the electricity is sourced from a grid connection, report
the following information:
(A) State where the facility with the DAC process unit is located.
(B) County where the facility with the DAC process unit is located.
(C) Name of the electric utility company that supplied the
electricity as shown on the last monthly bill issued by the utility
company during the reporting period.
(D) Name of the electric utility company that delivered the
electricity. In states with regulated electric utility markets, this
will generally be the same utility reported under paragraph
(i)(1)(i)(C) of this section, but in states with deregulated electric
utility markets, this may be a different utility company.
(E) Annual quantity of electricity consumed in MWh, calculated as
the sum of the total energy usage values specified in all billing
statements received during the reporting year. Most customers will
receive 12 monthly billing statements during the reporting year. Many
utilities bill their customers per kilowatt-hour (kWh); usage values on
bills that are based on kWh should be divided by 1,000 to report the
usage in MWh as required under this paragraph (i)(1)(i)(E).
(ii) If electricity is sourced from on-site or through a
contractual mechanism for dedicated off-site generation, for each
applicable energy source specified in paragraphs (i)(1)(ii)(A) through
(G) of this section, report the annual quantity of electricity
consumed, in MWh. If the on-site electricity source is natural gas,
oil, or coal, also indicate whether flue gas is also captured by the
DAC process unit.
(A) Non-hydropower renewable sources including solar, wind,
geothermal and tidal.
(B) Hydropower.
[[Page 31944]]
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
(2) Heat excluding CHP. For each applicable energy source specified
in paragraphs (i)(2)(i) through (vii) of this section, report the
annual quantity of heat, steam, or other forms of thermal energy
sourced from on-site or through a contractual mechanism for dedicated
off-site generation, in megajoules (MJ). If the on-site heat source is
natural gas, oil, or coal, also indicate whether flue gas is also
captured by the DAC process unit.
(i) Solar.
(ii) Geothermal.
(iii) Natural gas.
(iv) Oil.
(v) Coal.
(vi) Nuclear.
(vii) Other.
(3) CHP--(i) Electricity from CHP. If electricity from CHP is
sourced from on-site or through a contractual mechanism for dedicated
off-site generation, for each applicable energy source specified in
paragraphs (i)(3)(i)(A) through (G) of this section, report the annual
quantity consumed, in MWh. If the on-site electricity source for CHP is
natural gas, oil, or coal, also indicate whether flue gas is also
captured by the DAC process unit.
(A) Non-hydropower renewable sources including solar, wind,
geothermal and tidal.
(B) Hydropower.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
(ii) Heat from CHP. For each applicable energy source specified in
paragraphs (i)(3)(ii)(A) through (G) of this section, report the
quantity of heat, steam, or other forms of thermal energy from CHP
sourced from on-site or through a contractual mechanism for dedicated
off-site generation, in MJ. If the on-site heat source is natural gas,
oil, or coal, also indicate whether flue gas is also captured by the
DAC process unit.
(A) Solar.
(B) Geothermal.
(C) Natural gas.
(D) Oil.
(E) Coal.
(F) Nuclear.
(G) Other.
0
84. Amend Sec. 98.427 by revising paragraph (a) to read as follows:
Sec. 98.427 Records that must be retained.
* * * * *
(a) The owner or operator of a facility containing production
process units or DAC process units must retain quarterly records of
captured or transferred CO2 streams and composition.
* * * * *
Subpart QQ--Importers and Exporters of Fluorinated Greenhouse Gases
Contained in Pre-Charged Equipment or Closed-Cell Foams
0
85. Amend Sec. 98.436 by adding paragraphs (a)(7) and (b)(7) to read
as follows:
Sec. 98.436 Data reporting requirements.
(a) * * *
(7) The Harmonized tariff system (HTS) code for each type of pre-
charged equipment or closed-cell foam imported.
(b) * * *
(7) The Schedule B code for each type of pre-charged equipment or
closed-cell foam exported.
Subpart RR--Geologic Sequestration of Carbon Dioxide
0
86. Amend Sec. 98.449 by adding the definition ``Offshore'' in
alphabetical order to read as follows:
Sec. 98.449 Definitions.
* * * * *
Offshore means seaward of the terrestrial borders of the United
States, including waters subject to the ebb and flow of the tide, as
well as adjacent bays, lakes or other normally standing waters, and
extending to the outer boundaries of the jurisdiction and control of
the United States under the Outer Continental Shelf Lands Act.
* * * * *
0
87. Revise subpart SS consisting of Sec. Sec. 98.450 through 98.458 to
read as follows:
Subpart SS--Electrical Equipment Manufacture or Refurbishment
Sec.
98.450 Definition of the source category.
98.451 Reporting threshold.
98.452 GHGs to report.
98.453 Calculating GHG emissions.
98.454 Monitoring and QA/QC requirements.
98.455 Procedures for estimating missing data.
98.456 Data reporting requirements.
98.457 Records that must be retained.
98.458 Definitions.
Sec. 98.450 Definition of the source category.
The electrical equipment manufacturing or refurbishment category
consists of processes that manufacture or refurbish gas-insulated
substations, circuit breakers, other switchgear, gas-insulated lines,
or power transformers (including gas-containing components of such
equipment) containing fluorinated GHGs, including but not limited to
sulfur-hexafluoride (SF6) and perfluorocarbons (PFCs). The
processes include equipment testing, installation, manufacturing,
decommissioning and disposal, refurbishing, and storage in gas
cylinders and other containers.
Sec. 98.451 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains an electrical equipment manufacturing or refurbishing process
and the facility meets the requirements of Sec. 98.2(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. Instead of following the requirement of Sec. 98.453 to
calculate emissions from electrical equipment manufacture or
refurbishment, you must calculate emissions of each fluorinated GHG
that is a component of a reportable insulating gas and then sum the
emissions of each fluorinated GHG resulting from manufacturing and
refurbishing electrical equipment using equation SS-1 to this section.
[GRAPHIC] [TIFF OMITTED] TR25AP24.059
Where:
E = Annual production process emissions for threshold applicability
purposes (metric tons CO2e).
Pj = Total annual purchases of reportable insulating gas
j (lbs).
GHGi,w = The weight fraction of fluorinated GHG i in
reportable insulating gas j if reportable insulating gas j is a gas
mixture. If not a mixture, use 1.
GWPi = Gas-appropriate GWP as provided in table A-1 to
subpart A of this part.
EF = Emission factor for electrical transmission and distribution
equipment (lbs emitted/lbs purchased). For all gases, use an
emission factor of 0.1.
[[Page 31945]]
i = Fluorinated GHG contained in the electrical transmission and
distribution equipment.
0.000453592 = Conversion factor from lbs to metric tons.
Sec. 98.452 GHGs to report.
(a) You must report emissions of each fluorinated GHG, including
but not limited to SF6 and PFCs, at the facility level, except you are
not required to report emissions of fluorinated GHGs that are
components of insulating gases whose weighted average GWPs, as
calculated in equation SS-2 to this section, are less than or equal to
one. You are, however, required to report certain quantities of
insulating gases whose weighted average GWPs are less than or equal to
one as specified in Sec. 98.456(f), (g), (k) and (q) through (s).
Annual emissions from the facility must include fluorinated GHG
emissions from equipment that is installed at an off-site electric
power transmission or distribution location whenever emissions from
installation activities (e.g., filling) occur before the title to the
equipment is transferred to the electric power transmission or
distribution entity.
[GRAPHIC] [TIFF OMITTED] TR25AP24.060
Where:
GWPj = Weighted average GWP of insulating gas j.
GHGi,w = The weight fraction of GHG i in insulating gas
j, expressed as a decimal. fraction. If GHG i is not part of a gas
mixture, use a value of 1.0.
GWPi = Gas-appropriate GWP as provided in table A-1 to
subpart A of this part.
i = GHG contained in the electrical transmission and distribution
equipment.
(b) You must report CO2, N2O and
CH4 emissions from each stationary combustion unit. You must
calculate and report these emissions under subpart C of this part by
following the requirements of subpart C of this part.
Sec. 98.453 Calculating GHG emissions.
(a) For each electrical equipment manufacturer or refurbisher,
estimate the annual emissions of each fluorinated GHG that is a
component of any reportable insulating gas using the mass-balance
approach in equation SS-3 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.061
Where:
User emissionsi = Annual emissions of each fluorinated
GHG i (pounds).
GHGi,w = The weight fraction of fluorinated GHG i in
reportable insulating gas j if insulating gas j is a gas mixture,
expressed as a decimal fraction. If fluorinated GHG i is not part of
a gas mixture, use a value of 1.0.
Decrease in Inventory of Reportable Insulating Gas j Inventory =
(Pounds of reportable insulating gas j stored in containers at the
beginning of the year)--(Pounds of reportable insulating gas j
stored in containers at the end of the year).
Acquisitions of Reportable Insulating Gas j = (Pounds of reportable
insulating gas j purchased from chemical producers or suppliers in
bulk) + (Pounds of reportable insulating gas j returned by equipment
users) + (Pounds of reportable insulating gas j returned to site
after off-site recycling).
Disbursements of Reportable Insulating Gas j = (Pounds of reportable
insulating gas j contained in new equipment delivered to customers)
+ (Pounds of reportable insulating gas j delivered to equipment
users in containers) + (Pounds of reportable insulating gas j
returned to suppliers) + (Pounds of reportable insulating gas j sent
off site for recycling) + (Pounds of reportable insulating gas j
sent off-site for destruction).
(b) [Reserved]
(c) Estimate the disbursements of reportable insulating gas j sent
to customers in new equipment or cylinders or sent off-site for other
purposes including for recycling, for destruction or to be returned to
suppliers using equation SS-4 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.062
Where:
DGHG = The annual disbursement of reportable insulating
gas j sent to customers in new equipment or cylinders or sent off-
site for other purposes including for recycling, for destruction or
to be returned to suppliers.
Qp = The mass of reportable insulating gas j charged into
equipment or containers over the period p sent to customers or sent
off-site for other purposes including for recycling, for destruction
or to be returned to suppliers.
n = The number of periods in the year.
(d) Estimate the mass of each insulating gas j disbursed to
customers in new equipment or cylinders over the period p by monitoring
the mass flow of each insulating gas j into the new equipment or
cylinders using a flowmeter, or by weighing containers before and after
gas from containers is used to fill equipment or cylinders, or by using
the nameplate capacity of the equipment.
(e) If the mass of insulating gas j disbursed to customers in new
equipment or cylinders over the period p is estimated by weighing
containers before and after gas from containers is used to fill
equipment or cylinders, estimate this quantity using equation SS-5 to
this section:
[[Page 31946]]
[GRAPHIC] [TIFF OMITTED] TR25AP24.063
Where:
Qp = The mass of insulating gas j charged into equipment
or containers over the period p sent to customers or sent off-site
for other purposes including for recycling, for destruction or to be
returned to suppliers.
MB = The mass of the contents of the containers used to
fill equipment or cylinders at the beginning of period p.
ME = The mass of the contents of the containers used to
fill equipment or cylinders at the end of period p.
EL = The mass of insulating gas j emitted during the
period p downstream of the containers used to fill equipment or
cylinders and in cases where a flowmeter is used, downstream of the
flowmeter during the period p (e.g., emissions from hoses or other
flow lines that connect the container to the equipment or cylinder
that is being filled).
(f) If the mass of insulating gas j disbursed to customers in new
equipment or cylinders over the period p is determined using a
flowmeter, estimate this quantity using equation SS-6 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.064
Where:
Qp = The mass of insulating gas j charged into equipment
or containers over the period p sent to customers or sent off-site
for other purposes including for recycling, for destruction or to be
returned to suppliers.
Mmr = The mass of insulating gas j that has flowed
through the flowmeter during the period p.
EL = The mass of insulating gas j emitted during the
period p downstream of the containers used to fill equipment or
cylinders and in cases where a flowmeter is used, downstream of the
flowmeter during the period p (e.g., emissions from hoses or other
flow lines that connect the container to the equipment that is being
filled).
(g) Estimate the mass of insulating gas j emitted during the period
p downstream of the containers used to fill equipment or cylinders
(e.g., emissions from hoses or other flow lines that connect the
container to the equipment or cylinder that is being filled) using
equation SS-7 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.065
Where:
EL = The mass of insulating gas j emitted during the
period p downstream of the containers used to fill equipment or
cylinders and in cases where a flowmeter is used, downstream of the
flowmeter during the period p (e.g., emissions from hoses or other
flow lines that connect the container to the equipment or cylinder
that is being filled).
FCi = The total number of fill operations over the period
p for the valve-hose combination Ci.
EFCi = The emission factor for the valve-hose combination
Ci.
n=The number of different valve-hose combinations C used during the
period p.
(h) If the mass of insulating gas j disbursed to customers in new
equipment or cylinders over the period p is determined by using the
nameplate capacity, or by using the nameplate capacity of the equipment
and calculating the partial shipping charge, use the methods in either
paragraph (h)(1) or (2) of this section.
(1) Determine the equipment's actual nameplate capacity, by
measuring the nameplate capacities of a representative sample of each
make and model and calculating the mean value for each make and model
as specified at Sec. 98.454(f).
(2) If equipment is shipped with a partial charge, calculate the
partial shipping charge by multiplying the nameplate capacity of the
equipment by the ratio of the densities of the partial charge to the
full charge.
(i) Estimate the annual emissions of reportable insulating gas j
from the equipment that is installed at an off-site electric power
transmission or distribution location before the title to the equipment
is transferred by using equation SS-8 to this section:
[GRAPHIC] [TIFF OMITTED] TR25AP24.066
Where:
EI = Total annual emissions of reportable insulating gas j from
equipment installation at electric transmission or distribution
facilities.
GHGi,w = The weight fraction of fluorinated GHG i in
reportable insulating gas j if reportable insulating gas j is a gas
mixture, expressed as a decimal fraction. If the GHG i is not part
of a gas mixture, use a value of 1.0.
MF = The total annual mass of reportable insulating gas
j, in pounds, used to fill equipment during equipment installation
at electric transmission or distribution facilities.
MC = The total annual mass of reportable insulating gas
j, in pounds, used to charge the equipment prior to leaving the
electrical equipment manufacturer facility.
NI = The total annual nameplate capacity of the
equipment, in pounds, installed at electric transmission or
distribution facilities.
Sec. 98.454 Monitoring and QA/QC requirements.
(a) [Reserved]
(b) Ensure that all the quantities required by the equations of
this subpart have been measured using either flowmeters with an
accuracy and precision of 1 percent of full scale or better
or scales with an accuracy and precision of 1 percent of
the filled weight (gas plus tare) of the containers of each reportable
insulating gas that are typically weighed on the scale. For scales that
are generally used to weigh cylinders containing 115 pounds of gas when
full, this equates to 1 percent of the sum of 115 pounds
and approximately 120 pounds tare, or slightly more than 2
pounds. Account for the tare weights of the containers. You may accept
gas masses or weights provided by the gas supplier (e.g., for the
contents of cylinders containing
[[Page 31947]]
new gas or for the heels remaining in cylinders returned to the gas
supplier) if the supplier provides documentation verifying that
accuracy standards are met; however, you remain responsible for the
accuracy of these masses and weights under this subpart.
(c) All flow meters, weigh scales, and combinations of volumetric
and density measures that are used to measure or calculate quantities
under this subpart must be calibrated using calibration procedures
specified by the flowmeter, scale, volumetric or density measure
equipment manufacturer. Calibration must be performed prior to the
first reporting year. After the initial calibration, recalibration must
be performed at the minimum frequency specified by the manufacturer.
(d) For purposes of equation SS-7 to Sec. 98.453, the emission
factor for the valve-hose combination (EFC) must be estimated using
measurements and/or engineering assessments or calculations based on
chemical engineering principles or physical or chemical laws or
properties. Such assessments or calculations may be based on, as
applicable, the internal volume of hose or line that is open to the
atmosphere during coupling and decoupling activities, the internal
pressure of the hose or line, the time the hose or line is open to the
atmosphere during coupling and decoupling activities, the frequency
with which the hose or line is purged and the flow rate during purges.
You must develop a value for EFc (or use an industry-developed value)
for each combination of hose and valve fitting, to use in equation SS-7
to Sec. 98.453. The value for EFC must be determined for each
combination of hose and valve fitting of a given diameter or size. The
calculation must be recalculated annually to account for changes to the
specifications of the valves or hoses that may occur throughout the
year.
(e) Electrical equipment manufacturers and refurbishers must
account for emissions of each reportable insulating gas that occur as a
result of unexpected events or accidental losses, such as a
malfunctioning hose or leak in the flow line, during the filling of
equipment or containers for disbursement by including these losses in
the estimated mass of each reportable insulating gas emitted downstream
of the container or flowmeter during the period p.
(f) If the mass of each reportable insulating gas j disbursed to
customers in new equipment over the period p is determined by assuming
that it is equal to the equipment's nameplate capacity or, in cases
where equipment is shipped with a partial charge, equal to its partial
shipping charge, equipment samples for conducting the nameplate
capacity tests must be selected using the following stratified sampling
strategy in this paragraph (f). For each make and model, group the
measurement conditions to reflect predictable variability in the
facility's filling practices and conditions (e.g., temperatures at
which equipment is filled). Then, independently select equipment
samples at random from each make and model under each group of
conditions. To account for variability, a certain number of these
measurements must be performed to develop a robust and representative
average nameplate capacity (or shipping charge) for each make, model,
and group of conditions. A Student T distribution calculation should be
conducted to determine how many samples are needed for each make,
model, and group of conditions as a function of the relative standard
deviation of the sample measurements. To determine a sufficiently
precise estimate of the nameplate capacity, the number of measurements
required must be calculated to achieve a precision of one percent of
the true mean, using a 95 percent confidence interval. To estimate the
nameplate capacity for a given make and model, you must use the lowest
mean value among the different groups of conditions, or provide
justification for the use of a different mean value for the group of
conditions that represents the typical practices and conditions for
that make and model. Measurements can be conducted using SF6, another
gas, or a liquid. Re-measurement of nameplate capacities should be
conducted every five years to reflect cumulative changes in
manufacturing methods and conditions over time.
(g) Ensure the following QA/QC methods are employed throughout the
year:
(1) Procedures are in place and followed to track and weigh all
cylinders or other containers at the beginning and end of the year.
(2) [Reserved]
(h) You must adhere to the following QA/QC methods for reviewing
the completeness and accuracy of reporting:
(1) Review inputs to equation SS-3 to Sec. 98.453 to ensure inputs
and outputs to the company's system are included.
(2) Do not enter negative inputs and confirm that negative
emissions are not calculated. However, the decrease in the inventory
for each reportable insulating gas may be calculated as negative.
(3) Ensure that for each reportable insulating gas, the beginning-
of-year inventory matches the end-of-year inventory from the previous
year.
(4) Ensure that for each reportable insulating gas, in addition to
the reportable insulating gas purchased from bulk gas distributors, the
reportable insulating gas returned from equipment users with or inside
equipment and the reportable insulating gas returned from off-site
recycling are also accounted for among the total additions.
Sec. 98.455 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Replace missing data, if needed,
based on data from similar manufacturing operations, and from similar
equipment testing and decommissioning activities for which data are
available.
Sec. 98.456 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information for each chemical
at the facility level:
(a) Pounds of each reportable insulating gas stored in containers
at the beginning of the year.
(b) Pounds of each reportable insulating gas stored in containers
at the end of the year.
(c) Pounds of each reportable insulating gas purchased in bulk.
(d) Pounds of each reportable insulating gas returned by equipment
users with or inside equipment.
(e) Pounds of each reportable insulating gas returned to site from
off site after recycling.
(f) Pounds of each insulating gas inside new equipment delivered to
customers.
(g) Pounds of each insulating gas delivered to equipment users in
containers.
(h) Pounds of each reportable insulating gas returned to suppliers.
(i) Pounds of each reportable insulating gas sent off site for
destruction.
(j) Pounds of each reportable insulating gas sent off site to be
recycled.
(k) The nameplate capacity of the equipment, in pounds, delivered
to customers with each insulating gas inside, if different from the
quantity in paragraph (f) of this section.
(l) A description of the engineering methods and calculations used
to determine emissions from hoses or other flow lines that connect the
container to the equipment that is being filled.
(m) The values for EFci of equation SS-7 to Sec. 98.453
for each hose and valve combination and the associated valve fitting
sizes and hose diameters.
[[Page 31948]]
(n) The total number of fill operations for each hose and valve
combination, or, FCi of equation SS-7 to Sec. 98.453.
(o) If the mass of each reportable insulating gas disbursed to
customers in new equipment over the period p is determined according to
the methods required in Sec. 98.453(h), report the mean value of
nameplate capacity in pounds for each make, model, and group of
conditions.
(p) If the mass of each reportable insulating gas disbursed to
customers in new equipment over the period p is determined according to
the methods required in Sec. 98.453(h), report the number of samples
and the upper and lower bounds on the 95-percent confidence interval
for each make, model, and group of conditions.
(q) Pounds of each insulating gas used to fill equipment at off-
site electric power transmission or distribution locations, or MF, of
equation SS-8 to Sec. 98.453.
(r) Pounds of each insulating gas used to charge the equipment
prior to leaving the electrical equipment manufacturer or refurbishment
facility, or MC, of equation SS-8 to Sec. 98.453.
(s) The nameplate capacity of the equipment, in pounds, installed
at off-site electric power transmission or distribution locations used
to determine emissions from installation, or NI, of equation
SS-8 to Sec. 98.453.
(t) For any missing data, you must report the reason the data were
missing, the parameters for which the data were missing, the substitute
parameters used to estimate emissions in their absence, and the
quantity of emissions thereby estimated.
(u) For each insulating gas reported in paragraphs (a) through (j)
and (o) through (r) of this section, an ID number or other appropriate
descriptor unique to that insulating gas.
(v) For each ID number or descriptor reported in paragraph (u) of
this section for each unique insulating gas, the name (as required in
Sec. 98.3(c)(4)(iii)(G)(1)) and weight percent of each fluorinated gas
in the insulating gas.
Sec. 98.457 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the following records:
(a) All information reported and listed in Sec. 98.456.
(b) Accuracy certifications and calibration records for all scales
and monitoring equipment, including the method or manufacturer's
specification used for calibration.
(c) Certifications of the quantity of gas, in pounds, charged into
equipment at the electrical equipment manufacturer or refurbishment
facility as well as the actual quantity of gas, in pounds, charged into
equipment at installation.
(d) Check-out and weigh-in sheets and procedures for cylinders.
(e) Residual gas amounts, in pounds, in cylinders sent back to
suppliers.
(f) Invoices for gas purchases and sales.
(g) GHG Monitoring Plans, as described in Sec. 98.3(g)(5), must be
completed by April 1, 2011.
Sec. 98.458 Definitions.
Except as specified in this section, all terms used in this subpart
have the same meaning given in the CAA and subpart A of this part.
Insulating gas, for the purposes of this subpart, means any
fluorinated GHG or fluorinated GHG mixture, including but not limited
to SF6 and PFCs, that is used as an insulating and/or arc-
quenching gas in electrical equipment.
Reportable insulating gas, for purposes of this subpart, means an
insulating gas whose weighted average GWP, as calculated in equation
SS-2 to Sec. 98.452, is greater than one. A fluorinated GHG that makes
up either part or all of a reportable insulating gas is considered to
be a component of the reportable insulating gas.
Subpart UU--Injection of Carbon Dioxide
0
88. Revise and republish Sec. 98.470 to read as follows:
Sec. 98.470 Definition of the source category.
(a) The injection of carbon dioxide (CO2) source
category comprises any well or group of wells that inject a
CO2 stream into the subsurface.
(b) If you report under subpart RR of this part for a well or group
of wells, you shall not report under this subpart for that well or
group of wells.
(c) If you report under subpart VV of this part for a well or group
of wells, you shall not report under this subpart for that well or
group of wells. If you previously met the source category definition
for subpart UU of this part for a project where CO2 is
injected in enhanced recovery operations for oil and other hydrocarbons
(CO2-EOR) and then began using the standard designated as
CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec. 98.7) such
that you met the definition of the source category for subpart VV
during a reporting year, you must report under subpart UU for the
portion of the year before you began using CSA/ANSI ISO 27916:19 and
report under subpart VV for the portion of the year after you began
using CSA/ANSI ISO 27916:19.
(d) A facility that is subject to this part only because it is
subject to subpart UU of this part is not required to report emissions
under subpart C of this part or any other subpart listed in Sec.
98.2(a)(1) or (2).
0
89. Add subpart VV consisting of Sec. Sec. 98.480 through 98.489,
subpart WW consisting of Sec. Sec. 98.490 through 98.498, subpart XX
consisting of Sec. Sec. 98.500 through 98.508, subpart YY consisting
of Sec. Sec. 98.510 through 98.518, and subpart ZZ consisting of
Sec. Sec. 98.520 through 98.528 to part 98 to read as follows:
Subpart VV--Geologic Sequestration of Carbon Dioxide With Enhanced
Oil Recovery Using ISO 27916
Sec.
98.480 Definition of the source category.
98.481 Reporting threshold.
98.482 GHGs to report.
98.483 Calculating CO2 geologic sequestration.
98.484 Monitoring and QA/QC requirements.
98.485 Procedures for estimating missing data.
98.486 Data reporting requirements.
98.487 Records that must be retained.
98.488 EOR Operations Management Plan.
98.489 Definitions.
Sec. 98.480 Definition of the source category.
(a) This source category pertains to carbon dioxide
(CO2) that is injected in enhanced recovery operations for
oil and other hydrocarbons (CO2-EOR) in which all of the
following apply:
(1) You are using the standard designated as CSA/ANSI ISO 27916:19,
(incorporated by reference, see Sec. 98.7) as a method of quantifying
geologic sequestration of CO2 in association with EOR
operations.
(2) You are not reporting under subpart RR of this part.
(b) This source category does not include wells permitted as Class
VI under the Underground Injection Control program.
(c) If you are subject to only this subpart, you are not required
to report emissions under subpart C of this part or any other subpart
listed in Sec. 98.2(a)(1) or (2).
Sec. 98.481 Reporting threshold.
(a) You must report under this subpart if your CO2-EOR
project uses CSA/ANSI ISO 27916:19 (incorporated by reference, see
Sec. 98.7) as a method of quantifying geologic sequestration of
CO2 in association with CO2-EOR operations. There
is no threshold for reporting.
(b) The requirements of Sec. 98.2(i) do not apply to this subpart.
Once a CO2-EOR project becomes subject to the
[[Page 31949]]
requirements of this subpart, you must continue for each year
thereafter to comply with all requirements of this subpart, including
the requirement to submit annual reports until the facility has met the
requirements of paragraphs (b)(1) and (2) of this section and submitted
a notification to discontinue reporting according to paragraph (b)(3)
of this section.
(1) Discontinuation of reporting under this subpart must follow the
requirements set forth under Clause 10 of CSA/ANSI ISO 27916:19
(incorporated by reference, see Sec. 98.7).
(2) CO2-EOR project termination is completed when all of
the following occur:
(i) Cessation of CO2 injection.
(ii) Cessation of hydrocarbon production from the project
reservoir; and
(iii) Wells are plugged and abandoned unless otherwise required by
the appropriate regulatory authority.
(3) You must notify the Administrator of your intent to cease
reporting and provide a copy of the CO2-EOR project
termination documentation.
(c) If you previously met the source category definition for
subpart UU of this part for your CO2-EOR project and then
began using CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec.
98.7) as a method of quantifying geologic sequestration of
CO2 in association with CO2-EOR operations during
a reporting year, you must report under subpart UU of this part for the
portion of the year before you began using CSA/ANSI ISO 27916:19 and
report under subpart VV for the portion of the year after you began
using CSA/ANSI ISO 27916:19.
Sec. 98.482 GHGs to report.
You must report the following from Clause 8 of CSA/ANSI ISO
27916:19 (incorporated by reference, see Sec. 98.7):
(a) The mass of CO2 received by the CO2-EOR
project.
(b) The mass of CO2 loss from the CO2-EOR
project operations.
(c) The mass of native CO2 produced and captured.
(d) The mass of CO2 produced and sent off-site.
(e) The mass of CO2 loss from the EOR complex.
(f) The mass of CO2 stored in association with
CO2-EOR.
Sec. 98.483 Calculating CO2 geologic sequestration.
You must calculate CO2 sequestered using the following
quantification principles from Clause 8.2 of CSA/ANSI ISO 27916:19
(incorporated by reference, see Sec. 98.7).
(a) You must calculate the mass of CO2 stored in
association with CO2-EOR (mstored) in the
reporting year by subtracting the mass of CO2 loss from
operations and the mass of CO2 loss from the EOR complex
from the total mass of CO2 input (as specified in equation 1
to this paragraph (a)).
Equation 1 to paragraph (a)
mstored = minput-mloss operations-
mloss EOR complex
Where:
mstored = The annual quantity of associated storage in
metric tons of CO2 mass.
minput = The total mass of CO2
mreceived by the EOR project plus mnative (see
Clause 8.3 of CSA/ANSI ISO 27916:19 (incorporated by reference, see
Sec. 98.7) and paragraph (c) of this section), metric tons. Native
CO2 produced and captured in the CO2-EOR
project (mnative) can be quantified and included in
minput.
mloss operations = The total mass of CO2 loss
from project operations (see Clauses 8.4.1 through 8.4.5 of CSA/ANSI
ISO 27916:19 (incorporated by reference, see Sec. 98.7) and
paragraph (d) of this section), metric tons.
mloss EOR complex = The total mass of CO2 loss
from the EOR complex (see Clause 8.4.6 of CSA/ANSI ISO 27916:19
(incorporated by reference, see Sec. 98.7)), metric tons.
(b) The manner by which associated storage is quantified must
assure completeness and preclude double counting. The annual mass of
CO2 that is recycled and reinjected into the EOR complex
must not be quantified as associated storage. Loss from the
CO2 recycling facilities must be quantified.
(c) You must quantify the total mass of CO2 input
(minput) in the reporting year according to paragraphs
(g)(1) through (3) of this section.
(1) You must include the total mass of CO2 received at
the custody transfer meter by the CO2-EOR project
(mreceived).
(2) The CO2 stream received (including CO2
transferred from another CO2-EOR project) must be metered.
(i) The native CO2 recovered and included as
mnative must be documented.
(ii) CO2 delivered to multiple CO2-EOR
projects must be allocated among those CO2-EOR projects.
(3) The sum of the quantities of allocated CO2 must not
exceed the total quantities of CO2 received.
(d) You must calculate the total mass of CO2 from
project operations (mloss operations) in the reporting year
as specified in equation 2 to this paragraph (d).
Equation 2 to paragraph (d)
[GRAPHIC] [TIFF OMITTED] TR25AP24.067
Where:
mloss leakage facilities = Loss of CO2 due to
leakage from production, handling, and recycling CO2-EOR
facilities (infrastructure including wellheads), metric tons.
mloss vent/flare = Loss of CO2 from venting/
flaring from production operations, metric tons.
mloss entrained = Loss of CO2 due to
entrainment within produced gas/oil/water when this CO2
is not separated and reinjected, metric tons.
mloss transfer=Loss of CO2 due to any transfer
of CO2 outside the CO2-EOR project, metric
tons. You must quantify any CO2 that is subsequently
produced from the EOR complex and transferred offsite.
Sec. 98.484 Monitoring and QA/QC requirements.
You must use the applicable monitoring and quality assurance
requirements set forth in Clause 6.2 of CSA/ANSI ISO 27916:19
(incorporated by reference, see Sec. 98.7).
Sec. 98.485 Procedures for estimating missing data.
Whenever the value of a parameter is unavailable or the quality
assurance procedures set forth in Sec. 98.484 cannot be followed, you
must follow the procedures set forth in Clause 9.2 of CSA/ANSI ISO
27916:19 (incorporated by reference, see Sec. 98.7).
Sec. 98.486 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), the
annual report shall contain the following information, as applicable:
(a) The annual quantity of associated storage in metric tons of
CO2 (mstored).
(b) The density of CO2 if volumetric units are converted
to mass in order to be reported for annual quantity of CO2
stored.
(c) The annual quantity of CO2 input (minput)
and the information in paragraphs (c)(1) and (2) of this section.
(1) The annual total mass of CO2 received at the custody
transfer meter by the CO2-EOR project, including
CO2
[[Page 31950]]
transferred from another CO2-EOR project
(mreceived).
(2) The annual mass of native CO2 produced and captured
in the CO2-EOR project (mnative).
(d) The annual mass of CO2 that is recycled and
reinjected into the EOR complex.
(e) The annual total mass of CO2 loss from project
operations (mloss operations), and the information in
paragraphs (e)(1) through (4) of this section.
(1) Loss of CO2 due to leakage from production,
handling, and recycling CO2-EOR facilities (infrastructure
including wellheads) (mloss leakage facilities).
(2) Loss of CO2 from venting/flaring from production
operations (mloss vent/flare).
(3) Loss of CO2 due to entrainment within produced gas/
oil/water when this CO2 is not separated and reinjected
(mloss entrained).
(4) Loss of CO2 due to any transfer of CO2
outside the CO2-EOR project (mloss transfer).
(f) The total mass of CO2 loss from the EOR complex
(mloss EOR complex).
(g) Annual documentation that contains the following components as
described in Clause 4.4 of CSA/ANSI ISO 27916:19 (incorporated by
reference, see Sec. 98.7):
(1) The formulas used to quantify the annual mass of associated
storage, including the mass of CO2 delivered to the
CO2-EOR project and losses during the period covered by the
documentation (see Clause 8 and Annex B of CSA/ANSI ISO 27916:19
(incorporated by reference, see Sec. 98.7)).
(2) The methods used to estimate missing data and the amounts
estimated as described in Clause 9.2 of CSA/ANSI ISO 27916:19
(incorporated by reference, see Sec. 98.7).
(3) The approach and method for quantification utilized by the
operator, including accuracy, precision, and uncertainties (see Clause
8 and Annex B of CSA/ANSI ISO 27916:19 (incorporated by reference, see
Sec. 98.7)).
(4) A statement describing the nature of validation or verification
including the date of review, process, findings, and responsible person
or entity.
(5) Source of each CO2 stream quantified as associated
storage (see Clause 8.3 of CSA/ANSI ISO 27916:19 (incorporated by
reference, see Sec. 98.7)).
(6) A description of the procedures used to detect and characterize
the total CO2 leakage from the EOR complex.
(7) If only the mass of anthropogenic CO2 is considered
for mstored, a description of the derivation and application of
anthropogenic CO2 allocation ratios for all the terms
described in Clauses 8.1 to 8.4.6 of CSA/ANSI ISO 27916:19
(incorporated by reference, see Sec. 98.7).
(8) Any documentation provided by a qualified independent engineer
or geologist, who certifies that the documentation provided, including
the mass balance calculations as well as information regarding
monitoring and containment assurance, is accurate and complete.
(h) Any changes made within the reporting year to containment
assurance and monitoring approaches and procedures in the EOR
operations management plan.
Sec. 98.487 Records that must be retained.
You must follow the record retention requirements specified by
Sec. 98.3(g). In addition to the records required by Sec. 98.3(g),
you must comply with the record retention requirements in Clause 9.1 of
CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec. 98.7).
Sec. 98.488 EOR Operations Management Plan.
(a) You must prepare and update, as necessary, a general EOR
operations management plan that provides a description of the EOR
complex and engineered system (see Clause 4.3(a) of CSA/ANSI ISO
27916:19 (incorporated by reference, see Sec. 98.7)), establishes that
the EOR complex is adequate to provide safe, long-term containment of
CO2, and includes site-specific and other information
including:
(1) Geologic characterization of the EOR complex.
(2) A description of the facilities within the CO2-EOR
project.
(3) A description of all wells and other engineered features in the
CO2-EOR project.
(4) The operations history of the project reservoir.
(5) The information set forth in Clauses 5 and 6 of CSA/ANSI ISO
27916:19 (incorporated by reference, see Sec. 98.7).
(b) You must prepare initial documentation at the beginning of the
quantification period, and include the following as described in the
EOR operations management plan:
(1) A description of the EOR complex and engineered systems (see
Clause 5 of CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec.
98.7)).
(2) The initial containment assurance (see Clause 6.1.2 of CSA/ANSI
ISO 27916:19 (incorporated by reference, see Sec. 98.7)).
(3) The monitoring program (see Clause 6.2 of CSA/ANSI ISO 27916:19
(incorporated by reference, see Sec. 98.7)).
(4) The quantification method to be used (see Clause 8 and Annex B
of CSA/ANSI ISO 27916:19 (incorporated by reference, see Sec. 98.7)).
(5) The total mass of previously injected CO2 (if any)
within the EOR complex at the beginning of the CO2-EOR
project (see Clause 8.5 and Annex B of CSA/ANSI ISO 27916:19
(incorporated by reference, see Sec. 98.7)).
(c) The EOR operation management plan in paragraph (a) of this
section and initial documentation in paragraph (b) of this section must
be submitted to the Administrator with the annual report covering the
first reporting year that the facility reports under this subpart. In
addition, any documentation provided by a qualified independent
engineer or geologist, who certifies that the documentation provided is
accurate and complete, must also be provided to the Administrator.
(d) If the EOR operations management plan is updated, the updated
EOR management plan must be submitted to the Administrator with the
annual report covering the first reporting year for which the updated
EOR operation management plan is applicable.
Sec. 98.489 Definitions.
Except as provided in paragraphs (a) and (b) of this section, all
terms used in this subpart have the same meaning given in the Clean Air
Act and subpart A of this part.
Additional terms and definitions are provided in Clause 3 of CSA/
ANSI ISO 27916:19 (incorporated by reference, see Sec. 98.7).
Subpart WW--Coke Calciners
Sec.
98.490 Definition of the source category.
98.491 Reporting threshold.
98.492 GHGs to report.
98.493 Calculating GHG emissions.
98.494 Monitoring and QA/QC requirements.
98.495 Procedures for estimating missing data.
98.496 Data reporting requirements.
98.497 Records that must be retained.
98.498 Definitions.
Sec. 98.490 Definition of the source category.
(a) A coke calciner is a process unit that heats petroleum coke to
high temperatures for the purpose of removing impurities or volatile
substances in the petroleum coke feedstock.
(b) This source category consists of rotary kilns, rotary hearth
furnaces, or similar process units used to calcine petroleum coke and
also includes afterburners or other emission control systems used to
treat the coke calcining unit's process exhaust gas.
[[Page 31951]]
Sec. 98.491 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a coke calciner and the facility meets the requirements of
either Sec. 98.2(a)(1) or (2).
Sec. 98.492 GHGs to report.
You must report:
(a) CO2, CH4, and N2O emissions
from each coke calcining unit under this subpart.
(b) CO2, CH4, and N2O emissions
from auxiliary fuel used in the coke calcining unit and afterburner, if
applicable, or other control system used to treat the coke calcining
unit's process off-gas under subpart C of this part by following the
requirements of subpart C.
Sec. 98.493 Calculating GHG emissions.
(a) Calculate GHG emissions required to be reported in Sec.
98.492(a) using the applicable methods in paragraph (b) of this
section.
(b) For each coke calcining unit, calculate GHG emissions according
to the applicable provisions in paragraphs (b)(1) through (4) of this
section.
(1) If you operate and maintain a CEMS that measures CO2
emissions according to subpart C of this part, you must calculate and
report CO2 emissions under this subpart by following the
Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4) and all
associated requirements for Tier 4 in subpart C of this part. Auxiliary
fuel use CO2 emissions should be calculated in accordance
with subpart C of this part and subtracted from the CO2 CEMS
emissions to determine process CO2 emissions. Other coke
calcining units must either install a CEMS that complies with the Tier
4 Calculation Methodology in subpart C of this part or follow the
requirements of paragraph (b)(2) of this section.
(2) Calculate the CO2 emissions from the coke calcining
unit using monthly measurements and equation 1 to this paragraph
(b)(2).
Equation 1 to paragraph (b)(2)
[GRAPHIC] [TIFF OMITTED] TR25AP24.068
Where:
CO2 = Annual CO2 emissions (metric tons
CO2/year).
m = Month index.
Min,m = Mass of green coke fed to the coke calcining unit
in month ``m'' from facility records (metric tons/year).
CCGC.m = Mass fraction carbon content of green coke fed
to the coke calcining unit from facility measurement data in month
``m'' (metric ton carbon/metric ton green coke). If measurements are
made more frequently than monthly, determine the monthly average as
the arithmetic average for all measurements made during the calendar
month.
Mout,m = Mass of marketable petroleum coke produced by
the coke calcining unit in month ``m'' from facility records (metric
tons petroleum coke/year).
Mdust,m = Mass of petroleum coke dust removed from the
process through the dust collection system of the coke calcining
unit in month ``m'' from facility records (metric ton petroleum coke
dust/year). For coke calcining units that recycle the collected
dust, the mass of coke dust removed from the process is the mass of
coke dust collected less the mass of coke dust recycled to the
process.
CCMPC,m = Mass fraction carbon content of marketable
petroleum coke produced by the coke calcining unit in month ``m''
from facility measurement data (metric ton carbon/metric ton
petroleum coke). If measurements are made more frequently than
monthly, determine the monthly average as the arithmetic average for
all measurements made during the calendar month.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(3) Calculate CH4 emissions using equation 2 to this paragraph
(b)(3).
Equation 2 to paragraph (b)(3)
[GRAPHIC] [TIFF OMITTED] TR25AP24.069
Where:
CH4 = Annual methane emissions (metric tons
CH4/year).
CO2 = Annual CO2 emissions calculated in
paragraph (b)(1) or (2) of this section, as applicable (metric tons
CO2/year).
EmF1 = Default CO2 emission factor for
petroleum coke from table C-1 to subpart C of this part (kg
CO2/MMBtu).
EmF2 = Default CH4 emission factor for
``Petroleum Products (All fuel types in table C-1)'' from table C-2
to subpart C of this part (kg CH4/MMBtu).
(4) Calculate N2O emissions using equation 3 to this
paragraph (b)(4).
Equation 3 to paragraph (b)(4)
[GRAPHIC] [TIFF OMITTED] TR25AP24.070
Where:
N2O = Annual nitrous oxide emissions (metric tons
N2O/year).
CO2 = Annual CO2 emissions calculated in
paragraph (b)(1) or (2) of this section, as applicable (metric tons
CO2/year).
EmF1 = Default CO2 emission factor for
petroleum coke from table C-1 to subpart C of this part (kg
CO2/MMBtu).
EmF3 = Default N2O emission factor for
``Petroleum Products (All fuel types in table C-1)'' from table C-2
to subpart C of this part (kg N2O/MMBtu).
Sec. 98.494 Monitoring and QA/QC requirements.
(a) Flow meters, gas composition monitors, and heating value
monitors that are associated with sources that use a CEMS to measure
CO2 emissions according to subpart C of this part or that
are associated with stationary combustion sources must meet the
applicable monitoring and QA/QC requirements in Sec. 98.34.
(b) Determine the mass of petroleum coke monthly as required by
equation 1 to Sec. 98.493(b)(2) using mass measurement equipment
meeting the requirements for commercial weighing equipment as described
in NIST HB 44-2023 (incorporated by reference, see Sec. 98.7).
Calibrate the measurement device according to the procedures specified
by NIST HB 44-2023 (incorporated by reference, see Sec. 98.7) or the
procedures specified by the
[[Page 31952]]
manufacturer. Recalibrate either biennially or at the minimum frequency
specified by the manufacturer.
(c) Determine the carbon content of petroleum coke as required by
equation 1 Sec. 98.493(b)(2) using any one of the following methods.
Calibrate the measurement device according to procedures specified by
the method or procedures specified by the measurement device
manufacturer.
(1) ASTM D3176-15 (incorporated by reference, see Sec. 98.7).
(2) ASTM D5291-16 (incorporated by reference, see Sec. 98.7).
(3) ASTM D5373-21 (incorporated by reference, see Sec. 98.7).
(d) The owner or operator must document the procedures used to
ensure the accuracy of the monitoring systems used including but not
limited to calibration of weighing equipment, flow meters, and other
measurement devices. The estimated accuracy of measurements made with
these devices must also be recorded.
Sec. 98.495 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required (e.g., concentrations, flow rates,
fuel heating values, carbon content values). Therefore, whenever a
quality-assured value of a required parameter is unavailable (e.g., if
a CEMS malfunctions during unit operation or if a required sample is
not taken), a substitute data value for the missing parameter must be
used in the calculations.
(a) For missing auxiliary fuel use data, use the missing data
procedures in subpart C of this part.
(b) For each missing value of mass or carbon content of coke,
substitute the arithmetic average of the quality-assured values of that
parameter immediately preceding and immediately following the missing
data incident. If the ``after'' value is not obtained by the end of the
reporting year, you may use the ``before'' value for the missing data
substitution. If, for a particular parameter, no quality-assured data
are available prior to the missing data incident, the substitute data
value must be the first quality-assured value obtained after the
missing data period.
(c) For missing CEMS data, you must use the missing data procedures
in Sec. 98.35.
Sec. 98.496 Data reporting requirements.
In addition to the reporting requirements of Sec. 98.3(c), you
must report the information specified in paragraphs (a) through (i) of
this section for each coke calcining unit.
(a) The unit ID number (if applicable).
(b) Maximum rated throughput of the unit, in metric tons coke
calcined/stream day.
(c) The calculated CO2, CH4, and
N2O annual process emissions, expressed in metric tons of
each pollutant emitted.
(d) A description of the method used to calculate the
CO2 emissions for each unit (e.g., CEMS or equation 1 to
Sec. 98.493(b)(2)).
(e) Annual mass of green coke fed to the coke calcining unit from
facility records (metric tons/year).
(f) Annual mass of marketable petroleum coke produced by the coke
calcining unit from facility records (metric tons/year).
(g) Annual mass of petroleum coke dust removed from the process
through the dust collection system of the coke calcining unit from
facility records (metric tons/year) and an indication of whether coke
dust is recycled to the unit (e.g., all dust is recycled, a portion of
the dust is recycled, or none of the dust is recycled).
(h) Annual average mass fraction carbon content of green coke fed
to the coke calcining unit from facility measurement data (metric tons
C per metric ton green coke).
(i) Annual average mass fraction carbon content of marketable
petroleum coke produced by the coke calcining unit from facility
measurement data (metric tons C per metric ton petroleum coke).
Sec. 98.497 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) and (b) of this section.
(a) The records of all parameters monitored under Sec. 98.494.
(b) The applicable verification software records as identified in
this paragraph (b). 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 (b)(1) through (5) of this section.
Retention of this file satisfies the recordkeeping requirement for the
data in paragraphs (b)(1) through (5) of this section.
(1) Monthly mass of green coke fed to the coke calcining unit from
facility records (metric tons/year) (equation 1 to Sec. 98.493(b)(2)).
(2) Monthly mass of marketable petroleum coke produced by the coke
calcining unit from facility records (metric tons/year) (equation 1 to
Sec. 98.493(b)(2)).
(3) Monthly mass of petroleum coke dust removed from the process
through the dust collection system of the coke calcining unit from
facility records (metric tons/year) (equation 1 to Sec. 98.493(b)(2)).
(4) Average monthly mass fraction carbon content of green coke fed
to the coke calcining unit from facility measurement data (metric tons
C per metric ton green coke) (equation 1 to Sec. 98.493(b)(2)).
(5) Average monthly mass fraction carbon content of marketable
petroleum coke produced by the coke calcining unit from facility
measurement data (metric tons C per metric ton petroleum coke)
(equation 1 to Sec. 98.493(b)(2)).
Sec. 98.498 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart XX--Calcium Carbide Production
Sec.
98.500 Definition of the source category.
98.501 Reporting threshold.
98.502 GHGs to report.
98.503 Calculating GHG emissions.
98.504 Monitoring and QA/QC requirements.
98.505 Procedures for estimating missing data.
98.506 Data reporting requirements.
98.507 Records that must be retained.
98.508 Definitions.
Sec. 98.500 Definition of the source category.
The calcium carbide production source category consists of any
facility that produces calcium carbide.
Sec. 98.501 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a calcium carbide production process and the facility meets
the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.502 GHGs to report.
You must report:
(a) Process CO2 emissions from each calcium carbide
process unit or furnace used for the production of calcium carbide.
(b) CO2, CH4, and N2O emissions
from each stationary combustion unit following the requirements of
subpart C of this part. You must report these emissions under subpart C
of this part by following the requirements of subpart C.
Sec. 98.503 Calculating GHG emissions.
You must calculate and report the annual process CO2
emissions from each calcium carbide process unit not subject to
paragraph (c) of this section using the procedures in either paragraph
(a) or (b) of this section.
(a) Calculate and report under this subpart the combined process
and
[[Page 31953]]
combustion CO2 emissions by operating and maintaining CEMS
according to the Tier 4 Calculation Methodology in Sec. 98.33(a)(4)
and all associated requirements for Tier 4 in subpart C of this part.
(b) Calculate and report under this subpart the annual process
CO2 emissions from the calcium carbide process unit using
the carbon mass balance procedure specified in paragraphs (b)(1) and
(2) of this section.
(1) For each calcium carbide process unit, determine the annual
mass of carbon in each carbon-containing input and output material for
the calcium carbide process unit and estimate annual process
CO2 emissions from the calcium carbide process unit using
equation 1 to this paragraph (b)(1). Carbon-containing input materials
include carbon electrodes and carbonaceous reducing agents. If you
document that a specific input or output material contributes less than
1 percent of the total carbon into or out of the process, you do not
have to include the material in your calculation using equation 1.
Equation 1 to paragraph (b)(1)
[GRAPHIC] [TIFF OMITTED] TR25AP24.071
Where:
ECO2 = Annual process CO2 emissions from an
individual calcium carbide process unit (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
Mreducing agenti = Annual mass of reducing agent i fed,
charged, or otherwise introduced into the calcium carbide process
unit (tons).
Creducing agenti = Carbon content in reducing agent i
(percent by weight, expressed as a decimal fraction).
Melectrodem = Annual mass of carbon electrode m consumed
in the calcium carbide process unit (tons).
Celectrodem = Carbon content of the carbon electrode m
(percent by weight, expressed as a decimal fraction).
Mproduct outgoingk = Annual mass of alloy product k
tapped from the calcium carbide process unit (tons).
Cproduct outgoingk = Carbon content in alloy product k
(percent by weight, expressed as a decimal fraction).
Mnon-product outgoingl = Annual mass of non-product
outgoing material l removed from the calcium carbide unit (tons).
Cnon-product outgoing = Carbon content in non-product
outgoing material l (percent by weight, expressed as a decimal
fraction).
(2) Determine the combined annual process CO2 emissions
from the calcium carbide process units at your facility using equation
2 to this paragraph (b)(2).
Equation 2 to paragraph (b)(2)
CO2 = [Sigma]1k ECO2k
Where:
CO2 = Annual process CO2 emissions from
calcium carbide process units at a facility used for the production
of calcium carbide (metric tons).
ECO2k = Annual process CO2 emissions
calculated from calcium carbide process unit k calculated using
equation 1 to paragraph (b)(1) of this section (metric tons).
k = Total number of calcium carbide process units at facility.
(c) If all GHG emissions from a calcium carbide process unit are
vented through the same stack as any combustion unit or process
equipment that reports CO2 emissions using a CEMS that
complies with the Tier 4 Calculation Methodology in subpart C of this
part, then the calculation methodology in paragraph (b) of this section
must not be used to calculate process emissions. The owner or operator
must report under this subpart the combined stack emissions according
to the Tier 4 Calculation Methodology in Sec. 98.33(a)(4) and all
associated requirements for Tier 4 in subpart C of this part.
Sec. 98.504 Monitoring and QA/QC requirements.
If you determine annual process CO2 emissions using the
carbon mass balance procedure in Sec. 98.503(b), you must meet the
requirements specified in paragraphs (a) and (b) of this section.
(a) Determine the annual mass for each material used for the
calculations of annual process CO2 emissions using equation
1 to Sec. 98.503(b)(1) by summing the monthly mass for the material
determined for each month of the calendar year. The monthly mass may be
determined using plant instruments used for accounting purposes,
including either direct measurement of the quantity of the material
placed in the unit or by calculations using process operating
information.
(b) For each material identified in paragraph (a) of this section,
you must determine the average carbon content of the material consumed,
used, or produced in the calendar year using the methods specified in
either paragraph (b)(1) or (2) of this section. If you document that a
specific process input or output contributes less than one percent of
the total mass of carbon into or out of the process, you do not have to
determine the monthly mass or annual carbon content of that input or
output.
(1) Information provided by your material supplier.
(2) Collecting and analyzing at least three representative samples
of the material inputs and outputs each year. The carbon content of the
material must be analyzed at least annually using the standard methods
(and their QA/QC procedures) specified in paragraphs (b)(2)(i) and (ii)
of this section, as applicable.
(i) ASTM D5373-08 (incorporated by reference, see Sec. 98.7), for
analysis of carbonaceous reducing agents and carbon electrodes.
(ii) ASTM C25-06 (incorporated by reference, see Sec. 98.7) for
analysis of materials such as limestone or dolomite.
Sec. 98.505 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions
[[Page 31954]]
calculations in Sec. 98.503 is required. Therefore, whenever a
quality-assured value of a required parameter is unavailable, a
substitute data value for the missing parameter must be used in the
calculations as specified in the paragraphs (a) and (b) of this
section. You must document and keep records of the procedures used for
all such estimates.
(a) If you determine CO2 emissions for the calcium
carbide process unit at your facility using the carbon mass balance
procedure in Sec. 98.503(b), 100 percent data availability is required
for the carbon content of the input and output materials. You must
repeat the test for average carbon contents of inputs according to the
procedures in Sec. 98.504(b) if data are missing.
(b) For missing records of the monthly mass of carbon-containing
inputs and outputs, the substitute data value must be based on the best
available estimate of the mass of the inputs and outputs from all
available process data or data used for accounting purposes, such as
purchase records.
Sec. 98.506 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)
through (h) of this section, as applicable:
(a) Annual facility calcium carbide production capacity (tons).
(b) The annual facility production of calcium carbide (tons).
(c) Total number of calcium carbide process units at facility used
for production of calcium carbide.
(d) Annual facility consumption of petroleum coke (tons).
(e) Each end use of any calcium carbide produced and sent off site.
(f) If the facility produces acetylene on site, provide the
information in paragraphs (f)(1) through (3) of this section.
(1) The annual production of acetylene at the facility (tons).
(2) The annual quantity of calcium carbide used for the production
of acetylene at the facility (tons).
(3) Each end use of any acetylene produced on-site.
(g) If a CEMS is used to measure CO2 emissions, then you
must report under this subpart the relevant information required by
Sec. 98.36 for the Tier 4 Calculation Methodology and the information
specified in paragraphs (g)(1) and (2) of this section.
(1) Annual CO2 emissions (in metric tons) from each CEMS
monitoring location measuring process emissions from the calcium
carbide process unit.
(2) Identification number of each process unit.
(h) If a CEMS is not used to measure CO2 process
emissions, and the carbon mass balance procedure is used to determine
CO2 emissions according to the requirements in Sec.
98.503(b), then you must report the information specified in paragraphs
(h)(1) through (3) of this section.
(1) Annual process CO2 emissions (in metric tons) from
each calcium carbide process unit.
(2) List the method used for the determination of carbon content
for each input and output material included in the calculation of
annual process CO2 emissions for each calcium carbide
process unit (i.e., supplier provided information, analyses of
representative samples you collected).
(3) If you use the missing data procedures in Sec. 98.505(b), you
must report for each calcium carbide production process unit how
monthly mass of carbon-containing inputs and outputs with missing data
were determined and the number of months the missing data procedures
were used.
Sec. 98.507 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (d) of this
section for each calcium carbide process unit, as applicable.
(a) If a CEMS is used to measure CO2 emissions according to the
requirements in Sec. 98.503(a), then you must retain under this
subpart the records required for the Tier 4 Calculation Methodology in
Sec. 98.37 and the information specified in paragraphs (a)(1) through
(3) of this section.
(1) Monthly calcium carbide process unit production quantity
(tons).
(2) Number of calcium carbide processing unit operating hours each
month.
(3) Number of calcium carbide processing unit operating hours in a
calendar year.
(b) If the carbon mass balance procedure is used to determine
CO2 emissions according to the requirements in Sec.
98.503(b)(2), then you must retain records for the information
specified in paragraphs (b)(1) through (5) of this section.
(1) Monthly calcium carbide process unit production quantity
(tons).
(2) Number of calcium carbide process unit operating hours each
month.
(3) Number of calcium carbide process unit operating hours in a
calendar year.
(4) Monthly material quantity consumed, used, or produced for each
material included for the calculations of annual process CO2
emissions (tons).
(5) Average carbon content determined and records of the supplier
provided information or analyses used for the determination for each
material included for the calculations of annual process CO2
emissions.
(c) You must keep records that include a detailed explanation of
how company records of measurements are used to estimate the carbon
input and output to each calcium carbide process unit, including
documentation of specific input or output materials excluded from
equation 1 to Sec. 98.503(b)(1) that contribute less than 1 percent of
the total carbon into or out of the process. You also must document the
procedures used to ensure the accuracy of the measurements of materials
fed, charged, or placed in a calcium carbide process unit including,
but not limited to, calibration of weighing equipment and other
measurement devices. The estimated accuracy of measurements made with
these devices must also be recorded, and the technical basis for these
estimates must be provided.
(d) The applicable verification software records as identified in
this paragraph (d). 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 (d)(1) through (8) of this section.
Retention of this file satisfies the recordkeeping requirement for the
data in paragraphs (d)(1) through (8) of this section.
(1) Carbon content in reducing agent (percent by weight, expressed
as a decimal fraction) (equation 1 to Sec. 98.503(b)(1)).
(2) Annual mass of reducing agent fed, charged, or otherwise
introduced into the calcium carbide process unit (tons) (equation 1 to
Sec. 98.503(b)(1)).
(3) Carbon content of carbon electrode (percent by weight,
expressed as a decimal fraction) (equation 1 to Sec. 98.503(b)(1)).
(4) Annual mass of carbon electrode consumed in the calcium carbide
process unit (tons) (equation 1 to Sec. 98.503(b)(1)).
(5) Carbon content in product (percent by weight, expressed as a
decimal fraction) (equation 1 to Sec. 98.503(b)(1)).
(6) Annual mass of product produced/tapped in the calcium carbide
process unit (tons) (equation 1 to Sec. 98.503(b)(1)).
(7) Carbon content in non-product outgoing material (percent by
weight, expressed as a decimal fraction) (equation 1 to Sec.
98.503(b)(1)).
(8) Annual mass of non-product outgoing material removed from
calcium carbide process unit (tons) (equation 1 to Sec. 98.503(b)(1)).
[[Page 31955]]
Sec. 98.508 Definitions.
All terms used of this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart YY--Caprolactam, Glyoxal, and Glyoxylic Acid Production
Sec.
98.510 Definition of the source category.
98.511 Reporting threshold.
98.512 GHGs to report.
98.513 Calculating GHG emissions.
98.514 Monitoring and QA/QC requirements.
98.515 Procedures for estimating missing data.
98.516 Data reporting requirements.
98.517 Records that must be retained.
98.518 Definitions.
Table 1 to Subpart YY of Part 98--N2O Generation Factors
Sec. 98.510 Definition of the source category.
This source category includes any facility that produces
caprolactam, glyoxal, or glyoxylic acid. This source category excludes
the production of glyoxal through the LaPorte process (i.e., the gas-
phase catalytic oxidation of ethylene glycol with air in the presence
of a silver or copper catalyst).
Sec. 98.511 Reporting threshold.
You must report GHG emissions under this subpart if your facility
meets the requirements of either Sec. 98.2(a)(1) or (2) and the
definition of source category in Sec. 98.510.
Sec. 98.512 GHGs to report.
(a) You must report N2O process emissions from the
production of caprolactam, glyoxal, and glyoxylic acid as required by
this subpart.
(b) You must report under subpart C of this part the emissions of
CO2, CH4, and N2O from each stationary
combustion unit by following the requirements of subpart C of this
part.
Sec. 98.513 Calculating GHG emissions.
(a) You must determine annual N2O process emissions from
each caprolactam, glyoxal, and glyoxylic acid process line using the
appropriate default N2O generation factor(s) from table 1 to
this subpart, the site-specific N2O destruction factor(s)
for each N2O abatement device, and site-specific production
data according to paragraphs (b) through (e) of this section.
(b) You must determine the total annual amount of product i
(caprolactam, glyoxal, or glyoxylic acid) produced on each process line
t (metric tons product), according to Sec. 98.514(b).
(c) If process line t exhausts to any N2O abatement
technology j, you must determine the destruction efficiency for each
N2O abatement technology according to paragraph (c)(1) or
(2) of this section.
(1) Use the control device manufacturer's specified destruction
efficiency.
(2) Estimate the destruction efficiency through process knowledge.
Examples of information that could constitute process knowledge include
calculations based on material balances, process stoichiometry, or
previous test results provided the results are still relevant to the
current vent stream conditions. You must document how process knowledge
(if applicable) was used to determine the destruction efficiency.
(d) If process line t exhausts to any N2O abatement
technology j, you must determine the abatement utilization factor for
each N2O abatement technology according to paragraph (d)(1)
or (2) of this section.
(1) If the abatement technology j has no downtime during the year,
use 1.
(2) If the abatement technology j was not operational while product
i was being produced on process line t, calculate the abatement
utilization factor according to equation 1 to this paragraph (d)(2).
Equation 1 to paragraph (d)(2)
[GRAPHIC] [TIFF OMITTED] TR25AP24.072
Where:
AFj = Monthly abatement utilization factor of
N2O abatement technology j from process unit t (fraction
of time that abatement technology is operating).
Ti,j = Total number of hours during month that product i
(caprolactam, glyoxal, or glyoxylic acid), was produced from process
unit t during which N2O abatement technology j was
operational (hours).
Ti = Total number of hours during month that product i
(caprolactam, glyoxal, or glyoxylic acid), was produced from process
unit t (hours).
(e) You must calculate N2O emissions for each product i
from each process line t and each N2O control technology j
according to equation 2 to this paragraph (e).
Equation 2 to paragraph (e)
[GRAPHIC] [TIFF OMITTED] TR25AP24.073
Where:
EN2Ot = Monthly process emissions of N2O,
metric tons from process line t.
EFi = N2O generation factor for product i
(caprolactam, glyoxal, or glyoxylic acid), kg N2O/metric
ton of product produced, as shown in table 1 to this subpart.
Pi = Monthly production of product i, (caprolactam,
glyoxal, or glyoxylic acid), metric tons.
DEj = Destruction efficiency of N2O abatement
technology type j, fraction (decimal fraction of N2O
removed from vent stream).
AFj = Monthly abatement utilization factor for
N2O abatement technology type j, fraction, calculated
using equation 1 to paragraph (d)(2) of this section.
0.001 = Conversion factor from kg to metric tons.
(f) You must determine the annual emissions combined from each
process line at your facility using equation 3 to this paragraph (f):
Equation 3 to paragraph (f)
[GRAPHIC] [TIFF OMITTED] TR25AP24.074
[[Page 31956]]
Where:
N2O = Annual process N2O emissions from each
process line for product i (caprolactam, glyoxal, or glyoxylic acid)
(metric tons).
EN2Ot = Monthly process emissions of N2O from
each process line for product i (caprolactam, glyoxal, or glyoxylic
acid) (metric tons).
Sec. 98.514 Monitoring and QA/QC requirements.
(a) You must determine the total monthly amount of caprolactam,
glyoxal, and glyoxylic acid produced. These monthly amounts are
determined according to the methods in paragraph (a)(1) or (2) of this
section.
(1) Direct measurement of production (such as using flow meters,
weigh scales, etc.).
(2) Existing plant procedures used for accounting purposes (i.e.,
dedicated tank-level and acid concentration measurements).
(b) You must determine the annual amount of caprolactam, glyoxal,
and glyoxylic acid produced. These annual amounts are determined by
summing the respective monthly quantities determined in paragraph (a)
of this section.
Sec. 98.515 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data
value for the missing parameter must be used in the calculations as
specified in paragraphs (a) and (b) of this section.
(a) For each missing value of caprolactam, glyoxal, or glyoxylic
acid production, the substitute data must be the best available
estimate based on all available process data or data used for
accounting purposes (such as sales records).
(b) For missing values related to the N2O abatement
device, assuming that the operation is generally constant from year to
year, the substitute data value should be the most recent quality-
assured value.
Sec. 98.516 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)
through (j) of this section.
(a) Process line identification number.
(b) Annual process N2O emissions from each process line
according to paragraphs (b)(1) through (3) of this section.
(1) N2O from caprolactam production (metric tons).
(2) N2O from glyoxal production (metric tons).
(3) N2O from glyoxylic acid production (metric tons).
(c) Annual production quantities from all process lines at the
caprolactam, glyoxal, or glyoxylic acid production facility according
to paragraphs (c)(1) through (3) of this section.
(1) Caprolactam production (metric tons).
(2) Glyoxal production (metric tons).
(3) Glyoxylic acid production (metric tons).
(d) Annual production capacity from all process lines at the
caprolactam, glyoxal, or glyoxylic acid production facility, as
applicable, in paragraphs (d)(1) through (3) of this section.
(1) Caprolactam production capacity (metric tons).
(2) Glyoxal production capacity (metric tons).
(3) Glyoxylic acid production capacity (metric tons).
(e) Number of process lines at the caprolactam, glyoxal, or
glyoxylic acid production facility, by product, in paragraphs (e)(1)
through (3) of this section.
(1) Total number of process lines producing caprolactam.
(2) Total number of process lines producing glyoxal.
(3) Total number of process lines producing glyoxylic acid.
(f) Number of operating hours in the calendar year for each process
line at the caprolactam, glyoxal, or glyoxylic acid production facility
(hours).
(g) N2O abatement technologies used (if applicable) and
date of installation of abatement technology at the caprolactam,
glyoxal, or glyoxylic acid production facility.
(h) Monthly abatement utilization factor for each N2O
abatement technology for each process line at the caprolactam, glyoxal,
or glyoxylic acid production facility.
(i) Number of times in the reporting year that missing data
procedures were followed to measure production quantities of
caprolactam, glyoxal, or glyoxylic acid (months).
(j) Annual percent N2O emission reduction per chemical
produced at the caprolactam, glyoxal, or glyoxylic acid production
facility, as applicable, in paragraphs (j)(1) through (3) of this
section.
(1) Annual percent N2O emission reduction for all
caprolactam production process lines.
(2) Annual percent N2O emission reduction for all
glyoxal production process lines.
(3) Annual percent N2O emission reduction for all
glyoxylic acid production process lines.
Sec. 98.517 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (d) of this
section for each caprolactam, glyoxal, or glyoxylic acid production
facility:
(a) Documentation of how accounting procedures were used to
estimate production rate.
(b) Documentation of how process knowledge was used to estimate
abatement technology destruction efficiency (if applicable).
(c) Documentation of the procedures used to ensure the accuracy of
the measurements of all reported parameters, including but not limited
to, calibration of weighing equipment, flow meters, and other
measurement devices. The estimated accuracy of measurements made with
these devices must also be recorded, and the technical basis for these
estimates must be provided.
(d) The applicable verification software records as identified in
this paragraph (d). 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 (d)(1) through (4) of this section.
Retention of this file satisfies the recordkeeping requirement for the
data in paragraphs (d)(1) through (4) of this section.
(1) Monthly production quantity of caprolactam from each process
line at the caprolactam, glyoxal, or glyoxylic acid production facility
(metric tons).
(2) Monthly production quantity of glyoxal from each process line
at the caprolactam, glyoxal, or glyoxylic acid production facility
(metric tons).
(3) Monthly production quantity of glyoxylic acid from each process
line at the caprolactam, glyoxal, or glyoxylic acid production facility
(metric tons).
(4) Destruction efficiency of N2O abatement technology
from each process line, fraction (decimal fraction of N2O
removed from vent stream).
Sec. 98.518 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table 1 to Subpart YY of Part 98--N2O Generation Factors
------------------------------------------------------------------------
N2O
Product generation
factor \a\
------------------------------------------------------------------------
Caprolactam................................................ 9.0
Glyoxal.................................................... 520
[[Page 31957]]
Glyoxylic acid............................................. 100
------------------------------------------------------------------------
\a\ Generation factors in units of kilograms of N2O emitted per metric
ton of product produced.
Subpart ZZ--Ceramics Manufacturing
Sec.
98.520 Definition of the source category.
98.521 Reporting threshold.
98.522 GHGs to report.
98.523 Calculating GHG emissions.
98.524 Monitoring and QA/QC requirements.
98.525 Procedures for estimating missing data.
98.526 Data reporting requirements.
98.527 Records that must be retained.
98.528 Definitions.
Table 1 to Subpart ZZ of Part 98--CO2 Emission Factors
for Carbonate-Based Raw Materials
Sec. 98.520 Definition of the source category.
(a) The ceramics manufacturing source category consists of any
facility that uses nonmetallic, inorganic materials, many of which are
clay-based, to produce ceramic products such as bricks and roof tiles,
wall and floor tiles, table and ornamental ware (household ceramics),
sanitary ware, refractory products, vitrified clay pipes, expanded clay
products, inorganic bonded abrasives, and technical ceramics (e.g.,
aerospace, automotive, electronic, or biomedical applications). For the
purposes of this subpart, ceramics manufacturing processes include
facilities that annually consume at least 2,000 tons of carbonates,
either as raw materials or as a constituent in clay, which is heated to
a temperature sufficient to allow the calcination reaction to occur,
and operate a ceramics manufacturing process unit.
(b) A ceramics manufacturing process unit is a kiln, dryer, or oven
used to calcine clay or other carbonate-based materials for the
production of a ceramics product.
Sec. 98.521 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a ceramics manufacturing process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.522 GHGs to report.
You must report:
(a) CO2 process emissions from each ceramics process
unit (e.g., kiln, dryer, or oven).
(b) CO2 combustion emissions from each ceramics process
unit.
(c) CH4 and N2O combustion emissions from
each ceramics process unit. You must calculate and report these
emissions under subpart C of this part by following the requirements of
subpart C of this part.
(d) CO2, CH4, and N2O combustion
emissions from each stationary fuel combustion unit other than kilns,
dryers, or ovens. You must report these emissions under subpart C of
this part by following the requirements of subpart C of this part.
Sec. 98.523 Calculating GHG emissions.
You must calculate and report the annual process CO2
emissions from each ceramics process unit using the procedures in
paragraphs (a) through (c) of this section.
(a) For each ceramics process unit that meets the conditions
specified in Sec. 98.33(b)(4)(ii) or (iii), you must calculate and
report under this subpart the combined process and combustion
CO2 emissions by operating and maintaining a CEMS to measure
CO2 emissions according to the Tier 4 Calculation
Methodology specified in Sec. 98.33(a)(4) and all associated
requirements for Tier 4 in subpart C of this part.
(b) For each ceramics process unit that is not subject to the
requirements in paragraph (a) of this section, calculate and report the
process and combustion CO2 emissions from the ceramics
process unit separately by using the procedures specified in paragraphs
(b)(1) through (6) of this section, except as specified in paragraph
(c) of this section.
(1) For each carbonate-based raw material (including clay) charged
to the ceramics process unit, either obtain the mass fractions of any
carbonate-based minerals from the supplier of the raw material or by
sampling the raw material, or use a default value of 1.0 as the mass
fraction for the raw material.
(2) Determine the quantity of each carbonate-based raw material
charged to the ceramics process unit.
(3) Apply the appropriate emission factor for each carbonate-based
raw material charged to the ceramics process unit. Table 1 to this
subpart provides emission factors based on stoichiometric ratios for
carbonate-based minerals.
(4) Use equation 1 to this paragraph (b)(4) to calculate process
mass emissions of CO2 for each ceramics process unit:
Equation 1 to paragraph (b)(4)
[GRAPHIC] [TIFF OMITTED] TR25AP24.075
Where:
ECO2 = Annual process CO2 emissions (metric
tons/year).
Mj = Annual mass of the carbonate-based raw material j
consumed (tons/year).
2000/2205 = Conversion factor to convert tons to metric tons.
MFi = Annual average decimal mass fraction of carbonate-
based mineral i in carbonate-based raw material j.
EFi = Emission factor for the carbonate-based mineral i,
(metric tons CO2/metric ton carbonate, see table 1 to
this subpart).
Fi = Decimal fraction of calcination achieved for
carbonate-based mineral i, assumed to be equal to 1.0.
i = Index for carbonate-based mineral in each carbonate-based raw
material.
j = Index for carbonate-based raw material.
(5) Determine the combined annual process CO2 emissions
from the ceramic process units at your facility using equation 2 to
this paragraph (b)(5):
Equation 2 to paragraph (b)(5)
CO2 = [Sigma]k1 ECO2k
Where:
CO2 = Annual process CO2 emissions from
ceramic process units at a facility (metric tons).
ECO2k = Annual process CO2 emissions
calculated from ceramic process unit k calculated using equation 1
to paragraph (b)(4) of this section (metric tons).
k = Total number of ceramic process units at facility.
(6) Calculate and report under subpart C of this part the
combustion CO2 emissions in the ceramics process unit
according to the applicable requirements in subpart C of this part.
(c) A value of 1.0 can be used for the mass fraction
(MFi) of carbonate-based mineral i in each carbonate-based
raw material j in equation 1 to paragraph (b)(4) of this section. The
use of 1.0 for the mass fraction assumes that the carbonate-based raw
material comprises 100% of one carbonate-based mineral. As an
alternative to the default value, you may use data provided by either
the raw material supplier or a lab analysis.
[[Page 31958]]
Sec. 98.524 Monitoring and QA/QC requirements.
(a) You must measure annual amounts of carbonate-based raw
materials charged to each ceramics process unit from monthly
measurements using plant instruments used for accounting purposes, such
as calibrated scales or weigh hoppers. Total annual mass charged to
ceramics process units at the facility must be compared to records of
raw material purchases for the year.
(b) You must use the default value of 1.0 for the mass fraction of
a carbonate-based mineral, or you may opt to obtain the mass fraction
of any carbonate-based materials from the supplier of the raw material
or by sampling the raw material. If you opt to obtain the mass
fractions of any carbonate-based minerals from the supplier of the raw
material or by sampling the raw material, you must measure the
carbonate-based mineral mass fractions at least annually to verify the
mass fraction data. You may conduct the sampling and chemical analysis
using any x-ray fluorescence test, x-ray diffraction test, or other
enhanced testing method published by an industry consensus standards
organization (e.g., ASTM, ASME, API). If it is determined that the mass
fraction of a carbonate based raw material is below the detection limit
of available industry testing standards, you may use a default value of
0.005.
(c) You must use the default value of 1.0 for the mass fraction of
a carbonate-based mineral, or you may opt to obtain the mass fraction
of any carbonate-based materials from the supplier of the raw material
or by sampling the raw material. If you obtain the mass fractions of
any carbonate-based minerals from the supplier of the raw material or
by sampling the raw material, you must determine the annual average
mass fraction for the carbonate-based mineral in each carbonate-based
raw material at least annually by calculating an arithmetic average of
the data obtained from raw material suppliers or sampling and chemical
analysis.
(d) You must use the default value of 1.0 for the calcination
fraction of a carbonate-based mineral. Alternatively, you may opt to
obtain the calcination fraction of any carbonate-based mineral by
sampling. If you opt to obtain the calcination fraction of any
carbonate-based minerals from sampling, you must determine on an annual
basis the calcination fraction for each carbonate-based mineral
consumed based on sampling and chemical analysis. You may conduct the
sampling and chemical analysis using any x-ray fluorescence test, x-ray
diffraction test, or other enhanced testing method published by an
industry consensus standards organization (e.g., ASTM, ASME, API).
Sec. 98.525 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations in Sec. 98.523 is required. If the monitoring
and quality assurance procedures in Sec. 98.524 cannot be followed and
data is unavailable, you must use the most appropriate of the missing
data procedures in paragraphs (a) and (b) of this section in the
calculations. You must document and keep records of the procedures used
for all such missing value estimates.
(a) If the CEMS approach is used to determine combined process and
combustion CO2 emissions, the missing data procedures in
Sec. 98.35 apply.
(b) For missing data on the monthly amounts of carbonate-based raw
materials charged to any ceramics process unit, use the best available
estimate(s) of the parameter(s) based on all available process data or
data used for accounting purposes, such as purchase records.
(c) For missing data on the mass fractions of carbonate-based
minerals in the carbonate-based raw materials, assume that the mass
fraction of a carbonate-based mineral is 1.0, which assumes that one
carbonate-based mineral comprises 100 percent of the carbonate-based
raw material.
Sec. 98.526 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)
through (c) of this section, as applicable:
(a) The total number of ceramics process units at the facility and
the number of units that operated during the reporting year.
(b) If a CEMS is used to measure CO2 emissions from
ceramics process units, then you must report under this subpart the
relevant information required under Sec. 98.36 for the Tier 4
Calculation Methodology and the following information specified in
paragraphs (b)(1) through (3) of this section.
(1) The annual quantity of each carbonate-based raw material
(including clay) charged to each ceramics process unit and for all
units combined (tons).
(2) Annual quantity of each type of ceramics product manufactured
by each ceramics process unit and by all units combined (tons).
(3) Annual production capacity for each ceramics process unit
(tons).
(c) If a CEMS is not used to measure CO2 emissions from
ceramics process units and process CO2 emissions are
calculated according to the procedures specified in Sec. 98.523(b),
then you must report the following information specified in paragraphs
(c)(1) through (7) of this section.
(1) Annual process emissions of CO2 (metric tons) for
each ceramics process unit and for all units combined.
(2) The annual quantity of each carbonate-based raw material
(including clay) charged to each ceramics process unit and for all
units combined (tons).
(3) Results of all tests used to verify each carbonate-based
mineral mass fraction for each carbonate-based raw material charged to
a ceramics process unit, as specified in paragraphs (c)(3)(i) through
(iii) of this section.
(i) Date of test.
(ii) Method(s) and any variations used in the analyses.
(iii) Mass fraction of each sample analyzed.
(4) Method used to determine the decimal mass fraction of
carbonate-based mineral, unless you used the default value of 1.0
(e.g., supplier provided information, analyses of representative
samples you collected, or use of a default value of 0.005 as specified
by Sec. 98.524(b)).
(5) Annual quantity of each type of ceramics product manufactured
by each ceramics process unit and by all units combined (tons).
(6) Annual production capacity for each ceramics process unit
(tons).
(7) If you use the missing data procedures in Sec. 98.525(b), you
must report for each applicable ceramics process unit the number of
times in the reporting year that missing data procedures were followed
to measure monthly quantities of carbonate-based raw materials or mass
fraction of the carbonate-based minerals (months).
Sec. 98.527 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (d) of this
section for each ceramics process unit, as applicable.
(a) If a CEMS is used to measure CO2 emissions according
to the requirements in Sec. 98.523(a), then you must retain under this
subpart the records required under Sec. 98.37 for the Tier 4
Calculation Methodology and the information specified in paragraphs
(a)(1) and (2) of this section.
(1) Monthly ceramics production rate for each ceramics process unit
(tons).
(2) Monthly amount of each carbonate-based raw material charged to
each ceramics process unit (tons).
(b) If process CO2 emissions are calculated according to
the procedures
[[Page 31959]]
specified in Sec. 98.523(b), you must retain the records in paragraphs
(b)(1) through (6) of this section.
(1) Monthly ceramics production rate for each ceramics process unit
(metric tons).
(2) Monthly amount of each carbonate-based raw material charged to
each ceramics process unit (metric tons).
(3) Data on carbonate-based mineral mass fractions provided by the
raw material supplier for all raw materials consumed annually and
included in calculating process emissions in equation 1 to Sec.
98.523(b)(4), if applicable.
(4) Results of all tests, if applicable, used to verify the
carbonate-based mineral mass fraction for each carbonate-based raw
material charged to a ceramics process unit, including the data
specified in paragraphs (b)(4)(i) through (v) of this section.
(i) Date of test.
(ii) Method(s), and any variations of methods, used in the
analyses.
(iii) Mass fraction of each sample analyzed.
(iv) Relevant calibration data for the instrument(s) used in the
analyses.
(v) Name and address of laboratory that conducted the tests.
(5) Each carbonate-based mineral mass fraction for each carbonate-
based raw material, if a value other than 1.0 is used to calculate
process mass emissions of CO2.
(6) Number of annual operating hours of each ceramics process unit.
(c) All other documentation used to support the reported GHG
emissions.
(d) The applicable verification software records as identified in
this paragraph (d). 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 (d)(1) through (3) of this section.
Retention of this file satisfies the recordkeeping requirement for the
data in paragraphs (d)(1) through (3) of this section.
(1) Annual average decimal mass fraction of each carbonate-based
mineral in each carbonate-based raw material for each ceramics process
unit (specify the default value, if used, or the value determined
according to Sec. 98.524) (percent by weight, expressed as a decimal
fraction) (equation 1 to Sec. 98.523(b)(4)).
(2) Annual mass of each carbonate-based raw material charged to
each ceramics process unit (tons) (equation 1 to Sec. 98.523(b)(4)).
(3) Decimal fraction of calcination achieved for each carbonate-
based raw material for each ceramics process unit (specify the default
value, if used, or the value determined according to Sec. 98.524)
(percent by weight, expressed as a decimal fraction) (equation 1 to
Sec. 98.523(b)(4)).
Sec. 98.528 Definitions.
All terms used of this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table 1 to Subpart ZZ of Part 98--CO2 Emission Factors for Carbonate-
Based Raw Materials
------------------------------------------------------------------------
CO2 emission
Carbonate Mineral name(s) factor \a\
------------------------------------------------------------------------
BaCO3.......................... Witherite, Barium 0.223
carbonate.
CaCO3.......................... Limestone, Calcium 0.440
Carbonate, Calcite,
Aragonite.
Ca(Fe,Mg,Mn)(CO3)2............. Ankerite \b\........... 0.408-0.476
CaMg(CO3)2..................... Dolomite............... 0.477
FeCO3.......................... Siderite............... 0.380
K2CO3.......................... Potassium carbonate.... 0.318
Li2CO3......................... Lithium carbonate...... 0.596
MgCO3.......................... Magnesite.............. 0.522
MnCO3.......................... Rhodochrosite.......... 0.383
Na2CO3......................... Sodium carbonate, Soda 0.415
ash.
SrCO3.......................... Strontium carbonate, 0.298
Strontianite.
------------------------------------------------------------------------
\a\ Emission factors are in units of metric tons of CO2 emitted per
metric ton of carbonate-based material.
\b\ Ankerite emission factors are based on a formula weight range that
assumes Fe, Mg, and Mn are present in amounts of at least 1.0 percent.
[FR Doc. 2024-07413 Filed 4-24-24; 8:45 am]
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